Energy & Technology
- Cellulosic materials, such as agricultural or forestry residues, short rotation woody crops, and a variety of grasses, can be used to produce biofuels like ethanol. The process of converting cellulosic materials to ethanol is more complex than current ethanol production from corn or sugarcane, and the technology is not yet used at commercial scale.
- Cellulosic ethanol is currently an emerging technology and will require continued technological advancements and reduced costs to become commercially viable.
- The Energy Independence and Security Act (EISA) of 2007 includes requirements for cellulosic ethanol use, beginning with 100 million gallons of cellulosic ethanol in 2010 and increasing yearly to 16 billion gallons by 2022. EISA also requires that cellulosic ethanol achieve at least a 60 percent reduction in life-cycle greenhouse gas emissions per gallon relative to gasoline.
Ethanol, an alcohol that can be produced from a wide variety of plant materials as feedstocks, is used as a liquid fuel in motor vehicles. At present corn starch and sugarcane are the two main feedstocks used, respectively producing starch- and sugar-based ethanol. Another type of plant material, cellulose, can also be used to produce ethanol, but doing so requires additional processing to break down the cellulosic materials into sugars. Ethanol produced from cellulose is referred to as cellulosic ethanol.
Cellulosic materials, which provide structure to plants, are found in the stems, stalks, and leaves of plants and in the trunks of trees. The abundance of cellulosic materials – roughly 60 to 90 percent of terrestrial biomass by weight – along with the fact that they are not used for food and feed (unlike corn and sugarcane), are key reasons why cellulosic ethanol and other cellulose-based biofuels have attracted scientific and political interest. Cellulose and hemicellulose, which are referred to collectively as cellulosic materials, can be broken down into sugars, which can then be fermented into ethanol. Cellulosic materials being examined for the production of biofuels include those derived from switchgrass, prairie grasses, short rotation woody crops, agricultural residues, and forestry materials and residues.
Ethanol is chemically the same whether it is produced from corn, sugarcane, or cellulose, but the production processes are different and the necessary production technologies are in different stages of development. Corn- and sugar-based ethanol production technologies have been used at commercial scale for decades (see Climate TechBook: Ethanol). In contrast, some of the technologies needed to produce cellulosic ethanol, an “advanced biofuel” (broadly defined as a biofuel derived from organic materials other than simple sugars, starches, or oils1) are quite new. As of mid-2009, no large, commercial-size cellulosic ethanol facilities were in operation in the United States.
The production of ethanol from cellulosic materials is more complicated than the processes employed for starch- or sugar-based ethanol, because the complex cellulose-hemicellulose-lignin structure in which cellulosic materials are found needs to be broken up before fermentation can begin. The cellulosic ethanol conversion process consists of two basic steps: pretreatment and fermentation. This two-step process increases the complexity of, and processing time required for, converting the cellulosic biomass into ethanol, relative to the processes used to convert corn or sugarcane to ethanol.
Pretreatment is necessary to prepare cellulosic materials for a subsequent hydrolysis step which converts the hemicellulose and cellulose into sugars. Typical pretreatment involves a chemical pretreatment step (e.g., acid) and a physical pretreatment step (e.g., grinding). These steps make the cellulose more accessible to enzymes that catalyze its conversion to sugars in a subsequent step and begin the breakdown of hemicellulose into sugar. Following pretreatment, the conversion of cellulose to sugar is completed using a chemical reaction called hydrolysis, normally employing enzymes secreted by certain organisms (typically fungi or bacteria) to catalyze the reaction. The pretreatment and hydrolysis process usually results in one co-product, lignin, which can be burned to generate heat or electricity. Using lignin instead of a fossil-based energy source to power the conversion process reduces cellulosic ethanol’s life-cycle greenhouse gas (GHG) emissions, compared to corn-based ethanol. (This is also an example of biomass substitution for fossil fuels; for more information, see Climate TechBook: Agriculture Overview.)
Once the sugars have been obtained from the cellulosic materials, they are fermented using yeast or bacteria in processes similar to those used for the corn-based ethanol production. The liquid resulting from the fermentation process contains ethanol and water; the water is removed through distillation, again similar to the corn-based ethanol process. Finding the most effective and low-cost enzymes for the pretreatment process and organisms for the fermentation process has been one of the main areas of research in the development of cellulosic ethanol.2
The type of feedstock and method of pretreatment both influence the amount of ethanol produced. Currently, one dry short ton3 of cellulosic feedstock yields about 60 gallons of ethanol.4 Projected yields with anticipated technological advances are as high as 100 gallons of ethanol per dry short ton of feedstock.5
Environmental Benefit/Emission Reduction Potential
Cellulosic ethanol has the potential to provide significant lifecycle GHG reductions compared to petroleum-based gasoline. In addition, the use of cellulosic materials to produce ethanol may yield a variety of other environmental benefits relative to corn-based ethanol.
- GHG emission reduction potential
Researchers at the University of California at Berkeley estimated that on a life-cycle basis, cellulosic ethanol could lower GHG emissions by 90 percent relative to petroleum-based gasoline.6 Other analyses have shown that cellulosic ethanol produced using certain feedstocks could be carbon-negative, which means that more carbon dioxide (CO2) is removed from the atmosphere than is emitted into the atmosphere over the entire life-cycle of the product (see Climate TechBook: Agriculture Overview for a discussion of carbon storage in plants and soils).7 However, these studies do not include estimates of emissions due to indirect land use change (discussed under “Obstacles to Further Development”), which can affect GHG emission profiles significantly.
An analysis undertaken by the California Air Resources Board as it developed the California Low Carbon Fuel Standard found significant life-cycle GHG emission reductions from cellulosic ethanol relative to gasoline (see preliminary estimates in Table 1).8
Table 1: Life-cycle GHG Intensity for Cellulosic Ethanol, based on the California GREET Model9
|Fuel||Feedstock||CA GREET GHG|
Compared to Gasoline
|Cellulosic Ethanol||Farmed Trees||1.60||98.3%|
|Cellulosic Ethanol||Forest Residues||21.40||77.7%|
|California Gasoline (incl. 10% ethanol)||95.9|
Note: These impacts do not include the impact of indirect land use change on GHG emissions.
- Other environmental considerations
Using biomass for transportation fuels raises questions regarding land use and land use change, fertilizer and pesticide use, water consumption, and energy used for production and cultivation of feedstocks. Grasses and trees generally require lower inputs than other row crops such as corn. For example, grasses (e.g., switchgrass) are perennial crops that do not need to be re-planted for up to 20 years. Both grasses and trees require fewer passes of field equipment compared to annual crops such as corn,10 and they generally have lower fertilizer and pesticide needs.11 In addition, cellulosic feedstocks can be grown on marginal lands not suitable for other crops, although in this case per acre yields can be lower than feedstocks grown on other lands. Feedstocks can also include a variety of residues (e.g., agricultural and forestry residues). Where agricultural and forestry residues are used, care must be taken to ensure long-term soil health.
The increased complexity and longer processing time associated with producing ethanol from cellulosic materials also makes cellulosic ethanol more expensive to produce than corn- or sugarcane-based ethanol. As of early 2009, no commercial-scale facilities in the United States were producing cellulosic ethanol and costs will remain largely uncertain until the technology is demonstrated at a commercial scale. In 2006, U.S. Department of Energy (DOE) researchers reported achieving a cellulosic ethanol production cost of $2.25 per gallon.12 At this cost, cellulosic ethanol is competitive with petroleum-based gasoline when oil prices are near $120 per barrel.13
Two key factors that shape the cost of producing cellulosic ethanol are the high capital costs and uncertain feedstock costs.
- High capital costs
A first-of-its-kind cellulosic ethanol plant with a capacity of 50 million gallons per year is estimated to cost $375 million, roughly 6 times the capital cost of a similarly sized corn ethanol plant.14 These high initial investment costs can present a considerable hurdle to deployment, especially given the greater risk associated with investments in new technologies. As the technology matures, future plants are expected to have reduced capital costs.15
- Uncertain feedstock costs
Like all biofuels, costs of cellulosic ethanol are highly sensitive to feedstock costs. Therefore, estimating biomass supply costs is critical to estimating future cellulosic ethanol prices. Future feedstock production costs are uncertain and predictions depend on the assumptions made by analysts. Some predict that as the cellulosic ethanol industry matures, establishing a larger market for cellulosic crops and allowing feedstock producers to gain experience, costs could decline. On the other hand, as demand increases for cellulosic materials and the supply of low-cost waste products is used up, costs could increase. If technological advances and experience bring down capital costs, uncertain feedstock costs will continue to be an important factor in determining the cost competitiveness of cellulosic ethanol with other liquid motor fuels.
The overall cost of cellulosic ethanol is expected to decline in the future as technological advances are made, particularly in pretreatment steps. Table 2 provides a summary of cost estimates from several recent studies.
Table 2: Estimated future costs of cellulosic ethanol and price of oil where ethanol becomes cost-competitive
|Cost of Oil|
|Projected Year||Other Assumptions|
|Wyman, 2007||$0.75||$40||Feedstock accounts for 2/3 of production cost; $50/ton feedstock|
|Hemelinck et al., 2005||$1.50|
|Aden, 2002||$1.00-$1.35||$55-$70||2015-2020||Biomass feedstock cost ~$25-$50/dry short ton|
Sources: Goldemberg, J. (2007). "Ethanol for a Sustainable Energy Future." Science 315(5813): 808-810. Aden, A., M. Ruth, et al. (2002). “Lignocellulosic Biomass to Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis for Corn Stover.” Other Information: PBD: 1 Jun 2002. Hamelinck, C. N., van Hooijdonk, G., and Faaij, A. P. C. (2005) “Ethanol from Lignocellulosic Biomass: Techno-economic Performance in Short-, Middle-, and Long-term.” Biomass and Bioenergy 28(4): 384-410. Wyman, C. E. (2007). “What is (and is not) Vital to Advancing Cellulosic Ethanol.” TRENDS in Biotechnology 25(4): 153-157.
Cellulosic ethanol is not yet produced at a commercial scale in the United States. Public and private efforts continue to support research on cellulosic ethanol, and technological advances are expected to reduce costs and improve production methods. As of early 2009, no commercial-size cellulosic ethanol facilities were in operation in the United States. However a number of demonstration plants are in operation and a number of commercial-size facilities are expected to begin production by 2011.16 In 2007, the DOE funded six facilities with annual plant production goals ranging from 11.4 million to 40 million gallons of cellulosic ethanol.17 Although two of the funded companies canceled their plans to move forward due to economic difficulties, the remaining four companies intend to begin production by 2010-2011 and, together, produce a minimum of 70 million gallons of cellulosic ethanol per year. In 2007, the National Academy of Sciences found that the United States, using currently available crop residues as a feedstock, could produce about 10 billion gallons of cellulosic ethanol per year. This value assumes a production yield of 60 gallons of cellulosic ethanol per dry short ton, requiring the use of 160 million dry short tons of crop residues. If technological improvements increase production yields to 90 gallons per dry short ton, as some studies expect, annual production volumes could be about 14 billion gallons of cellulosic ethanol per year.18
In addition to production of ethanol, cellulosic materials are also being examined as a way to produce other biomass-based substitutes for existing fossil fuels (e.g., gasoline, diesel, and jet fuel) and biobutanol. Like the cellulosic ethanol production process, the thermochemical process that produces biomass-based replacements for existing fossil fuels is not yet at commercial scale, and research in this area is ongoing with the support of the DOE. Biobutanol, like ethanol, is an alcohol-based fuel that can be produced from biomass feedstocks. Biobutanol can be added to gasoline at higher blending quantities than ethanol (in unmodified engines), has a higher energy content per volume than ethanol, and is less corrosive, enabling transport in existing petroleum pipelines.19 Biobutanol is currently in research stages and no commercial production facilities currently exist.
Overall, as of January 2009, there were 26 projects using one of these three pathways (cellulose to ethanol, biomass-based substitutes for existing fossil fuels, or biobutanol) to produce fuel from cellulosic materials.20
Obstacles to Further Development or Deployment
Technological immaturity and high cost are two key barriers to cellulosic ethanol at present. Making this fuel competitive in the marketplace will require more experience and significantly reduced production costs, including capital costs. If the costs of cellulosic ethanol production come down as the technology matures, this fuel will still face some, although not all, of the obstacles that corn-based ethanol currently faces.
- Flex-fuel vehicle deployment
Recent research indicates that current passenger vehicles may be capable of running on fuel blends containing up to 20 percent ethanol by volume (E20).21 Higher-level blends (up to E85) can be used by flex-fuel vehicles. Flex-fuel modifications are relatively inexpensive when made during vehicle production (estimated to be $50 - $100 per vehicle22), but retrofitting existing vehicles could be costly. As of 2008, an estimated 7.3 million light-duty E85 vehicles,23 or roughly 3 percent of the roughly 250 million passenger vehicles currently registered in the United States,24 were flex-fuel vehicles. Higher-level blends also require dedicated pumps to dispense the fuel. Currently most of the 1,600 stations with E85 dispensing capability are concentrated in the Midwest, where most ethanol production occurs.25
- Infrastructure requirements
Ethanol cannot be shipped in existing crude oil or petroleum fuel pipelines, because ethanol can absorb water and other impurities that accumulate in these pipes, affecting fuel quality, and because ethanol’s corrosiveness can shorten pipeline lifetime. Instead, ethanol is currently transported via rail (60 percent of domestic ethanol shipped), truck (30 percent), and barge (10 percent).26 Currently in the United States, cellulosic feedstocks can be most easily grown in the Midwest and Southeast, but much of the demand for transportation fuels is along the coasts. Thus, large volumes of ethanol may need to be shipped long distances to reach areas of high demand in the future. Without substantial infrastructure investment, increased ethanol shipping could result in significant bottlenecks on both rail and highway networks. These problems could be reduced by encouraging the use of high-level ethanol blends (i.e., E85) regionally instead of low-level blends (E10) on a national basis. Distributing and using ethanol close to where it is produced – i.e., in the Midwest and Southeast – would also minimize the GHG emissions associated with transporting ethanol.27,28
- Food versus fuel
Unlike corn ethanol (or ethanol produced from sugarcane), cellulosic ethanol does not necessarily compete with food markets for feedstock directly. However, the production of cellulosic crops is constrained by land availability, which is a limited resource. To decrease competition with other agricultural crops, cellulosic feedstocks could be grown on degraded or marginal farmland unsuitable for production of food crops. However, doing so can decrease yields or increase input energy and fertilizer requirements, which could result in higher feedstock prices and increased GHG emissions.
- Land use change
The production of fuels from biomass feedstocks has direct and indirect impacts on land use. For example, clearing grasslands or forests to plant biofuel crops are direct land use changes that result in releases of carbon stored in soils and vegetation. Indirect land use change refers to the land use changes that result from the impacts on land and biomass prices due to increased demand for biomass for biofuel production and the interactions with ongoing demand for food, feed, and fiber products.
Accounting for indirect land use changes is particularly challenging and relies upon a number of estimates and assumptions. Recent studies have shown that the GHG impacts of indirect land use changes could significantly affect the overall life-cycle GHG emissions of biofuels. Both direct and indirect land-use change remain important areas of concern and a topic of continued scientific research.
Policy Options to Help Promote Cellulosic Ethanol
Federal, state, county, and local governments currently support biofuels in a variety of ways. For a discussion of policies that support biofuel production and consumption generally, see Climate TechBook: Biofuels Overview. The following discussion summarizes policies that specifically target cellulosic ethanol and other advanced biofuels.
- Mandates requiring biofuel use
The Energy Independence and Security Act (EISA) of 2007 establishes a renewable fuel standard that steadily increases U.S. biofuel use to 36 billion gallons by 2022. Advanced biofuels comprise 21 billion gallons of the total requirement, with cellulosic ethanol making up 16 billion gallons.
- Subsidies and tax credits
In addition to subsidies and tax benefits already in place promoting corn ethanol (discussed in Climate TechBook: Ethanol), producers of cellulosic biofuels benefit from an income tax credit of $1.01 per gallon, more than double the $0.45 tax credit available for corn ethanol.29
- Funding for pre-commercial scale plants
Federal funding for pilot-scale advanced biofuel plants will help accelerate advanced biofuels toward profitability. See the ‘Current Status of Technology’ section for more detail on current federal funding.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading/Additional Resources
National Renewable Energy Laboratory, “Biomass Research”
Renewable Fuels Association, “Cellulosic Ethanol”
U.S. Department of Energy (DOE)
- Biomass Energy Data Book, 2009
- Biomass Program: Information Resources
- Cellulosic Ethanol Production
- Transportation Energy Data Book, 2008
1 Other examples of advanced biofuels include bio-based hydrocarbon fuels (e.g., diesel fuel) from cellulosic materials, biogas from landfills and sewage waste treatment, and butanol or other alcohols produced from organic matter.
2 The U.S. Department of Energy (DOE) is working with biotechnology and biofuel companies to reduce enzyme costs, which are currently one of the key barriers to cost-competitive production of cellulosic ethanol. See U.S. DOE. “Testimony of Alexander Karsner, Assistant Secretary, Office of EERE, Before the Subcommittee on Conservation, Credit, Energy & Research; Committee on Agriculture; U.S. House of Representatives.” March 7, 2007.
3 A dry short ton of material has been dried to a relatively low, consistent moisture level (dry weight).
4 This is based on a mix of feedstocks, mainly waste products and some energy crops. For more information, see Tables 4.3 and 4.5, Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2007.
5 Granda, Cesar B., L. Zhu, and M.T. Holtzapp. (2007). “Sustainable Liquid Biofuels and Their Environmental Impact.” Environmental Progress 26(3): 233-250.
6 Farrell, A. E., R. J. Plevin, et al. (2006). "Ethanol Can Contribute to Energy and Environmental Goals." Science 311(5760): 506-508.
7 High-diversity prairie grasses and agricultural residues, such as corn stover, have both been studied as potentially carbon negative feedstocks when indirect land use change impacts are not included. For more, see Tilman, D., J. Hill, et al. (2006). "Carbon-Negative Biofuels from Low-Input High-Diversity Grassland Biomass." Science 314(5805): 1598-1600.
Sheehan, J., A. Aden, et al. (2003).
8 For more information, see California Air Resources Board, Low Carbon Fuel Standard Program.
9 These life-cycle GHG intensities were calculated for the purposes of the California Low-Carbon Fuel Standard program. For more information on the analysis, see California Air Resources Board, Stationary Source Division. Detailed California-Modified GREET Pathway for Cellulosic Ethanol from Farmed Trees by Fermentation. Release Date: February 27, 2009. California Air Resources Board, Stationary Source Division. Detailed California-Modified GREET Pathway for Cellulosic Ethanol from Forest Waste, Release Date: February 27, 2009. and California Air Resources Board. Fuel GHG Pathways Update, Presentation: January 30, 2009.
10 Parrish, D.J. and J.H. Fike. (2005). “The Biology and Agronomy of Switchgrass for Biofuels.” Critical Reviews in Plant Sciences. 24(5): 423-459.
11 Fertilizer impacts can include eutrophication (increased chemical nutrients in an ecosystem) that leads to hypoxia (oxygen depletion) in aquatic environments.
12 Goldemberg, J. (2007). "Ethanol for a Sustainable Energy Future." Science 315(5813): 808-810.
13 All oil prices used for comparison in this section are calculated assuming refinery costs and profits are 30% of crude oil costs, and that distribution and marketing costs and taxes are equivalent for ethanol and fossil fuels.
14 Energy Information Administration. (2007). “Biofuels in the U.S. Transportation Sector.” Accessed April 25, 2009.
15 McAloon, A., F. Taylor, et al. (2000). Determining the Cost of Producing Ethanol from Corn Starch and Lignocellulosic Feedstocks. Other Information: PBD: 25 Oct 2000: Size: 30 p.
16 Fehrenbacher, K. (2008). “11 Companies Racing to Build U.S. Cellulosic Ethanol Plants.” Accessed: March 12, 2009.
17 U.S. Department of Energy. (2007). “DOE Selects Six Cellulosic Ethanol Plants for Up to $385 Million in Federal Funding.” Press Release. Accessed: March 12, 2009.
18 Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2007.
19 Suszkiw, Jan. (2008). “Banking on biobutanol: new method revisits fermenting this fuel from crops instead of petroleum.” Agricultural Research. 56(9):8-9.
20 For more information, see Renewable Fuels Association, “Celluosic Ethanol.”
21 State of Minnesota. (2008). “E20: The Feasibility of 20 Percent Ethanol Blends by Volume as a Motor Fuel.” Minnesota Department of Agriculture and the Minnesota Pollution Control Agency.
22 Yost, N. and D. Friedman. (2006). The Essential Hybrid Car Handbook: A Buyer’s Guide. The Lyons Press: 160 pages.
23 U.S. Department of Energy. (2009). “Light Duty E85 FFVs in Use.” Excel file. Accessed April 27, 2009.
24 Bureau of Transportation Statistics (2009). “National Transportation Statistics, 2009.” Accessed April 27, 2009.
25 For more information on the distribution of E85 stations, see U.S. DOE, “E85 Fueling Station Locations.”
26 U.S. Department of Agriculture. (2007). “Ethanol Transportation Backgrounder.” Accessed April 27, 2009.
27 Morrow, W.R., W.M. Griffin, H.S. Matthews. (2006). “Modeling switchgrass derived cellulosic ethanol distribution in the United States.” Environmental Science & Technology. 40, 2877-2886.
28 Ibid (Wakeley).
29 Renewable Fuels Association. (2008). “Cellulosic Biofuel Producer Tax Credit.” Accessed April 27, 2009.
At the Environment and Public Works hearing on Tuesday, both Secretary LaHood of the Department of Transportation (DOT) and Administrator Jackson of the Environmental Protection Agency (EPA) explained that emissions reductions progress is already underway in the transportation sector. Sec. LaHood stated, “We have much to do, but we are not waiting to begin taking aggressive and meaningful action.”
While the Congress has been working towards establishing comprehensive climate legislation, the DOT, EPA, and Department of Housing and Urban Development (HUD) have been collaborating to develop Federal policies that could help create sustainable communities. The aim is to support and shape state and local land use decisions and infrastructure investments to develop livable communities where people have the option to drive less. According to the DOT, on an average day American adults travel 25 million miles in trips of a half-mile or less and almost 60 percent use motor vehicles for this travel. Walking, biking, and riding transit, regardless of the area where an American might live, are excellent alternatives. “If the presence of these alternatives promotes less driving, then that will reduce road congestion, reduce pollutants and greenhouse gases, and use land more efficiently."
As President Obama called for U.S. leadership in clean energy technology in a speech at MIT Friday, up on Capitol Hill members of the U.S. Climate Action Partnership (USCAP) demonstrated how they’re already putting innovative ideas into practice.
At a Clean Technology Showcase, we joined six corporations and fellow USCAP members to present cutting-edge solutions to a low-carbon future. While the displays varied from solar shingles to renewably-sourced swimwear to advanced coal technology, all participants agreed that making these solutions mainstream requires enacting comprehensive energy and climate legislation. Economy-wide federal policies that put a price on carbon and deliver incentives for clean energy development and deployment are today’s big missing ingredient.
Instead of the policy talk more common to Capitol Hill, Friday’s event focused on existing and emerging solutions to our energy and climate concerns. It proved an uplifting view of the opportunities that a clean energy economy can deliver.
This afternoon President Obama delivered an energizing speech to students and faculty of MIT on the need for the United States to draw on its “legacy of innovation” in transitioning to a clean energy future. We are engaged in a “peaceful competition” to develop the technologies that will drive the future global energy economy and he wants to see the U.S. emerge as the winner. The President further declared that in making the transition from fossil fuels to renewable energy, we can lead the world in “preventing the worst consequences of climate change."
After citing the ongoing efforts of his Administration on this front, including the $80 billion in the American Recovery and Reinvestment Act (a.k.a the “Stimulus Package”) for clean energy, he talked about what’s needed next – comprehensive legislation to transform our energy system. He noted that this should include sustainable use of biofuels, safe nuclear power, and more use of renewables like wind and solar technology, all while growing the U.S economy. And he applauded Senator Kerry – also in attendance for the speech – for his work with Senator Boxer on their legislation.
The hiatus on nuclear plant construction might be about to end. Renewed interest in nuclear power has been spurred by existing government incentives, and comprehensive climate policy will provide further impetus.
So what does proposed legislation do to promote nuclear power? The energy bill passed by the Senate Energy and Natural Resources Committee (S.1462), the energy and climate bill introduced by Senators Kerry and Boxer (S.1733), and the energy and climate bill passed in the House (H.R. 2454) all include provisions to expand nuclear power generation. Most importantly, the latter two bills include a greenhouse gas cap-and-trade program. This will send a long-term price signal to drive investment in low-carbon technologies, including nuclear power, and will make the cost of electricity generated from new nuclear power lower relative to traditional fossil fuel-based generation.
This weekend marks the conclusion of the Solar Decathlon on the National Mall in Washington, D.C., a competition sponsored by the U.S. Department of Energy in which 20 college teams from around the world challenge one another in the high jump, pole vault, and other various athletic feats while dressed up as flaming balls of gas.
Okay, that’s not quite right: the Decathlon is indeed a competition among 20 college teams from around the globe, but rather than throwing javelins or jumping hurdles, these students compete to design, build, and run the most energy-efficient solar-powered house they can. Teams spend nearly two years designing and constructing their homes, which are then shipped to D.C., assembled on the Mall, and judged in ten different categories ranging from architectural excellence to market viability to engineering. The ultimate result is that a village of the future sprouts up in the middle of the U.S. capital almost literally overnight, and when the homes are not being judged, visitors are free to stroll through them and learn about their innovative features.
As energy prices continue to swing and the prospects for carbon constraints grow, it’s no wonder more and more companies are focusing their efforts on energy efficiency. But while most firms recognize the benefits of energy efficiency, many lack the information and resources required to take their efficiency programs to the next level.
To help provide these resources, we have launched a web portal with tools and information to help companies develop stronger energy efficiency strategies. The key feature of the portal is a searchable database of the energy efficiency activities undertaken by the 45 companies in the Center’s Business Environmental Leadership Council (BELC).
Also included on the web portal are results of our recent survey distributed to 95 major corporations that offer key insights for those exploring best practices in corporate energy efficiency. These include:
- Firms recognize the energy paradigm is changing rapidly.
- Companies are responding by establishing corporate-wide energy efficiency targets.
- Senior management support is critical in the development and implementation of energy efficiency programs.
- The most common challenge companies face in pursuing efficiency gains are resource constraints, especially limits on capital.
- Employee engagement is an effective, but possibly underutilized strategy for improving energy efficiency.
- Energy efficiency can be a gateway to wider business innovation.
The portal and survey are part of a larger research project that seeks to document and communicate best practices in corporate energy efficiency strategies across the following categories: internal operations, the supply chain, products and services, and cross-cutting issues. The next step of the project is the release of a comprehensive report summarizing our findings at a major conference in Chicago, April 6-7, 2010. The project is funded by a three-year, $1.4 million grant from Toyota.
- Ruminant animals have a unique digestive system, which enables them to eat plant materials, but also produces methane, a potent greenhouse gas that contributes to global climate change. Methane is released into the atmosphere from animal effluences.
- Globally, ruminant livestock emit about 80 million metric tons of methane annually, accounting for 28 percent of global methane emissions from human-related activities. Cattle in the U.S. produce about 5.5 metric tons of methane per year – about 20% of U.S. methane emissions.1
Enteric fermentation is a natural part of the digestive process for many ruminant animals where anaerobic microbes, called methanogens, decompose and ferment food present in the digestive tract producing compounds that are then absorbed by the host animal. A resulting byproduct of this process is methane (CH4), which has a global warming potential (GWP) 25 times that of carbon dioxide (CO2). Because the digestion process is not 100 percent efficient, some of the food energy is lost in the form of methane. It is estimated that 7-10 percent of a ruminant’s energy intake is lost to enteric fermentation (though it can be closer to 4 percent for feedlot cattle in some instances).2 Measures to mitigate enteric fermentation would not only reduce emissions, they may also raise animal productivity by increasing digestive efficiency.
Enteric fermentation and its corresponding methane emissions take place in many wild and domestic ruminant species,—such as deer, elk, moose, cattle, goats, sheep, and bison. Ruminant animals are different from other animals in that they have a “rumen” – a large fore-stomach with a complex microbial environment.3 The rumen allows these animals to digest complex carbohydrates that nonruminant animals cannot digest; a natural component of this process also creates methane that is emitted by the animal. Ruminants produce much more methane per head than non-ruminant animals, with the rumen being responsible for 90 percent of the methane from enteric fermentation in a ruminant. Larger ruminants like bison, moose and cattle produce greater amounts of methane than smaller ruminants because of their greater feed intake.4
In aggregate, the large number of domestic ruminants, particularly beef cattle and dairy cattle—combined with the high level of methane emissions per head and the high GWP of methane—make enteric fermentation a significant contributor to domestic greenhouse gases from agriculture, with around 28 percent of GHGs in the agriculture sector coming from enteric fermentation in 2007 (the agriculture sector accounts for over 6 percent of U.S. GHG emissions). Enteric fermentation also accounts for nearly a quarter of domestic anthropogenic methane emissions. Beef and dairy cattle are the greatest methane emitters from enteric fermentation that are attributed to anthropogenic activities. Collectively, their effluences accounted for 95 percent of methane emissions from enteric fermentation in the year 2007. Smaller ruminants, like sheep and goats, emitted less than or the same as non-ruminants, like horses and swine, because of their domestic population size. Overall, enteric fermentation from all major domestic livestock groups was responsible for 139 Tg CO2e (1.9 percent of total greenhouse gas emissions domestically) in the year 2007.5 Figure 1 below shows the relative contributions to global warming from enteric fermentation in major domestic livestock groups.
|Figure 1: Domestic Enteric Fermentation Emissions by Livestock Animal in 2007|
|Source: U.S. Environmental Protection Agency (EPA), 2009 U.S. Greenhouse Gas Inventory Report: Agriculture, 2007.|
Annual methane emissions from enteric fermentation increased by 4.3 percent between 1990 and 2007, though there were fluctuations in annual emissions levels over this period (emissions trended downwards between 1995 and 2004). This increase can be largely attributed to the growth in domestic beef cattle population, with some of the increase coming from growth in the domestic and wild horse population.6
The greatest contributors to GHG emissions from enteric fermentation are states that have large ruminant populations. Texas and California, with their immense dairy and beef cattle operations, are the greatest contributors—each emitting over 7.5 Tg CO2e annually. Not surprisingly, many agricultural states in the Midwest are also a significant source of enteric fermentation emissions. Figure 2 below illustrates GHG emissions from enteric fermentation by state.7
It is estimated that enteric fermentation is responsible for 20-25 percent of anthropogenic methane emissions on a global level.8 Nations that have agrarian economies with large ruminant populations have much higher emission levels. For example, in New Zealand enteric fermentation is the greatest source of GHG emissions, accounting for 31 percent of total emissions.9 In addition, cattle populations have increased dramatically in many developing nations over the past two decades because of rising standards of living and agricultural policy changes in developed nations that have shifted production overseas. As a result, it is estimated that enteric fermentation emissions from the developing world had increased by around 33 percent between 1984 and 2004.10
|Figure 2: Methane Emission from Enteric Fermentation by State|
|Source: United States Department of Agriculture (USDA), U.S. Agriculture and Forestry Greenhouse Gas Inventory: 1990-2005 Chapter 2: Livestock and Grazed Land Emissions, 2005.|
Environmental Benefit/Emission Reduction Potential
Methods to mitigate enteric fermentation emissions are still in development and need further research, but early studies looking at potential mitigation options have yielded some promising results. Most research has focused on manipulating animal diet in an effort to inhibit a rumen environment favorable to methanogens. Diet manipulation can abate methane by decreasing the fermentation of organic matter in the rumen, allowing for greater digestion in the intestines—where less enteric fermentation takes place. This inhibits methanogens and limits the amount of hydrogen (H) available for methane (CH4) production.11 Alternatively, changing the type of fermentation taking place – by switching ruminants from a cellulosic to a starch-based diet, for example – can increase the amount of fermentation while still decreasing levels of methane production.
Early research demonstrates that increasing animal intake of dietary oils helps to curb enteric fermentation and increase yields by limiting energy loss due to fermentation. These oils appear to be a viable option because they can be easily substituted into animal diets. A study by Grainger et al. (2008) found that increasing dietary oils could mitigate emissions from enteric fermentation, with a 1 percent increase in dietary oils decreasing methane emissions by 6 percent. As part of this study, whole cottonseed was introduced into the diet of dairy cattle and observed to reduce methane emissions by around 12 percent and increase milk yield by about 15 percent.12 Another study conducted by Beauchemin et al. found that the introduction of sunflower oil abated methane emissions by 22 percent.13 Similar studies have demonstrated promising results using other oils, such as coconut and palm. Further research will be needed to examine the long-term viability of dietary oils, as it may be possible that the rumen could adapt to new feed environments and return to previous levels of methane emissions.14
There remain other options to combat enteric fermentation—like genetic engineering and the use of additives, but further research and development is needed before such options can be employed. The use of the antibiotic monensin was examined by Beuachemin et al but its use did not significantly reduce methane emissions, and questions remain about the permanence of these reductions.15 Studies have also been conducted examining the potential for genetic engineering aimed at increasing the efficiency of feed conversion to biomass—which would also reduce enteric fermentation— within animals. One recent study laid the groundwork for breeding cattle that would have 25 percent less methane emissions and require less feed.16
One remaining option is to reduce the consumption of ruminant animals and ruminant animal products,17 but this would involve changes in consumer behavior and preferences that are unlikely to take place in the near future.
As several potential options exist for mitigating enteric fermentation, it is difficult to enumerate the costs of abatement. For example, diet manipulation options have costs that are subject to feed market volatility. Furthermore, the availability of certain feed or oil types will vary by region and season in some cases, so it would be difficult to assign costs on a national level for diet manipulation. Rather, farmers and ranchers will likely choose to source the lowest-cost dietary supplements available to them at any given time. Increases in yield may also be observed when utilizing supplements to mitigate enteric fermentation, and these would act to ameliorate any costs associated with their purchase.
Genetic engineering will have R&D costs associated with it, but whether or not animals that are genetically engineered to produce more efficiently cost more over their lifetime than current livestock populations remains to be seen. One must take into account both the upfront costs of genetic engineering vs. the potential lifetime benefits of increased production and lower feed usage.
Current Status of Enteric Fermentation Mitigation
Business and research groups have made some early efforts to address enteric fermentation emissions, but a national-level effort has not yet materialized. The USDA and the EPA have both acknowledged enteric fermentation as a source of emissions and included these emissions in greenhouse gas inventory reports, but the EPA’s recently proposed national greenhouse gas reporting rule does not include enteric fermentation emissions.
New Zealand has decided to include emissions from enteric fermentation in its GHG emissions trading scheme. In January of 2013, emissions from agriculture in that country—including enteric fermentation emissions—will be capped. Owners of livestock operations out of compliance with their cap will be required to buy permits from those in compliance in order to emit, or they will have to pay a fine. The Australian Government is currently in the process of deciding whether or not to include agricultural emissions—including those from enteric fermentation— in its Carbon Pollution Reduction Scheme. If included, owners of livestock operations in Australia will also have their emissions capped and will be required to buy permits if they exceed their allowance. The Australian Government is set to issue a decision on whether or not to include agriculture by 2013.
Obstacles to Further Development or Deployment of Enteric Fermentation Mitigation
There are several obstacles that could prevent action on enteric fermentation for the foreseeable future. These include:
- Difficulty of measurement
Emissions from enteric fermentation are diffuse and this makes them difficult to measure. Emissions can be measured in vitro, by trying to simulate the rumen in a lab, or in vivo, by measuring emissions directly from an animal.18 Preference is given to in vivo methods when possible. Current in vivo methods include placing livestock in emissions measurement chambers or using portable sulfur hexafluoride (SF6) tracers to measure methane emissions from the rumen in the field. Both techniques have disadvantages; the SF6 tracer does not measure emissions from the anterior of the animal and the chamber can be costly and place animals under stress, which could increase emissions. Neither method provides instantaneous data on emissions from the animal. A study by McGinn et al. (2004) found that, on average, methane emission measurements from the SF6 tracer method were 4 percent lower than those of the chamber, while a study by Grainger et al. (2008) found the SF6 tracer method results were 8 percent lower.19,20 While the SF6 tracer method and the chamber method are both accurate, a mobile measuring apparatus that provides instantaneous data will improve both the ability to make management decisions and research capabilities.
- Heterogeneity in management practice
Studies examining abatement through enteric fermentation mitigation must assume baseline diets and management practices from which reductions are taking place. In reality, farms have many different diets they feed animals that vary with season, price, and availability. Thus, it becomes difficult for farmers to accurately estimate emissions reductions from new management practices because their baselines may be dramatically different than those assumed in studies.
- Inherent price volatility of mitigation
Enteric fermentation mitigation options dependent on diet manipulation are subject to volatility in feed markets. A mitigative diet that is affordable one year may not be the following year, and this will make long term mitigation dynamic in nature as farmers will have to periodically adjust the composition of the diets they are giving animals because of the costs and availability of certain feeds. This will have an impact on both the costs of mitigation and the level of emissions abated at any given period.
Policy Options to Help Promote Enteric Fermentation Mitigation
- Inclusion in EPA greenhouse gas reporting rule
Requiring livestock operations to report enteric fermentation emissions will improve the understanding of emissions sources and catalyze the development of cost-effective technologies to measure and report emissions from enteric fermentation at the farm level. Quantifying these emissions will allow farmers to make better decisions and allow for their inclusion in various abatement mechanisms. This reporting may have costs to the livestock producer.
- Incentivization of management practices
Previous farm bills have established environmental performance programs, such as the Conservation Reserve Program, designed to incentivize practices that protect the environment. The inclusion of enteric fermentation mitigation in an existing program, or the establishment of a program dealing with enteric fermentation, would incite many farmers to take action.
- Cap and trade with functioning offsets markets
A price on carbon alone would not stimulate enteric fermentation mitigation because it is unlikely that enteric fermentation emissions would be included in any regulatory regime, be it cap-and-trade or a tax. Rather, the establishment of a cap on carbon emissions, along with offsets markets where polluters can buy emissions reductions not included in the cap, would create a market for enteric fermentation reductions. If farmers could verify their emissions reductions from enteric fermentation mitigation, they could sell them to polluters covered under the cap who could then use them for compliance.ederal, state, county, and local governments currently support biofuels in a variety of ways. This support falls into two general categories: (1) policies that mandate levels of use for biofuels and (2) policies that offer subsidies or tax credits for biofuel production and/or use.
Related C2ES Resources
Further Reading/Additional Resources
U.S. Environmental Protection Agency Resources:
2009 US Greenhouse Gas Inventory Report: Agriculture
U.S. Department of Agriculture Resources:
U.S. Agriculture and Forestry Greenhouse Gas Inventory: 1990-2005 Chapter 2: Livestock and Grazed Land Emissions
Wood, Christina, et al. Global Climate Change and Environmental Stewardship by Ruminant Livestock Producers. s.l. : National Council for Agricultural Education, 1998.
1 United States Environmental Protection Agency (EPA). Ruminant Livestock. EPA. 2007. Accessed October 13th, 2009.
2 Moss, A.R. and D.R. Givens. Effect of supplement type and grass silage:concentrate ratio. Vol. Proc. Br. Soc. Anim. Prod. Paper No. 52. 1993.
3 Thorpe, Andy. Enteric fermentation and ruminant eructation: the role (and control?) of methane in the climate change debate. Numbers 3-4, Berlin : Springer Netherlands, 2009, Vol. 93.
4 Johnson, DE, et al. Ruminants and other animals. In:Kahlil (ed) Atmospheric methane: its role in the global environment. Berlin: Springer, 2000.
5 U.S. EPA. 2009 US Greenhouse Gas Inventory Report. United States Enviromental Protection Agency. April 2009. Accessed June 23, 2009.
7 United States Department of Agriculture (USDA). U.S. Agriculture and Forestry Greenhouse Gas Inventory-Livestock and Grazing. USDA. 2005. Accessed June 25, 2009.
8 Thorpe 2009.
9 New Zealand's Greenhouse Gas Inventory 1990-2007: Agriculture. New Zealand Ministry for the Environment. Accessed July 6, 2009.
10 Thorpe 2009.
11 S. M. McGinn, K. A. Beauchemin, T. Coates and D. Colombatto. Methane emissions from beef cattle: Effects of monensin, sunflower oil, enzymes, yeast, and fumaric acid. Journal of Animal Science. American Society of Animal Science, 2004.
12 Grainger, C., T. Clarke, K.A. Beauchemin, S.M. McGinn, & R.J. Eckard. Effect of whole cottonseed supplementation on energy and nitrogen partitioning and rumen function in dairy cattle on a forage and cereal grain diet. Australian Journal of Experimental Agriculture, 48, 860-865. 2008. DOI: 10.1071/EA07400
13 McGinn et al. 2004.
16 Britten, Nick. Cows that burp less methane to be bred. UK Telegraph. June 24, 2009. Accessed June 28, 2009.
17 Thorpe 2009.
18 Hess, H.D. and C.R. Soliva. Measuring Methane Emission of Ruminants by In Vitro and In Vivo Techniques . [book auth.] Harinder P.S. Makkar and Philip E. Vercoe. Measuring Methane Production From Ruminants. Dordrecht: Springer Netherlands, 2007.
19 S. M. McGinn, K. A. Beauchemina, A. D. Iwaasab and T. A. McAllistera. Assessment of the Sulfur Hexafluoride (SF6) Tracer Technique for Measuring Enteric Methane Emissions from Cattle. JEQ. 2006. Accessed June 28, 2009.
20 C. Grainger, T. Clarke, S. M. McGinn, M. J. Auldist, K. A. Beauchemin, M. C. Hannah, G. C. Waghorn, H. Clark, and R. J. Eckard. Methane Emissions from Dairy Cows Measured Using the Sulfur Hexafluoride (SF6) Tracer and Chamber Techniques. Journal of Dairy Science. 2007. Accessed June 28, 2009.
Electricity generation accounts for more than one third of total U.S. greenhouse gas (GHG) emissions (Figure 1). Nuclear power is a virtually carbon-free source of reliable, baseload electricity which can play a very large role in decarbonizing the U.S. electric power sector. Existing government incentives have already spurred a renewed interest in building new nuclear plants, and comprehensive climate policy is expected to provide further impetus for a significant expansion of U.S. nuclear power generation (for an in-depth discussion of nuclear power and its role in climate mitigation see the Pew Center’s Nuclear Power factsheet).
Nuclear Power’s Current Role
In 2008, nuclear power provided one fifth of total U.S. electricity and constituted nearly 70 percent of total U.S. non-emitting electricity generation (see Figure 2). With 104 operating nuclear reactors at 65 plants in 31 states, the United States is the world’s largest generator of nuclear power, accounting for about 30 percent of global nuclear generation.1,2 97 percent of current U.S. nuclear generating capacity was built and brought online between 1965 and 1990.3 No new nuclear plants have been ordered in the United States since 1978, and no U.S. plant has been completed that was ordered after 1973.4
Existing Incentives for Nuclear Power and Pending Climate Legislation
The construction of much of the existing nuclear fleet saw significant cost overruns and delays, which makes financing new plants challenging.5,6 Recent changes to the licensing process, standardized plant designs, and improved construction management and quality assurance offer the promise of avoiding the problems of past U.S. nuclear plant construction. The expansion of nuclear power, though, depends on demonstrated success in constructing and operating the first few new nuclear plants.
The Energy Policy Act of 1992 overhauled the nuclear licensing process and moved major regulatory risks to the front end of the process. The Energy Policy Act of 2005 provided financial incentives to promote investment in the first few new plants—most importantly federal loan guarantees.7 In 2007, Congress authorized the Department of Energy (DOE) to grant $18.5 billion of loan guarantees. 17 applications for combined construction and operating licenses for 26 new reactors are under review by the Nuclear Regulatory Commission (NRC)—all submitted since 2007.8
The Waxman-Markey American Clean Energy and Security Act (ACES Act), H.R.2454, includes provisions likely to spur a major expansion of nuclear power. The energy bill passed by the Senate Energy and Natural Resources Committee, the American Clean Energy and Leadership Act (ACEL Act, S.1462) and the energy and climate bill, which includes a GHG cap-and-trade program, introduced by Senators Kerry and Boxer, the Clean Energy Jobs and American Power Act (S.1733), also include provisions related to nuclear power (see Table 1). This brief focuses on the ACES Act because it has been extensively modeled, but any legislation that puts a price on carbon is expected to have a similar effect on nuclear power. Future briefs will discuss the projected impacts of the Senate proposals.
Putting a Price on Carbon
The most important thing that pending climate legislation does for advancing low-carbon energy technologies, especially nuclear power, is to put a price on carbon via a GHG cap-and-trade program.9 A carbon price guides investments toward a variety of low-carbon technologies and makes the cost of electricity from new nuclear power plants lower relative to traditional fossil fuel-based generation.
Financing Low-Carbon Energy Technology
The ACES Act amends the existing DOE nuclear loan guarantee program in order to make the program more effective, including providing the Secretary of Energy with more flexibility in setting the financial terms of the loan guarantees.10 In addition, the ACES Act creates a new Clean Energy Deployment Administration (CEDA), an independent corporation wholly owned by the United States with a 20-year charter, with the mission of promoting domestic development and deployment of clean energy technologies, such as nuclear power, by making available affordable financing. The ACES Act instructs the U.S. Treasury to issue $7.5 billion in “green bonds” to initially capitalize CEDA. The Senate ACEL Act includes similar provisions related to the loan guarantee program and creation of a CEDA.
The Role for Nuclear Power under Market-Based Climate Policy
The U.S. Energy Information Administration (EIA) modeled the effects of the ACES Act and projected that CO2 emission reductions from the electric power sector would comprise more than 80 percent of cumulative GHG emission reductions from sources covered under cap and trade through 2030.11 EIA projects that new nuclear power plants will play a key role in providing these emission reductions. According to EIA, under “business-as-usual,” between 2012 and 2030 only 11 gigawatts (GW) of new nuclear generating capacity would come online (compared to a current nuclear generating capacity of about 100 GW). By contrast, during the same time period under the ACES Act, EIA projects that new nuclear power would make up almost 40 percent of new generating capacity (96 GW) such that by 2030 nuclear power would provide one third of U.S. electricity (see Figure 3).
The United States and the rest of the world cannot avoid dangerous climate change without reducing GHG emissions from electricity generation. Pending cap-and-trade legislation establishes a regulatory framework and long-term price signal to guide investments in low-carbon energy technologies, including nuclear power. In addition, pending legislation builds on existing incentives to overcome the hurdle of financing the first wave of new U.S. nuclear power plants. Under an aggressive global effort to reduce GHG emissions, the International Energy Agency (IEA) projects that nuclear power generation will increase more than three-fold by 2050 with the largest increases in the United States, China, and India.12 The very large deployment of nuclear power projected under climate legislation with a price on carbon could revitalize the U.S. nuclear power industry and position the United States as a leader in a critical low-carbon technology industry.
|Figure 1: Total U.S. Greenhouse Gas Emissions (2007)13|
|Figure 2: U.S. Electricity Generation by Type (2008)14|
|Figure 3: Projected Cumulative New Electric Generating Capacity (2012-2030)|
|Notes: The figure above is based on the EIA ACES Act modeling analysis’s reference and “Basic” policy cases.|
1. Holt, Mark, Advanced Nuclear Power and Fuel Cycle Technologies: Outlook and Policy Options, Congressional Research Service (CRS), Jul 2008. All of the 104 U.S. nuclear reactors were ordered between 1963 and 1973.
2. EIA, International Energy Annual 2006, 2008, see Table 2.7.
3. EIA, U.S. Nuclear Statistics.
4. National Commission on Energy Policy (NCEP), Ending the Energy Stalemate: A Bipartisan Strategy to Meet America’s Energy Challenges, 2004.
5. According to the 2003 Future of Nuclear Power report from the Massachusetts Institute of Technology (MIT), the “historical construction costs reflected a combination of regulatory delays, redesign requirements, construction management and quality control problems” (p. 38).
6. See Table 2-1 and accompanying discussion in Congressional Budget Office (CBO), Nuclear Power’s Role in Generating Electricity, 2008.
7. The Energy Policy Act of 2005 also included a production tax credit (PTC) of $18 per megawatt-hour for 6,000 megawatts (MW) of new nuclear capacity for the first 8 years of operation and a form of insurance (called standby support) under which the federal government will cover debt service for up to six new reactors (subject to funding) if commercial operation is delayed.
8. NEI, Status and Outlook for Nuclear Energy in the United States, May 2009.
9. For explanation of how cap and trade works, see the Pew Center’s Cap and Trade 101.
10.For a detailed discussion of the challenges faced in implementing the DOE loan guarantee program, see the letter “Administrative Changes Necessary for a Workable Title XVII Loan Guarantee Program” sent to the Obama Administration and signed by several clean energy industry associations, including the Nuclear Energy Institute.
11. EIA, Energy Market and Economic Impacts of H.R. 2454, the American Clean Energy and Security Act of 2009, August 2009. Unless otherwise noted, this document refers to EIA’s “Basic” core policy case. EIA’s modeling timeframe only extends to 2030. Abatement refers to the difference between covered emissions under climate policy and under “business-as-usual.”
12. IEA, Energy Technology Perspectives 2008: Scenarios and Strategies to 2050, BLUE Map Scenario, see Figure 8.1.
13. EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007.
14. U.S. Energy Information Administration (EIA), Annual Energy Review 2008, 2009, see Table 8.2a.
15. The summary of S.1733 is based on the version released September 30, 2009.
- High global warming potential (GWP) gases are mostly man-made gases used in industrial processes. They typically have much longer atmospheric lifetimes and much stronger radiative forcing properties than carbon dioxide.
- Currently, high GWP gases account for 2.1 percent of domestic greenhouse gas (GHG) emissions in terms of carbon dioxide equivalency (CO2e). The EPA has created several voluntary programs aimed at lowering these emissions.
Because of their immense contributions to climate change per molecule emitted, abatement of high GWP gases can be very cost-effective.
This factsheet examines high GWP gases outside of methane and nitrous oxide. High global warming potential gases are gases that have a greater impact on climate change per molecule emitted than carbon dioxide (CO2). GWP is a reporting mechanism developed by the IPCC to standardize the impact of GHGs on climate in units of carbon dioxide equivalency (abbreviated as CO2e). Typically, these potentials are reported over a 100-year time horizon. Carbon dioxide is assigned a 100-year GWP of 1, and this is the standard used to determine the GWPs of other gases (i.e., a gas with a GWP of 50 has an impact on warming 50 times greater than that of CO2 across a 100-year time span).
GHGs can be thought of as having three specific properties: they selectively absorb radiation—meaning they let shortwave radiation (solar radiation) pass through and absorb longwave radiation (infrared radiation) before it can exit the earth’s atmosphere; they have long residency times in the atmosphere; and they are strong absorbers of longwave radiation. GWP is a function of these three properties. Thus, a gas that is a very strong absorber of longwave radiation and remains in the atmosphere for a long time will have a high GWP.
While two high GWP gases—methane (CH4) and nitrous oxide (N2O)—are accounted for in most GHG inventories, many other high GWP gases are not. Some of these GHGs have an extremely high GWP—e.g., sulfur hexafluoride (SF6), which has a GWP 22,800 times that of CO2. Industrial processes are responsible for the majority of high GWP GHG emissions. Many of these high GWP gases do not occur naturally; rather, they are man-made, industrial gases that have been manufactured for certain applications.1
There are three key types of high GWP gases outside of methane and nitrous oxide. These are: sulfur hexafluoride (SF6), other types of perfluorocarbons (PFCs), and hydrofluorocarbons (HFCs). All of these gases contain fluorine, and fluorinated compounds are very potent GHGs because of their long lifetime in the atmosphere and high absorption potential. Over the past two decades, PFC and HFC usage has increased because these gases are good substitutes for chlorofluorocarbons (CFCs), hydrochlorofluorocarbons (HCFCs), and halons—all of which are ozone depleting substances2 (ODSs) being phased out of production under the Montreal Protocol.3 HFCs and PFCs have replaced ODSs in many cases, as they are not ODSs; however, these gases do have high GWPs. Overall, replacement provides net-benefits because HCFCs and CFCs are potent greenhouse gases as well as ODSs. For example, CFC-11 is a common chlorofluorocarbon that depletes the ozone and has a 100-year GWP of approximately 4,750 CO2e. HCFCs and CFCs were excluded from the Kyoto Protocol, however, because the Montreal Protocol had already mandated reductions in these gases. Despite ozone benefits relative to the use of HCFCs, CFCs, and halons, HFCs and PFCs are powerful greenhouse gases. In order to achieve climate protection, it is important to increase the efficiency of their use, abate emissions, or find substitutes that are environmentally benign.4
High GWP gases only account for about 2.1 percent of U.S. greenhouse gas emissions in terms of CO2e (carbon dioxide is the dominant greenhouse gas, accounting for 85 percent of domestic emissions).5 The chart below illustrates domestic sources of high GWP gas emissions and their relative contributions.
|Figure 1: Relative Contributions of Domestic Sources of High GWP Gases|
|Source: 2009 U.S. Greenhouse Gas Inventory Report, EPA. 2009.|
PFCs are very potent GHGs with 100-year GWPs between 7,390 to 17,700 CO2e and atmospheric lifetimes in the range of 740 to 50,000 years. There are a few types of sources of PFC emissions in the United States at present. One source category is aluminum production. Aluminum production is a very electricity-intensive process during which alumina is electrolytically reduced into aluminum in a reaction cell.6 During this process, alumina concentrations may drop below a certain optimal threshold, and this causes a surge in voltage in the cell and switches the reduction reaction to carbon in the anode, called an “anode effect.” During an anode effect, carbon in the anode and fluorine present in the reaction cell are converted to PFCs.7
Solvents are also a source of PFC emissions. Many solvents used for electronics and metals cleaning contain PFCs. These solvents have low boiling points, so they convert easily to gas. Once in gaseous form, they can remain in the atmosphere for thousands of years.8
HFCs have a 100-year GWP range between 124 and 14,800 CO2e and atmospheric lifetimes in the range of 1.4 to 270 years. They are emitted from a wide variety of industrial processes and are the most common of the high GWP gas types. The greatest source of HFCs, and the greatest source of any high GWP gas, is leakage from refrigeration, heat pumps and air conditioning equipment. They may leak from these units during operation, repair, or disposal at the end of a unit’s useful life.9
Like PFCs, HFCs are also used in solvents designed for electronics and metals cleaning. HFCs are emitted when these solvents evaporate.10
The production of HCFC-22, commonly known as R-22, is another source of HFC emissions. HFC-23, a powerful greenhouse gas, is created as a byproduct in the production of R-22, which is currently used for a variety of applications.11
HFCs are also used as blowing agents in the production of certain types of foams. HFCs will escape during the manufacture of the foam, and they will also gradually leak from the foam throughout its life, although a portion of the HFCs will remain trapped indefinitely.12
Many aerosols also contain HFCs. For example, metered dose inhalers used for various medical applications have recently switched from CFC-based propellants to HFC-based propellants. Many other consumer products, like aerosol computer dusting agents and emergency air horns, also contain HFCs.13
HFCs have now replaced halons in fire extinguishers as well. These HFCs are emitted when a fire extinguisher is discharged.14
- Sulfur Hexafluoride
Sulfur hexafluoride (SF6) has a 100-year GWP potential of 22,800 CO2e and an atmospheric lifetime of 3,200 years, making it an extremely potent GHG. It acts as an insulator in electric transmission and distribution equipment. A vast majority of SF6, about 80 percent of all emissions, is emitted when such equipment is damaged or opened during repair or disposal.15
Magnesium production and casting have also become sources of SF6 emissions. SF6 has replaced sulfur dioxide (SO2) in magnesium production as an inhibitor of violent molten magnesium oxidation.16 Its use in this process generates GHG emissions.17
Several high GWP gases—including HFCs, PFCs, and SF6—are used in the manufacture of semiconductors. These gases are largely used for plasma etching and the cleaning of semiconductor production equipment.18
Environmental Benefit/Emission Reduction Potential
As there are many different sources of high GWP gas emissions, there are also many different potential options for emission reduction.
PFC emissions result from sub-optimal concentrations of alumina, in the form of anode effects. Thus, improving control of alumina concentrations could mitigate PFC emissions. At present, computerization of the smelting process or capital additions, such as point feeders,19 provide means to better control alumina concentrations in the production process. There are two gases emitted from anode effects, CF4 and C2F6, with GWPs of 7,390 and 12,200 CO2e, respectively. In 2001, the EPA estimated that these technologies could reduce 2010 emissions by between 17 and 30 percent, depending on the technologies used and the degree to which they are employed.20
Reductions in PFC emissions from solvents can be achieved several ways: through improvements to cleaning equipment and properties; through improvements in the efficiency of solvent usage and recycling; and through improvements in solvent technology and the development of alternative solvents. These GHGs have GWPs upwards of 7,400 CO2e. Reductions will vary by technology used—with greater reductions occurring from displacement of PFC solvents and smaller reductions coming from process improvements. In 2001, the EPA estimated overall emissions reduction potential to be between 31 and 35 percent in the year 2010 depending on the technologies employed.21
Refrigeration, cooling units, and heat pumps are the greatest sources of HFC emissions. Thus, finding ways to improve the handling and operation of such units will decrease fugitive HFC emissions. In many cases, this may be as simple as providing routine maintenance to units and performing leakage tests. In addition, ensuring that refrigeration units are properly disposed of will prevent HFC leakage at landfills. The EPA requires the recovery of refrigerant from retired equipment, but the degree to which this actually occurs is unknown. Design and performance improvements aimed at emission reductions for future units, and upgrades to existing units, can also be implemented. Non-HFC refrigeration systems that do not contribute to climate change, such as ammonia or hydrocarbon-based refrigeration systems, could be deployed at scale, but there are flammability and toxicity issues that must be addressed with many of these systems before they can be fully commercialized. Finally, alternative cooling technologies, like geothermal cooling—where the relatively constant temperature present in subterranean environments can be used as a heat sink—could be employed. These geothermal systems would have to employ HFC-free heat pump systems or water based systems in order to be emissions-free. Overall, these non-or-low-HFC technologies limit emissions from leakage, and they may also limit emissions from electricity production, as some use significantly less energy than conventional refrigeration and cooling systems. As refrigeration and air conditioning are the greatest contributors to high GWP emissions, significant potential for reduction exists. In 2001, the EPA estimated that reductions between 4 and 12 percent could be achieved in 2010.22
HFC-23 emissions from R-22 production will remain problematic in the short-term. However, as part of the Montreal Protocol, R-22 is to be gradually phased out of production and usage in the United States by 2020.23 Until then, measures that improve the efficiency of R-22 production will limit diffuse emissions of HFC-23. Additionally, HFC-23 emissions can be thermally oxidized, thereby decreasing their GWP by converting them to carbon dioxide, hydrogen fluoride, and water. Thermal oxidation has the potential to eliminate over 99 percent of HFC-23 emissions.24
Like PFCs, HFCs are also present in solvents. Reduction options for HFCs in solvents mirror those for PFCs, and the EPA estimated reduction potential is the same, as HFCs are part of these reductions, at about 31 to 35 percent.25
For HFC emissions related to foam and foam blowing, the best mitigation option is substituting other blowing agents that have lower GWPs than HFCs. For example, hydrofluoroolefin (HFO) and hydrocarbon-based blowing agents offer viable alternatives to HFC blowing agents. Concerns about flammability exist with the use of some hydrocarbons. In addition, performance issues and other obstacles may need to be overcome with the use of certain blowing agents, but alternative blowing agents present promising options. In 2001, the EPA estimated that emissions reductions between 35 and 37 would occur.26
CFC use in aerosols has largely been replaced by the use of HFCs. As of December 31, 2008, all metered dose inhalers (MDIs) have switched to a hydrofluoroalkane (HFA) propellant from a CFC based propellant (inhalers were the last consumer product in the United States to use a CFC propellant).27 The GWP of the HFA propellant is nearly six times less than that of the CFC propellant, and almost 30 percent less propellant is required per dose. Tire inflators and air horns are other types of equipment that utilize HFCs. There are several options for mitigation, such as transitioning to dry powder-based inhalers that do not require propellants in the case of MDIs and finding lower GWP alternatives for other types of equipment. Performance and safety issues, particularly issues with flammability, will have to be overcome for certain alternatives, but the EPA estimates that alternative propellants could reduce emissions by up to 20 percent by 2010. When combined with other options, like non-propellant based alternatives and the use of hydrocarbon based propellants, up to 37 percent reductions could occur by 2010.28
For portable and installed fire extinguishers with HFCs, water mist systems and inert gas systems present lower GWP alternatives. In addition, technologies that impede the spread of fires or allow for early detection and quick extinguishment may cut down on emissions because they will allow extinguishing systems to use smaller amounts of chemicals to put out fires. In 2001, the EPA estimated that water mist systems could reduce emissions by 3 percent and inert gas systems could reduce emissions by 25 percent by 2010.29
- Sulfur Hexafluoride
- SF6 emissions from electricity transmission and distribution equipment can be reduced by:
- ensuring that equipment is properly disposed of and that SF6 is recycled whenever possible; the EPA estimates that this could reduce emissions by 10 percent;
- installing new equipment that is easier to service, uses SF6 and has greater structural integrity, which could reduce SF6 emissions by up to 50 percent;
- developing alternative insulating gases, with lower GWP than SF6, as an alternative;
- and installing leak detection systems that will inform operators of leakage, which could reduce emissions by up to 20 percent.30
- SF6 emissions from magnesium production can be reduced by:
- replacing SF6 with lower GWP cover gases;
- improving the efficiency of SF6 usage and implementing measures to reduce leakage;
- installing alternative production and casting systems that limit the need for cover gases.31
- SF6 emissions from electricity transmission and distribution equipment can be reduced by:
Several technologies have been employed that improve the efficiency of and reduce emissions from etching and production operations. Some of these technologies involve capturing emissions and subsequently destroying them through thermal or catalytic processes. Emissions reductions can be anywhere between 50 to 98 percent or greater, depending on the technology used. While there are currently no alternatives to the use of fluorinated GHGs (F-GHGs) in semiconductor manufacture, some processes are amenable to substitution by F-GHGs that have lower GWPs and/or are more efficiently reacted, thus lowering CO2e emissions.32
As there are numerous sources of high GWP emissions, costs of emission reductions vary widely depending on the source of emissions and the available mitigation technologies. Typically, costs will be lower for reductions achieved through efficiency improvements or lower GWP gas substitutes—these options may even generate a net savings. The installation of new capital or additions to existing capital designed to mitigate emissions are generally more costly options across all emission sources because of the large upfront expenditures required for such projects.
Overall, those high GWP gases that are point source emissions—meaning they come from a fixed, identifiable source—present more cost-effective mitigation options than other diffuse emissions sources, like fugitive emissions from electricity transmission lines, because they only require improvements to single sources rather than large-scale improvements to expansive systems. Some reductions in certain high GWP gases could be spill-over effects from other actions taken to reduce GHG emissions. For example, electricity efficiency measures aimed at reducing CO2 emissions could also be responsible for indirect reductions in fugitive SF6 emissions by cutting down on the amount of electricity transmission and distribution equipment needed. These indirect benefits may not be accounted for when estimating the cost of mitigation projects.33
Finally, it is important to note that several economic studies have concluded that the inclusion of high GWP gases—including methane and nitrous oxide— in measures designed to reduce GHG emissions creates greater GHG reductions at lower costs than just targeting CO2 alone. For example, a Pew Center on Global Climate Change report completed in 2003 estimated that meeting Kyoto Protocol targets with a multi-gas mitigation system would be about 30 percent cheaper and would allow for about 5 percent greater reductions than a CO2-only system. Because these gases are far stronger than CO2, emissions reductions per dollar expended tend to be much higher in many cases, making them very cost-effective options relative to CO2.34
Current Status of High GWP Gas Mitigation
As noted before, the Montreal Protocol has called for the phase out of ODSs—which are also potent GHGs. Class I ODSs, of which CFCs are a part, are no longer used or produced in the United States. Class II ODSs, of which HCFCs are part, will be completely phased out by January 1, 2030. As the Montreal Protocol is an international treaty, gradual phase out can be expected on a global level, and this will have a significant impact on reducing high GWP gases not included in the Kyoto Protocol. In fact, a decision to accelerate the phase out of HCFCs made by parties to the Montreal Protocol in 2007 will avoid emissions of approximately 16 gigatons CO2e.37
The EPA has established several voluntary programs aimed at reducing high GWP emissions. It estimates that these voluntary programs will be responsible for reductions of approximately 90 million metric tons CO2e for the year 2010 when compared to business as usual estimates, about a 300 percent reduction.38 These voluntary programs are as follows:
- SF6 Emission Reduction Partnership for Electric Power Systems
- The electric power systems partnership focuses on reducing emissions of SF6 emissions from electric transmission and distribution equipment. Partners agree to keep an inventory of SF6 emissions and implement measures to reduce them. About 45 percent of the industry now participates in the program, and Partners were collectively responsible for 4 million metric tons carbon equivalent (MMTCE) reduction in 2006 alone.39
- The Voluntary Aluminum Partnership (VAIP)
- VAIP was established in 1995 with the goal of reducing PFC emissions from aluminum production through the mitigation of anode effects. It represents 98 percent of U.S. aluminum production capacity. VAIP’s efforts have reduced PFC emissions per ton of aluminum produced by 77 percent from 1990 levels.40
- SF6 Emission Reduction Partnership for the magnesium Industry
- Established in 1999, this partnership between the EPA and the magnesium industry focuses on reducing the SF6 emissions associated with the production and casting of magnesium. It was responsible for emissions reductions of 40 percent per ton of magnesium produced between 1999 and 2002. The program has a goal of eliminating SF6 emissions from this industry entirely by 2010.41
- PFC Reduction/Climate Partnership for the Semiconductor Industry
- Established in 1996, this partnership focuses on reducing a wide variety of high GWP emissions from semiconductor manufacturing through efficiency and capital improvements. The program has a goal of reducing emissions 10 percent below a 1995 baseline, and the EPA estimates that it will mitigate 10 MMTCE in the year 2010 alone.42
The EPA also maintains a regulatory program called the Significant New Alternatives Policy Program. Under this program, the EPA may evaluate and control substitutes to ODSs so as to ensure that they are more environmentally benign than the substances they seek to replace.
Obstacles to Further Development or Deployment of High GWP Emissions Controls
High GWP gas mitigation has increasing marginal costs, meaning that smaller emissions reductions achieved by substituting gases or implementing marginal efficiency improvements may be cheap, but large reductions—which require new capital or alternative processes—will have much higher costs in the form of R&D or expenditures on new equipment. Thus, attaining high levels of reductions may be very costly, and some technologies still remain prohibitively expensive.
Many high GWP emissions come from diffuse sources, such as electricity transmission equipment, that are more difficult to monitor and control. Mitigation options for diffuse emission will be systemic in scope. In most cases, this will make their implementation longer and more difficult than mitigation measures for point sources.
Policy Options to Help Promote High GWP Emissions Reductions
- Price on greenhouse gases
A price on greenhouse gases, as would exist, for example, under a greenhouse gas cap-and-trade program, would incentivize high GWP emissions reductions so long as they were included in the cap. If they were not included in the cap, inclusion in an offsets program— where high GWP gas-emitting firms could still earn emission reduction credits that they could sell to covered firms—would incentivize reductions.
Mandates or incentives
The Montreal Protocol has contributed to significant emissions reductions in ODSs, which are also high GWP gases. A similar mandate targeting industrial high GWP gases, or a program that incentivizes or subsidizes their reduction, could effectively reduce emissions. However, this approach is limited by the availability of technically acceptable and cost-effective alternatives.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading/Additional Resources
U.S. Environmental Protection Agency (EPA)
1 Reilly, John M., Jacoby, Henry D. and Prinn, Ronald G. Multi-gas contributors to global climate change 2003. Arlington, VA : Pew Center on Global Climate Change, 2003.
2 ODSs are chemicals that deplete the stratospheric ozone layer in the earth’s atmosphere. The ozone layer absorbs ultraviolet radiation; its depletion allows more ultraviolet radiation to reach earth’s surface, and this has negative impacts on public health and agricultural productivity. The Montreal Protocol, an international treaty that called for a reduction in the use of ODSs, was ratified in 1987. Since then, the United States and many other nations have sought to phase out the usage of ODSs.
3 Phasing Out Ozone Depleting Substances and Safeguarding the Global Climate. UNDP-Environment and Energy. [Online] United Nations . [Cited: July 15, 2009.]
4 Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. EPA High Global Warming Potential Gases. [Online] June 2001. [Cited: July 18, 2009.]
5 2009 U.S. Greenhouse Gas Inventory Report. Climate Change - Greenhouse Gas Emissions. [Online] EPA, 2009. [Cited: July 15, 2009.]
6 Production. International Aluminum Institute. [Online] International Aluminum Institute, 2009. [Cited: July 17, 2009.]
7 Cost and Emission Reduction Analysis of PFC Emissions from Aluminum Smelters in the United States . Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
8 Cost and Emission Reduction Analysis of HFC and PFC/PFPEs Emissions from Solvents in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
9 Cost and Emission Reduction Analysis of HFC Emissions from Refrigeration and Air Conditioning in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
10 Cost and Emission Reduction Analysis of PFC Emissions from Aluminum Smelters in the United States, 2001.
11 Cost and Emission Reduction Analysis of HCFC-22 Production in the United States, 2001.
12 Cost and Emission Reduction Analysis of HFC Emissions from Foams in the United States, 2001.
13 Cost and Emission Reduction Analysis of HFC Emissions from Aerosols in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
14 Cost and Emission Reduction Analysis of HFC and PFC Emissions from Fire Extinguishing in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
15 Cost and Emission Reduction Analysis of SF6 Emissions from Electric Utilities in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
16 Magnesium is a highly flammable metal that reacts violently with oxidizing or extinguishing agents. This may result in excessive oxidation which is dangerous and results in losses of the metal during production. SF6 is used as a cover gas, a gas that helps stabilize the magnesium production process by inhibiting ignition violent oxidation.
17 Cost and Emission Reduction Analysis of SF6 Emissions from Magnesium Production and Parts Casting in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
18 Cost and Emission Reduction Analysis of PFC, HFC, and SF6 Emissions from Semiconductor Manufacturing in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
19 Point feeders are alumina distribution devices that allow for greater control and precision in the administration of alumina in the reaction cell. By incrementally adding alumina into the reaction cell, they help maintain optimal reaction conditions and cut down on anode effects.
20 Cost and Emission Reduction Analysis of PFC Emissions from Aluminum Smelters in the United States, 2001.
21 Cost and Emission Reduction Analysis of HFC and PFC/PFPEs Emissions from Solvents in the United States, 2001.
22 Cost and Emission Reduction Analysis of HFC Emissions from Refrigeration and Air Conditioning in the United States, 2001.
23 Phaseout of HCFC-22 and HCFC-142b in the United States. Ozone Layer Depletion - Regulatory Programs. [Online] EPA, 2009.
24 Cost and Emission Reduction Analysis of HCFC-22 Production in the United States, 2001.
25 Cost and Emission Reduction Analysis of HFC and PFC/PFPEs Emissions from Solvents in the United States, 2001.
26 Cost and Emission Reduction Analysis of HFC Emissions from Foams in the United States, 2001.
27 CFC-Free Inhalers: Time to Make the Switch. American Lung Association. [Online] American Lung Association. [Cited: July 15, 2009.]
28 Dalby, Richard. Introduction to Pharmaceutical Aerosols. University of Maryland. [Online] [Cited: July 15, 2009.]
29 Cost and Emission Reduction Analysis of HFC and PFC Emissions from Fire Extinguishing in the United States, 2001.
30 Cost and Emission Reduction Analysis of SF6 Emissions from Electric Utilities in the United States, 2001.
31 Cost and Emission Reduction Analysis of SF6 Emissions from Magnesium Production and Parts Casting in the United States, 2001.
32 Cost and Emission Reduction Analysis of PFC, HFC, and SF6 Emissions from Semiconductor Manufacturing in the United States. Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions. [Online] EPA, June 2001. [Cited: July 17, 2009.]
33 Final Report on U.S. High Global Warming Potential (High GWP) Emissions 1990-2010: Inventories, Projections, and Opportunities for Reductions, 2001.
34 Reilly, 2003.
35 Phase Out of Class I Ozone Depleting Substances. Ozone Layer Depletion-Regulatory Programs. [Online] EPA, June 2001. [Cited: July 17, 2009.]
36 Phaseout of HCFC-22 and HCFC-142b in the United States. Ozone Layer Depletion - Regulatory Programs. [Online] EPA, June 2001. [Cited: July 17, 2009.]
37 Phasing Out Ozone Depleting Substances and Safeguarding the Global Climate, 2009.
38 High Global Warming Potential Gases. EPA. [Online] EPA, October 2006. [Cited: July 16, 2009.]
39 SF6 Emission Reduction Partnership for Electric Power Systems. EPA . [Online] EPA, February 2009. [Cited: July 15, 2009.]
40 Voluntary Aluminum Industrial Partnership (VAIP). [Online] EPA, March 2008. [Cited: July 15, 2009.]
41 SF6 Emission Reduction Partnership for the Magnesium Industry. SF6 Emission Reduction Partnership for the Magnesium Industry. [Online] EPA, March 2008. [Cited: July 15, 2009.]
42 PFC Reduction/Climate Partnership for the Semiconductor Industry. PFC Reduction/Climate Partnership for the Semiconductor Industry . [Online] EPA, March 2008. [Cited: July 15, 2009.]