Energy & Technology

National Enhanced Oil Recovery Initiative Looks for Progress in Energy Policy

Recently, I had the opportunity to attend as an observer the launch of the National Enhanced Oil Recovery Initiative, facilitated by the Center and the Great Plains Institute.  In the short time since the launch, the EOR Initiative has generated notable

Carbon dioxide enhanced oil recovery (CO2-EOR) works by injecting CO2 into existing oil fields to increase oil production.  It is not a new concept. In fact, around 5 percent, or 272,000 barrels per day, of all domestic oil produced comes from oil recovered using this technique, which was first deployed in West Texas in 1972.  Decades of monitoring CO2-EOR sites have shown that in properly managed operations the majority of CO2 is retained in the EOR operation and not released to the atmosphere.  One of the initiative’s goals is to better understand the role of CO2-EOR for carbon storage as this industry grows to produce more than 1 million barrels per day, or around 17 percent of domestic oil supply in 2030.

In Brief: Clean Energy Markets: Jobs and Opportunities

In Brief: Clean Energy Markets: Jobs and Opportunities

July 2011 Update (originally published February 2010)

Download this Brief (PDF)

This brief discusses how investment in clean energy technologies will generate economic growth and create new jobs in the United States and around the globe. The United States stands to benefit from the expansion of global clean energy markets, but only if it moves quickly to support domestic demand for and production of clean energy technologies through well-designed policy that enhances the competitiveness of U.S. firms.

Clean energy markets are already substantial in scope and growing fast. Between 2004 and 2010, global clean energy investment exhibited a compound annual growth rate of 32 percent, reaching $243 billion in 2010. Forecasts of investment totals over the next few decades vary according to assumptions made regarding the nature of future global climate policies. Over the next decade, assuming strong global action on climate change, cumulative global investment totals for clean power generation technologies could reach nearly $2.3 trillion.

Recognizing the potential of these markets, the European Union, China, and other nations are moving to cultivate their own clean energy industries and to position them to gain large market shares in the decades ahead.

  • The European Union continues to lead the world in clean energy investments, spending nearly $81 billion in 2010. Since 2009, China has invested more money per year in clean energy technologies than the United States, investing $54.4 billion in 2010 compared to the United States’ $34 billion. Over 85 percent of today’s market for clean energy technologies is outside of the United States, primarily in Asia and Europe.
  • Germany’s clean energy investments of $41.2 billion were the second most for any country in 2010, surpassing the now third-place United States.
  • China now boasts the world’s largest solar panel and wind turbine manufacturing industries, accounting for nearly 50 percent of manufacturing for both technologies.
  • Danish wind manufacturers produce close to 22 percent of annual global installed wind capacity.

These countries have taken deliberate steps to position themselves as leaders in the 21st century clean energy economy. History shows that it matters where industries are first established, and countries can use policy to foster domestic “lead markets” for particular industries, giving them the foothold that can lead to significant growth in global market share. In the United States, well-crafted climate and clean energy policy can give nascent clean energy industries such a foothold by creating domestic demand and spurring investment and innovation. Strong domestic demand creates not only export opportunities but also jobs – many of which must be located where the demand is, thus fostering domestic job growth even when industry supply chains are globally dispersed.

National climate and clean energy policy in the United States can help create jobs and domestic early-mover industries with the potential to become major international exporters. Such policy should provide incentives for investment in clean energy, for example through a clean energy standard, that requires a certain amount of electricity be obtained from clean energy sources, or a market-based mechanism that puts a price on carbon. The time to act is now: through policy leadership at home and abroad, the United States can position itself to become a market leader in the industries of the 21st century.

Click here for the press release.


Press Release: Members of Congress Support New National Enhanced Oil Recovery Initiative

Press Release
July 12, 2011

Contact: Tom Steinfeldt,, 703-516-0638
Patrice Lahlum,, 701-281-5007

Members of Congress Support New National Enhanced Oil Recovery Initiative
Industry, State, NGO Leaders to Develop Recommendations to Improve U.S. Energy Security

WASHINGTON, D.C. – Industry, government and organizational leaders gathered in Washington, DC, today to launch a national enhanced oil recovery initiative aimed at increasing the supply of domestic oil produced through enhanced oil recovery using carbon dioxide (CO2-EOR).

Senator Kent Conrad (D-ND), Senator John Hoeven (R-ND), and Congressman Mike Conaway (R-TX) were on hand to help kick off the National Enhanced Oil Recovery Initiative (EOR Initiative). Senator John Barrasso (R-WY) and Senator Richard Lugar (R-IN) offered written statements in support of the initiative.

The EOR Initiative includes executives from oil and gas, electric power, ethanol, pipeline and other industry sectors; state officials; technical experts; and environmental advocates. The group will develop recommendations for federal and state policymakers on how to ramp up CO2-EOR to improve U.S. energy security, create economic opportunities, support high-paying jobs, and reduce greenhouse gas emissions. The slate of recommendations is expected to be released in early 2012.

“We know where the oil is, we just need the CO2 to help produce it,” said Robert Mannes, President and CEO of Michigan-based Core Energy, LLC. “We are the only company engaged in commercial CO2-EOR in the Great Lakes Region, and we have a limited amount of CO2. With additional supplies of sufficient volumes of CO2 we could produce a significant amount of oil, providing much needed jobs and revenue to local economies.”

The EOR Initiative will marshal support from diverse constituencies for accelerated nationwide expansion of CO2-EOR projects. Commercially proven, safe, and environmentally sound, CO2-EOR stands out as a compelling and largely unheralded example of American private sector technological innovation that can support a wide range of urgent national priorities.

“Carbon capture and sequestration technology combined with enhanced oil recovery addresses our growing demand for energy, the need for sound environmental policy, and provides the kind of economic and energy security that can only come from increased domestic production,” said Texas State Rep. Myra Crownover. “I look forward to working with the other members of this initiative on improving and expanding opportunities for EOR production throughout the United States.”

Reasonable policies to advance CO2-EOR could produce significant amounts of new American oil and advance the development of infrastructure needed for long-term carbon capture and storage. An estimated 35-50 billion barrels of economically recoverable oil could be produced in the United States using currently available CO2-EOR technologies and practices, or potentially more than twice the country’s proved reserves.

“The fiscal struggles facing federal and state governments combined with a challenging political climate demand new ideas for U.S. energy policy,” said Eileen Claussen, President of the Pew Center on Global Climate Change. “The diverse interests represented in this group offer a unique opportunity to secure broad support for sensible policies that increase domestic oil supply and limit emissions – a win for our nation’s economy, security, and the climate.”

In CO2-EOR, carbon dioxide is injected into oil wells to help draw more oil to the surface, while the carbon dioxide remains underground in deep geologic formations. Expanding CO2-EOR will increase domestic production from already developed oil fields, while reducing greenhouse gas emissions and creating economic opportunities.

“EOR has the potential to bring Americans together around a common agenda of energy security, job creation, and environmental stewardship, and overcome the energy policy gridlock that’s putting our nation at risk,” said Brad Crabtree, Policy Director at the Great Plains Institute.

The EOR Initiative is facilitated by the Great Plains Institute and the Pew Center on Global Climate Change. Financial support for the EOR Initiative is provided by the Joyce Foundation, the Edgerton Foundation and the Energy Foundation. Additional funding is being sought from foundations, industry, and other private-sector sources.


Related Materials


Statements from Members of Congress in support of the National Enhanced Oil Recovery Initiative

In addition to remarks delivered today by Senator Kent Conrad (D-ND), Senator John Hoeven (R-ND), and Congressman Mike Conaway (R-TX) at the National Enhanced Oil Recovery Initiative kick-off event in Washington, DC, the following statements of support were issued by Senator John Barrasso (R-WY) and Senator Dick Lugar (R-IN).

Sen. John Barrasso (R-WY)
“Wyoming has been a leader in the field of enhanced oil recovery (EOR).  It’s a valuable part of America’s energy future.  I congratulate the National Enhanced Oil Recovery Initiative for its important step forward in this area.  Increasing EOR production and advancing technology innovation will help grow our economy in an environmentally responsible way.  The good news is that EOR is viable without heavy subsidies or Washington mandates.  I look forward to reviewing the Initiative’s work.”

Sen. Richard Lugar (R-IN)
“Enhanced oil recovery is a win for fiscal responsibility, a win for energy security, and a win for environmental stewardship. I commend members of the National Enhanced Oil Recovery Initiative for taking up this opportunity and look forward to reviewing their recommendations. Addiction to foreign oil imperils United States’ national security and makes our economy more vulnerable to conflict, terrorist activity, and natural disasters far outside the United States. My Practical Energy Plan would propel about 1.8 million barrels of oil per day by enabling a truly national infrastructure to connect oil resources with the CO2 necessary to harvest it, including from sources in Indiana, and generate substantial taxpayer returns.”

More information on Senator Lugar’s plan is available at


Quick Facts

  • In 2011, approximately 967 million gallons of biodiesel were produced in the United States, compared to 10 million gallons only 10 years earlier.[1]
  • As of 2011, 158 biodiesel plants were operating in 42 states,[2] with total production 100 times the 2001 level.[3] Production in 2011 rebounded to 967 million gallons with the reinstatement of the biodiesel tax credit, after dropping to 343 million gallons in 2010.[4]
  • U.S. biodiesel is projected to increase in supply, from 0.6 million barrels per day (mmb/d) in 2011 to 0.8 mmb/d by 2020.[5]
  • The EPA recently announced that the 2013 Renewable Fuel Standard mandate for biodiesel would increase to 1.28 billion gallons from 1 billion gallons in 2012.[6]


Biodiesel is a nonpetroleum-based diesel fuel composed of fatty acid methyl ester molecules[7] derived from vegetable oils, animal fats, or recycled greases. It is similar to conventional petroleum-based diesel fuel and can be used in compression-ignition (diesel) engines with little to no modification. Biodiesel also has some favorable properties compared to conventional diesel (e.g., no sulfur content, lower particulate matter, and lower lifecycle greenhouse gas emissions).

Since commercial biodiesel use began in 2001, production and consumption have expanded considerably (see Figure 1). After showing steady annual increases, production and consumption fell from 2008 to 2010, partly because the biodiesel tax credit, providing a $1.00 per blended gallon incentive, expired at the end of 2009. However, production recovered strongly in 2011 after the biodiesel tax credit was reinstated at the end of 2010.[8] Additionally, demand for biodiesel is increasing as blenders need to reach new mandates under the Renewable Fuel Standard (RFS) (for more, see C2ES Renewable Fuels Standard (RFS2))[9] Over 900 million gallons were produced and nearly that much consumed in 2011 (see Table 1).

Figure 1 United States Annual Biodiesel Production and Consumption, 2001 - 2011

Source: Energy Information Agency (2012),

Table 1. Biodiesel Summary, million gallons, 2009 – 2011
















Gross Imports





Gross Exports







Biodiesel production involves the extraction and esterification[10] of oils or fats using alcohols. Compared to the production of other biofuels, the technology used to produce biodiesel is relatively simple and well developed.

  • Biodiesel feedstocks

The feedstocks used in biodiesel production vary by region. The most common feedstocks by region are: soybean oil in the United States; rapeseed (canola) and sunflower oil in Europe; and palm oil in Indonesia and Malaysia. Biodiesel can also be produced from numerous other feedstocks, including vegetable oils, tallow and animal fats, used fryer oil (also called yellow grease), and trap grease (also called brown grease, from restaurant grease traps). The relatively low price of soybean oil in the U.S. makes it the most common feedstock, accounting for approximately 57 percent of U.S. biodiesel production.[11] The chemical properties of the biodiesel (cloud point, pour point, and cetane number) depend on the type of feedstock used (see endnote for further explanation). Following soybean oil, the next three most common biodiesel feedstocks are corn oil, yellow grease, and brown grease.[13]

  • Production pathways

To produce biodiesel, the feedstock is chemically treated in a process called transesterification, in which the oils or fats are combined with an alcohol (usually methanol) and a catalyst to produce fatty acid methyl esters (the chemical name for biodiesel molecules). The major byproduct of the reaction, crude glycerin, is usually sold to the pharmaceutical, food, and cosmetics industries.

Figure 2. Biodiesel Production Pathways

Source: U.S. Department of Energy, Energy Efficiency and Renewable Energy. 2009. “Biodiesel Production.”

Cetane number is the combustion quality of the fuel during compressed ignition. Biodiesel has about 93 percent of the energy content of petroleum diesel, on a per gallon basis, and a cetane number between 50 and 60. For comparison, petroleum diesel sold in the United States has a cetane number between 38 and 42. The chemical composition of biodiesel, especially its higher cetane number, translates to better engine performance and lubrication. However, its lower energy density results in a decrease in fuel economy (2-8 percent).[14]

Since biodiesel’s combustion properties are similar to those of petroleum-based diesel fuel, biodiesel can be legally blended with conventional diesel in any fraction, unlike raw oils not registered with the EPA.[15] As opposed to the use of ethanol, the use of biodiesel does not require many significant modifications to the fuel system. Individual engine manufacturers determine which blends can be used in their engines. The most common blend of biodiesel in the United States is 20 percent biodiesel, 80 percent petroleum diesel (B20). Some newer vehicles are also capable of using pure biodiesel, B100.[16]

Biodiesel is also commonly used as a fuel additive (in lower level blends of 2 to 5 percent) to reduce emissions of particulates, carbon monoxide, hydrocarbons, and other air pollutants from diesel-powered vehicles. For example, low-sulfur diesel fuel currently used in the United States is lower in lubricity—the characteristic of diesel fuel necessary to keep diesel fuel injection systems properly lubricated—than higher- sulfur diesel fuels. Since biodiesel has no sulfur content and high lubricity, it can be blended with low-sulfur diesel to improve lubricity without increasing sulfur emissions.

One of the disadvantages of biodiesel is that it can gel or freeze, possibly causing engines to stall in cold winter temperatures. For example, 100 percent soy biodiesel can begin to form ice crystals at 32ºF (0ºC), whereas petroleum diesel generally forms ice crystals at about 10º or 20ºF (-12º to -5ºC). Proper blending with petroleum diesel and other fuel additives can counteract this problem; B20 blended with specially formulated cold weather petroleum diesel forms ice crystals at -4ºF (-20ºC).[17]

Environmental Benefit / Emission Reduction Potential

By replacing conventional diesel fuel, the use of biodiesel can lower greenhouse gas emissions from the transportation sector. The potential greenhouse gas reductions from switching to biodiesel from petroleum-based diesel depend largely on the type of feedstock used to produce the fuel.

Depending on the feedstock used, one gallon of biodiesel can reduce greenhouse gas emissions by 12 to over 80 percent when compared to a gallon of conventional diesel, on a lifecycle basis. The California Air Resources Board (CARB), as part of its analyses in support of California’s Low Carbon Fuel Standard, calculated that when soybean oil is used as a feedstock, the average reduction in direct lifecycle emissions per gallon is about 78 percent.[18] This reduction only considers the direct lifecycle impacts of biodiesel production, processing, and combustion, and does not include any potential impacts of indirect land use change (see Obstacles to Further Development or Deployment of Biodiesel). According to CARB, when the indirect land impacts are included, soybean-based biodiesel would reduce greenhouse gas emissions by only about 15 percent compared to petroleum-based diesel.[19]

Using animal fats and recycled greases instead of agricultural crops can result in greater greenhouse gas reductions since energy inputs (e.g., fertilizers and farming equipment) are not directly needed to grow the feedstocks. These feedstocks also have the added benefit of recycling waste products, although the overall availability of these waste feedstocks is limited.


The cost of producing biodiesel depends on a number of factors, including the following:

  • the feedstock used in the process;
  • the capital and operating costs of the production plant;
  • the current value and sale of byproducts, which can offset the per-gallon cost of production; and
  • the yield and quality of the fuel and byproducts.

The overall cost of biodiesel production depends mainly on the feedstock used and its price.[20] The prices of most feedstocks are subject to market fluctuations, which can also make biodiesel production costs vary over time. The price of conventional diesel provides the baseline against which to compare the cost of biodiesel production and determines the economic viability of large-scale biodiesel production.

Biodiesel production costs from waste feedstocks (e.g., yellow or brown grease) depend on the source and procurement method. For example, in some areas, providers of these feedstocks pay biodiesel processors to collect waste materials; in other cases, biodiesel producers have to purchase them directly from these providers. In either case, biodiesel produced from waste feedstocks is cheaper, although the overall supply of these feedstocks is limited.[21]

Soybean oil provides approximately 60 percent of the U.S. biodiesel feedstock, with 7.6 pounds of soybean oil required for each gallon of biodiesel.[22] With consistent low pricing in 2011 (around $0.50 per pound of soybean oil), the market was favorable for increased biodiesel production.[23] Biodiesel costs more than petroleum diesel, but in 2011, the price of biodiesel was competitive, averaging $3.91 per gallon for B20 blend and $4.18 for B99-B100 compared with $3.81 per gallon of petroleum-based diesel (see Figure 3).[24]

Renewable Identification Numbers (RINs) have become increasingly important in overall biodiesel costs. RINs are a traceable serial number attached to a batch of renewable fuel produced, as required by the EPA as part of the RFS. In 2011, biodiesel RINs averaged $0.75 per gallon. Because of the higher ethanol equivalence in biodiesel, one gallon of biodiesel generates 1.5 RINs, earning blenders $1.13 per gallon of biodiesel. These RIN values, coupled with the Biodiesel Tax Credit, encouraged increased biodiesel production at the close of 2011 and throughout 2012.[25]

Figure 3. Cost per Gasoline-Gallon Equivalent (GGE) of Biodiesel (B99/B100), Biodiesel (B20), and Diesel (2000 - 2012)

Source: Department of Energy, Alternative Fuel Data Center,

Current Status of Biodiesel

Using vegetable oil for fuel has been around since the invention of the diesel engine itself. The first diesel engine, invented by Rudolf Diesel in 1898, ran on a “biofuel”—peanut oil—although this was not the same as biodiesel used today since it was not transesterified. Although this engine type was later modified to run on petroleum-based fuels, the development of biodiesel continued throughout the 20th century. Unlike other biofuels, biodiesel can be produced using relatively little equipment; in fact, instructions and materials for “home brewing” biodiesel are readily available via the Internet.[26]

Globally, biodiesel production has increased from 71.3 thousand barrels per day in 2005 to over 400 thousand barrels per day in 2012 (see Figure 4).[27] Between 2005 and 2012, production more than doubled in Europe.[28] In 2011, the European Union still accounted for a plurality of the world’s biodiesel production, at roughly 44 percent, down from 55 percent in 2009. The United States produced about 16 percent of the world total in 2011, up from 10 percent in 2009.[29]

In the United States, the Energy Independence and Security Act (EISA) of 2007 mandated one billion gallons of biodiesel use annually by 2012. EPA extended that mandate to 1.28 billion gallons for 2013 (see C2ES Renewable Fuels Standard (RFS2)). By the end of 2011, an estimated 7.1 percent of total U.S. soy crops (5.45 million acres) were used for biodiesel. Preliminary figures for 2012 show these figures jumping to 13.6 percent of total U.S. soy crop (10.02 million acres) as soybean oil use increases to fulfill an estimated 66 percent of the 2012 biodiesel mandate in the RFS2.[30] Projections for 2013 and 2014 show these figures leveling off at around 14.5 percent of the total soybean crops.[31]

Figure 4. Biodiesel Production (Thousand Barrels Per Day), 2005 - 2011

Source: EIA, (2012)

In the United States, between October 2010 and September 2011, 4.2 billion pounds (14 percent) of domestic soybean oil was used to produce biodiesel – up from 1.1 billion pounds of soybean oil in 2010.[32]  This figure is expected to increase to 5.2 billion pounds of soybean oil in 2012, or about 27 percent of total domestic soybean oil production.[33] Additionally, 2.5 billion pounds of animal fat was used for biodiesel in 2010, increasing to 7.3 billion pounds in 2011.[34] As of 2011, a total of 158 biodiesel plants were operating in 42 states,[35] with a total annual production capacity of 2.7 billion gallons.[36]

Increased consumption of soy-based biodiesel can result in increased prices for that feedstock. Improving biofuel conversion efficiency, feedstock yields, and technologies to advance other feedstocks can lessen the pressure on a single feedstock.[37] Significant research efforts are underway to develop new feedstocks like jatropha, algae, and camelina, many of which could contribute to the biodiesel supply over the longer term. Researchers are also studying synthetic biofuel production that generates a diesel-type fuel through biomass gasification and catalytic conversion using the Fischer-Tropsch process (biomass-to-liquid, or BtL).[38] Fischer-Tropsch diesel has better cold weather performance compared to current biodiesel and could be substituted more easily and directly for petroleum-based diesel.

Finally, efforts are also underway to make renewable jet fuel. Typical biodiesel cannot be commingled with jet fuel in any product pipelines in any quantity. Instead, researchers are treating oil  from renewable sources with hydrogen to produce a drop-in biofuel, called hydrotreating, which allows it to be used alongside traditional jet fuel, without adverse effects on existing infrastructure and equipment.

Obstacles to Further Development or Deployment of Biodiesel

  • Economic issues

The growth of the biodiesel industry has been significant in recent years, but it is not expected to continue growing at the same pace given challenging economic conditions and the leveling off of government requirements after 2012, though EPA increased the 2013 requirements above the mandated level for that year.[39] If the price of petroleum-based diesel drops and the relative costs of biodiesel increase, possibly by allowing policies promoting biodiesel to expire, the incentive to produce the fuel will be reduced. In the United States, biodiesel production dropped in 2009 (to 516 million barrels) and again in 2010 (343 million barrels), while global production from 2009 to 2010 showed the smallest increase (9 percent) since data gathering began.[40] Though the market rebounded strongly in 2011, uncertainties of long-term market conditions remain because of price fluctuations and the unclear future of tax incentives.

  • Land use change

As with other biofuels produced from agricultural feedstocks, the production of biodiesel has direct and indirect impacts on land use. The clearing of grassland or forests to plant biofuel crops is a direct land use change that can affect the greenhouse gas emissions due to the loss of a carbon sink. The practice of clearing peatland in Malaysia and Indonesia to produce palm oil for biodiesel has raised particular concerns about land and net greenhouse gas impacts of biodiesel.[41]

Indirect land use change occurs when increased demand for a crop for fuel production leads to increased prices for the crop. This in turn results in food and fuel crops being planted in additional locations, increasing the land use emissions associated with crop production. Although it is important to include emissions across the complete lifecycle of fuel production and use when examining potential greenhouse gas reductions from biodiesel use, accounting for land use changes is particularly challenging and uncertain, and it requires a number of estimates and assumptions.

  • Impact on agricultural commodities and environmental resources

Like corn ethanol, biodiesel produced from soy, palm, rapeseed, or sunflower oil competes with other uses for those products, including food, feed, and timber. In addition to impacts on land use and agricultural prices, biofuel production can also affect water supply; habitat and ecosystems; and soil, air, and water quality.

  • Infrastructure Limitations

Today, most biodiesel is transported by rail because rural production sites are typically far from biodiesel consumers.[42] Even where pipeline infrastructure exists, biodiesel is often prohibited because of its solvent properties and related concerns about equipment damage. There are some exceptions where low-level blends (B5 and lower) of biodiesel are able to use existing infrastructure, such as in the Colonial Pipeline, which allows for low percent blends on its Georgia pipeline, or Kinder Morgan’s Plantation System, which allows low blends from Mississippi to Virginia.[43]

In contrast to existing infrastructure issues, existing retail infrastructure is relatively adaptive to distributing biodiesel because of the ability to more easily update and install retail infrastructure. Low percent blends of biodiesel can be sold at any pump while higher blends (above B20) require a new or upgraded pump. B20 stations increased over 11 percent between January 2011 (637 stations) and January 2012 (710 stations).[44]

Policy Options to Help Promote Biodiesel

Federal, state, county, and local governments currently support biofuels in a variety of ways. Similar to policies to promote corn ethanol, government support includes: (1) mandates on the minimum levels of biodiesel consumption, and (2) subsidies or tax credits for biodiesel production and/or use.

  • Mandates requiring biofuel use

Under authority given to it by the EISA of 2007, the EPA mandates annual renewable fuel volumes for sales of cellulosic, biodiesel, advanced biofuel, and total renewable fuels from 2008 to 2022. The EPA’s current policy is called the Renewable Fuels Standard (RFS2) (see Table 2 for the requirements over time). In order to qualify under the RFS2, biomass-based diesel fuels must meet a 50 percent reduction (below traditional diesel fuels) in lifecycle greenhouse gas emissions. The RFS2 made important changes from the RFS1 (mandated under the Energy Policy Act of 2005); including the extension to 2022 of renewable fuel mandates and the inclusion of biodiesel in addition to gasoline replacements.

Table 2. RFS Ethanol Equivalent Volume Requirements, 2011 – 2013 (billion gallons unless noted)

Fuel Type



2013 (proposed)

Cellulosic biofuel

6.6 million

10.45 million

14 million





Advanced biofuel




Total renewable fuel (Including ethanol)




Note: Volumes are ethanol-equivalent, except for biodiesel that is actual volume,

Source: EPA (2013)

  • Subsidies and tax credits

Currently, suppliers of biodiesel can claim a $1 per gallon tax credit. The tax credit has been in place since 2005, though it has lapsed twice, in 2010 and 2012. It was reenacted retroactively for 2012 and covers biodiesel production activity through 2013.[45] Additionally, many state and local policies encourage biodiesel in the form of infrastructure grants, alternative fuel tax credits, use in public school bus fleets, blending tax credits, and production incentives. For more on state level policies, see C2ES resource Biofuels: Incentives and Mandates.

As with other biofuels, policies should consider lifecycle emissions to ensure that biodiesel production contributes effectively to greenhouse gas emission reductions. Policies that do this include the federal RFS2 and California’s low carbon fuel standard, which is specifically designed to lower the overall carbon intensity of the transportation fuel supply. For more information on biofuel policies, see Climate TechBook: Biofuels Overview.

Related C2ES Resources

Climate TechBook: Biofuels Overview

Climate TechBook: Ethanol

Biofuels for Transportation: A Climate Perspective

State Map – Biofuels: Incentives and Mandates

Further Reading / Additional Resources

U.S. Energy Information Administration,

National Biodiesel Board

Biomass Research and Development Board

U.S. Department of Energy (DOE), Office of Energy Efficiency and Renewable Energy



[1] Energy Information Administration (EIA), Petroleum and Other Liquids Navigator, Biodiesel Overview.

[2] National Biodiesel Board,

[3] U.S. Energy Information Administration (US EIA), Biofuels issues and trends, (2012),

[4] Energy Information Administration (EIA), Petroleum and Other Liquids Navigator, Biodiesel Overview.

[5] EIA AEO,

[6] EPA, EPA Proposes 2013 Renewable Fuel Standards (2013),

[7] Methyl ester is the chemical name for biodiesel molecules.

[8] US EIA, Biofuels issues and trends, 2012.

[9] US EIA, Biofuels issues and trends, 2012.

[10] Esterification is the general name for a chemical reaction in which two reactants (typically an alcohol and an acid) form an ester, a type of organic compound, as the reaction product.

[11] Using annual estimates. During November 2012, 244 million pounds of soybean oil was used, followed by 48 million pounds corn oil, 35 million pounds yellow grease, and 28 million pounds white grease. EIA, Monthly Biodiesel Production Report: February 1, 2013,

[12] Cloud point refers to the temperature below which the wax in diesel (or biowax in biodiesel) precipitates out and begins to “cloud.” Pour point is the temperature at which the diesel fuel thickens and will no longer pour, usually a temperature lower than the cloud point. Cetane number is a measure of the ignition quality of diesel-based fuels; a higher cetane number results in improved combustion.

[13] EIA, Monthly Biodiesel Production Report: Feb 1, 2013,

[14] U.S. Environmental Protection Agency (EPA), Biodiesel: Technical Highlights, updated February 2010.

[15] EPA, Guidance for Biodiesel Producers and Biodiesel Blenders/Users, 2007,

[16] U.S. Department of Energy (DOE), Energy Efficiency and Renewable Energy, B20 and B100: Alternative Fuels, updated 3 February 2009.

[17] NREL, Biodiesel Handling and Use, 2009,

[18] CARB. (2011, July 1). Detailed California-Modified GREET Pathway for Transportation Fuels. Retrieved July 11, 2011, from California Air Resources Board:

[19] Ibid.

[20] EIA, Biofuels in the U.S. Transportation Sector, updated February 2007.

[21] International Energy Agency (IEA), IEA Energy Technology Essentials: Biofuels Production. Paris: IEA, 2007.

[22] US EIA, Biofuels issues and trends, 2012.

[23] U.S. Energy Information Administration, Biofuels issues and trends,

[24] EIA, Weekly Retail Gasoline and Diesel Prices: Annual,

[25] US EIA, Biofuels issues and trends, 2012.

[26] For example:

[27] Energy Information Administration (EIA), International Energy Statistics, Biodiesel Production tables,

[28] Ibid.

[29] Ibid.

[30] Wisner, R. Soybean Oil and Biodiesel Usage Projection & Balance Sheet (2013),

[31] Wisner, R. Soybean Oil and Biodiesel Usage Projection & Balance Sheet (2013),

[32] EIA, Biofuels issues and trends, 2012.

[33] EIA, Biofuels issues and trends, 2012.

[34] EIA, Biofuels issues and trends, 2012.

[35] National Biodiesel Board,

[36]U.S. Energy Information Administration, Annual Energy Outlook 2011,

[37] Biomass Research and Development Board, Increasing Feedstock Production: Economic Drivers, Environmental Implications, and the Role of Research (2009),

[38] The Fischer-Tropsch process is a chemical reaction in which synthesis gas (often called syngas) – produced from a mixture of carbon monoxide and hydrogen from biomass or fossil fuels, such as natural gas and coal – is converted into liquid diesel

[39] C2ES, Renewable Fuel Standard 2,

[40] Energy Information Administration (EIA), International Energy Statistics, Biodiesel Production tables,

[41] Rosenthal, Elisabeth. "Once a Dream Fuel, Palm Oil May Be an Eco-Nightmare," New York Times, 31 January 2007.

[42] EIA, Biofuels issues and trends, 2012.

[43] EIA, Biofuels issues and trends, 2012.

[44] DOE AFDC, “Alternative Fueling Station Total Counts by State and Fuel Type,”

[45] U.S. DOE, Alternative Fuels Data Center, Biodiesel Income Tax Credit,


Carbon Markets Take Flight (In Europe)

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

Quick Facts

  • 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.[1]
  • 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.[2]
  • 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.[3]

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.[4] 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.

  1. In pre-treatment, wastes may be processed, separated, or mixed to ensure that they will decompose in the digester;
  2. During digestion, waste products are broken down by bacteria and biogas is produced;
  3. 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
  4. 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.[5]

Digestion process

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.[6]

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

Liquid waste

Slurry waste

Semi-solid waste

Appropriate digester

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.[7]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.[8]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.

Source: Managing Manure with Biogas Recovery Systems: Improved Performance at Competitive Costs. EPA AgSTAR


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.[9] 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.[10]

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. [11]

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.[12] Finally, anaerobic digesters reduce the number of pathogens present in many types of waste.[13]


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.[14]

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.[15] 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.[16]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.[17]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.[18] 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.[19]

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.[20]

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.[21] 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.[22]

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.[23]Improvements have been made to the current generation of digesters, but questions about long-term reliability still remain.

Investment uncertainty

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[24]; WWTP digesters have a payback period of less than 3 years, and less if food wastes are also accepted as co-digestion fuel.[25] 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,[26] 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.[27] Further hindering adoption are varying limits on the amount of electricity that may be sold back to the grid under net metering rules.[28] 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

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

Further Reading/Additional Resources

International Energy Agency Bioenergy: Biogas Production and Utilization, 2005

California Integrated Waste Management Board: Current Anaerobic Digestion Technologies Used for Treatment of Municipal Organic Solid Waste, 2008

U.S. Environmental Protection Agency (EPA)

[1] The Agstar Program. U.S. Farm Anaerobic Digestion Systems: A 2010 SnapshotU.S. EPA. U.S. EPA. Accessed June 2, 2011.

[2] IEA Bioenergy Task 37. Country Reports of Member Countries, Istanbul, April 2011. International Energy Agency. Accessed June 3, 2011.

[3] IEA Bioenergy. Biogas Production and Utilisation. International Energy Agency. May 2005. Accessed June 3, 2011.

[4] Lukehurst, C. T., Frost, P., Al Seadi, T. Utilisation of digestate from biogas plants as biofertiliser. IEA Bioenergy. June 2010. Accessed June 3, 2011.

[5] Fabien, Monnet. An Introduction to the Anaerobic Digestion of Organic Waste. Biogas Max. Remade Scotland, November 2003. Accessed June 13, 2011.

[6] Ibid.

[7] Oregon Department of Energy. Biogas Technology. Oregon Department of Energy. Accessed June 3, 2011.

[8] Supra note 1.

[10] Ibid.

[11] Landfill Methane Outreach Program. Frequently Asked Questions. U.S. EPA. U.S. EPA. Accessed June 6, 2011.

[12] Landfill Methane Outreach Program. Basic Information. U.S. EPA. U.S. EPA. Accessed June 6, 2011.

[13] Supra note 7.

[14] 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.

[15] Supra note 5.

[16] Supra note 3.

[17] Supra note 7.

[18] Supra note 1.

[19] Supra note 12.

[20] 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.

[21] Supra note 2.

[22] Alternative and Advanced Fuels. What is biogas? U.S. DOE. U.S. DOE. Accessed June 13, 2011.

[23] Supra note 7.

[24] Supra note 14.

[25] Supra note 9.

[26] DSIRE. California – Net Metering. Accessed June 13, 2011.

[27] 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.

[28] DSIRE. Net Metering Map. June 2011. Accessed June 13, 2011. 


Biological and mechanical systems to capture greenhouse gases from certain industrial and agricultural operations

Biological and mechanical systems to capture greenhouse gases from certain industrial and agricultural operations

Recovery Act’s Impact on Energy Spending

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. 

Getting It Right on Fuel Efficiency

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

Forum on Next Steps Toward Fuel Efficiency

Promoted in Energy Efficiency section: 

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.

Nuclear Power

Quick Facts

  • 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.[1] The United States is the largest generator of nuclear power, accounting for about 27 percent of global nuclear generation in 2011.[2] 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.[3] 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.[4]
  • 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.[5],[6]
  • 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).[7] Globally, electricity generation accounts for more than 27 percent of total CO2 emissions and more than one fifth of total GHG emissions.[8] 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.[9] 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).[10] 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.[11] Globally, nuclear power generates roughly 13 percent of total electricity.[12]

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.[13] 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.[14] 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.[15] 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).[16]
  • 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.[17],[18] There are two types of LWR, the boiling water reactor (BWR) and the pressurized water reactor (PWR).[19] Roughly seventy percent of U.S. nuclear reactors are PWRs.[20] Nuclear reactors are often classified in terms of their reactor generation, or stage of reactor technology development:[21]
    • 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.[22]
  • 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.[23] 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.[24] 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.[25]

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.[26] 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.[27]

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).[28] 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.[29],[30] 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.[31] 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.[32] In a 2013 update to this report, the overnight capital costs for new nuclear plants were unchanged.[33]

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.[34] 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.[35]

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).[36]

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.[37]

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.[38]  Additionally, construction is well underway at Vogtle Unit 3 in Georgia and V.C. Summer Unit 2 in South Carolina.[39], [40] 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.[41] 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.[42], [43]

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.[44] 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.[45] According to the nuclear industry, the new generation of reactors necessary for a fully closed fuel cycle is decades away from commercial development.[46]

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.[47] However, Prime Minister Abe plans to enhance safety standards and restart reactors.[48]  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.[49], [50] 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.[51] 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.[52] , [53] 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.[54] 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.[55] final waste disposal facilities ,[57] 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.[58] 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.[59] 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.[60] Given current law, indefinite storage at reactor sites and other existing temporary facilities is the only alternative to Yucca Mountain absent additional congressional action.[61] 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.[62] 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.[63]

  • 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.[64] Moreover, the current nuclear workforce is aging and retirements may exceed new entries resulting in a loss of experienced operator and maintenance personnel.[68]

  • 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.[69] 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.[70] 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.[71] 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.[72] 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.[73] In particular, current commercial reprocessing technology generates separated plutonium that is directly usable in nuclear weapons.[74]

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).[75] 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.[76] 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.[77] 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.[78]

  • 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.[79] 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.[80] 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.[81]

  • 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.[83] 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.[84] 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.[86]

  • 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.[87] 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



DTE Energy

Duke Energy





Rio Tinto

Related C2ES Resources

Climate Change 101: Technological Solutions, 2011.

A Performance Standards Approach to Reducing CO2 Emissions from Electric Power Plants, 2009.

The U.S. Electric Power Sector and Climate Change Mitigation, 2005.

Further Reading / Additional Resources

Blue Ribbon Commission on America’s Nuclear Future.

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)

Keystone Center, Nuclear Power Joint Fact-Finding, 2007.    

Massachusetts Institute of Technology (MIT)

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).


[1] U.S. Energy Information Administration (EIA), Electric Power Monthly, April 2013, see Table 1.1.

[2] EIA, International Energy Statistics, 2011 data.

[3] EIA, International Energy Statistics, 2011 data.

[4] EIA, International Energy Statistics. In 2011 data.

[5] U.S. Environmental Protection Agency (EPA), EPA Analysis of the American Power Act of 2010, June 2010, ADAGE Model Scenario 2.

[6] International Energy Agency (IEA), Energy Technology Perspectives 2010: Scenarios and Strategies to 2050, 2010, BLUE Map Scenario.

[7] EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, 2013. See Tables ES-7 and 2-13.

[8] 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. 

[9] Fthenakis, VM and HC Kim, “Greenhouse-Gas Emissions from Solar Electric- and Nuclear Power: A Life-Cycle Study,” Energy Policy 35: 2549-2557, 2007.

[10] EIA, Electric Power Monthly, April 2013, see Table 1.1.

[11] World Nuclear Association, Nuclear Power in the USA, June 2013. All of 100 U.S. nuclear reactors were ordered between 1963 and 1973.

[12] EIA, International Energy Statistics, 2013 data.

[13] For a helpful overview of the basics of nuclear power, see EIA’s Introduction to Nuclear Power.

[14] 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.”

[15] Government Accountability Office (GAO), Global Nuclear Energy Partnership: DOE Should Reassess Its Approach to Designing and Building Spent Nuclear Fuel Recycling Facilities, April 2008.

[16] MIT, 2003.

[17] Holt, July 2008.

[18] 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.

[19] 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).

[20] EIA, U.S. Nuclear Reactors.

[21] NEA, 2008.

[22] Gen IV International Forum.

[23] MIT, 2003.

[24] MIT, Update of the MIT 2003 Future of Nuclear Power, May 2009.

[25] Holt, July 2008.

[26] 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.

[27] EIA, Annual Energy Outlook 2013: Greenhouse Gas $15, April 2013.

[28] 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.

[29] 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.

[30] Du, Yangbo and John Parsons, Update on the Cost of Nuclear Power, MIT Center for Energy and Environmental Policy Research, 2009, see Figure 1.

[31] Du and Parsons, 2009.

[32] EIA, Updated Capital Cost Estimates for Electricity Generation Plants, November 2010.

[33] EIA, Updated Capital Costs Estimates for Utility Scale Electricity, April 2013.

[34] EIA, Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013, April 2013.

[35] MIT, 2009.

[36] Nuclear Energy Institute (NEI), Status and Outlook for Nuclear Energy in the United States, May 2009.

[37] U.S. Nuclear Regulatory Commission, Combined License Applications for New Reactors, Jun 2012. Available at:

[38] TVA, Watts Bar Unit 2 project construction update. April 2013.

[39] Southern Company, Construction Video and Photos, June 2013.

[40] SCE&G, New Nuclear Development, March 2013.

[41] NEI, April 2011.

[42] 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.

[43] World Nuclear Association, Nuclear Power in the USA, June 2013.

[44] Blue Ribbon Commission on America’s Nuclear Future, January 2012.

[45] NEI, Advanced Fuel-Cycle Technologies Hold Promise for Used Fuel Management Program, Jan 2009.

[46] NEI, Jan 2009.

[47] Fackler, Martin, “Japan to Cancel Plan to Build More Nuclear Plants,” New York Times, 10 May 2011.

[48] Tabuchi, Hiroko, “Japanese Nuclear Regulator Announces an Overhaul of Safety Guidelines.” New York Times, 19 June 2013.

[49] BBC, Germany: Nuclear power plants to close by 2022, 30 May 2011.

[50] 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.

[51] NRC, Japan Lessons Learned, June 2013

[52] WNA, World Nuclear Power Reactors & Uranium Requirements, June 2013.

[53] Xu, Wan, “China to Erect Nuclear Reactors to Match U.S.,” Wall Street Journal, 27 May 2009.

[54] MIT, 2009.

[55] MIT, 2003.

[56] The United States has built and operates the Waste Isolation Pilot Plant, a geological repository for defense-related transuranic waste.

[57] NEI, “Sweden Picks Location for Its Used Fuel Repository,” Nuclear Energy Insight, July 2009.

[58] Vogel, Steve, “Controversy Over Yucca Mountain May Be Ending,” Washington Post, 4 March 2009.

[59] Wald, Matthew, “As Nuclear Waste Languishes, Expense to U.S. Rises,” New York Times, 17 February 2008.

[60] Vogel, 2009.

[61] Holt, Mark, Nuclear Waste Disposal: Alternatives to Yucca Mountain, CRS, February 2009.

[62] NEI, “State Bills Promote New Nuclear Plants,” May 2008.

[63] Nuclear Regulatory Commission (NRC), “Waste Confidence Decision Update,” December 2010.

[64] Directors of DOE National Laboratories, A Sustainable Energy Future: The Essential Role of Nuclear Energy, Aug 2008.

[65] Klein, Dale, “Perspectives and Challenges of the Nuclear Renaissance,” Address by NRC Chairman to the American Nuclear Society, Raleigh, NC, 31 January 2008.

[66] NEI, “New Nuclear Plants Create Opportunities for Expanding US Manufacturing,” August 2008.

[67] U.S. Department of Energy (DOE), DOE NP2010 Nuclear Power Plant Construction Infrastructure Assessment, 2005.

[68] Keystone Center, Nuclear Power Joint Fact-Finding, 2007.

[69] MIT, 2003. See the MIT report for examples of fuel cycle facility incidents.

[70] Keystone, 2007.

[71] Keystone, 2007.

[72] Holt, July 2008.

[73] Nuclear Energy Study Group of the American Physical Society (APS) Panel on Public Affairs, Nuclear Power and Proliferation Resistance: Securing Benefits, Limiting Risk, 2005.

[74] APS, 2005.

[75] 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.

[76] NEI, May 2009.

[77] Roy, Rukmini et al., Loan Guarantees for Advanced Nuclear Energy Facilities: Bankers' Viewpoints on DOE Implementing Regulations, Letter to DOE Secretary Bodman, March 2007.

[78] 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.

[79] Blue Ribbon Commission on America’s Nuclear Future, January 2012.

[80] MIT, 2003.

[81] Holt, July 2008.

[82] Directors of DOE National Laboratories, 2008.

[83] APS, 2005.

[84] MIT, 2003.

[85] Directors of DOE National Laboratories, 2008.

[86]IAEA Approves Global Nuclear Fuel Bank,” World Nuclear News, 6 December 2010.

[87] APS, Readiness of the U.S. Nuclear Workforce for 21st Century Challenges, 2008.

An overview on the use of nuclear power for electricity generation

An overview on the use of nuclear power for electricity generation

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