Energy & Technology

Electric Energy Storage

Quick Facts

  • Electric energy storage (EES) uses forms of energy such as chemical, kinetic, or potential energy to store energy that will later be converted to electricity. Such storage can provide three basic services: supplying peak electricity demand by using electricity stored during periods of lower demand, balancing electricity supply and demand fluctuations over a period of seconds and minutes, and deferring expansions of electrical grid capacity.
  • Global EES capacity in 2010 was 127 gigawatts[1] (GW), which is only 2.6 percent[2] of electric power production capacity due to the high capital cost of EES compared to natural gas power plants, which can provide similar services, and regulatory barriers to entry in the electricity market. Of that global capacity, 22 GW[3] of EES is in the United States (2.4 percent[4] of U.S. power capacity).
  • EES can potentially smooth the variability in power flow from renewable generation and store renewable energy so that its generation can be scheduled to provide specific amounts of power, which can decrease the cost of integrating renewable power with the electrical grid, increase market penetration of renewable energy, and lead to greenhouse gas (GHG) emissions reductions.


Electric energy storage (EES) technology has the potential to facilitate the large-scale deployment of variable renewable electricity generation, such as wind and solar power, which is an important option for reducing greenhouse gas (GHG) emissions from the electric power sector. Wind and solar power emit no carbon dioxide (CO2) during electricity generation but are also variable or intermittent electricity sources. Wind power only produces electricity when the wind is blowing, and solar power only when the sun is shining, thus the output of these sources varies with wind speeds and sunshine intensity. Since operators of the electrical grid must constantly match electricity supply and demand, this makes variable renewable resources more challenging to incorporate into the electrical grid than traditional baseload (e.g., coal and nuclear) and dispatchable (e.g., natural gas) generation technologies, which can be scheduled to produce power in specific amounts at specific times. Electrical grid operators have several options for managing the variability of electricity supply introduced by large amounts of renewable generation, one of which is EES.[5]

EES promises other benefits unrelated to renewable energy, such as improved grid reliability and stability, deferral of new generation and transmission investments, and other grid benefits.[6]


EES technologies vary by method of storage, the amount of energy they can store, and how quickly and for how long they can release stored energy. Some EES technologies are more appropriate for providing short bursts of electricity for power quality[7] applications, such as smoothing the output of variable renewable technologies from hour to hour (and to a lesser extent within a time scale of seconds and minutes). Other EES technologies are useful for storing and releasing large amounts of electricity over longer time periods (this is referred to as peak-shaving, load-leveling, or energy arbitrage).[8] These EES technologies could be used to store variable renewable electricity output during periods of low demand and release this stored power during periods of higher demand. For example, wind farms often generate more power at night when winds speeds are high but demand for electricity is low; EES could be used to shift this output to periods of high demand.

The major technology options for EES include the following:

  • Pumped Hydro

Pumped hydro storage uses low-cost electricity generated during periods of low demand to pump water from a lower-level reservoir (e.g., a lake) to a higher-elevation reservoir. During periods of high electricity demand (and higher prices), the water is released to flow back down to the lower reservoir while turning turbines to generate electricity, similar to conventional hydropower plants. Pumped hydro storage is appropriate for load leveling because it can be constructed at large capacities of 100-1000s of megawatts (MW) and discharged over long periods of time (6 to 10 hours).[9]

  • Compressed Air

Compressed air energy storage (CAES) is a hybrid generation/storage technology in which electricity is used to inject air at high pressure into underground geologic formations. When demand for electricity is high, the high pressure air is released from underground and used to help power natural gas-fired turbines. The pressurized air allows the turbines to generate electricity using significantly less natural gas. CAES is also appropriate for load leveling because it can be constructed in capacities of a few hundred MW and can be discharged over long (8-20 hours) periods.[10]

  • Rechargeable Batteries

Several different types of large-scale rechargeable batteries can be used for EES including sodium sulfur (NaS), lithium ion, and flow batteries.[11] Batteries could be used for both power quality and load-leveling applications. In addition, if plug-in hybrid electric vehicles (PHEVs) become widespread, their onboard batteries could be used for EES, by providing some of the supporting or “ancillary” services[12] in the electricity market such as providing capacity, spinning reserve,[13] or regulation[14] services, or in some cases, by providing load-leveling or energy arbitrage services by recharging when demand is low to provide electricity during peak demand.

  • Thermal Energy Storage

There are two very different types of thermal energy storage (TES): TES applicable to solar thermal power plants and end-use TES. TES for solar thermal power plants consists of a synthetic oil or molten salt that stores solar energy in the form of heat collected by solar thermal power plants to enable smooth power output during daytime cloudy periods and to extend power production for 1-10 hours past sunset.[15] End-use TES stores electricity from off-peak periods through the use of hot or cold storage in underground aquifers, water or ice tanks, or other storage materials and uses this stored energy to reduce the electricity consumption of building heating or air conditioning systems during times of peak demand.[16]

  • Hydrogen

Hydrogen storage could be used for load-leveling or power quality applications.[17] Hydrogen storage involves using electricity to split water into hydrogen and oxygen through a process called electrolysis. When electricity is needed the hydrogen can be used to generate electricity via a hydrogen-powered combustion engine or a fuel cell.

  • Flywheels

Flywheels can be used for power quality applications since they can charge and discharge quickly and frequently. In a flywheel, energy is stored by using electricity to accelerate a rotating disc. To retrieve stored energy from the flywheel, the process is reversed with the motor acting as a generator powered by the braking of the rotating disc.

  • Ultracapacitors

Ultracapacitors are electrical devices that consist of two oppositely charged metal plates separated by an insulator. The ultracapacitor stores energy by increasing the electric charge accumulation on the metal plates and discharges energy when the electric charges are released by the metal plates. Ultracapacitors could be used to improve power quality because they can rapidly provide short bursts of energy (in under a second) and store energy for a few minutes.[18]

  • Superconducting Magnetic Energy Storage (SMES)

Superconducting magnetic energy storage (SMES) consists of a coil with many windings of superconducting wire that stores and releases energy with increases or decreases in the current flowing through the wire. Although the SMES device itself is highly efficient and has no moving parts, it must be refrigerated to maintain the superconducting properties of the wire materials, and thus incurs energy and maintenance costs.[19] SMES are used to improve power quality because they provide short bursts of energy (in less than a second).

Environmental Benefit / Emission Reduction Potential

The use of EES can potentially enable very large penetration of variable renewable generation in the longer term by lowering the cost of connecting these resources with the transmission grid and of managing the increased variability of generation.[20] For example, a modeling analysis conducted in 2008 by the National Renewable Energy Laboratory (NREL) examined the effect of EES on wind power.[21] In a “business-as-usual” case, NREL’s model projected that building about 30 GW of EES could allow for the installation of an additional 50 GW of wind generation capacity by 2050 (a 17 percent increase compared to a scenario with no EES).NREL also modeled a scenario that required 20 percent of electricity to come from wind power by 2030. In this case, NREL found that investments in EES (in the form of CAES) became economic once wind penetration reached 15 percent of generation and that EES would lower the cost of electricity in the case of high wind penetration by 3 percent (about $3/MWh) in 2050.[22]

EES enables GHG emission reductions by two main mechanisms:

  • EES can be used instead of natural gas generators to smooth out the variable output of renewable resources such as wind or solar power over long periods, and allow these resources to be scheduled according to daily fluctuations of electricity demand. For example, the use of CAES to smooth wind power generation would result in a 56 percent reduction in CO2 emissions per kilowatt-hour of electricity, compared to smoothing variable wind power with generation from a gas turbine, and would enable a greater penetration of wind power.[23] Another study estimated that over the span of 20 years, a 20 MW flywheel facility could reduce CO2 emissions from coal power plants by 67-89 percent[24], depending on the regional regulations and intended use of the coal power plant (whether it is for peak or base power generation). The flywheel plant would remove the need to have a coal power plant that could produce 20 MW of power to the grid, resulting in CO2 emissions reduction.[25]   
  • EES charged with electricity from low-carbon sources can also be used to displace fossil fuel generation to provide regulation services by smoothing out the fluctuations between supply and demand over short periods of less than 15 minutes. This use of EES could reduce the amount of fossil fuels burned by generators, leading to GHG and conventional emission reductions.

However, EES can also increase GHG emissions if recharged with cheap electricity from high-carbon baseload coal power plants to displace more expensive peaking power from lower-carbon natural gas generators. The GHG emission reduction potential from EES depends on its use with renewable or low-carbon (i.e. nuclear or coal with carbon capture and storage (CCS)) resources.


The up-front capital costs of EES vary by technology and capacity. Total capital costs per unit of power capacity for most EES technologies are high compared to a $800-1100/kW natural gas power plant,[26] varying from $500/kW for ultracapacitors[27], $1000-$1250/kW for underground CAES[28], $950-$1590/kW for batteries[29], $434-$3000/kW  for hydrogen fuel cells, $758-$1,044/kW for hydrogen fueled gas turbine,[30] $1500-$4300/kW for pumped hydro, and $1950-$2200/kW for flywheels.[31] These costs are highly uncertain and complicated by the fact that the cheaper technologies, such as SMES, ultracapacitors, and some batteries, are only available with small (a few kilowatt to MW) power capacities. Integrating many small units of these cheaper storage technologies into a 100+ MW-scale utility application would lead to additional cost and complexity.

The cost premium for stored electricity,[32] which depends on the lifetime of the EES technology and its useable energy storage capacity, are not well understood for most EES technologies. One study calculated a cost premium of $0.05-0.12/kWh for pumped hydro storage, $0.07-0.86/kWh for batteries, and $0.07-0.64/kWh for flywheels.[33] EES technologies at the low cost ranges seem promising in a few applications when competing against average U.S. peak electricity prices of $0.18/kWh.[34]

TES for solar thermal power plant and end-use applications are also commercially promising. A study by the Electric Power Research Institute (EPRI) of a 125 MW solar thermal power plant in New Mexico estimated that a parabolic troughdesign solar thermal power plant with TES has almost a 10 percent lower levelized cost of electricity[35] compared to one without storage, and up to 30 percent cost savings with a central receiver design.[36],[37] EPRI has also found that the use of end-use TES systems can save between 2-7 percent of annual heating/cooling energy costs, if well-designed.[38]

Current Status of Electric Energy Storage

The current use of EES technologies is limited compared to the rates of storage in other energy markets such as the natural gas or petroleum markets. EES capacity, most of which is pumped hydro, is only 2.3 percent of U.S. electric power capacity.[39] However, demonstration projects of various EES technologies are underway in the U.S. and internationally.

  • Pumped Hydro

The majority of EES in operation today consists of pumped hydro facilities. The U.S. has 40 pumped hydro facilities[40] in operation that provide up to 22 GW of power. As of August 2011, The Federal Energy Regulatory Commission (FERC) has issued 25 preliminary permits since the start of 2010 for pumped hydro energy storage projects, totaling 16.7 GW of capacity.These preliminary permits allow feasibility studies but no permanent or large-scale installations. The potential use of this technology is limited by the availability of suitable geographic locations for pumped hydro facilities near demand centers or generation.

  • Compressed Air Energy Storage (CAES)

Two CAES facilities are in operation today: a 290 MW facility in Huntorf, Germany, which is used to level variable power from wind turbines, and a 110 MW facility in McIntosh, Alabama, which is used to provide a variety of power quality functions.[41] Several improved second-generation CAES systems are being designed that have potential for lower installed costs, higher efficiency, and faster construction time than first-generation systems.[42] The American Recovery and Reinvestment Act (ARRA) is providing funds for two CAES demonstration projects in New York and California.[43] Some studies forecast that CAES will provide the bulk of EES services by 2050 because of its lower capital and operating costs.[44]

  • Batteries

As of 2010, sodium sulfide (NaS) batteries have been used by utilities worldwide in 221 projects with a total capacity of 316 MW.[45] EPRI estimates that with current efforts the installed capacity of NaS batteries will increase to 606 MW by 2012.[46] Globally, there are 16 MW in commercial service with numerous demonstration projects in the kW range.[47] Several flow batteries are being field-tested around the world, and a 4 MW commercial unit is already operating in Japan.[48] ARRA has provided funding for several large-scale demonstration projects for flow, battery chemistries newer than NaS like lithium ion, and other battery technologies.[49]

  • Thermal Energy Storage (TES)

There are several operational commercial solar thermal power plants with integrated TES as of August 2011. They include:

o   AndaSol One in Andalusia, Spain;[50]

o   Solar Tower in Seville, Spain;[51]

o   La Florida Solar Power Plant in Alvarado, Spain;[52]

o   Extresol-1 and Extresol-2 in Torre de Miguel Sesmero, Spain;[53]

o   La Dehesa in La Garrovilla, Spain;[54]

o   Manchasol in Alcazar de San Juan, Spain;[55]

o   Archimedes Solar Power Plant in Priolo Gargallo, Italy;[56]

o   Holaniku in Keahole Point, Hawaii, U.S.A;[57]

o   Nevada Solar One in Boulder City, Nevada, U.S.A;[58]

The majority of the concentrated solar power (CSP) plants use molten salt as the energy storage medium. The planned Hualapai Valley Solar Project in Arizona is a 340 MW thermal solar power plant using molten salt for energy storage and will be completed in 2014.[59] Demonstrations of end-use TES technologies have occurred in the United States, United Kingdom, Germany, and Scandinavia. For example, about 8 percent of residential water heaters in the United Kingdom use a specific TES material that is heated at night in order to heat water throughout the day and reduce peak electricity consumption.[60]

  • Hydrogen

There are some demonstrations of EES using hydrogen and fuel cells for utility applications. However, hydrogen storage requires significant cost reductions prior to large-scale deployment since electrolysis is about 62-87 percent efficient while fuel cells are about 47-58 percent efficient[61], resulting in lower efficiency to provide electricity to the grid compared to the 60-94 percent efficiencies of other EES technologies.[62] A combustion turbine using hydrogen as fuel instead of natural gas results in 42-70 percent efficiency.[63]

  • Flywheels

Several installations of flywheels to provide power quality services have taken place across the United States. Flywheel modules can be connected together to increase the storage capacity. In July 2011, a 20 MW flywheel energy storage facility, built using two hundred 100 kW flywheels, in Stephentown, New York became operational.[64] Flywheels have a high cycle life[65] of 100,000 to 2,000,000 cycles[66], long operating life of about 20 years[67], rapid response time of 4 milliseconds or less[68], and fast charging and discharging times of a few seconds to 15 minutes.[69] More research needs to be conducted to improve the energy densities[70] of this storage technology.

  • Ultracapacitors

ARRA is currently funding a grid-scale ultracapacitor demonstration project with a 3 MW capacity.[71] The Advanced Research Projects Agency-Energy (APRA-E) is funding research and development of ultracapacitors with greater energy density.[72]

  • Superconducting Magnetic Energy Storage (SMES)

Several MW-capacity SMES demonstration projects are in operation around the United States and the world to provide power quality services, especially at manufacturing plants requiring ultra-reliable electricity such as microchip fabrication facilities.[73] SMES requires further research to lower capital costs and improve energy densities.

Obstacles to Further Development or Deployment to Electric Energy Storage

  • High Capital Costs

The capital costs of current EES technologies are high compared to natural gas generators that provide similar services.

  • Need for Large-Scale Demonstration Projects

EES technologies such as CAES require a few large-scale demonstration projects before utility managers will have the confidence to invest in these technologies. ARRA is supporting two utilities in New York and California with funding to build large-scale CAES plants that will demonstrate technological maturity and economic feasibility, but other technologies such as SMES will also require large-scale demonstrations before wider adoption can take place. 

  • Transmission Planning Processes

Transmission planning only takes into account the location of demand centers and generation facilities. As a result, geographically remote EES facilities such as pumped hydro or CAES have limited access to the transmission grid.[74]

  • Regulatory Barriers

Federal and state regulations treat EES as a type of electricity generation technology rather than as an investment in transmission capacity. Thus transmission and distribution companies are barred from owning EES.[75] In addition, most renewable portfolio standards or government investment or production incentives are written for renewable generation only and exclude EES, despite the fact that EES can enable higher penetration of renewable energy.[76], [77]

  • Conservative Industry Culture With Respect to Technology Risks

Regulated utilities are risk averse and reluctant to invest in new technologies, such as EES, due to the capital-intensive nature of electric generation and the lack of competition in the market. Deregulation of the electricity industry in parts of the U.S. created a competitive market for generation, but generator owners are unsure whether they will be able to recover their capital costs and are also reluctant to invest in new technologies. In general, the energy industry invests a tiny fraction of profits in research and development compared to other industries, which limits the pace of improvements in technologies such as EES.[78]

  • Incomplete Electricity Markets

Most regions of the United States have not yet fully developed markets and transparent prices for all the types of ancillary services that EES (and generation) technologies provide besides providing electricity, such as regulation, spinning reserve, load-following,[79] and other services.

Policy Options to Help Promote Electric Energy Storage

  • Carbon Price

A price on carbon, such as that which would exist under a greenhouse gas cap-and-trade program (see Climate Change 101: Cap and Trade), would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from variable renewable sources, such as wind and solar power, and from low carbon sources, such as nuclear and coal power with CCS. This would, in turn, increase the value of the services provided by EES in situations where EES could store relatively inexpensive low-carbon electricity to displace carbon-intensive power.

  • Real-Time Electricity Pricing

The cost of producing and delivering electricity to consumers varies throughout the day, since cheaper baseload coal or nuclear power plants generate more of the electricity at night when demand is low, and more expensive peaking power plants must be activated during the day when demand is high. However, most residential consumers are charged a flat price for electricity, and commercial and industrial consumers face demand charges for high power consumption and higher peak electricity rates that are not set according to the daily hour-by-hour variations of electricity production costs. If consumers were charged a real-time price for electricity, the high cost of peak electricity would be transparent and investments in EES to reduce peak load would have greater value. A national smart grid would facilitate real-time electricity pricing. (See Climate Techbook: Smart Grid.)

  • Markets for Ancillary Electric Services

EES technologies would benefit from receiving prices set by competitive markets for ancillary electric services such as regulation, spinning reserve, and load-following, which would increase the overall value of EES.

  • Relaxation of Ownership Restrictions

EES can serve both generation and transmission functions, but existing deregulated electricity markets place limits on who can own such facilities. Removing restrictions on the ownership of EES facilities by end-use customers, transmission owners, or distribution companies could enable greater market penetration of EES.[80]

  • Integration of EES in Transmission Planning

Decisions regarding new transmission lines could factor in the location of large-scale EES sites, as well as demand centers and generation facilities. Investments in EES are often less costly than building new transmission lines. The Federal Energy Regulatory Commission could modify rules so that EES is subject to transmission pricing incentives and a part of the transmission planning process.[81]

  • Matching Grants for Large-Scale EES Demonstration Projects

Matching grants can lower the cost of large-scale technology demonstration projects and accelerate commercialization. For instance, the ARRA is providing $185 million in federal matching funds to support energy storage project with a total value of $772 million.[82] The projects would add 537.3 MW of energy storage capacity to the grid.[83]

  • Basic and Applied Research and Development

Low charge/discharge efficiencies, low cycle lives, and high capital costs make most EES technologies less economically competitive for smoothing out renewable energy or providing power quality services compared to power plants that provide similar services. Federal or state investments and incentives for private investment in basic and applied research and development would help to improve the performance of existing technologies and support the discovery of fundamental breakthroughs for the next generation of EES technologies. Department of Energy’s ARPA-E program is supporting advanced research in energy storage technologies with $55 million in funds for fiscal year (FY) 2011 and FY 2012.[84]

Related Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Komor, Paul. 2009. Wind and Solar Electricity: Challenges and Opportunities.

Morgan, Granger, Jay Apt, and Lester Lave. 2005. The U.S. Electric Power Sector and Climate Change Mitigation.

 American Physical Society (APS). 2007. Challenges of Electricity Storage Technologies. See

California Independent System Operator (CAISO). 2007. Integration of Renewable Resources: Transmission and Operating Issues and Recommendations for Integrating Renewable Resources on the California ISO-Controlled Grid. See Chapter 7, “Storage Technology,” available at

Electricity Advisory Committee. “Energy Storage Activities in the United States Electricity Grid.” May 2011. See

Denholm, Paul. 2008. The Role of Energy Storage in the Modern Low-Carbon Grid. National Renewable Energy Laboratory. See

International Energy Agency (IEA). 2008. Empowering Variable Renewables: Options for Flexible Electricity Systems. See

Lee, Bernard and David Gushee. 2008. Massive Electricity Storage. American Institute of Chemical Engineers. See

National Renewable Energy Laboratory (NREL). “Energy Storage Basics.” See

Peters, Roger and Lynda O’Malley. 2008. Storing Renewable Power. Pembina Institute. See

Rastler, Dan. "Electricity Energy Storage Technology Options." Electric Power Research Institute. 1020676. 2010. See

Yan, Chi-Jen and Eric Williams (Nicholas Institute). 2009. Energy Storage for Low-carbon Electricity. Duke University Climate Change Policy Partnership. See

[1] Rastler, D. Electric Power Research Institute (EPRI). "Electricity Energy Storage Technology Options." 1020676. 2010.

[2] Total global generating capacity was estimated at 4,950 GW. Renewable Energy Policy Network for the 21st Century. “Renewables 2011 Global Status Report.” 2011.

[3]Energy Storage Activities in the United States Electricity Grid”. Electricity Advisory Committee. May 2011.

[4] U.S. Energy Information Administration. “Annual Energy Outlook 2011”. 2011. Using data for 2010.

[5] Other approaches for managing the variability of renewable generation include increasing the interconnectedness of electric grids, developing more flexible generation technologies capable of increasing or decreasing output at faster rates (called ramping rates), demand response programs which create flexibility in demand, and market mechanisms, such as different pricing structures for variable renewable resources. For more information, see the resources under Further Reading, especially the Center’s report on wind and solar power and the reports from IEA and CalISO.

[6] Jewell, Ward et al. 2004. Evaluation of Distributed Electric Energy Storage and Generation. Power Systems Engineering Research Center. See .

[7]Power quality is defined as the provision of power with specified voltage and frequency characteristics to the customer. Small imbalances in the sub-minute time frame between electricity supply and demand, and the physical properties of electricity generators, electricity-consuming devices, and the transmission grid lead to small deviations (1 to 5 percent) between the expected and actual voltage and frequency of power delivered, which can cause highly sensitive equipment such as computers to fail. When electricity supply and demand are in balance, these deviations in voltage and frequency are eliminated.

[8] Load leveling or peak shaving refers to the use of electricity stored during times of low demand to supply peak electricity demand, which reduces the need for electricity generation from peaking power plants. The use of EES for load leveling is also known as “energy arbitrage” since it may be possible to earn a profit by charging EES with cheap electricity when demand is low and selling discharged electricity at a higher price when demand is high. Load leveling can also be achieved through demand-side measures such as using higher peak prices to induce a reduction in peak demand through demand charges, real-time pricing, or other market measures.

[9] Rastler, 2010     

[10] Ibid.

[11] Unlike traditional batteries, flow batteries use fuel that is external to the battery that flow in and out to generate electricity through an electro-chemical process.

[12] Generators (and potentially EES) provide energy and ancillary services to electricity markets. Energy services are defined as providing electric generation to meet demand, usually scheduled on a day-ahead basis. The term, “ancillary services” includes a variety of services related to power quality. For example, in some electricity markets, generators (and potentially EES) are paid for the capacity of power they can produce, whether or not they are actually generating, in order to ensure that the market has sufficient capacity to meet peak demand.

[13] Spinning reserve is an ancillary service in the electricity market defined as the ability of (usually a generator) to remain on and ready to start generating given notice over a short period of time (15 minutes to an hour).

[14] Regulation refers to an ancillary electric service (usually provided by electric generators) to maintain power quality by following unpredicted minute-by-minute fluctuations in electric demand.

[16] End-use thermal energy storage could also be considered a type of demand response as it reduces the electricity use of heating or air conditioning systems during times of peak demand. By pre-cooling or heating the building during off-peak times and using a few hours of hot or cold storage in the form of aquifers, water/ice tanks, or heat storage materials, the heating, air-conditioning, and refrigeration loads of the building can be shifted to off-peak hours. For more information, see International Energy Agency. Energy Conservation through Energy Storage website.   

[17] Schoenung, S. M. Hydrogen Energy Storage Comparison. Department of Energy. See

[18] American Physical Society (APS). 2007. Challenges of Electricity Storage Technologies. See

[19] Ibid.

[20] Ibid.

[21] Sullivan,P., Short, W., and Blair, N. 2008. “Modeling the Benefits of Storage Technologies to Wind Power.” American Wind Energy Association (AWEA) WindPower 2008 Conference. Conference Paper NREL/CP-670-43510.

[22] Ibid.

[23] Greenblatt, J. B., Succar, A., Denkenberger, D. C., Williams, R. H., and Socolow, R. H. 2007. “Baseload wind energy: modeling the competition between gas turbines and compressed air energy storage for supplemental generation.” Energy Policy. 35: 1474–1492.

[25] Ibid.

[26] California Public Utility Commission.Greenhouse Gas Modeling. “New Combined Cycle Gas Turbine (CCGT) Generation Resource, Cost, and Performance Assumptions.” Assumptions%20v4.doc. Development and construction capital costs from 2002 escalated by 3% per year to 2009 from Northwest Council. “Natural Gas Simple-Cycle Gas Turbine Power Plants.” /powerplan/grac/052202/gassimple.htm.

[27] Schoenung, S. “Energy Storage Systems Cost Update” Sandia National Labatory. April 2011. SAND2011-2730.

[28] Rastler, 2010.

[29] Ibid.

[30] Steward, Darlene M. “Analysis of Hydrogen and Competing Technologies for Utility-Scale Energy Storage” National Renewable Energy Labatory. February 2010.

[31] Rastler, 2010..

[32] The cost premium is the difference between the cost of electricity discharged from an EES facility and the cost of the electricity used to charge the EES facility.

[33] Poonpun, P., and Jewell, W. T. 2008. “Analysis of the Cost per Kilowatt Hour to Store Electricity.” IEEE Transactions on Energy Conversion. Vol 23. No 2. June.

[34] Ibid.

[35] Levelized cost of electricity (LCOE) is defined as the ratio of the sum of the plant operation and maintenance costs and amortized capital costs to the annual plant generation.

[36] Electric Power Research Institute. “Program on Technology Innovation: Evaluation of Concentrating Solar Thermal Energy Storage Systems.” 1018464. 2009.

[37] While TES increases the capital costs of a solar thermal power plant, it also increases the total electricity output from the power plant by using a larger solar collector to heat the molten salt-based TES material and allowing the plant to operate during sundown. The increase in power output is greater than the increase in capital costs for the TES material and additional solar collector area.

[38] Electric Power Research Institute. “Thermal Energy Storage Systems Operation and Control Strategies Under Real-Time Pricing.” Palo Alto, CA: 2004. 1007401.

[39] Electric Advisory Committee, 2011.

[40] Rastler, 2010.

[41] Rastler, 2010.

[42] Ibid, page 4-4.

[43] EAC 2011

[44] Sullivan, et. al., 2008.

[45] Rastler, 2010, page 4-10

[46] Ibid.

[47] Ibid, page 4-18.

[48] Ibid, page 4-13.

[49] EAC 2011.

[50] Andasol Solar Power Station, Spain. Accessed August 9, 2011. See

[51] Solar Tower, Seville, Spain. Accessed August 9, 2011. See

[52] La Florida Solar Power Plant, Spain. Accessed August 9, 2011. See

[53] Concentrating Solar Power Projects: Extresol-1. National Renewable Energy Laboratory. January 20, 2011. Accessed August 12, 2011.

[54] Concentrating Solar Power Projects: La Dehesa. National Renewable Energy Laboratory. March 30, 2011. Accessed August 12, 2011.

[55] Concentrating Solar Power Projects: Manchasol-1. National Renewable Energy Laboratory. March 30, 2011. Accessed August 12, 2011.

[56] Concentrating Solar Power Projects: Archimede. National Renewable Energy Laboratory. June 22, 2011. Accessed August 9, 2011.

[57] Concentrating Solar Power Projects: Holaniku at Keahole Point. National Renewable Energy Laboratory. December 3, 2010. Accessed August 12, 2011.

[58] Concentrating Solar Power Projects: Nevada Solar One. National Renewable Energy Laboratory. June 1, 2007. Accessed August 12, 2011.

[59] Hualapai Valley Solar Project, Arizona, USA. See

[60] Baker, J. 2008. “New Technology and Possible Advances in Energy Storage.” Energy Policy. Vol. 36, p 4368–4373.

[61] Steward, D., Saur, G., Penev, M., Ramsden, T. “Lifecycle Cost Analysis of Hydrogen Versus Other Technologies for Electrical Energy Storage.” National Renewable Energy Laboratory. NREL/TP-560-46719. 2009.

[62] Rastler, 2010. Pages xxiii-xxiv

[63] Ibid.

[65] Cycle life is defined as the number of times an EES technology can be charged and discharged up to its maximum charging capacity during its lifetime.

[66] Walawalkar, Rahul, and Jay Apt. 2008. Market Analysis of Emerging Electric Energy Storage Systems. National Energy Technology Laboratory. See

[67] Rastler, 2010.

[68] Ibid.

[69] Ibid.

[70] Energy density is defined as the ratio of the energy storage capacity in kWh to the physical footprint required for the technology, often in expressed in units of square meters. Energy density is most important for vehicular applications.

[71] EAC 2011.

[72] Ibid.

[73] APS, 2007.

[74] Yan, Chi-Jen and Eric Williams (Nicholas Institute). 2009. Energy Storage for Low-carbon Electricity. Duke University Climate Change Policy Partnership. See

[75] Ibid.

[76] Ibid.

[77] The Energy Independence and Security Act of 2007 (EISA 2007) is an exception, as it provides $50 million in basic research funding, $80 million in applied research funding for automotive and utility energy storage, and defines “deployment and integration of advanced electricity storage and peak-shaving technologies, including plug-in electric and hybrid electric vehicles, and thermal-storage air conditioning” as a “Smart Grid” characteristic” and eligible for matching grants and other incentives for Smart Grid technologies found in the law. Source: Peters, Roger and Lynda O’Malley. 2008. Storing Renewable Power. Pembina Institute. See

[78] Margolis, R. M., and Kammen, D. M. 1999. “Underinvestment: The Energy Technology and R&D Policy Challenge.” Science. Vol. 285. no. 5428, pp. 690 – 692.

[79] Load-following is an ancillary service is the electricity market defined as the ability of (usually a generator) to increase or decrease electricity output over a short period of time (15 minutes to an hour) according to the predicted change in electric demand throughout a day.

[80] Nicholas Institute, 2009.

[81] Ibid.

[82] EAC 2011.

[83] Ibid.

[84] Ibid.


Introduction to existing and emerging energy storage options for electricity

Introduction to existing and emerging energy storage options for electricity

Smart Grid

Quick Facts

  • The smart grid refers to the application of digital technology to the electric power sector to improve reliability, reduce cost, increase efficiency, and enable new components and applications.
  • Compared to the existing electrical grid, the smart grid promises improvements in reliability, power quality, efficiency, information flow, and improved support for renewable and other technologies.
  • Smart grid technologies, including communication networks, advanced sensors, and monitoring devices, form the foundation of new ways for utilities to generate and deliver power and for consumers to understand and control their electricity consumption.
  • Some of the largest utilities in the country, including Florida Power and Light, Xcel Energy, Pacific Gas and Electric, and American Electric Power, have undertaken initiatives to deploy smart grid technologies.
  • Smart grid technologies could contribute to greenhouse gas emission reductions by increasing efficiency and conservation, facilitating renewable energy integration, and enabling plug-in electric vehicles.


The Smart Grid and Its Potential Benefits

The smart grid is a concept referring to the application of digital technology to the electric power sector. It is not one specific technology. Rather, the smart grid consists of a suite of technologies expected to improve the performance, reliability, and controllability of the electrical grid. Many of these technologies have been employed in other sectors of the economy, such as the telecommunications and manufacturing sectors.

Smart grid technologies offer several potential economic and environmental benefits:

  • Improved reliability
  • Higher asset utilization
  • Better integration of plug-in electric vehicles (PEVs)[1] and renewable energy
  • Reduced operating costs for utilities
  • Reduced expenditures on electricity by households and businesses
  • Increased efficiency and conservation
  • Support for new components and applications
  • Lower greenhouse gas (GHG) and other emissions

Digital technologies have been integral to the modernization of many sectors of the economy and have resulted in efficiency gains, new opportunities, and greater productivity. The electric power sector, however, has lagged behind. Many utilities still use the same designs as they did when most of the grid was built in the 1960s and 1970s.

Issues with the Existing Grid

The U.S. electrical grid is an enormous and extremely complex system consisting of centralized power plants, transmission lines, and distribution networks.[2] It is capable of carrying over 850 gigawatts (GW) of power and continuously balancing supply with fluctuating demand. It does so with remarkable reliability, providing 99.97 percent uptime (when the grid is operational), or about 160 minutes of downtime a year.[3],[4]

However, the traditional electric power grid was designed neither with the latest technology nor with the goal of supporting a high-tech economy and enabling low-carbon technologies, energy efficiency, and conservation. Some of the grid issues described below are addressed by smart grid technologies but do not relate directly to GHG emission reductions.

  • Power outages and power quality disruptions cost more than $150 billion annually.[5],[6]

The power still goes out for customers at an average of 2.5 hours per year, which leads to sizeable economic losses. Power quality disruptions for ordinary consumers may be no more than lights flickering or dimming, but for high-tech manufacturing and critical infrastructure that rely on high quality power (such as communications networks and pipelines), these events can disrupt operations and collectively can cost millions.[7]

  • The grid is inefficient at managing peak load.

Peak load is the short period when electricity demand is at its highest within a day, season, or year. Electricity demand is cyclical and variable, and the cost of meeting that demand varies, but because utilities have limited tools for managing demand, supply must be adjusted continuously to track demand. In addition, the power grid must constantly maintain a buffer of excess supply, which is primarily fossil fuel based, resulting in lower efficiency, higher emissions, and higher costs.

  • The grid does not support robust information flow.

For example, utilities often do not find out about blackouts until consumers call to notify them. Moreover, consumers have very little knowledge about how their electricity is priced or how much energy they are using at any given time. This limits the incentives for efficiency, conservation, and demand response.

  • Very high levels of renewable energy pose challenges for the grid.[8],[9]

The electricity generation from certain important renewable technologies fluctuates based on the availability of variable resources (e.g., the wind and sunlight).  The ability of the existing grid to support high levels of variable renewable generation is uncertain.[10] Efforts are currently underway to better understand the impact of high levels of renewable energy in the electricity grid, and will become more important as renewable energy increases. For instance, California aims to incorporate 33 percent renewable energy by 2020.[11]

  • The grid has limited support for distributed generation.

Because the grid was designed for a one-way power flow from centralized power stations to end users, it has to be upgraded to allow a two-way power flow that supports small distributed generators. Adding variable generators such as rooftop solar or micro wind (small wind turbines able to be mounted on a residential rooftop) makes managing distributed generation even more difficult for the existing grid.

  • The grid would be strained by high PEV deployments.

A significant deployment of PEVs over the next few decades would represent a major strain on the electric power system. Due to the nature of the charging cycles of PEVs, it will be both expensive and technically difficult to manage the fleet’s demands through the existing grid.


Characteristics of smart grid technologies enable many functions beyond what the existing grid does. A smart grid:

  • Gives the utility actionable information[12]

Instead of estimating network activity or having to send out physical readers to many locations, utilities receive a constant flow of information about their network, their customers, and their options for managing their operations.

  • Gives the consumer actionable information[13]

Customers can be provided with information about their electricity usage patterns and costs. They can use this information to reduce their energy costs and their environmental impact.

  • Automates and decentralizes decisions[14]

Instead of forcing centralized system operators and planners to make decisions, a smart grid automates easy decisions[15] and empowers consumers to take informed actions.

  • Supports and enhances new technologies[16]

A smart grid provides support for new applications and components, such as smart appliances, PEVs, distributed generation, and renewable energy by allowing for better management of their interaction with the grid.

Key Technologies

The technologies that comprise a smart grid address the existing grid’s shortcomings by providing actionable intelligence and enhanced management capabilities that can improve operational efficiency and performance. These technologies are available now, and some of the largest utilities in the country, including Xcel Energy[17], Pacific Gas and Electric (PG&E)[18], and American Electric Power (AEP)[19], have begun large-scale deployment of these technologies to their customers.[20]

According to the Smart Grid Information Clearinghouse (SGIC) the smart grid consists of five key technology areas[21]:

  • Integrated Communications

High-speed, standardized, two-way communication allows for real-time information flows and decision-making among all grid components. Several existing technologies, including wide-area wireless internet and cellular networks, could provide the communications infrastructure needed.

  • Sensing and Measurement

Sensing and measurement allow utilities and consumers to understand and react to the state of the electrical grid in real-time. For example, households could monitor their energy demand and the current price of electricity through smart meters, which communicate with home networks that link smart appliances and display devices.

  • Advanced Components

Advanced components such as GPS systems, current-limiting conductors, advanced energy storage, and power electronics will improve generation, transmission, and distribution capacity and operational intelligence for utilities.

  • Advanced Control Methods

As more information is available to grid controllers and faster response times are required, the task of managing an electrical grid is becoming more complex. Advanced control systems find and process important information quickly, streamlining operations and providing clarity to human operators.

  • Improved Interfaces and Decision Support

New tools, such as software to visualize networks at any scale (from an individual neighborhood to the entire national grid), provide system operators with greater situational awareness and diagnostics and allow planners, operators, and policymakers to make informed decisions.

Key Applications

The smart grid technologies that form the foundation of a new grid enable new smart grid applications, including:

  • Automatic Meter Reading / Advanced Metering Infrastructure (AMR / AMI)[22],[23]

AMR allows utilities to read electricity, water, and gas meters electronically; as opposed to sending a meter-reader to each house every month. AMI goes the next step, adding 2-way communications that allow the utility to act on information coming back from meters, adjusting prices and responding to outages or power quality events in real-time.

  • Real-Time Pricing (RTP)[24]

RTP charges electricity prices dynamically to reflect the realities of the electricity market. Successful RTP depends on a price-elastic demand for electricity, allowing markets to determine prices quickly and keeping prices in a reasonable range for consumers. A smart grid lets consumers prioritize and monitor their electricity use, resulting in cost savings and a more economically efficient electricity market.

DR allows utilities to reduce demand during periods of peak load and thus avoid dispatching high-cost generating units which are often among the least efficient and dirtiest. DR can distinguish between valuable and low-priority electricity uses – for example, dimming lights and adjusting air conditioners without disrupting vital services.

  • Smart Charging / Vehicle-to-Grid (V2G)[27]

PEVs will greatly increase the load on the grid. A single PEV can draw more power than a typical household. Smart Charging devices allow PEVs to communicate with the utility, timing the charging to coincide with low prices, low grid impact, and potentially low emissions periods (e.g., when renewable energy sources are available). V2G takes this concept one step further by allowing PEVs to feed their power back into the grid to help stabilize voltage and frequency, reducing the need for spinning reserves and regulation services and thus avoiding emissions from electricity generating units that would otherwise need to provide these services.[28]

  • Distribution Automation[29]

Distribution automation allows distribution systems to reconfigure themselves when a fault occurs, restricting the problem to a smaller area.[30] This reduces the amount of time that backup generators (usually diesel-based) operate and cuts total outage time.

  • Distributed Generation Integration[31]

By providing greater fault tolerance and islanding detection, a smart grid allows for safer and more reliable connections of distributed generation units such as rooftop solar installations, small natural gas turbines used for heat and electricity in commercial buildings, and building integrated wind systems.[32]

Environmental Benefits/Emissions Reduction Potential[33]

Smart grid technologies reduce GHG emissions in a number of ways. This Climate Techbook entry focuses on three:

  • Increasing efficiency and conservation
  • Enabling renewable energy integration
  • Enabling PEV integration

The Electric Power Research Institute (EPRI) calculates that a national smart grid could reduce annual GHG emissions by 60-211 million metric tons of carbon dioxide equivalent (MMT CO2e) compared to “business-as-usual” by 2030, an amount equal to 2.7-9.6 percent of GHG emissions from electricity generation in 2009.[34],[35]

  • Increasing Efficiency and Conservation

More than half of this potential reduction in GHG emissions would be achieved through energy efficiency and conservation measures enabled by the smart grid, such as:

o   Reducing transmission losses through better management of distribution systems.[36]

o   By having a better understanding of equipment conditions through real-time equipment monitoring, utilities can keep vital components operating at high efficiency.

o   Managing peak-load through demand response instead of spinning reserves.

o   Increasing transparency in electricity prices, helping customers understand the true cost of electricity. The simple act of giving consumers continuous direct feedback on electricity use could reduce annual CO2 emissions by 31-114 MMT CO2e/year in 2030 as consumers adjust their usage in response to pricing and consumption information.[37]

  • Enabling Renewable Energy Integration

EPRI estimated that the increased renewable generation enabled by a smart grid could reduce GHG emissions by 19-37 MMT CO2e /year in 2030.[38] There are two separate components to better renewable integration:

Support for distributed generation

o   Control technologies enable safer and more reliable integration of distributed renewable generation (e.g., rooftop solar)

o   More accurate accounting for distributed generation with advanced meters makes net metering more attractive

Network-wide resilience to variable renewable supply

o   Demand response resources buffer variability in supply[39]

o   PEV integration offers distributed energy storage and ancillary services

o   Better pricing mechanisms and demand side management can reduce transmission congestion, allowing more utility-scale renewable projects to connect to the grid

  • Enabling Plug-in Electric Vehicles

A large source of GHG emissions in the United States is the auto fleet. PEVs can have lower emissions than traditional automobiles with gasoline internal combustion engines. EPRI estimated that the incremental adoption of plug-in hybrid electric vehicles (PHEVs) enabled by a smart grid could result in GHG emission reductions of 10-60 MMT CO2e/year by 2030.[40] A smart grid is needed to integrate PHEVs, and PEVs more generally, without putting intense strain on grid resources.

Smart Charging

With real-time pricing and system-wide price signals, PEV charging can be done primarily during off-peak periods, avoiding reliance on costlier and often more polluting “peaker” plants.

Vehicle-to-Grid (V2G)

PEVs can be used to provide regulation services for the grid instead of relying on fossil fuel generation such as diesel or natural gas generators.


The business case for a smart grid can be separated into costs and benefits for three major stakeholders: utilities, consumers, and society. Unlike some technologies whose primary benefit is direct avoidance of GHG emissions, the smart grid provides a wide array of benefits beyond helping combat climate change, and also indirectly reduces GHG emissions to a large degree by enabling other low-carbon technologies. Moreover, the benefit-cost rationale for smart grid investments is not dominated by GHG emission reductions.

  • Utilities 

Smart grid projects represent large capital expenditures for utilities. For example, an AMI deployment is estimated to have a cost about $70 to $140/meter for residential users and $7 to $15/meter installation cost.[41] As metering components and communications systems become more standardized costs may come down. EPRI estimates that a national smart grid could cost $338 to $476 billion over 20 years, but resulting in $1,294 to $2,028 billion in benefits over the same period.[42] As of May 2011, California’s Pacific Gas and Electric (PG&E) company installed 7.9 million meters at a cost of $2.095 billion.[43] PG&E reports that it has already accumulated $111.3 million in benefits since the start of the transition to smart meters that began in 2007.[44]

  • Consumers

Consumers undoubtedly bear much of the cost of smart grid projects through rate increases. At the same time, consumers who are active in managing their electricity consumption will benefit in the long-run from decreased peak electricity consumption and a lower total cost of energy. A Department of Energy (DOE) smart grid demonstration project in Olympic Peninsula, Washington found that consumers save 10 percent on their utility bills.[45] Consumers also stand to benefit from improved power quality and fewer outages. For example, estimated incremental monthly costs for consumers of providing advanced meters for every household and business vary from $9 to $12 per residential and $60 to $84 per commercial customer,[46] but consumers can benefit from monthly rate savings from greater control over electricity usage.  A benefit to utilities can in turn benefit consumers through rate reductions or reduced rate increases.[47]

  • Society

Society stands to benefit from the environmental benefits, increase in reliability, and other benefits of a smart grid. For example, EPRI estimates that $102 to $390 billion benefits to the environment in terms of lower carbon dioxide emissions from greater electricity system efficiency, and $281 to $444 billion in benefits to society from improved grid reliability.[48]

Current Status

According to National Energy Technology Laboratory (NETL), most of the needed smart grid technologies are commercially available now or are actively being developed.[49] This availability of technology is reflected by the hundreds of AMI projects currently underway across the country.[50] At least 10 different coalitions exist to promote smart grid technologies, conduct R&D, and organize standards and interoperability.[51] The market penetration for advanced meters has also increased, jumping from 1 percent of households and businesses in 2005 to 8.7 percent in 2009.[52] Certain states, such as Arizona, Oregon and Idaho, have reached about 25 percent smart meter penetration.[53] Examples of recent projects include:

  • Southern California Edison, through its SmartConnect program, is planning to install advanced meters for all its household and small business customers (approximately 5.3 million meters) by 2012 and initiate dynamic pricing and demand reduction practices; the efforts are expected to avoid as much as 1 GW of capacity additions and to lower electricity bills for consumers[54], while reducing GHGs per year by 365,000 metric tons.[55] As of July 2011, it has installed more than 2.7 million smart meters.[56]
  • Florida Power and Light has partnered with General Electric (GE), Cisco Systems, and Silver Spring Networks in a $200 million overhaul of 1 million homes and businesses with open-standards, internet-based smart grid system. The system is expected to save customers 10-20 percent on their power bills, with half the cost of the smart grid investments paid by the utility and half by the American Recovery and Reinvestment Act of 2009 (ARRA).[57],[58]
  • PG&E has installed more than 7.9 million meters and reported $111.3 million in benefits since the first smart meter became active in 2007.[59]

Obstacles to Further Development or Deployment

Several obstacles prevent the implementation of a nationwide smart grid:

  • Upfront Consumer Expenses

In the responses of 200 utility managers to a 2009 survey, 42 percent cited “upfront consumer expenses” as a major obstacle to the smart grid.[60]These concerns were confirmed by consumer responses in which 95 percent of respondents indicated they are interested in receiving detailed information on their energy use; however, only 1 in 5 were willing to pay an upfront fee to receive that information.[61] Regulatory approval for rate increases needed to pay for smart grid investments is always difficult, and the receptiveness of regulators varies from state to state.

  • Lack of Standardization

30 percent of utility managers cited “lack of technology standards” as a major obstacle to smart grid deployment.[62] Uncertainty about interoperability and technology standards present the greatest risk to utilities, who do not want to purchase components that will not work with new innovations down the road.[63]

  • Regulatory Barriers

Many of the obstacles to a smart grid are regulatory issues. Electric power is traditionally the regulatory domain of states. The patchwork of regulatory structures and jurisdictions is only loosely coordinated, and final authority on many decisions can be unclear, as projects are subject to multiple levels of review. Local (municipal, county), state-level, and federal jurisdictions overlap, and conflicting decisions can result in regulatory lead times of several years. Some regulatory decisions can also be challenged in court, resulting in more potential delays at each level. This series of delays adds significantly to the cost and regulatory risk of pursuing a smart grid project.

  • Lack of Widespread Understanding

Because smart grid is still a new concept and the technologies that enable it are rapidly evolving, there is misunderstanding amongst consumers, regulators, policymakers, and businesses about what its costs and benefits are. Stakeholders that are generally aligned may reach different conclusions based on a different understanding of the smart grid. As an example of the mistrust of new smart meter technologies, some customers have complained about rate increases after receiving a smart meter, which resulted in a lawsuit against California’s PG&E.[64] The suit has damaged consumer confidence with new technology and prompted California’s PG&E to slow smart meter deployment.[65] Ultimately, the suit was dismissed based on California Public Utilities Commission’s findings that the smart meters are accurate and functioning properly.[66]

Policy Options to Help Promote a Smart Grid

  • Develop National Standards

The 2007 Energy Security Act tasked the National Institute of Standards and Technology (NIST) with developing nationwide standards for smart grid technology in consultation with industry groups, such as the GridWise Alliance, and other standards bodies, such as the Institute of Electrical and Electronics Engineers (IEEE). Because technology risk from changing standards represents the largest risk to utilities, developing and institutionalizing national standards that are available to all players will greatly accelerate development. Standards would cover such technical areas as communication among smart grid devices and security.

  • Provide Federal Funding for Smart Grid

The Energy Independence and Security Act of 2007 (EISA) and the economic stimulus bills of 2008 and 2009 all authorized federal funding for smart grid projects and R&D.[67] The American Recovery and Reinvestment Act of 2009 (ARRA) directs $4.5 billion to modernize the electrical grid.[68] Over 150 smart grid projects[69] have been funded through ARRA as of July 2011. The projects include replacing traditional meters with smart meters, adding monitoring and controlling software to existing electric power infrastructure to enable smart grid features and to conduct consumer behavior surveys to see how consumers react to time-based electricity pricing.[70] In addition, the federal government could provide a direct incentive to utilities in the form of tax credits to accelerate smart grid deployment.

  • Require Greater Reliability

The current grid is 99.97 percent reliable on average, however this varies amongst utilities.[71] Increasing the requirement for grid reliability or establishing performance-based rates that would allow utilities to charge a higher rate for better reliability, would incentivize utilities to invest in new technologies.[72]

  • Develop the National Communications Infrastructure

Many utilities engaged in smart grid projects find that they are spending significant portions of their project costs on communications and IT infrastructure rather than physical smart grid components. Creating a nationwide broadband infrastructure and allowing the smart grid to leverage it could have benefits for both the communications and electric power sectors.

  • Provide for Utility Cost Recovery

Because states bear the primary responsibility for approving smart grid projects and cost recovery for utilities, there is significant disparity in smart grid deployment levels among states. Coupling federal incentives for smart grid with prudent cost recovery at the state level can help to accelerate deployment.

  • Increase Consumer Awareness

Greater educational efforts could be made to inform consumers about smart grid and the environmental impacts of energy use.

Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Climate Change 101: Technology, 2011

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

Wind and Solar Electricity: Challenges and Opportunities, 2009

Further Reading / Additional Resources

SMART 2020: Enabling the Low Carbon Economy in the Information Age, The Climate Group, Prepared for the Global eSustainability Initiative (GeSI), 2008

Edison Foundation , Transforming America's Power Industry: Investment Challenge 2010-2030, 2008  

Electric Power Research Institute (EPRI), The Green Grid: Energy Savings and Carbon Emissions Reduction Enabled by a Smart Grid, 2008 

U.S. Energy Information Administration (EIA), Energy in Brief: What Is the Electric Power Grid, and What Are Some Challenges It Faces?

EPRI, Estimating the Costs and Benefits of the Smart Grid: A Preliminary Estimate of the Investment Requirements and the Resultant Benefits of a Fully Functioning Smart Grid, 2011  

The Electricity Advisory Committee, Smart Grid: Enabler of the New Energy Economy, 2008

Federal Smart Grid Task Force

IEEE, Smart Grid Technology Portal

National Energy Technology Lab (NETL), “The NETL Smart Grid Implementation Strategy”

Smart Grid Information Clearinghouse

[1] PEVs include plug-in hybrid electric vehicles and battery-electric vehicles.

[2] For a useful overview of the electricity grid, see the U.S. Energy Information Administration (EIA), Energy in Brief: What Is the Electric Power Grid, and What Are Some Challenges It Faces?

[3] Jon Wellinghoff, Prepared Testimony of Jon Wellinghoff, Commissioner Federal Energy Regulatory Commission, 2007.

[4] The Smart Grid - An Introduction (U.S. Department of Energy).

[5] Ibid.

[6] U.S. Department of Energy Electricity Advisory Committee. “Smart Grid: Enabler of the New Energy Economy” December 2008.

[7] Power quality is defined as the provision of power with specified voltage and frequency characteristics to the customer. Small imbalances in the sub-minute time frame between electric power supply and demand, and the physical properties of electric power generators, electricity-consuming devices, and the transmission grid itself lead to small deviations (1 to 5 percent) between the expected and actual voltage and frequency of power delivered, which can cause highly sensitive equipment such as computers to fail. When electric power supply and demand are in balance, these deviations in voltage and frequency are eliminated.

[9] Smith, C., Demeo E., Smith, S. “Integrating Wind Generation Into Utility Systems” North American Wind Power. September 2006.

[11] California Governor Issues Executive Order Increasing State RPS. Center for Climate and Energy Solutions. September 2009.

[12] Smart Grid Information Clearinghouse. “Learn More About Smart Grid”. Accessed August 5, 2011.

[13] U.S. Department of Energy National Energy Technology Laboratory. “Smart Grid Principal Characteristics: Enables Active Participation by Consumers”. September 2009.

[14] U.S. Department of Energy National Energy Technology Laboratory. “A Systems View of the Modern Grid – Appendix A1: Self-Heals v2.0” 2007.

[15] Software that monitors the smart grid could automatically sense power fluctuation that could interrupt service and make adjustments without operator intervention. See Smart Grid Information Clearinghouse: distributed intelligent control systems.

[16] U.S. Department of Energy National Energy Technology Laboratory. “Smart Grid Principal Characteristics: Enables New Products, Services, and Markets” February 4, 2010.

[17]SmartGridCity.” Accessed August 11, 2011.

[18]SmartMeterTM – See your power.” Accessed August 11, 2011.

[19]AEP Texas – Smart Meters.” Access August 11, 2011.

[21] Enabling Technologies. Smart Grid Information Clearninghouse. Accessed July 26, 2011.

[22] Electric Power Research Institute. “Advanced Metering Infrastructure (AMI) Factsheet” February 2007.

[23] Department of Energy National Energy Technology Laboratory. “Advanced Metering Infrastructure: Powering our 21st-Century Economy.” February 2008.

[25] National DR Directory. “Demand Response Overview.” Accessed August 5, 2011.

[26] Federal Energy Regulatory Commission. “Assessment of Demand Response & Advanced Metering.” February 2011.

[27] University of Delaware. “The Grid-Integrated Vehicle with Vehicle to Grid Technology.” Accessed August 5, 2011.

[28] Spinning reserve is an ancillary service in the electricity market defined as the ability of (usually a generator) to remain on and ready to start generating given notice over a short period of time (15 minutes to an hour). Regulation refers to an ancillary service (usually provided by electricity generators) to maintain power quality by ramping generation up and down to follow unpredicted minute-by-minute fluctuations in electricity demand.

[29] Smart Grid Information Clearinghouse. “Distribution Automation.” Accessed August 5, 2011.

[30] Distribution automation is the use of intelligence to create automated operational decisions in electric power distribution infrastructure for the purpose of maintaining or restoring power.

[31] Reitenbach, G. “The Smart Grid and Distributed Generation: Better Together.” POWER. April 1, 2011. Accessed August 5, 2011.

[32] Fault tolerance allows distributed generation to “ride through” fault events on the distribution system that would otherwise force it to disconnect and stop producing power. This allows the distributed generation to be connected for a larger amount of time and provide a better return on investment for the investor. Islanding detection refers to the ability of utilities to detect unintentional islanding (or parallel operation) of distributed generation systems, which can result in poor power quality, be harmful to equipment and dangerous for electricians. Island operation occurs if one or more distributed generators continue to energize a part of the grid after the connection to the rest of the system has been lost, this can be dangerous to utility workers, the generation equipment itself, and other equipment connected to the grid.

[33] U.S. Department of Energy National Energy Technology Laboratory. “Environmental Impacts of Smart Grid.” January 10, 2011.

[34] The Green Grid - Energy Savings and Carbon Emissions Reduction Enabled by a Smart Grid, Technical Update (Electric Power Research Institute (EPRI), June 2008), 1016905.

[35] Environmental Protection Agency, 2011, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009. Table 2-13.

[36] Greater information availability about distribution systems will allow utilities to make better decisions about maintenance and operations. The information allows utilities to make informed decisions about field equipment.

[37] The Green Grid, EPRI 2008.

[38] The Green Grid, EPRI 2008.

[39] Wind and solar power are both variable electricity generation technologies insofar as they only generation power when the wind is blowing or the sun is shining, respectively.

[40] The Green Grid, EPRI 2008.

[42] Ibid

[43] SmartMeterTM Steering Committee Update. Pacific Gas and Electric Company. May 2011. Accessed July 26,2011.

[44] Ibid.

[45] A Smart Grid: Cost Reduction. 2011. Accessed August 10, 2011.

[46] EPRI 2011.

[47] Ibid.

[48] Ibid.

[49] Compendium of Modern Grid Technologies, NETL Modern Grid Strategy, July 2009.

[50] Smart Grid Projects. Smart Grid Information Clearinghouse. Accessed July 2011.

[52] Assessment of Demand Response & Advanced Metering. Federal Energy Regulatory Commission. February 2011.

[53] FERC 2011.

[54] Amy Abel, “Smart Grid Provisions in H.R. 6, 110th Congress”, Congressional Research Service, Dec 2007

[55] Edison SmartConnectTM: Benefits to You. Southern California Edison. Accessed July 22, 2011.

[56] Edison SmartConnectTM: About Edison SmartConnectTM. Southern California Edison. Accessed July 28, 2011.

[58] Open standards, as opposed to proprietary standards, allow any firm to develop devices or applications that interface with a system rather than limiting a system, such as the smart grid or a component thereof, to devices and applications from a single or limited set of firms. Open standards are thought by many to be more conducive to innovation and flexibility.

[59] SmartMeterTM Steering Committee Update. PG&E 2011.

[60] Turning Information Into Power, Survey (Oracle, March 2009).

[61] Oracle 2009.

[62] Oracle 2009.

[63] Barriers to Achieving the Modern Grid, NETL Modern Grid Initiative, June 2007.

[64] See Flores v. Pacific Gas and Electric. Kern County Superior Court of California, case number S-1500-CV-268647.

[65] PG&E Sued Over Smart Meters, Slows Down Bakersfield Deployment. Greentech Grid. November 11, 2009. Accessed July 28, 2011.

[66] SmartMeterTM Updates: Lawsuit Dismissed; Final CCST Report Issued. PG&E Currents. April 18, 2011. Accessed July 28, 2011.

[67] The stimulus bills are the Economic Stimulus Act of 2008 and the American Recovery and Reinvestment Act of 2009.

[68] Overview. Accessed on July 25, 2011.

[70] Smart Grid Investment Grant (SGIG) Program Asset Investment. U.S. Department of Energy. June 10, 2011. Accessed July 28, 2011.

[71]In addition to raising the reliability standard from 99.97 percent, the minimum outage duration counted against reliability could be lowered. Currently, reliability standards ignore outages of less than 5 minutes.

[72] Policy Framework for a Consumer-Driven Electric Power System. Perfecting Power. Galvin Electricity Initiative. January 2010. 


Technology to improve the reliability, reduce the costs, and increase the efficiency of the electricity grid

Technology to improve the reliability, reduce the costs, and increase the efficiency of the electricity grid

Wind Power

Quick Facts

  • Wind currently provides about 2.3 percent of America’s electricity.[1]
  • Wind power was 26 percent of all U.S. electricity generation capacity added in 2010.[2]
  • The U.S. Department of Energy found that generating 20 percent of U.S. electricity from wind by 2030 would avoid 825 million metric tons of carbon dioxide (CO2) in 2030, a 25 percent reduction relative to a no-new-wind scenario.[3]
  • The levelized cost of electricity generation[4] (including tax incentives) from a new wind farm can range from around 6-11 cents per kilowatt-hour (kWh).[5] Actual costs for wind power projects will vary depending on project specifics, and the cost of wind power is sensitive to tax incentives.


Wind power harnesses the energy generated by the movement of air in the earth’s atmosphere to drive electricity-generating turbines. Although humans have used wind power for hundreds of years, modern turbines reflect significant technological advances over early windmills and even over turbines from just ten or twenty years ago.

Wind resource potential varies significantly across the United States with substantial resources found in the Midwest and along the coasts (see Figure 1).

Winds generally blow more consistently and at higher speeds at greater heights. As wind speed increases, the amount of available energy increases following a cubic function,[6] so a 10 percent increase in speed corresponds to a 33 percent increase in the amount of available energy.[7] Modern turbines continue to grow larger and more efficient--two important factors that allow a single turbine to produce more usable energy.  Improved materials and design have allowed for larger rotor blades and overall improvements in efficiency (measured as total energy production per unit of swept rotor area,[8] given in kilowatt-hours per square meter) and greater gross generation.

Figure 1: Wind resource potential at 50 meters (164 feet) above ground

Source: NREL[9]


Wind technologies come in a variety of sizes (larger turbines can generally produce more electricity), and styles. Since wind is a variable and uncertain resource, wind turbines tend to have lower capacity factors than conventional power plants that provide most of the nation’s energy. A power plant’s “capacity factor” provides a measure of its productivity by comparing its actual power production over a given period of time with the amount of power the plant would have produced had it run at full capacity over that period. Conventional coal- and gas-fired power plants generally have capacity factors between 40% to 60%.[10],[11] Wind turbines generally have capacity factors that are closer to 25 to 40 percent.[12]  Wind turbine capacity factors have improved over time with advances in technology and better siting, but capacity factors are fundamentally limited by how much the wind blows.

Technologies to harness wind power can be classified into a number of broad categories:

  • Offshore wind

Offshore wind technology has yet to reach full commercial scale and remains a relatively expensive technology. Even so, projects do exist and more are planned. Offshore wind installations could take advantage of higher sustained wind speeds at sea to increase electricity output by 50 percent compared to onshore wind farms.[13]

  • Onshore, utility-scale turbines

A modern utility-scale wind turbine generally has three blades, sweeps a diameter of about 80-100 meters, and is installed as part of a larger wind farm of between 30 and 150 turbines.[14] An individual wind turbine can have a generation capacity of up to 3.0 megawatts (MW).[15]

  • Onshore, Small Wind

The National Renewable Energy Laboratory defines “small wind” as projects that are less than or equal to 100 kilowatts, which are much smaller than utility-scale turbines.[16]  These systems provide power directly to private residential properties and farms, businesses, industrial facilities, and schools. Small turbines can be utility grid connected or coupled with diesel generators, batteries, and other distributed energy sources for remote use where there is no access to the grid.[17]

As of 2011, are 27 domestic small wind manufacturers operating in the United States.[18] In the past 5 years, there has been a trend towards installing grid-connected small wind turbines with greater capacity.[19] For example, sales of turbines smaller than 1 kW capacity were stable or declined from 2006 – 2011, while sales of 1 – 10 kW and 11 – 100 kW grew four and five-fold, respectively.  While capacity additions were steadily increasing each year from 2005 to 2010, there was a 26 percent decline in 2011 from the previous year, returning to 2009 levels of capacity sales.[20]  The brief decline has been attributed to a downturn in the general U.S. economy as well as inconsistent state policies, with several states suspending programs in 2011.[21] In 2011, domestic sales of small wind reached 33 MW – a 13 percent increase over 2010.[22]

Small wind’s growth trend is likely the result of an assortment of state policies, with 2011 reporting over $38 million in tax credits, rebates, grants, and low-interest loans – a 27 percent increase from 2010.[23] 35 states offered some form of rebates, tax credits, or grants for renewable energy sources that could be applied to small wind, including the New York State Energy Research and Development Authority (NYSERDA).[24] While only three states have a specific incentive policy for small wind,[25] including Oregon’s Small Wind Incentive Program[26], more than 25 states offered cash incentives and grants that covered small wind investments.[27] 16 states offered state-wide net-metering, which encourages investment by providing compensation when offsite electricity production exceeds private usage and enters the grid. Finally, 38 states and the District of Columbia have some form of policy that requires a certain percentage of electricity to be from renewable sources, called a Renewable Portfolio Standard (RPS).[28] Many states, including Pennsylvania, allow for distributed energy contributions to RPS fulfillment.[29]

Additional federal government programs contribute to the growth of small wind capacity. In the Wind for Schools program, the Department of Energy funded 33 small wind turbines on educational buildings in 2011.[30] Moreover, a 30 percent Investment Tax Credit for small wind turbines (in effect until December 31, 2016) remained important in 2011, while the U.S. Department of Agriculture provided support to over 200 small wind installations in 30 states, totaling 5.8 megawatts (MW) through the Rural Energy for America Program (REAP).[31]

Table 1. Annual Sales of Small Wind Turbines (? 100 kW) in the United States


Number of Turbines

Capacity Additions

Sales Revenue



3.3 MW

$11 million



8.6 MW

$36 million



9.7 MW

$43 million



17.4 MW

$74 million



20.4 MW

$91 million



25.6 MW

$139 million



19.0 MW

$115 million

Source: EERE,

Environmental Benefit / Emission Reduction Potential

Wind power generates almost no net greenhouse gas emissions. Although electricity generation from wind energy produces no greenhouse gas emissions, the manufacture and transport of turbines produces a small amount. Compared to conventional fossil fuel sources, wind energy also avoids a variety of environmental impacts, such as those pertaining to mining, drilling, and air and water pollutants.[32]

  • Emissions reduction potential in the United States

The U.S. Department of Energy found that generating 20 percent of U.S. electricity from wind by 2030 would avoid 825 million metric tons of carbon dioxide (CO2) annually in 2030, a 25 percent reduction relative to a no-new-wind scenario.[33] This also represents a cumulative CO2 emissions reduction of more than 7,600 million metric tons by 2030.

  • Emissions reduction potential globally

The International Energy Agency’s aggressive technology scenario for reducing GHG emissions included a significant role for wind power—i.e., 1.5 to 4.8 gigatons of annual GHG abatement compared to “business-as-usual,” or 4 percent of total abatement from energy use, and about 12 percent of global electricity production in 2050.[34]


The cost of wind power has fallen significantly over the past few decades.[35] In 1981, the cost of generating electricity from a 50-kW capacity wind turbine was around 40 cents per kWh. Technological and efficiency improvements (such as longer and stronger turbine blades from new advanced materials and designs) allow today’s turbines to produce 30 times as much power at a much lower cost.[36] Technological improvements have the potential to further drive down costs over time.

Wind is cost-competitive with traditional power generation technologies in some U.S. regions.  Recent analyses estimate the levelized cost of electricity[37] generation from a new wind power project to be 6-11 cents per kWh.[38] These costs, however, depend on project specifics (such as the wind turbines’ capacity factor) and are sensitive to the inclusion of tax incentives for wind power. For example, the Federal Production Tax Credit for wind power lowers the levelized cost of electricity generation from wind by roughly 2 cents per kWh.[39] Recent estimates for the levelized cost of electricity generation from new coal-fueled generation run from 6.4 cents per kWh to 9.5 cents per kWh.[40],[41] Similar estimates for the levelized cost of electricity from a natural gas combined cycle plant are in the range of 6.9 to 9.6 cents per kWh.[42]

At present, offshore wind turbines are approximately 50 percent more expensive than onshore installations, yet they produce about 50 percent more electricity due to higher wind speeds.[43]

Current Status of Wind

Wind capacity is growing fast and accounts for the largest share of added renewable energy capacity over the last several years.[44] Cumulative global wind capacity has grown at approximately 26 percent per year since 2003.[45]

  • Wind in the United States

Wind currently provides about 2.3 percent of America’s electricity, but this relative share is growing quickly. Twenty-six percent of all electricity generation capacity added in the United States in 2010 was wind power,[46] while it accounted for 39 percent in 2009.[47] The amount of electricity generated from wind in the United States increased by 61 percent between 2007 and 2008[48] and by 28 percent between 2008 and 2009.[49]  In 2010, United States dropped to second globally in terms of installed wind power capacity (40.2 gigawatts (GW)) after China more than tripled its installed capacity since 2008 (12 GW to 44.7 GW by the end of 2010).[50]

In February 2011, the Departments of Energy and the Interior released A National Offshore Wind Strategy: Creating an Offshore Wind Industry in the United States, calling for the deployment of 54 GW of offshore wind capacity by 2030, with 10 GW of offshore wind capacity by 2020 as an interim target.[51]  Offshore wind projects in Massachusetts and New Jersey could begin construction in 2011, and several other coastal states are in the process of approving possible projects.

  • Wind at a global scale

Since 1996, global installed wind power capacity has grown by a factor of 32,[52] reaching 197.0 GW in 2010,[53] which could meet approximately 2.5 percent of global electricity demand in 2010.[54] The United States accounts for about 20.4 percent of installed global wind power capacity.[55]

Even assuming no new policy interventions – such as renewable portfolio standards or carbon emissions constraints – wind will continue to grow quickly, with installed capacity expected to quintuple in size by 2035.[56] Though some projections estimate it could account for as little as 5 percent of global electricity production in 2035, this share could be as high as 13 percent if policies are put in place to aggressively reduce greenhouse gas emissions and spur technological developments in renewable energy.[57]

A number of offshore wind farms are currently in operation or development globally. The United Kingdom has the world’s largest offshore capacity (1,341 MW), followed by Denmark (854 MW). Additional offshore wind projects in Europe and China began electricity generation in 2010.[58]  The London Array, the world’s largest offshore development, is expected to have a capacity of 1,000 MW.[59]

Obstacles to Further Development or Deployment of Wind

A number of factors pose barriers to the further development of wind resources.

  • Variability and uncertainty

Wind power is inherently variable and uncertain due to weather factors, since winds vary in strength and sometimes do not blow at all. Wind power is uncertain insofar as wind speeds can be forecast with only limited accuracy. These issues can be overcome to some extent by developing better wind forecasting methods and addressing electricity grid interconnection issues between regions. The U.S. DOE estimates that the U.S. could generate 20 percent of its electricity from wind without any new energy storage.[60] To achieve even higher levels of generation, wind power will require enabling technologies such as energy storage and demand-response. Storage options for wind energy include pumped hydroelectric storage, compressed air energy storage, hydrogen, and batteries.[61]

  • Geographic distribution and transmission

Wind resources are unevenly distributed and many of the best wind resources are located far from the population centers that require electricity. New transmission infrastructure is necessary to bring electricity generated by wind resources in remote areas to end users.

  • Siting issues

Related to issues over geographic distribution of wind resources, siting of wind power projects can face opposition from local communities who see wind farms as a form of visual pollution that spoils views and property or have concerns about the potential impacts of the wind farm on wildlife (especially birds and bats) and habitat.

  • Investment uncertainty

Recent wind power growth rates in the United States have been volatile – largely driven by the cycle of lapses and reinstatements of tax policy support, namely the Federal Production Tax Credit. Such uncertainty hurts investment in wind power projects.

Policy Options to Help Promote Wind

  • Price on carbon

A price on carbon would raise the cost of electricity produced from fossil fuels, making wind power more cost-competitive.[62]

  • Tax credits and other subsidies

Stabilizing Federal Production Tax Credit cycles can help sustain investment and growth in wind power (for example, by putting into place incentive programs with longer periods before required Congressional renewal). Other forms of assistance include grant programs and loan guarantees to wind power project developers.

  • Renewable portfolio standards

A renewable portfolio standard (RPS), sometimes called a renewable or alternative energy standard, requires that a certain amount or percentage of a utility’s power plant capacity or generation come from renewable sources by a given date. At present, 29 U.S. states and the District of Columbia have adopted an RPS, while 8 U.S. states have renewable portfolio goals.[63] RPSs encourage investment in new renewable generation and can guarantee a market for this generation. States and jurisdictions can further encourage investment in specific resources, such as wind power, by including a “carve-out” or set-aside in an RPS, as is the case in Illinois, Minnesota, and New Mexico.

  • Development of new transmission infrastructure

One of the greatest barriers to investment in new renewable generation and tapping the full potential of resources such as solar and wind is the lack of necessary electricity transmission infrastructure. While estimated wind and solar resources are vast, frequently the areas with the most abundant concentrations of these resources are remote and far removed from end-users of electricity. Policies that promote the build-out of new electricity transmission lines allow access to these resources and can provide additional incentives for utilities to invest in them.

Related Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Climate Change 101: State Action, 2011

Wind and Solar Electricity: Challenges and Opportunities, 2009

Further Reading / Additional Resources


American Wind Energy Association (AWEA)

Congressional Research Service

InterAcademy Council, Lighting the Way: Toward a Sustainable Energy Future, 2007

International Energy Agency (IEA), Energy Technology Perspectives 2010: Scenarios and Strategies to 2050, 2010 

 “Levelized Cost of Energy Analysis Version 3.0” Lazard, June 2009

U.S. Department of Energy (DOE)



[1] American Wind Energy Association. 2010 U.S. Wind Industry Market Update. Accessed 19 July 2011

[2] AWEA 2011.

[3] U. S. Department of Energy (DOE). 20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply. 2008.

[4] 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. The levelized cost does not include costs associated with transmission and distribution of electricity. For all resources, levelized cost estimates vary considerably based on uncertainty and variability involved in calculating costs for electricity.  This includes assumptions made about the size and application of the system, what taxes and subsidies are included, location of the system, and others.

[5]  Lazard. “Levelized Cost of Energy Analysis – Version 3.0” presentation by Lazard, June 2009. Accessed 19 July 2011.

[6] The power (P) available in the area swept by the wind turbine rotor can be calculated using the following equation: P (in Watts = J/s = (kg*m2)/s3))= 0.5 * (air density, ~1.225 kg/m3) * (area of rotor in m2) * (wind speed in m/s) 3. The 33 percent increase in power from a 10 percent increase in speed can be illustrated using a sample calculation (simplifying the equation to represent the first three variables on the left, which are simply multipliers, as X). At 10 meters per second (m/s), P = X*(10)3 = 1000X. If we increase the wind speed by 10 percent, to 11 m/s, P = X*(11)3 = 1331X. Windspeed has increased 10 percent, and available power has increased by 33 percent.

[7] DOE 2008. 

[8] This is the area covered by the rotor blades as they make a rotation. More efficient turbines produce more energy for a given amount of area covered.

[9] National Renewable Energy Laboratory (NREL). “U.S. Wind Resources Map.” Accessed 20 July 2010.

[10]  American Wind Energy Association (AWEA). “Wind Web Tutorial.” Accessed 19 July 2011.

[11] Note that natural gas power plants have lower capacity factors not due to technical limitations but because they are used for load-following and intermediate load duty rather than baseload generation, which is what coal plants are typically used to provide.

[12]  AWEA 2011.

[13] International Energy Agency (IEA), Energy Technology Perspectives 2010: Scenarios and Strategies to 2050. Paris: IEA, 2010.

[14].Vestas. “Turbine overview.” Accessed 20 July 2011.

General Electric.”Wind Turbines” Accessed 20 July 2011.

[15] Ibid.

[17] The DOE provides a range of small wind resources at

[18] American Wind Energy Association (AWEA), 2011 U.S. Small Wind Turbine Market Report (2012),

[19] American Wind Energy Association (AWEA), 2011 U.S. Small Wind Turbine Market Report (2012),

[20] DOE EERE, Wind Technologies Market Report, 2011.

[21] DOE EERE, Wind Technologies Market Report, 2011.

[22] AWEA, 2012.

[23] Reported assistance for 2010 was $30 million, AWEA, 2011.

[24] AWEA, 2012.

[25] DSIRE Database, Incentives/Policies for Renewables & Efficiency,

[27] One fifth used funds from the American Recovery and Reinvestment Act (ARRA) as a primary or secondary source, AWEA, 2012.

[29] Pennsylvania Utility Commission, Alternative Energy,

[30] AWEA, 2012.

[31] AWEA, 2012; DOE EERE, Wind Technologies Market Report (2011),

[32] DOE 2008. 

[33] Ibid.

[34] IEA 2010, BLUE Map scenario.

[35] IEA 2010.

[36] Schiermeier Q., J. Tollefson, T. Scully, A. Witze, and O. Morton. “Electricity Without Carbon.” Nature 454 (2008): 816-822.

[37] See endnote 4.

[38] Lazard 2009.

[39] The PTC is currently 2.2¢/kWh, however one cannot simply add 2.2¢/kWh to cost estimates to yield a cost without the PTC, as the PTC is limited to 10 years and is furthermore not available to all investors.  The analysis is further complicated by the 2009 stimulus bill, which extended the PTC and provided the option of an investment tax credit in lieu of the PTC.  Nonetheless, a rough estimate is that the non-PTC price would be 2 cents per kWh higher than the PTC price.  The in-service deadline for the PTC is December 31, 2012.

[40] These, again, are levelized costs of generation, and do not include transmission and distribution costs.

[41] Low estimate taken from Logan, Jeff and Stan Mark Kaplan, Wind Power in the United States: Technology, Economic, and Policy Issues, Congressional Research Service, June 2008, see High estimate comes from communication with Jeffrey Jones (Energy Information Administration) regarding the levelized cost of electricity generation in the Annual Energy Outlook 2009.

[42] Lazard 2009.

[43] IEA 2010.

[44] Renewable Energy Policy Network for the 21st Century. Renewables 2011 Global Status Report. 2011.

[45]  Global Wind Energy Council (GWEC). Global Wind Report – Annual market update 2010. 2011.

[46] AWEA July 2011

[47] American Wind Energy Association. AWEA U.S. Wind Industry Annual Market Report Year Ending 2009. 2010.

U.S. Energy Information Administration (EIA). Monthly State Electricity Data available online at

[49] Ibid.

[51] U.S. Department of the Interior. “Overview: National Offshore Wind Strategy.”

[52] GWEC. 2011.

[53] GWEC. 2011.

[54] World Wind Energy Association. World Wind Energy Report 2010. 2011.

[55] GWEC 2011.

[56] International Energy Agency (IEA), World Energy Outlook (WEO) 2010. Paris: IEA, 2010.

[57] IEA WEO 2010.

[58] Global Wind Energy Council (GWEC). Global Wind Report – Annual market update 2010. 2011

[59] International Energy Agency (IEA), Energy Technology Perspectives 2008: Scenarios and Strategies to 2050. Paris: IEA, 2010.

[60] DOE 2008.

[61] InterAcademy Council (IAC), Lighting the Way: Toward a Sustainable Energy Future. Amsterdam: IAC, 2007.

[62] “The Future of Energy.” The Economist, 19 June 2008.

[63] Database of State Incentives for Renewables & Efficiency (DSIRE). “Summary Maps” Accessed 22 July 2011.


Small- and large-scale wind turbines can be used to harness the wind's power

Small- and large-scale wind turbines can be used to harness the wind's power

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.

Medium- and Heavy-Duty Vehicles

Quick Facts

  • Medium-duty vehicles (MDVs) have a vehicle weight of 10,000 to 26,000lbs. Heavy-duty vehicles (HDVs) have a vehicle weight over 26,00lbs.
  • Medium- and heavy-duty trucks and buses are responsible for about 16 percent of total transportation energy use and nearly 18 percent of carbon dioxide (CO2) emissions from transportation.
  • Under a business-as-usual (BAU) scenario, energy consumption by trucks is predicted to grow more rapidly than other transportation modes over the next 25 years.
  • Studies show that technologies to decrease fuel consumption can have a measurable impact on both short- and long-term fuel use and GHG emissions.
  • The U.S. Environmental Protection Agency and the National Highway Traffic Safety Administration (NHTSA) recently proposed a set of complementary CO2 emission and fuel consumption standards, the first regulation of this type in the U.S. for medium- and heavy-duty vehicles.


Although the exact labels sometimes differ, medium-duty vehicles (MDVs) are those vehicles with a gross vehicle weight of 10,000 to 26,000 pounds. The largest of this group (Class 6 trucks) are also referred to as medium heavy-duty trucks.[1] Heavy-duty vehicles (HDVs) have a gross vehicle weight over 26,000 pounds.

The U.S. Department of Transportation (DOT) uses the following system of vehicle classes to group light-, medium-, and heavy-duty vehicles. This classification system is based on Gross Vehicle Weight Rating (GWVR), which is the weight of the vehicle while empty plus the maximum allowed weight from a cargo load.

Table 1: Description of Vehicle Weight Classes

Size Class

Gross Vehicle Weight Rating (GWVR)

Vehicle Registration



Class 1 and 2

Less than 10,000 lb


Light-duty vehicle, most have gasoline engines, most are for personal use

 Pickups, small vans, SUVs

Class 3

10,001 – 14,000 lb


Medium-duty vehicle, gasoline or diesel engine, single rear axle, commercial use

Delivery trucks, ambulances, small buses

Class 4

14,001 – 16,000 lb


Class 5

16,001 – 19,500 lb


Class 6

19,501 – 26,000 lb


Class 7

26,001 – 33,000 lb


Heavy-duty vehicle, gasoline or diesel engine, two or more rear axles, commercial use

Tractor trailers, school and transit buses, refuse trucks

Class 8*

33,001 – 80,000 lb


Heavy-duty vehicle, almost all have diesel engines, two or more rear axles, commercial use


* Class 8 is divided into two sub-groups: class 8a, which includes dump and refuse trucks, fire engines and city buses, and class 8b, which consists of tractor-trailers. A tractor is defined as a highway vehicle that is designed to tow a vehicle, such as a trailer or semitrailer. The majority of Class 8 vehicles are Class 8b tractor-trailers (1,720,000 registered vehicles in 2006).

Source: National Research Council (NRC), Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles, 2010.

Unlike light-duty vehicles, the majority of which are for personal use, there is a range of uses for medium- and heavy-duty vehicles in all sectors of the economy. Some carry passengers, such as urban transit buses, while others move goods across the country. Some vehicles are used primarily on high-speed highways with few stops, while others operate on lower speed urban roads in stop-and-go traffic. The top three uses for medium- and heavy-duty vehicles are construction, agriculture, and “for hire” or transportation of freight.[2] (See also Climate Techbook: Freight Transportation.)

The manufacture and distribution of medium- and heavy-duty vehicles is dependent on a network of suppliers, subcontractors, and other service industries. For example, a major vehicle manufacturer makes the chassis and powertrain,[3] but a separate body or equipment builder determines the final vehicle configuration. The fuel consumption of a medium- or heavy-duty vehicle depends on the decision made by these different actors over the production process. This approach is used for vehicles such as school buses, utility trucks, and delivery trucks and is unlike the manufacture of light-duty vehicles, where automakers are responsible for virtually all aspects of vehicle design (although many parts are manufactured by outside suppliers).

Sales of medium- and heavy-duty vehicles have declined by 30 percent, over a five-year period from 2004 to 2009, although the percent changes differ by size class.[4] This decline can be attributed to the economic downturn and more stringent diesel emission requirements. For example, sales of Class 8 trucks, which have the highest yearly sales among medium- and heavy-duty vehicles, dropped by nearly 50 percent from 2006 to 2007. This change can partly be attributed to an increase in vehicle price due to new emission control devices, which also lowered engine efficiency. The decrease in new engine efficiency may make it difficult for truck owners to upgrade if fuel prices increase, unless future engines can become more energy efficient and comply with emission control requirements at the same time.Sales for Class 8 vehicles continued to decrease in 2008, although to a lesser extent, in part due to the economic recession.[5]

Energy Use and Emissions

Medium- and heavy-duty trucks and buses are currently responsible for about 16 percent of total transportation energy use (4,525.5 trillion Btu) and nearly 18 percent of the carbon dioxide emissions from transportation in 2009.[6] Although class 8 trucks are only 42 percent of the heavy- and medium-duty truck fleet, they account for most of the fuel consumed (78 percent).[7]

Figure 1: Annual Range in Vehicle Fuel Consumption (gal), by size class

Source: NRC, Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles, 2010.

Figure 2: Total Energy Use (trillion Btu) by Mode, 2009

Source: U.S. Department of Energy (DOE) Energy Information Administration. Annual Energy Outlook, 2011.

From 1970 to 2003, energy consumption by heavy trucks grew at a rate of 3.7 percent annually. In comparison, passenger car energy consumption grew 0.3 percent annually over the same period. The divergence in growth rates is a function of a faster increase in miles driven and, to a smaller extent, improvements in car fuel economy. However because medium- and heavy-duty vehicles are designed to move goods, a more accurate measure of truck efficiency is in terms of the energy used to move a ton of goods over a given distance – for example, gallons of diesel or gasoline per ton-mile. From 1975 to 2005, fuel consumption per ton shipped over a given distance (per ton-mile) has decreased by more than half; the rate of improvement has slowed since then, in part due to pollution control requirements that have reduced engine efficiency.[8]

Under a BAU scenario, energy use by medium- and heavy-duty freight trucks is predicted to grow over the next 25 years than other transportation modes.

Figure 3: Average Annual BAU Growth in Energy Use by Mode, 2009-2035

Source: U.S. DOE Energy Information Administration. Annual Energy Outlook 2011.

A study by the National Academy of Sciences found that the best way to calculate fuel consumption for medium- and heavy-duty vehicles is to use load-specific fuel consumption (LSFC), which is measured in gallons of fuel per load-tons per 100 miles. There is an inverse relationship between load-specific fuel consumption and load: generally the higher the load the vehicle carries, the lower the LSFC.[9] As mentioned previously, trucks and buses are load-carrying vehicles with fuel consumption depending on the weight of the load being carried. A loaded HDV can weigh more than double the empty weight of the vehicle. In comparison, a loaded light-duty vehicle weighs only 25 to 35 percent more than its empty weight.[10] Thus, the day-to-day fuel consumption of a HDV can vary significantly, depending on the load being carried.

Technologies to Reduce Fuel Consumption

There is a range of technologies to reduce fuel consumption in medium- and heavy-duty vehicles. The specific technologies used will depend on vehicle size, type, and use.

Powertrain technologies: The powertrain is a group of components that includes the vehicle engine and transmission. The following powertrain technologies can be used to lower fuel consumption:

  • Diesel engines: Diesel engines used in MDV and HDVs are highly efficient, turbocharged, direct fuel injected, and electronically controlled. Nevertheless there are a number of technologies that be used to reduce fuel consumption, such as dual turbochargers[11] used in a series configuration and variable-valve actuation.[12]
  • Gasoline engines: Gasoline engines are used in Class 2-6 vehicles. These engines can benefit from technologies to reduce fuel consumption: variable-valve actuation and cylinder deactivation,[13] direct injection, turbocharging and downsizing, and electrically driven accessories (rather than mechanically). With some changes, these engines can be configured to use natural gas, propane, hydrogen, ethanol, methanol, and other lower-carbon intensity fuels.[14]
  • Transmission improvements: Transmission improvements include designs that increase the efficiency of the transfer of power from the propulsion system to the wheels (e.g., automated manual transmissions, Lepelletier transmissions) and designs that allow the engine to operate at higher efficiencies (e.g., increases in the number of speeds, continuously variable transmissions).
  • Hybrid powertrains: There are two main types of hybrid technologies that can be used in medium- and heavy-duty vehicles. The first, a hybrid electric, uses an electric motor and generator, an energy storage device and power electronics, as well as an internal combustion engine. Hybrid electric vehicles are use across almost all weight classes, from light-, medium-, and heavy-duty vehicles. Since they provide little benefit at steady highway cruising, they are not as useful for long-haul trucks. The second, a hydraulic hybrid, has a hydraulic system using pressurized fluid, instead of electric power, as an additional power source alongside the engine. The hydraulic system is suitable for vehicles such as refuse trucks, transit buses, and delivery vehicles, which operate in stop-and-go traffic.[15] The fuel consumption benefits of these technologies will depend on the vehicle use and duty cycle.

Alternative fuels: Lower-carbon fossil fuels, including natural gas and biodiesel blends, can reduce conventional air pollutants as well as GHG emissions in medium- and heavy-duty vehicles.

Box 1: The U.S. Department of Energy's Clean Cities Program recommends the following currently available fuel and powertrain alternatives by vehicle type

Vehicle Type


School Bus

Compressed natural gas (CNG) or propane is the most popular. Hybrid electric and plug-in electric hybrids are also available

Shuttle Bus

CNG, propane, hybrid electric power, and fuel cells

Transit Bus

Hybrid-powered transit buses, CNG and liquefied natural gas (LNG). There are some fuel cell demonstrations currently in progress.

Refuse Truck

CNG, Biomethane from landfill gas. Good application for hybrids, particularly hydraulic hybrid systems, because of stop-and-go operation.


Diesel electric hybrids (but not for long-haul trucks), CNG and LNG operation available for some models


Hybrids and plug-in hybrids. Vans that run on a set route (e.g., package delivery service) are well suited for all-electric. CNG and propane are also available.

Vocational Truck

CNG, propane, all-electric, and hybrid vehicles

Source: U.S. DOE. “Clean Cities’ Guide to Alternative Fuel and Advanced Medium- and Heavy-Duty Vehicles.” Accessed 16 May 2011.

Other technologies and techniques to improve vehicle fuel economy include the following:

  • Aerodynamics: Techniques that reduce aerodynamic drag improves fuel efficiency by reducing the amount of work needed to move the vehicle. For example, a heavy-duty truck (tractor-trailer) operating on uncongested highways can save about 15 to 20 percent in fuel consumption from aerodynamic improvements. [16]
  • Rolling resistance: About one-third of the power required to propel a Class 8 truck (at highway speeds, on level roads) can be accounted for by tire rolling resistance. Low rolling resistance tires could reduce the fuel consumption in these vehicles by 4 to 11 percent and to a lesser extent for other size classes.[17]
  • Operational measures: Operational measures include more fuel-efficient driving techniques and idle reduction. For tractor-trailers, these can reduce fuel consumption by an estimated 7 percent.[18]

Box 2: Efficiency Improvements for Tractor-trailers

Although tractor trailers (Class 8 trucks) already have highly efficient diesel engines, there remain potential improvements in engine design (highlighted above) that can help reduce fuel consumption. Reduction in aerodynamic drag can be obtained from better cab shaping, replacing mirrors with cameras, closing the gap between cab and trailer, and adding a short boat-tailed rear. Other methods to reduce fuel consumption include: improving freight logistics and driving techniques, using higher capacity trucks, reducing truck idling, and improving product packaging so products need less space and more products can be carried in one trip. One importance means of reducing truck idling is the use of cab heaters and other devices that allow drivers to sleep in the truck while parked without having to run the main engine.

Source: Greene, D. and S. Plotkin. Reducing Greenhouse Gas Emissions from U.S. Transportation, 2011.

GHG Reduction Potential

A study by National Academy of Sciences evaluated a wide range of technologies and estimated the potential fuel consumption reduction when applied to six different medium- or heavy-duty vehicles. The study estimated that fuel consumption from tractor-trailers (Class 7 and class 8 trucks) could be cost-effectively reduced by 51 percent in the 2015 to 2020 time frame.[19]

Table 2: Fuel Consumption Reduction and Cost-Effectiveness for New Vehicles in 2015

Vehicle Class

Fuel Consumption Reduction (%)

Capital Cost ($)

Breakeven Fuel Price ($/gal)





Class 6 box truck*




Class 6 bucket truck*




Refuse truck




Transit bus




Motor coach





* A box truck has a “box-shaped” cargo area; a bucket truck has an aerial work platform with a bucket that uses a hydraulic lifting system.

Source: NRC. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles, 2010.

A joint study by the Northeast States Center for a Clean Air Future and the International Council on Clean Transportation found similar results. In that case, fuel consumption for new tractor-trailers could be reduced by 20 percent and up to 50 percent from 2012 to 2017. Over the long term, this would reduce fuel consumption and CO2 emissions from these trucks by 30 percent in 2022 from BAU levels and 39 percent by 2030.[20]

Policy Options

Vehicle Standards: In October 2010, the U.S. Environmental Protection Agency (EPA) and the National Highway Traffic Safety Administration (NHTSA) proposed a set of complementary standards as part of the “Heavy-Duty National Program.” The EPA expects to issue the final rule in August 2011. The program includes CO2 emission standards and fuel consumption standards, proposed by EPA and NHTSA respectively. The standards cover model years 2014 to 2018 and would apply to any vehicle with a gross vehicle weight at or above 8,500lbs: tractor-trailers, heavy-duty pickup trucks and vans, and vocational vehicles, which include buses and refuse and utility trucks. The standards use a load-based metric to account for the fact that these vehicles are used primarily for transporting goods and equipment, in addition to passengers, and thereby use more fuel and emit more CO2 when compared to moving lighter loads.

For tractor-trailers, the CO2 emission and fuel consumption standards are expected to achieve 7 to 20 percent reduction in GHG emissions in MY 2017, depending on size class and type, from a 2010 baseline.[21] For heavy-duty pickup trucks and vans, MY 2018 standards would result in a reduction in GHG emissions of 17 percent for diesel vehicles and 12 percent for gasoline vehicles. For vocational vehicles, the standards would achieve an emission reductions from seven to 10 percent, also depending on size class, for MY 2017.[22]

Additional emission standards are also included under the EPA proposal – for HFC emissions from vehicle air conditioner, which would apply to pickups, vans and tractors and for N2O and CH4 from all heavy-duty engines, pickups and vans.[23]EPA is currently reviewing comments to the proposed rulemaking, which was released in October 2010.

SmartWay Program: In 2004, the EPA launched the SmartWay Program, a collaboration between government, business, and consumers. The program is designed to promote fuel efficient vehicles, help truck owners and freight transport operators choose efficient vehicles, and save energy and lower operating costs through improved logistics, and thereby reduce GHG emissions and air pollution, improve fuel efficiency, and strengthen the freight sector. The program works with shippers, carriers, truck stops and other related groups and currently has more than 2,600 partners.[24]Before the introduction of vehicle standards (above), the SmartWay voluntary certification program was the main approach to deal with GHG emissions from medium- and heavy-duty vehicles.

The program facilitates the adoption of fuel efficient technologies in the freight sector, using the following methods:

  • Certified vehicles: Under the SmartWay program the EPA certifies tractors and trailers based on certain design criteria, including aerodynamic improvements, 2007 or newer engines, and idle reduction technology. These certified vehicles are available from eight major truck manufacturers, which offer at least one model meeting SmartWay specifications.
  • Verified fuel savings products: EPA evaluates fuel savings and emission reduction or technologies in the following categories: Idle Reduction Technologies, Aerodynamic Technologies, Low Rolling Resistance Tires, and Retrofit Technologies. To help companies upgrade existing vehicles, the EPA offers "Upgrade Kits," a group of fuel savings technologies and emission-control devices that reduce GHG emission and other air pollutants. According to EPA estimates, installation of these kits may improve fuel economy up to 15 percent.[25]
  • Financing: SmartWay offers financing options that provide companies with the capital to invest in fuel-saving technologies. In 2009, the EPA was awarded $30 million from the American Recovery and Reinvestment Act of 2009 to develop financing programs for trucks, school buses, and non-road vehicles and equipment. In addition, SmartWay provides a clearinghouse web site where trucking companies can apply for private loans for SmartWay Certified Tractor or Certified Trailer or SmartWay approved fuel efficiency technologies.
  • Federal Excise Tax Exemption: Under the Energy Improvement and Extension Act (EIEA) of 2008, retailers of certain fuel efficiency technologies (idling reduction devices and advanced insulation) are exempt from the federal excise tax.

Other EPA Programs: Other programs coordinated by EPA include the National Clean Diesel Campaign (NCDC)and Clean School Bus USA. Both these programs focus on reducing traditional air pollutants, yet also have the benefit of reducing GHG through strategies that reduce fuel consumption and thereby GHG and tailpipe emissions. National Clean Diesel Campaign works with manufacturers, fleet operators, air quality professionals, environmental and community organizations, and state and local officials to reduce emissions from diesel engines. The program focuses on projects that use diesel technologies, operational strategies and alternative/renewable fuels to reduce emissions and provides grants and funding for technology adoption.[26]

Clean School Bus USA is a public-private environmental partnership that tries to reduce children’s exposure to diesel exhaust and air pollution from diesel school buses. The program focuses on reducing emissions through anti-idling strategies, engine retrofits, clean fuels, and bus replacement.[27]

DOE Clean Cities: Clean Cities is a government-industry partnership, sponsored by DOE and designed to reduce petroleum consumption in the transportation sector. The program works with local and state organizations to adopt technologies that reduce fuel consumption, such as:

  • Alternative and renewable fuels
  • Idle-reduction measures, targeted to buses and heavy-duty trucks
  • Fuel economy improvements
  • New transportation technologies

Clean Cities facilitates the adoption of these technologies by providing funding and financial incentives to support projects.[28] Its network includes almost 90 coalitions and local partners, which represent about three quarters of the U.S. population. Among the program's accomplishments is increasing the number of alternative fuel transit buses from 6 percent in 1997 to 20 percent in 2007.[29]

Box 3: Case Studies

UPS - UPS has the largest commercial fleet in the United States with over 93,000 trucks in its fleet.[30]Its alternative fuel fleet includes more than 1,900 compressed natural gas, liquefied natural gas, propane, hydrogen fuel cell, electric and hybrid electric vehicles.[31]In 2006, the company was the first to test a full-series hydraulic hybrid truck, built through a partnership between U.S. Environmental Protection Agency (EPA), Eaton, International Truck and Engine, and the U.S. Army National Automotive Center. A hydraulic hybrid uses two power sources to propel the vehicle – a small, fuel-efficient diesel engine and hydraulic components, which removes the need for a mechanical transmission and drive train.[32]

The company has also used a variety of operational measures to reduce vehicle fuel consumption. UPS uses careful routing to avoid unnecessary driving, including the company's famous “right turn policy,” which reduces the number of left turns a driver must make. According to company estimates, this policy reduced delivery routes by 30 million miles and saved 3 million gallons of gas.[33]The company also has an anti-idling program that reduced the amount of time delivery vehicles idle by 24 minutes per driver per day.[34]

FedEx - FedEx operates the second largest commercial fleet in the United States, with over 65,000 vehicles.[35]In 2000, FedEx partnered with Environmental Defense Fund (EDF) to begin developing more efficient delivery trucks. The company uses a variety of alternative energy vehicles, and as of 2010, has one of the largest hybrid fleets, with nineteen all-electric vehicles in London, Paris, and Los Angeles.[36]The company has a goal of improving the efficiency of the entire fleet by 20 percent by 2020 from 2008 levels. It plans to use a number of strategies including route optimization, smaller, more efficient vehicles, and couriers who delivery packages by foot or bicycle in New York City and London.[37]

New York City Transit - In 2000, NYC Transit was the first public transportation system to use ultra-low sulfur fuel, which reduces emissions from diesel buses. The agency also has the largest hybrid-electric bus fleet in the world, more than 1,000 vehicles in 2009. In a study by the National Renewable Energy Laboratory, these hybrid-electric buses had an average fuel economy that was 34 percent higher than that for diesel buses.[38]

Maryland Hybrid Truck Initiative - The Maryland Hybrid Truck Initiative is a partnership between the Maryland Energy Administration (MEA), the U.S. Department of Energy, Maryland Clean Cities, ARAMARK, Efficiency Enterprises, Nestlé Waters North America, Sysco Corporation, and United Parcel Service. Launched in early 2011, the Initiative aims to facilitate the deployment of heavy-duty hybrid truck, including 143 Freightliner hybrid electric vehicles (HEVs) and Freightliner Custom Chassis hydraulic hybrid vehicles (HHVs).[39]

State Programs: Thirty-nine states have polices that affect medium- and heavy-duty vehicles. These policies include the following:

  • Financial Incentives: tax credits for vehicle retrofit, new vehicle purchase, and refueling infrastructure; grants for fleet modernization, truck stop electrification, and retrofits;
  • Idle Reduction: fines for excessive idling; weight exemptions for vehicles containing idle reduction technology;
  • State Fleet Procurement: mandates to alternative fuel vehicles and retrofit existing vehicles to be more fuel-efficient; and
  • R&D: funding for research and development.

For a map of the states and a description of their policies, see “U.S. States and Regions: Medium- and Heavy-Duty Vehicle Policies

California Standards: In addition to some of the programs mentioned above, the State of California also regulates heavy-duty truck under its 2006 Global Warming Solutions Act. The program is designed to reduce GHG emissions by improving tractor and trailer aerodynamics and tire rolling resistance, using EPA’s SmartWay technologies. The first part of the program began in January 2010; new MY 2011 tractors and trailers purchased after this time must be SmartWay certified. Older vehicles will need to be retrofitted with SmartWay technologies over time, beginning in January 2013.[40]

Related Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Greene, D. L., & Plotkin, A. (2011). Reducing Greenhouse Gas Emissions From U.S. Transportation.

Climate TechBook. Freight Transportation

Further Reading / Additional Resources

U.S. Environmental Protection Agency (EPA), Office of Transportation and Air Quality. SmartWay.

Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[1]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[2]See Table 5-7, in U.S. Department of Energy (DOE). Transportation Energy Data Energy Book 29. Oak Ridge, TN: Oak Ridge National Laboratory, 2010.

[3]The powertrain consists of a group of components that includes the vehicle engine and transmission

[4]U.S. DOE. 2008 Vehicle Technologies Market Report. Golden, Colorado: National Renewable Energy Laboratory. July 2009; and Table 5-3, in U.S. Department of Energy (DOE). Transportation Energy Data Energy Book 29. Oak Ridge, TN: Oak Ridge National Laboratory, 2010.

[5]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[6]U.S. DOE. Annual Energy Outlook 2011. 26 April 2011. Accessed 15 May 2011.

[7]National Renewable Energy Laboratory. “Vehicle Technologies and Program Market Data.” 30 June 2010. Accessed 15 May 2011.

[8]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[9]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[10]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[11]In turbo-charging, the intake air is compressed with some of the exhaust gas energy, which would otherwise be wasted. Thus, more air can be taken in and more engine power can be produced from a given engine size.

[12]Variable valve actuation alters the degree of lift and/or the timing of valve opening and closing within an internal combustion engine.

[13]Cylinder deactivation shuts down some of the cylinders in a multi-cylinder engine when they're not needed, thereby increasing fuel economy during periods of light load.

[14]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[15]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[16]Greene, D. and S. Plotkin. Reducing Greenhouse Gas Emissions from U.S. Transportation, 2011.

[17]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[18]Greene, D. and S. Plotkin. Reducing Greenhouse Gas Emissions from U.S. Transportation, 2011.

[19]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[20]Miller, P., Ed. "Heavy-Duty Long Haul Combination Truck Fuel Consumption and CO2 Emissions." NESCCAF and ICCT, 2009.

[21]The range of possible reductions is due to the different standards depending on cab type and roof type. For example, the gallon per 1,000 ton-mile standard for Class 7, Day Cab, High Roof trucks is 11.4 for MY2017, while Class 8, Sleeper Cab, Low Roof Trucks have a standard of 6.3 gal/1,000 ton-mile.

[22]U.S. EPA. “EPA and NHTSA Propose First-Ever Program to Reduce Greenhouse Gas Emissions and Improve Fuel Efficiency of Medium- and Heavy-Duty Vehicles: Regulatory Announcement.” October 2010.

[23]Green Car Congress. “NHTSA, EPA propose first greenhouse gas and fuel efficiency standards for heavy-duty trucks and buses.” 25 October 2010. Accessed 12 May 2011.

[24]U.S. EPA. SmartWay. Accessed 13 Apr 2011.

[25]U.S. EPA “Benefits: Upgrade Kits.” 12 May 2011.

[26]U.S. EPA. “NCDC: Basic Information.” 15 April 2011. Accessed 12 May 2011.

[27]U.S. EPA. “Clean School Bus USA: Basic Information.” 20 October 2007. Accessed 13 May 2011.

[28]U.S. DOE. “Clean Cities: About the Program.” 6 May 2011. Accessed 13 May 2011.

[29]U.S. DOE. “Clean Cities: Goals, Strategies, and Top Accomplishments.” May 2010.

[30]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[31]UPS. “Alternative Fuels Drive UPS to Innovative Solutions.” Accessed 13 April 2011.

[32]UPS. “Saving Fuel: Alternative Fuels Drive UPS to Innovative Solutions.”, 25 Feb 2011. Accessed 13 April 2011.

[33]Davis, Scott. Speech: “Right Turn at the Right Time.” Accessed 16 May 2011.

[34]UPS. “Saving Fuel: The Benefits of No Idling” 10 Mar 2011. Accessed 13 April 2011.

[35]Committee to Assess Fuel Economy Technologies for Medium- and Heavy-Duty Vehicles; National Research Council, Transportation Research Board. Technologies and Approaches to Reducing the Fuel Consumption of Medium- and Heavy-Duty Vehicles. Washington, DC: National Academies Press, 2010.

[36]FedEx. “Alternative Energy: Cleaner Vehicles.”, 3 January 2011. Accessed 13 April 2011.

[37]Environmental Defense Fund. “EDF and FedEx: Driving Toward Cleaner Trucks.” Accessed 13 April 2011.

[38]Barnitt, R. and K. Chandler. "New York City Transit (NYCT) Hybrid (125 Order) and CNG Transit Buses: Final Evaluation Results." Boulder, CO; NREL, 2006.

[39]Maryland Hybrid Truck Initiative. Accessed 13 April 2011.

[40]California Air Resources Board. “Presentation: Heavy-Duty Vehicle Greenhouse Gas (Tractor-Trailer GHG) Emission Reduction Regulation.” 21 March 2011. Accessed 12 May 2011.


 Technology and policy solutions to save oil and reduce greenhouse gas emissions from medium- and heavy-duty vehicles.

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

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