Energy & Technology

Geothermal Electricity

Quick Facts

  • Geothermal electricity generation is a commercially proven technology that harnesses the nearly inexhaustible heat of the earth’s core to continuously generate nearly zero-emission renewable electricity at a cost that is competitive with, and in many cases lower than, traditional fossil fuel power generation.
  • Geothermal energy is available twenty-four hours a day, seven days a week, which avoids problems of variability associated with other renewable technologies like wind and solar.
  • While it constitutes 8 percent of U.S. non-hydroelectric renewable electricity generation, geothermal energy currently provides less than 1 percent of total U.S. electricity.[1],[2]
  • Currently, nine states produce electricity from geothermal plants, with more than 80 percent of total geothermal generation capacity in California.[3]
  • While the United States currently has about 3,000 megawatts (MW) of geothermal electric generating capacity, the U.S. Geological Survey estimates the United States possesses 39,000 megawatts MW of geothermal potential, including identified resources and resources that are hidden or undetectable at the surface.[4],[5],[6]

Background

Geothermal energy can be used for electricity generation, heat pumps, or direct applications. This document focuses only on the traditional, commercially available technologies that produce electricity by exploiting the naturally occurring heat of the earth. Enhanced geothermal systems, which utilize advanced, and often experimental, drilling and fluid injection techniques to augment and expand the availability of geothermal resources, are the subject of a separate factsheet (see Climate TechBook: Enhanced Geothermal Systems).

Unlike other sources of renewable energy, such as wind and solar, geothermal power generation can operate steadily nearly twenty-four hours a day, seven days a week. Continual production makes geothermal an ideal candidate for providing nearly zero-emission renewable baseload power.

In 2011, the 15.3 billion kilowatt-hours (kWh)  of geothermal electricity generated in the United States constituted 8 percent of the non-hydroelectric, renewable electricity generation, but only 0.4 percent of total electricity generation.[7],[8] The same year, five states generated electricity from geothermal energy (CA, HI, ID,  NV, and UT), but California alone accounted for 82 percent of U.S. geothermal electric generation.[9] Geothermal plays an important role in some of the states where it is installed. Geothermal facilities satisfy 6 percent of California’s electricity consumption and 2 percent of Hawaii’s. [10],[11]

Despite its current limited application, geothermal energy has a very large potential for expansion. As Figure 1 illustrates, most of the U.S. geothermal potential is in the western states. The U.S. Geological Survey estimates that current technologies could harness nearly 40,000 MW of geothermal resources in America’s West, compared to a current U.S. electric generating capacity of roughly 1 million MW.[12]

Figure 1: Distribution of U.S. Geothermal Resources

http://www.nrel.gov/gis/images/geothermal_resource2009-final.jpg

Source: Roberts, Billy J. National Renewable Energy Laboratory. October 2009. http://www.nrel.gov/gis/images/geothermal_resource2009-final.jpg

Description

Geothermal energy taps into the natural heat of the earth to produce electricity. More specifically, conventional geothermal energy draws on the earth’s hydrothermal resources (underground heated water and steam). After drilling into these reservoirs, geothermal plants extract hot water and steam from the earth’s crust to drive electricity-generating turbines, a process called “heat mining.”[13]

The various techniques currently used to produce geothermal energy include the following (see Figure 2 for illustrations of these techniques):

Dry Steam

Dry steam plants draw steam directly from under the earth’s surface to a turbine that drives a generator. The steam then condenses into water and is reinjected into the geothermal reservoir.

Flash Steam

Flash steam plants extract geothermal water exceeding 350°F under extremely high pressure. Upon surfacing, a sudden reduction in pressure causes a portion of the heated water to vaporize, or “flash,” into steam. That steam turns a turbine, which drives a generator, after which the water is reinjected into the geothermal reservoir.

Binary Cycle

Binary cycle plants operate in areas with substantially lower-temperature geothermal water (225°F). Rather than using hydrothermal resources to drive a turbine, binary cycle plants use the earth’s heated water to vaporize a “working fluid,” any fluid with a lower boiling point than water (e.g., iso-butane). The vaporized working fluid drives a turbine that powers a generator, while the extracted geothermal water is promptly reinjected into the reservoir without ever leaving its closed loop system.

Figure 2: The Three Most Common Techniques Used for Geothermal Electricity Generation

Illustration of a Dry Steam Power Plant - Geothermal steam comes up from the reservoir through a production well.  The steam spins a turbine, which in turn spins a generator that creates electricity.  Excess steam condenses to water, which is put back into the reservoir via an injection well.

Source: U.S. Department of Energy. Geothermal Technology Program. Hydrothermal Power Systems. November, 2010. http://www1.eere.energy.gov/geothermal/powerplants.html

Geothermal energy also depends on advanced hard-rock drilling technology. While oil and gas drilling techniques apply to geothermal drilling, temperatures above 250°F found in geothermal reservoirs complicate the process. The high heat increases the probability of well failure due to collapse, mechanical malfunction, and casing failure.[14],[15] Extensive research has gone into understanding the geological characteristics of geothermal reservoirs and how to adapt drilling technologies to these conditions.[16]

Environmental Benefit and Emission Reduction Potential

Environmental benefits from geothermal energy include near-zero greenhouse gas emissions from plant operations and low freshwater use and contamination. Traces of carbon dioxide (CO2) and other greenhouse gases are found dissolved in some hydrothermal reservoirs. Using those hydrothermal resources with dry steam and flash steam geothermal plants does allow these dissolved greenhouse gases to escape into the atmosphere.[17] [18]A geothermal plant will emit only zero to four percent as much CO2 as a traditional coal-fueled power plant per unit of electricity generated.[19] Geothermal plants also emit significantly less conventional air pollutants (nitrogen oxides, sulfur dioxide, and particulate matter) than coal power plants, as these emissions are virtually nonexistent.[20]

A market-based policy to reduce greenhouse gas emissions and spur the deployment of clean energy technology could lead to much more rapid growth in geothermal electricity generation. For example, in its analysis of a 2010 greenhouse gas cap-and-trade proposal, U.S. Energy Information Administration projected that, geothermal electricity generation could grow more than twice as fast with such a policy in place.[21]

Globally, the International Energy Agency (IEA) estimates that geothermal electricity generation provided about 0.3 percent of total electricity in 2010. With current policies, IEA projects that geothermal sources will provide only about 0.5 percent of global electricity by 2035. However, with coordinated international action to keep greenhouse gases emissions in the atmosphere below 450 parts per million, IEA projects that geothermal electricity generation could provide about 1.4 percent of global electricity generation by 2035.[22]

Cost

There are at least two categories of costs associated all types of electricity generation: capital costs and operating and maintenance costs. The capital cost for a geothermal plant can vary significantly depending upon the conversion technology, the depth of the wells, and the temperature of the hydrothermal resource. The capital cost of a geothermal plant can range from $1,000 to more than $6,000 per kilowatt (kW) of capacity.[23]

While the capital cost of a geothermal plant can be either comparable to or much higher than that of a traditional fossil fuel power plant, the full cost of generating electricity includes operating and maintenance costs. Unlike a coal or natural gas plant, geothermal facilities do not need to purchase fuel to generate electricity. Accounting for this fact through a levelized cost analysis reveals that geothermal plants can produce electricity for 6 to 9 cents per kilowatt-hour (kWh), a rate competitive with traditional fossil fuel generation.[24] Depending on tax incentives, the EIA expects that the levelized cost of geothermal energy will remain competitive with fossil fuels.[25]

Geothermal plants harnessing high-temperature resources tend to be less expensive than those relying on low-temperature resources. This is because in high-temperature areas, more electricity can be generated from each unit of geothermal water, reducing the number of wells required. Therefore, flash steam geothermal plants, which generate electricity using hotter geothermal fluids and fewer wells, are likely to have lower capital costs than binary geothermal plants, which use cooler geothermal fluids and more wells. This correlation is pictured in Figure 3. The capital costs of flash steam plants range from $1,000 to $2,000 per kilowatt installed, while the capital costs of binary plants range from $2,000 to $6,500 per kilowatt.[26],[27]

With time, experts expect the cost of geothermal energy to drop as firms gain experience installing geothermal plants. Costs will also fall as new drilling technologies improve the exploration and well drilling phase, which constitutes, on average, 37.5 percent of a geothermal plant’s total capital cost.[28]

Figure 3: Relationship between Capital Cost of Geothermal Plants and Resource Temperature

Source: National Renewable Energy Laboratory, 2012. Renewable Electricity Futures Study. http://www.nrel.gov/docs/fy12osti/52409-2.pdf

Current Status of Geothermal Energy

From the early 1970s to the early 1990s, geothermal electricity generation saw rapid growth, with an average annual growth rate of more than 16 percent.[29] From the early 1990s until the present, however, geothermal generation has been relatively flat. As of February 2013, the United States possessed about 3,386 MW of installed geothermal capacity.[30] An additional 175 geothermal projects across fifteen states are currently under development.[31] According to the EIA, under current policies geothermal generation is projected to increase much more quickly than total electricity demand, with an annual growth rate of 4.3 percent between 2011 and 2035.[32]

Legislation and government incentives may help jumpstart the expansion of the geothermal industry. In 2012, the U.S. Department of Energy (DOE) provided $62 million for research in geothermal technologies.[33] Geothermal energy also received a production tax credit (PTC) through 2013.[34]

Geothermal energy plays an important role in some countries. Iceland, for example, generates over 80 percent of its electricity from geothermal sources.[35] The United States leads the world in terms of total installed geothermal capacity.[36] Global electric generation from geothermal sources is projected at an annual growth rate of 4.8 to 6.3%, depending on climate and energy policies.[37]

Obstacles to Further Development or Deployment of Geothermal Energy

High-Risk Exploration Phase

The exploratory phases of a geothermal project are marked by not only high capital costs but also a 75-80 percent chance of failure for exploratory well drilling, due to uncertainties regarding reservoir geology.[38] The combination of high risk and high capital costs can make financing geothermal projects difficult.[39]

Investment Uncertainty

Changes in government funding for geothermal generation and uncertainty over future climate-related regulations create uncertainty for potential project developers. Certainty is especially important in geothermal projects, which take an average of ten years to move from exploration to generation.[40] In the past, Congress has allowed the federal Production Tax Credit (PTC) to expire before renewing it. In addition, after years of moderate funding, the 2007 budget contained no provision to continue funding geothermal research. More recent federal budgets have, however, provided some funding to promote geothermal research and development, including $62 million from the DOE’s Energy Efficiency and Renewable Energy (EERE) fiscal year 2012 budget appropriated by the U.S. Congress.[41]

Geographic Distribution and Transmission

Some of the most promising geothermal resources lie great distances from regions of large electricity consumption, or load centers. The need to install adequate transmission capacity can deter investment in geothermal projects. For example, in 2002, MidAmerica Energy abandoned its geothermal project near California’s Salton Sea primarily due to lack of available transmission resources.[42]

Permitting Delays

Delays in permitting can increase the amount of time it takes to bring new geothermal facilities on-line, and increase project costs and developer risk.

Policy Options to Help Promote Geothermal Energy

Price on Carbon

A price on carbon, such as that which would exist under a greenhouse gas cap-and-trade program, would raise the cost of electricity produced from fossil fuels relative to the cost of electricity from renewable sources, such as geothermal energy, and other lower-carbon technologies.

Electricity Portfolio Standard

Electricity portfolio standards generally require that electric utilities obtain specified minimum percentages of their electricity from certain energy sources. Thirty-one states and the District of Columbia have renewable portfolio standards or alternative energy portfolio standards.[43] Congress has also considered federal renewable electricity standards and clean energy standards. Electricity portfolio standards encourage investment in new geothermal power and can guarantee a market for its generation.

Tax Credits and Other Subsidies

The federal Production Tax Credit (PTC) for geothermal electricity generation expires at the end of 2013. The PTC can lower the after-tax, levelized cost of electricity from geothermal by as much as 30 percent.[44] Geothermal developers can also choose to substitute their PTC benefits with the Investment Tax Credit (ITC). The ITC would provide tax credits equivalent to 10 percent of their investment costs in geothermal technologies. The ITC credits will expire at the end of 2016 unless the legislation is renewed.[45]

Development of New Transmission Infrastructure

Improving transmission corridors to areas with geothermal reservoirs would facilitate investment in geothermal energy. Policies to build new transmission to areas with significant renewable energy resources are already proposed for accessing the wind-rich regions of the central plains and the extensive solar resources of the desert in the Southwest United States. Such policies could also promote expanded transmission to reach the geothermal fields of the West.

Related Business Environmental Leadership Council (BELC) Companies

Alcoa

DTE Energy

GE

Johnson Controls

PG&E

Related Pew Center Resources

Climate Change 101: Technology Solutions, 2011 http://www.c2es.org/docUploads/climate101-technology.pdf

The Case for Action: Creating a Clean Energy Future. 2010 http://www.c2es.org/docUploads/case-for-action-creating-clean-energy-future.pdf

Deploying Our Clean Energy Future. 2009 http://www.c2es.org/docUploads/claussen-deploying-our-clean-energy-future-innovations-fall-2009.pdf

Further Reading / Additional Resources

Blodgett, Leslie, and Kara Slack. 2009. Geothermal 101: Basics of Geothermal Energy Production and Use. Geothermal Energy Association.

Geothermal Energy Association. Deloitte. 2008. Geothermal Risk Mitigation Strategies Report. Department of Energy, Office of Energy Efficiency and Renewable Energy Geothermal Program.

Energy Information Administration. Geothermal Explained. 2011.

Fridleifsson, I.B., R. Bertani, E. Huenges, J. W. Lund, A. Ragnarsson, and L. Rybach. 2008. “The Possible Role and Contribution of Geothermal Energy to the Mitigation of Climate Change.” In: O. Hohmeyer and T. Trittin (Eds.) IPCC Scoping Meeting on Renewable Energy Sources, Proceedings, Luebeck, Germany, 20-25 January 2008, 59-80.

Geothermal Technologies Program. 2008. Geothermal Tomorrow 2008. U.S. Department of Energy, Energy Efficiency and Renewable Energy.

Geothermal Technologies Program. 2008. Multi-year Research, Development and Demonstration Plan: 2009-2015 with program activities to 2025. U.S. Department of Energy, Energy Efficiency and Renewable Energy.

Idaho National Laboratory. 2007. The Future of Geothermal Energy. The U.S. Department of Energy National Laboratory operated by the Battelle Energy Alliance.

International Geothermal Energy Association.

Union of Concerned Scientists. 2009. How Geothermal Energy Works.

Salmon, J. Pater, J. Meurice, N. Wobus, F. Stern, and M. Duaime. 2011. Guidebook to Geothermal Power Finance. National Renewable Energy Laboratory.

Williams, Colin, Marshall Reed, Robert Mariner, Jacob DeAngelo and S. Peter Galanis. 2008. Assessment of Moderate-and High-Temperature Geothermal Resources of the United States. United States Geological Survey.

Williams, Eric, Rich Lotstein, Chrisopher Galik and Hallie Knuffman. July 2007. A Convenient Guide to Climate Change Policy and Technology. Duke University.

Endnotes

 


[1] Energy Information Administration (EIA), Electric Power Annual Report. 2013. Table 3.1.B. http://www.eia.gov/electricity/annual/html/epa_03_01_b.html

[2] EIA, Electric Power Annual. 2013. Table 3.1.A. http://www.eia.gov/electricity/annual/html/epa_03_01_a.html

[3] Matek, Benjamin. Geothermal Energy Association. 2013. 2013 Annual US Geothermal Power Production and Development Report. http://geo-energy.org/pdf/reports/2013AnnualUSGeothermalPowerProductionandDevelopmentReport_Final.pdf

[4] Ibid.

[5] Williams, Colin, Marshall Reed, Robert Mariner, Jacob DeAngelo and S. Peter Galanis. 2008. Assessment of Moderate-and High-Temperature Geothermal Resources of the United States. United States Geological Survey. http://pubs.usgs.gov/fs/2008/3082/

[6] Represents a 50 percent chance of at least this amount.

[7] EIA, Electric Power Annual. 2013. Table 3.1.B.

[8] EIA, Electric Power Annual. 2013. Table 3.1.A.

[9] EIA, Electric Power Annual. 2013. Table 3.19. http://www.eia.gov/electricity/annual/html/epa_03_19.html

[10] Ibid.

[11] EIA, Electric Power Annual. 2013. Table 3.6. http://www.eia.gov/electricity/annual/html/epa_03_06.html

[12] EIA, Electric Power Annual. 2013. Table 4.3. http://www.eia.gov/electricity/annual/html/epa_04_03.html

[13] Tester, Jefferson, et. al. 2006. The Future of Geothermal Energy: Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century. Massachusetts Institute of Technology. http://www1.eere.energy.gov/geothermal/pdfs/future_geo_energy.pdf

[14] Casing is the pipe that connects the geothermal well to the generation facility, and prevents the mixing of hot geothermal fluids with groundwater at other depths. High temperatures can cause the steel piping to expand or buckle if not properly enforced with cement, a process referred to as “casing failure”.

[15] Geothermal Technologies Program. 2011. Multi-year Research, Development and Demonstration Plan: 2009-2015 with program activities to 2025. U.S. Department of Energy, Energy Efficiency and Renewable Energy. http://www1.eere.energy.gov/geothermal/pdfs/gtp_myrdd_2009-cover.pdf

[16]For an example of this work, see Blankenship, Douglas, David Chavira, Joseph Henfling, Chris Hetmaniak, David Huey, Ron Jacobson, Dennis King, Steve Knudsen, A.J. Mansure, and Yarom Polsky. 2009. Development of a High-Temperature Diagnostics-While-Drilling Tool. Sandia Report 2009-0248. http://www.ntis.gov/help/ordermethods.asp?loc=7-4-0#online

[17] Kagel, Alysa, Diana Bates, and Karl Gawell. 2007. A Guide to Geothermal Energy and the Environment. Geothermal Energy Association. [www.geo-energy.org]. See Williams, Eric, Rich Lotstein, Chrisopher Galik and Hallie Knuffman. July 2007. A Convenient Guide to Climate Change Policy and Technology. http://www.nicholas.duke.edu/ccpp/convenientguide/cg_pdfs/ClimateBook.pdf

[18] The gases released through geothermal energy production would have eventually entered the atmosphere, regardless of production in the area; however, the timing of their release is material to near-term climate forcing.

[19] Binary plants emit 0 lbs. of CO2 per MWh, flash plants emit 60 lbs. of CO2 per MWh, and dry steam plants emit 88.8 lbs. of CO2 per MWh.

[20] Williams, Eric, Rich Lotstein, Chrisopher Galik and Hallie Knuffman. July 2007. A Convenient Guide to Climate Change Policy and Technology. Duke University. http://www.nicholas.duke.edu/ccpp/convenientguide/

[21] Energy Information Administration. July 2010. Energy Market and Economic Impacts of the American Power Act of 2010. http://www.eia.gov/oiaf/servicerpt/kgl/index.html. The text compares EIA’s “Reference” and “APA Basic” cases.

[22] International Energy Agency (IEA). 2011. World Energy Outlook 2012. http://www.worldenergyoutlook.org/media/weowebsite/2012/WEO2012_Renewables.pdf

[23] Augustine, C.; Denholm, P.; Heath, G.; Mai, T.; Tegen, S.; Young. K. (2012). "Geothermal Energy Technologies," Chapter 7. National Renewable Energy Laboratory. Renewable Electricity Futures Study, Vol. 2, Golden, CO: National Renewable Energy Laboratory; pp. 7-1 – 7-32.

[24] Ibid.

[25] EIA. 2013. Annual Energy Outlook 2013. Available at: http://www.eia.gov/forecasts/aeo/electricity_generation.cfm

[26] Costs are given in 2009 dollars.

[27] Augustine, et al. 2012

[28]Augustine et al, 2012.

[29] EIA. 2012. Annual Energy Review. See Table 8.2b.

[30] Matek, Benjamin. Geothermal Energy Association. 2013. 2013 Annual US Geothermal Power Production and Development Report. http://geo-energy.org/pdf/reports/2013AnnualUSGeothermalPowerProductionandDevelopmentReport_Final.pdf

[31] Ibid.

[32] Energy Information Administration. 2013. Annual Energy Outlook 2013. See Table 16. http://www.eia.gov/forecasts/aeo/tables_ref.cfm

[33] U.S. Department of Energy. 2012. Fiscal Year 2012 Agency Financial Report. http://energy.gov/sites/prod/files/2012parafr_0.pdf

[34] HR1: The American Recovery and Reinvestment Act. THOMAS. http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=111_cong_public_laws&docid=f:publ005.111.pdf

[35] Williams et.al, 2008.

[36] Matek, 2013.

[37] IEA. 2012. World Energy Outlook 2012.

[38]Geothermal Technologies Program. 2008. Geothermal Tomorrow 2008. U.S. Department of Energy, Energy Efficiency and Renewable Energy. http://www.nrel.gov/docs/fy08osti/43504.pdf

[39] Deloitte, 2008.        

[40] Williams et.al, 2007.

[41] U.S. Department of Energy. 2012. Fiscal Year 2012 Agency Financial Report. http://energy.gov/sites/prod/files/2012parafr_0.pdf

[42] See footnote 9 in Tester et. al, 2006.

[43] For more information on state RPSs, see http://www.c2es.org/us-states-regions/policy-maps/renewable-energy-standards.

[44] Owens, Brandon. 2002. An Economic Valuation of a Geothermal Production tax Credit. National Renewable Energy Laboratory. http://www.nrel.gov/docs/fy02osti/31969.pdf

[45] DSIRE. 2013. Business Investment Tax Credit (ITC). http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=US02F

Focus on conventional methods of generating electricity from the earth's heat
0
Teaser: 

Focus on conventional methods of generating electricity from the earth's heat

Building Envelope

Quick Facts

  • Residential and commercial buildings account for almost 39 percent of total U.S. energy consumption and 38 percent of U.S. carbon dioxide (CO2) emissions.[1]
  • Space heating, cooling, and ventilation account for the largest amount of end-use energy consumption in both commercial and residential buildings. In the commercial sector they are responsible for 34 percent for energy used on site and 31 percent of primary energy use[2]. In the residential sector, space heating and cooling are responsible for 52 percent of energy used on site, and 39 percent of primary energy use.[3]
  • The building envelope – the interface between the interior of the building and the outdoor environment, including the walls, roof, and foundation – serves as a thermal barrier and plays an important role in determining the amount of energy necessary to maintain a comfortable indoor environment relative to the outside environment.

Background

Nearly all of greenhouse gas (GHG) emissions from the residential and commercial sectors can be attributed to energy use in buildings (see Climate TechBook: Residential and Commercial Sectors Overview). Even so, existing technology and practices can be used to construct “net-zero energy” buildings ­ buildings that use design and efficiency measures to reduce energy needs dramatically and rely on renewable energy sources to meet remaining energy demand. The Energy Independence and Security Act of 2007 (EISA 2007) calls for all new commercial buildings to be net-zero energy by 2030. An integrated approach provides the best opportunity to achieve significant GHG reductions from the buildings sector, because many different building elements interact with one another to influence overall energy consumption (see Climate TechBook: Buildings Overview). However, certain key building elements can play a significant role in determining a building’s energy use and associated GHG emissions and merit a more in-depth consideration.

The building envelope is the interface between the interior of the building and the outdoor environment, including the walls, roof, and foundation. By acting as a thermal barrier, the building envelope plays an important role in regulating interior temperatures and helps determine the amount of energy required to maintain thermal comfort. Minimizing heat transfer through the building envelope is crucial for reducing the need for space heating and cooling. In cold climates, the building envelope can reduce the amount of energy required for heating; in hot climates, the building envelope can reduce the amount of energy required for cooling. A substantial part of “weatherization” includes improvements to the building envelope, and government weatherization programs often cite energy and energy bill savings as a primary rationale for these initiatives.

Description

The building envelope can affect energy use and, consequently, GHG emissions in a variety of ways:

  • Design of the building envelope

The overall design can help determine the amount of lighting, heating, and cooling a building will require. Architects and engineers have developed innovative new ways to improve overall building design in order to maximize light and heat efficiency, for example through passive solar heating, which uses the sun’s heat to warm the building when it is cold without relying on any mechanical or electrical equipment.[4] Local climate is an important determinant for identifying the design features that will result in the greatest reductions of energy needs. These may include such things as south-facing windows in cool climates and shading to avoid summer sun in hot climates.[5]

  • Building envelope materials and product selection
  • Embodied energy

Embodied energy refers to the energy required to extract, manufacture, transport, install, and dispose of building materials, including those used in the building envelope. Efforts to reduce this energy use and associated emissions, for example through the substitution of bio-based products, can be made as part of a larger effort to reduce emissions from buildings.

  • Insulation and air sealing

Heat naturally flows from a warmer to a cooler space; insulation provides resistance to heat flow, thereby reducing the amount of energy needed to keep a building warm in the winter and cool in the summer. Insulation is frequently discussed in terms of its ability to resist heat flow, or its R-value. A variety of insulation options exist, including blanket, concrete block, insulating concrete forms, spray foam, rigid foam, and natural fiber insulation.

Adding insulation strategically will improve the efficiency of the building; however, it is only effective if the building is properly sealed. Sealing cracks and leaks prevents air flow and is crucial for effective building envelope insulation. Leaks can generally be sealed with caulk, spray foam, or weather stripping.[6]

  • Roofs

Roof design and materials can reduce the amount of air conditioning required in hot climates by increasing the amount of solar heat that is reflected, rather than absorbed, by the roof. For example, roofs that qualify for ENERGY STAR®[7] are estimated to reduce the demand for peak cooling by 10 to 15 percent.[8] Proper insulation is also important in attics and building cavities adjacent to the roof.

In addition, roofs also offer several opportunities for installing on-site generation systems. Solar photovoltaic (PV) systems can either be installed as a rooftop array on top of the building or a building-integrated photovoltaic system can be integrated into the building as roofing tiles or shingles (see also Climate TechBook: Solar Power).

  • Walls

Like roofs, the amount of energy lost or retained through walls is influenced by both design and materials. Design considerations affect the placement of windows and doors, the size and location of which can be optimized to reduce energy losses. Decisions regarding the appropriate material can be more complicated because the energy properties of the entire wall are affected by the design. Importantly, material selection and wall insulation can both affect the building’s thermal properties.

A building’s thermal mass – i.e., its ability to store heat – is determined in part by the building materials used. Thermal mass buildings absorb energy more slowly and then hold it longer, effectively reducing indoor temperature fluctuations and reducing overall heating and cooling requirements. Thermal mass materials include traditional materials, such as stone and adobe, and cutting edge products, such as those that incorporate phase change materials (PCMs). PCMs are solid at room temperature and liquefy as they absorb heat; the absorption and release of energy through PCMs helps to moderate building temperature throughout the day.

  • Windows, doors, and skylights

Collectively known as fenestration, windows, exterior doors, and skylights influence both the lighting and the HVAC requirements of a building. In addition to design considerations (the placement of windows and skylights affects the amount of available natural light), materials and installation can affect the amount of energy transmitted through the window, door, or skylight, as well as the amount of air leakage around the window components. New materials, coatings, and designs all have contributed to the improved energy efficiency of high-performing windows, doors, and buildings. Some of the advances in windows include: multiple glazing, the use of two or more panes of glass or other films for insulation, which can be further improved by filling the space between the panes with a low-conductivity gas, such as argon, and low-emissivity (low-e) coatings, which reduce the flow of infrared energy from the building to the environment.

In residential buildings, using optimum window design and glazing specification is estimated to reduce energy consumption from 10 to 50 percent below accepted practice in most climates; in commercial buildings, an estimated 10 to 40 percent reduction in lighting and HVAC costs is attainable through improved fenestration.[9]

  • Interactions with other building elements

The building envelope can affect the lighting, heating, and cooling needs of the building. These interactions are important to consider when retrofitting or weatherizing buildings to reduce their energy use in the most cost-effective manner. For example, with a new building it may be more cost-effective to choose a design with a more costly, high-performance building envelope that significantly reduces the need for heating and cooling with a smaller, less-costly HVAC system. For existing buildings, it may be more cost-effective to add insulation to a building than to install a more efficient heating system.

Environmental Benefit / Emission Reduction Potential

Improvements to the building envelope have the potential to reduce GHG emissions from new and existing buildings in the residential, commercial, and industrial sectors. The building envelope can significantly affect the amount of required lighting and HVAC, the two largest end uses of energy in both the residential and commercial sectors. Local climate influences the appropriateness and cost-effectiveness of many decisions pertaining to building envelope design and product selection.

Greater GHG emission reductions can be achieved through integrated approaches that consider the entire building as a whole. Significant improvements in energy efficiency are attainable and can reduce building-related emissions to very low levels or, when coupled with renewable energy sources, to zero.

In addition to the climate benefits, many building envelope improvements also result in a variety of benefits for consumers, including lower energy bills, as well as improved thermal comfort, moisture control, and noise control.

Cost

Improvements to the building envelope have the potential to be cost-effective for both new and existing buildings. From a climate perspective, improvements to the building envelope should be pursued because they reduce GHG emissions; from a consumer perspective, improvements to the building envelope should be pursued because they can result in both a more comfortable indoor environment and reduced energy costs. The ENERGY STAR® program provides estimates of cost savings associated with several building envelope elements, for example:

  • Windows

For a typical home, an ENERGY STAR® window will save $126 to $465 per year when replacing single-pane windows and $27 to $111 per year when replacing double-pane windows.[10]

  • Insulation and air sealing

By sealing air leaks and adding insulation from average values to recommended values, the average home in the northern United States can save 12 percent on its total utility bill (19 percent of heating and cooling costs) and the average home in the southern United States can save 11 percent on its total utility bill (20 percent of total costs).[11]

Energy audits can be conducted to identify the most cost-effective ways to improve energy efficiency in existing buildings. New buildings can be cost-effectively built to have lower energy needs, and the Commercial Building Initiative, a public-private collaboration, has a goal of having marketable net-zero commercial buildings beginning in 2025.[12] Importantly, these whole-building efforts include, but are not limited to, improvements to the building envelope.

Obstacles to Further Development or Deployment

In broad terms, the obstacles to improved building envelopes are the same as the obstacles faced by buildings broadly. These barriers include cost concerns, market barriers, public policy and planning barriers, and customer barriers. More narrowly, these obstacles pose different barriers to new and existing buildings, as well as to each of the different building envelope elements. The cost-effectiveness of certain building envelope improvements, such as improved insulation and sealing of air leaks, has not led to widespread implementation. Insulation retrofits, for example, would not only reduce GHG emissions, but they would also reduce energy consumption and consumer energy bills, improve air quality, and reap a variety of public health benefits.[13] These kinds of energy efficiency projects are part of the low-hanging fruit for reducing GHG emissions.

Policy Options to Help Promote Building Envelope Improvements

Like the obstacles to building envelope improvements, the available policy options fall into the same general categorization as buildings overall. Some policy and program interventions focus on improvements to a single building-envelope element, such as insulation. Tax incentives and other programs can change annually. A number of organizations track buildings-related policies; see below for a sample of useful references:

  • Standards and codes

Regulatory policies include mandatory and voluntary building codes passed by states and localities.

  • U.S. Department of Energy (DOE) Building Energy Codes Program – provides state-by-state information on residential and commercial building codes. http://www.energycodes.gov/states/
  • Financial incentives

Financial incentives include tax credits, rebates, low-interest loans, energy-efficient mortgages, and innovative financing, all of which address the barrier of first costs. Many utilities also offer individual incentive programs, because reducing demand, especially peak demand, can enhance the utility’s system-wide performance.

  • Weatherization Assistance Program – provides low-income families with weatherization services, including insulation, air sealing, and windows. http://apps1.eere.energy.gov/weatherization/about.cfm
  • Database of State Incentives for Renewables and Efficiency (DSIRE) – tracks federal and state incentives for renewable and energy efficiency programs, including summary maps and tables, as well as a searchable database. http://www.dsireusa.org/
  • Information and education

While many businesses and homeowners express interest in making energy-efficiency improvements for their own buildings and homes, they often do not know which products or services to ask for, who supplies them in their areas, or whether the actual energy savings will live up to claims. A variety of programs provide useful information on building envelope improvements and other energy efficiency measures.

  • ENERGY STAR® – a joint program of the U.S. Environmental Protection Agency (EPA) and DOE provides information on and standards for energy efficient products and practices. http://www.energystar.gov
  • Energy Savers – a government program that provides information on ways to save energy at home, while driving, and at work. http://www.energysavers.gov
  • Lead-by-example programs

A variety of mechanisms are available to ensure that government agencies lead by example in the effort to build and manage more energy-efficient buildings and reduce GHG emissions.

  • Research and development (R&D)

R&D programs provide funding and support for advanced building materials and practices. Government funding is important because the fragmented and highly competitive market structure of the building sector and the small size of most building companies discourage private R&D, on both individual components and the interactive performance of components in whole buildings.

Related Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Climate TechBook: Buildings Overview, 2009 http://www.c2es.org/technology/overview/buildings

Climate TechBook: Residential and Commercial Sectors Overview, 2009 http://www.c2es.org/technology/overview/res-comm

MAP:Commercial Building Energy Codes http://www.c2es.org/what_s_being_done/in_the_states/comm__energy_codes.cfm

MAP: Green Building Standards for State Buildings http://www.c2es.org/what_s_being_done/in_the_states/leed_state_buildings.cfm

MAP: Residential Building Energy Codes http://www.c2es.org/what_s_being_done/in_the_states/res__energy_codes.cfm

Additional Resources

DOE, Office of Energy Efficiency and Renewable Energy. 2009 Buildings Energy Data Book, 2009 http://buildingsdatabook.eren.doe.gov/

Whole Building Design Guide http://www.wbdg.org/index.php



[1] U.S. Department of Energy (DOE). 2009 Buildings Energy Data Book. Prepared for U.S. Department of Energy Office of Energy Efficiency and Renewable Energy by D&R International, Ltd. Silver Spring, MD. October 2009. http://buildingsdatabook.eren.doe.gov/

[2] Primary energy use defined as, “energy used at the source (including fuel input to electric power plants)”. Ibid.

[3] Ibid.

[4] For more information on passive solar design, see the DOE’s site on Passive Solar Home Design, http://www.energysavers.gov/your_home/designing_remodeling/index.cfm/mytopic=10250. The National Renewable Energy Laboratory also provides case studies of passive solar homes in a variety of climates, http://www.nrel.gov/buildings/passive_solar.html.

[5] The DOE has developed the Building America Best Practices Series that includes five climate-specific sets of building best practices that focus on reducing energy use and improving housing durability and comfort. Learn more at http://www1.eere.energy.gov/buildings/building_america/publications.html; also see the Whole Building Design Guide on Passive Solar Heating http://www.wbdg.org/resources/psheating.php.

[7] ENERGY STAR® is joint program of the U.S. Environmental Protection Agency (EPA) and U.S. Department of Energy (DOE) that provides information on and standards for energy efficient products and practices. For more information, see http://www.energystar.gov.

[8] For more information on ENERGY STAR® qualified roof products, visit http://www.energystar.gov/index.cfm?c=roof_prods.pr_roof_products.

[9] Ander, G. D. “Windows and Glazing.” Whole Building Design Guide, updated 18 June 2010. http://www.wbdg.org/resources/windows.php?r=minimize_consumption

[10] For more information on ENERGY STAR® windows, see http://www.energystar.gov/index.cfm?c=windows_doors.pr_savemoney.

[11] See ENERGY STAR® Methodology for Estimating Energy Savings from Cost-Effective Air Sealing and Insulating. http://www.energystar.gov/index.cfm?c=home_sealing.hm_improvement_methodology.

[13] Levy, J. I., Y. Nishioka, J. D. Spengler. “The Public Health Benefits of Insulation Retrofits in Existing Housing in the United States.” Environmental Health: A Global Access Science Source 2: 4 (2003). 

 

The interface between the building's interior and the environment, e.g., walls and windows
0
Teaser: 

The interface between the building's interior and the environment, e.g., walls and windows

Regulatory Reality vs. Rhetoric

First there was the warning about a construction moratorium – all new major stationary sources would come to an immediate halt because of EPA’s new source review requirements for greenhouse gas emissions (GHGs). Soon after the alarm went out about the approaching regulatory “train wreck” that would result from a series of EPA rules impacting electric utilities. A large number of power plants would shut down, the reliability of our energy supply would be sacrificed, and consumers would face skyrocketing costs.

There was only one problem with these warnings – they were made before anybody knew what the actual regulations would require. Now that EPA has issued several of these rules, it is useful to revisit these doomsday scenarios and see if the reality of the proposals matches the rhetoric before the fact.

All Energy Sources Entail Risk, Efficiency a No-Brainer

At the moment, our attention is riveted by the events unfolding at a nuclear power plant in Japan. Over the past year or so, major accidents have befallen just about all of our major sources of energy: from the Gulf oil spill, to the natural gas explosion in California, to the accidents in coal mines in Chile and West Virginia, and now to the partial meltdown of the Fukushima Dai-ichi nuclear reactor. We have been reminded that harnessing energy to meet human needs is essential, but that it entails risks. The risks of different energy sources differ in size and kind, but none of them are risk-free.

Transportation Modes

Quick Facts

  • Transportation activity and vehicle ownership is expected to grow significantly worldwide over the next several decades. The transportation sector, however, offers some of the greatest potential to alter the growth path in energy consumption, as illustrated by the expected effects of increased fuel economy and greenhouse gas standards for vehicles on overall energy consumption in the United States.
  • In the United States, passenger or light-duty vehicles are the largest source of energy consumption and greenhouse gas emissions within the transportation sector. Medium- or heavy-duty vehicles make up many commercial vehicle fleets; these fleets consume large quantities of fuel because of intensive use and the low fuel economy of their vehicles.
  • Aircraft emissions in the United States are a small percentage of total transportation sector emissions, but are expected to grow significantly over the long term. Emissions from marine transportation are a very small percentage of current transportation sector emissions in the United States, with little growth expected over the next 30 years.

Background

The transportation sector consists of cars and light-duty trucks (also referred to as passenger vehicles), medium- and heavy-duty trucks, buses, trains, ships, and aircraft. Energy use and, as a result, greenhouse gas emissions from each mode are determined by four major elements: the fuels used and their carbon content, the efficiency of each vehicle, the distance traveled, and the overall efficiency in transportation system operations. (See Transportation Overview)

Of the various transportation modes, passenger vehicles consume the most energy (see Figure 1). Despite major efforts to shift away from petroleum, oil accounted for over 95 percent of the energy used in transportation in 2011, although biofuels accounted for almost 10 percent of energy used for light-duty vehicles.[1]

Figure 1: Transportation Energy Use by Mode (2011)

* Commercial light trucks are medium-duty trucks weighing between 8,500 and 10,000 pounds.

Source: U.S. EIA. 2013. "Annual Energy Outlook 2013." U.S. Energy Information Administration. April. Accessed August 15, 2013. http://www.eia.gov/forecasts/aeo.

Over the next 30 years, analysts expect energy use for rail, aircraft, buses, and freight trucks to grow at higher average annual rates than energy use for light-duty vehicles, which is expected to decline due to federal fuel economy and greenhouse gas standards; see Figure 2.

Figure 2: Average Annual Growth in Transportation Energy Use by Mode (2011-2040)

Overall transportation energy use is expected not to change from 2011 to 2040. Light-duty vehicle energy use is expected to decrease due to the recent fuel economy and greenhouse gas standards.

Source: U.S. EIA. 2013. "Annual Energy Outlook 2013." U.S. Energy Information Administration. April. Accessed August 15, 2013. http://www.eia.gov/forecasts/aeo.

This factsheet gives a brief overview of the various transportation modes and discusses efficiency improvements available for each.

Passenger Vehicles

Light-duty vehicles, or passenger vehicles, are defined as cars or light-duty trucks with a gross vehicle weight of less than 8,500 pounds. They are the largest source of energy consumption and greenhouse gas emissions within the transportation sector.

Figure 3: Passenger Vehicle Statistics in the United States (1980-2011).

Annual statistics for cars and light trucks: vehicle sales and registrations, vehicle miles traveled (VMT), average new vehicle fuel economy, and federal fuel economy standards.

Source: ORNL. 2013. "Transportation Energy Data Book Edition 32." Oak Ridge National Laboratory. Accessed August 14, 2013. http://cta.ornl.gov/data/download32.shtml.  

Technology options to reduce fuel consumption and greenhouse gas emissions from passenger vehicles can include the following:

  • Technology improvements for conventional vehicles: The technological improvements for passenger vehicles can be grouped according to application: engine efficiency, transmission, and other improvements such as vehicle weight reduction, aerodynamic improvements, and reduced rolling resistance. One significant engine efficiency improvement, the hybrid electric vehicle, has been on the road for over a decade. There is a range of hybrids available today, and they are expected to make up about 10 percent of annual passenger vehicle sales by 2040.[2] In 2011, hybrids made up about 3 percent of the U.S. passenger vehicle market.[3]
  • Plug-in technology: All-electric vehicle, plug-in hybrid, and extended range electric vehicle technologies can eliminate or significantly reduce gasoline consumption. All-electric vehicles are very efficient vehicles that can only be powered by batteries. Extended range electric vehicles offer considerable improvements in fuel economy over conventional hybrids because a battery-powered electric motor can run the vehicle on its own, which is more energy efficient than an internal combustion engine or hybrid vehicle drivetrain. Once the battery is depleted, the vehicle’s internal combustion engine can power the vehicle, giving it a range comparable to that of a conventional vehicle. A plug-in hybrid operates like a conventional hybrid, but with a larger battery pack that is capable of powering the vehicle on its own. Key hurdles for electric vehicles include the development of batteries with higher capacity and longer durability, reducing upfront cost, and deploying needed charging infrastructure. Many electric vehicle models are now available and over 100,000 were sold in the United States between 2011 and mid-2013.[4] The EIA expects electric vehicles to make up 3.8 percent of the passenger vehicle market in 2040.[5]
  • Hydrogen fuel cells: Hydrogen fuel cell vehicles use fuel cells to produce electricity, which is then used to power the vehicle. Fuel cells promise a two- to three-fold increase in vehicle efficiency over conventional internal combustion engine vehicles and emit only water vapor in use. Similar to electric vehicles, storing enough hydrogen to obtain sufficient vehicle range before refueling is a challenge. Fuel cells also require a convenient refueling infrastructure, which does not exist today. Durability and costs of fuel cells and hydrogen production also remain challenges. (See Climate TechBook: Hydrogen Fuel Cell Vehicles)
  • Biofuels: Until electric vehicles were widely introduced in 2011, biofuels had been the primary focus of use and research for alternative fuels in the passenger vehicle market. Biofuels used currently include ethanol, biodiesel, and other fuels derived from biomass. To obtain significant reductions in greenhouse gas emissions using biofuels in passenger vehicles, a transition to advanced biofuels (e.g., cellulose for drop-in biofuels) with significantly lower greenhouse gas emission profiles will be required. (See Climate TechBook: Biofuels Overview)

Medium- and Heavy-Duty Vehicles

Medium-duty vehicles have a gross vehicle weight of 8,500 to 26,000 pounds, such as large pick-up trucks and SUVs, small buses, cargo vans, and short-haul trucks. Heavy-duty vehicles have a vehicle weight over 26,000 pounds and are used in both long-distance and local transport. Heavy-duty vehicles include long-haul trucks, large buses, and other vehicles. Medium- or heavy-duty vehicles (e.g., freight and delivery trucks) make up many commercial vehicle fleets; these fleets consume large quantities of fuel because of intensive use and the relatively low fuel economy of their vehicles. (See Climate TechBook: Medium- and Heavy-Duty Vehicles)

Table 1: Medium- and Heavy-Duty Trucks in the United States (2011).

Vehicle classes are defined by vehicle weight. Since Class 3 starts at 10,001 pounds, medium-duty vehicles that weigh between 8,500 and 10,000 pounds are not included here. Class 7-8 vehicles weigh more than 26,000 pounds.

 

Number of Registered Vehicles

Average Annual Miles per Vehicle

Average Fuel Economy (mpg)

Class 3-8 Single-Unit Trucks

7,819,000

13,239

7.3

Class 7-8 Combination Trucks

2,452,000

66,759

5.8

Source: ORNL. 2013. "Transportation Energy Data Book Edition 32." Oak Ridge National Laboratory. Accessed August 14, 2013. http://cta.ornl.gov/data/download32.shtml.

Technology options to reduce fuel consumption and greenhouse gas emissions include the following:

  • Idle reduction: A significant amount of fuel use could be avoided by reducing vehicle idling – an average tractor-trailer spends six hours each day idling to generate electricity for AC and heating systems.[6] Idle reduction technologies include several options. For example, auxiliary power units in vehicles or electrical outlets at truck stops  allow drivers to “plug in” their vehicles to operate the necessary systems. Hybrid drivetrains, similar to those used in passenger vehicles, can also help reduce idling, especially for vehicles used locally in stop-and-go traffic. In the case of buses, idle reduction technologies and strategies have the co-benefit of improving air quality in areas of heavy bus use, such as schools.
  • Vehicle efficiency improvements: Most medium- and heavy-duty vehicles have turbo-charged,[7] direct-injection diesel engines, which are the most energy-efficient internal combustion engines available. State-of-the-art turbo-charged diesel engines achieve 46 to 47 percent efficiency, versus only 25 percent for spark-ignited gasoline engines, which are used in most passenger vehicles in the United States. Options for improving medium- and heavy-duty vehicle efficiency include engine improvements, transmission enhancements, improved aerodynamics and changes in systems and logistics. Overall, existing technology improvements could reduce fuel use by new long-haul tractor-trailers by 18 to 50 percent, with the 50 percent reduction requiring about 5 years of savings to pay off.[8]
  • Low-carbon fuels: These modes can also benefit from alternative fuel use. Lower-carbon fossil fuels, such as natural gas, can reduce conventional air pollutants as well as greenhouse gas emissions.[9] For diesel-powered trucks, blends of up to 20 percent biodiesel can be used in engines without any modification. (See Climate TechBook: Biodiesel)

Aircraft

Aircraft emissions in the United States are about 8 percent of total transportation sector emissions,[10] and are expected to grow significantly in the long term. Business-as-usual projections for aircraft energy consumption growth in the United States are estimated at 0.5 percent per year from 2011 to 2040.[11]

Table 2: U.S. Certificated Air Carrier Fuel Consumption and Travel (2011)

 

Domestic operations

International operations

Aircraft-miles (millions)

6,004

1,777

Fuel consumed (million gallons)

11,071

6,523

Seats per aircraft

114.9

191.5

Aircraft-miles flown per gallon

0.54

0.27

Energy Intensity (Btu/passenger-mile)

2,638

-

Energy Intensity (Btu/vehicle-mile)

269,681

-

Source: U.S. BTS. 2013. "Table 4-8: Certificated Air Carrier Fuel Consumption and Travel." Bureau of Transportation Statistics. Accessed August 15, 2013. http://www.rita.dot.gov/bts/sites/rita.dot.gov.bts/files/publications/national_transportation_statistics/html/table_04_08.html; ORNL. 2013. "Transportation Energy Data Book Edition 32." Oak Ridge National Laboratory. Accessed August 14, 2013. http://cta.ornl.gov/data/download32.shtml.

A number of options are available to limit the growth in aviation greenhouse gas emissions. These include improved navigation systems in the near to medium term and advanced propulsion systems, lightweight materials, improved aerodynamics, new airframe designs, and alternative fuels over the medium to long term.

In the near term (to 2025), the most promising strategies for improving the efficiency of aircraft operations are improvements to the aviation system: advanced communications, navigation, surveillance, and air traffic management, as opposed to changes to aircraft themselves. These improvements have the potential to decrease aircraft fuel consumption and improve aviation operations by shortening travel distances and reducing congestion in the air and on the ground.

Over the longer term (out to 2050), efficiency improvements can be achieved by aircraft technologies including more efficient engines, advanced lightweight materials, and improved aerodynamics. Since aircraft have a much longer lifetime than on-road vehicles (30 to 40 years compared to an average of 14 years for a passenger vehicle in the United States), the fleet-wide penetration of advanced technologies will take a number of years. Early aircraft retirement programs might be able to push more rapid fleet turnover, but the potential benefits of such a program are uncertain.

The potential for fuel switching on jet aircraft is limited in the near future, compared to on-road vehicles. The only feasible options that will reduce greenhouse gas emissions are “drop-in” replacements to petroleum-based jet fuels, which include hydroprocessed renewable jet fuel (from plants or algae) and thermochemically produced Fischer-Tropsch fuels (from biomass or fossil fuel feedstocks, if produced with carbon capture and storage). These fuel production processes are being demonstrated by major carriers today, but are not being produced at commercial scale. Over the longer term, these fuels face numerous challenges with respect to production, distribution, cost, and the magnitude of greenhouse gas benefits.

Marine Transportation

Emissions from marine transportation are about 2 percent of current U.S. transportation emissions, with little domestic growth expected over the next 30 years. On the other hand, due to increases in economic activity and international trade, international marine emissions are estimated to increase by at least 50 percent over 2007 levels by 2050.

Table 3: Domestic Marine Statistics (2011)

Number of Vessels

40,521

Ton-miles (billions)

500

Tons shipped (millions)

888

Average length of haul (miles)

563.5

Source: Department of Energy (DOE), Transportation Energy Data Energy Book 32, 2013. http://cta.ornl.gov/data/chapter9.shtml.

The majority of marine vessels used for commercial operations are powered by highly efficient diesel engines.[12] These engines generally have a longer lifetime than those used in on-road transportation (30 years or more); thus, technical improvements to new engines might not reduce this sector’s emissions in the shorter term.

Immediate reductions in greenhouse gas emissions from marine vessels are available by simply reducing speed. However, reducing speed also reduces shipping capacity. To maintain shipping supply, shippers would have to perform more trips or increase ship utilization (the load factor). Although more trips could increase greenhouse gas emissions, reductions in shipping supply from reduced speeds can also be countered by increasing port efficiency and optimizing land-side intermodal transportation systems, allowing for faster ship turnaround times.

Additional optimization of shipping logistics, routing, and maintenance could reduce greenhouse gas emissions from shipping. These improvements include increased ship utilization (increased load factor), improved and more consistent maintenance practices, optimized ship control, and route planning optimized for current weather conditions and ocean currents.

Technological mitigation options for new ships, aside from alternative fuels and power, include larger ship sizes, hull and propeller optimization, more efficient engines, and novel low-resistance hull coatings. Improvements in engine design include a more flexible design utilizing a series of smaller diesel-electric engines, all optimized for a single speed, that power an electric drive.

Most alternative energy sources currently in use or under development for application in other sectors could be applied in the marine sector as well. Substituting marine diesel oil or liquefied natural gas for heavy fuel oil (i.e., residual fuel oil) currently used in ships can achieve greenhouse gas reductions. Other alternative fuel and power sources, such as biofuels, solar photovoltaic cells, and fuel cells, are longer-term options.

Other Modes

Rail transportation and buses constitute a very small percentage of current transportation sector emissions in the United States, yet growth rates of energy consumption within these modes are expected to be higher than the growth rates of other modes, with the exception of freight trucks. In the future, these modes could make use of technological advances in other sectors, such as improvements in diesel engine efficiency, hybrid technologies, and alternative fuels. For example, many metropolitan transit systems are transitioning to natural gas buses. In 2011, natural gas accounted for 20 percent of fuel consumed by transit buses.[13]

Global Context

Transportation activity and vehicle ownership is expected to grow significantly worldwide over the next several decades. The transportation sector, however, offers some of the greatest potential to alter the growth path in energy consumption, as illustrated by the expected effects of increased fuel economy and greenhouse gas standards for vehicles on overall energy consumption in the United States. Many non-OECD economies are predicted to experience rapid growth in energy consumption as transportation systems are modernized and the demand for personal motor vehicle ownership increases due to higher per capita incomes. Non-OECD transportation energy use is expected to increase by an average of 2.3 percent per year from 2010 to 2040, compared with a decrease by an average of 0.1 percent per year for transportation energy consumption in the OECD countries.[14]

Policy Options

A range of policy options is available for reducing greenhouse gas emissions from these various modes of transportation. Policies can include pricing policies, fuel economy or greenhouse gas emission standards, and funding for technology research and development.

  • Pricing policy options include feebates,[15] carbon pricing, low-carbon fuel subsidies, fuel taxes based on distance traveled, and more.
  • In the United States and worldwide, strengthening fuel economy and greenhouse gas standards has been the main mechanism for improving the efficiency of passenger vehicles. Vehicle fuel economy standards can be expressed in miles per gallon (mpg) or kilometers per liter (km/l). Vehicle emissions standards limit greenhouse gas emissions from a vehicle and are typically expressed as grams of CO2 equivalent per mile (gCO2e/mi).
  • The U.S. Environmental Protection Agency has two programs – SmartWay Tractors and Trailers and the SmartWay Transport Partnership – which are both designed to help truck owners and freight transport operators choose the most efficient vehicles and save energy and lower operating costs through improved logistics.[16]
  • Policies to address greenhouse gas emissions from international aviation and marine shipping are especially challenging, because they are produced along routes where no single nation has regulatory authority. Two broad policy options are available for controlling emissions from international transportation: continuing work under the International Civil Aviation Organization and International Marine Organization to construct an international agreement for addressing these emissions; or assigning responsibility for these emissions to parties for inclusion in national commitments to reducing greenhouse gas emissions.

Related Business Environmental Leadership Council (BELC) Company Activities

Related C2ES Resources

Plug-in Electric Vehicle Dialogue Initiative, 2011-present

Primer on Federal Surface Transportation Authorization and the Highway Trust Fund, 2011

Reducing Greenhouse Gas Emissions from U.S. Transportation, 2011

Federal Vehicle Standards

Greenhouse Gas Emissions from Aviation and Marine Transportation: Mitigation Potential and Policies, 2009

Comparison of Actual and Projected Fuel Economy for New Passenger Vehicles, 2012

Further Reading / Additional Resources

U.S. Department of Energy, Alternative and Advanced Vehicles

U.S. Department of Transportation, National Transportation Statistics

Endnotes


[1] U.S. EIA. 2013. "Annual Energy Outlook 2013." U.S. Energy Information Administration. April. Accessed August 15, 2013. http://www.eia.gov/forecasts/aeo.

[2] Ibid.

[3] Ibid.

[4] Green Car Reports. 2013. 100,000th Plug-In Electric Car In U.S. Sold Today (More Or Less). May 20. Accessed August 15, 2013. http://www.greencarreports.com/news/1084252_100000th-plug-in-electric-car-in-u-s-sold-today-more-or-less.

[5] U.S. EIA. 2013.

[6] By government mandate, long-haul truckers must rest for 10 hours after driving for 11 hours. During the rest periods, truckers might park at truck stops for several hours and idle their engines to provide their sleeper compartments with air conditioning or heating or to run electrical appliances such as refrigerators or televisions.

[7] 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.

[8] Greene, David, and Steven Plotkin. 2011. Reducing Greenhouse Gas Emissions from U.S. Transportation. Arlington, Virginia: Center for Climate and Energy Solutions.

[9] Ibid.

[10] U.S. EPA. 2013. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011. Washington, DC: U.S. Environmental Protection Agency, 2-26. Accessed July 19, 2013. http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Main-Text.pdf.

[11] U.S. EIA. 2013.

[12] These engines commonly achieve efficiencies near 50 percent, which is higher than most diesel engine applications, since ships typically operate at steady state under high load conditions.

[13] APTA. 2013. "2013 Public Transportation Fact Book." American Public Transportation Association. April. Accessed August 15, 2013. http://www.apta.com/resources/statistics/Documents/FactBook/2013-Fact-Book-Appendix-A.pdf.

[14] U.S. EIA. 2013. "International Energy Outlook." U.S. Energy Information Administration. July 25. Accessed August 15, 2013. http://www.eia.gov/forecasts/ieo

[15] A feebate can be formulated in terms of fuel economy (fuel consumption per unit distance) or greenhouse gas emissions. The manufacturer (or the purchaser) pays a fee for any vehicles produced (or purchased) that are less efficient than the target level for fuel economy or greenhouse gas emissions. The purchasers of any vehicle produced or sold that is more efficient than the target receive a rebate. The value of the fee or rebate can increase in proportion to the divergence from the targeted value. The feebate changes the initial purchase price of a vehicle, which can have a larger impact on consumer decisions than the savings from higher fuel economy alone.

[16] U.S. EPA. 2013. SmartWay. Accessed August 15, 2013. http://www.epa.gov/smartway.  

0
Teaser: 

Overview of the emissions and energy use associated with different transportation modes, including cars and light-duty trucks, medium- and heavy-duty trucks, buses, trains, ships, and aircraft

Rising Oil Prices: It’s About More Than What You Pay At The Pump

For many Americans, U.S. oil dependence has become a concern for reasons ranging from climate change and environmental protection to national security and the economic impact of higher gas prices. But there are other important impacts of our oil dependence, including how foreign oil contributes to the U.S. trade deficit and how rising oil prices decrease American jobs – both particularly salient issues on the current U.S. political agenda.  


A recent article from Daily Finance shines light on the 2010 trade deficit, more than half of which is from petroleum-related products. In 2010, the U.S. petroleum-related trade deficit was $256.9B, which represents a 29.6 percent jump from the 2009 petroleum trade deficit. This rise is largely due to increased prices, as the consumption of petroleum-related products in the United States grew by only 1.9 percent from 2009 to 2010 while the price per barrel of oil grew 31.1 percent to $74.66. An issue currently receiving a lot of attention in Washington, the $61B worth of cuts to the national budget sought by the U.S. House of Representatives, is equal to only one fourth of the country’s 2010 petroleum-related trade deficit.


Numbers that large can be hard to put into perspective, so let’s look at how this affects the average American. The graph below shows the U.S. petroleum-related trade deficit per capita (left axis), which is closely related to oil prices (right axis). In 2010 the petroleum-related trade deficit per capita was $832 and has ranged from $600 to $1200 in the past several years. This translates into each American household sending roughly $2,155 out of the U.S. economy in 2010 to pay for oil.

 

 

Rising oil prices not only increase the trade deficit, they decrease the number of jobs in America. As energy prices rise, businesses and consumers must spend more on energy and thus have less to spend elsewhere. In his presentation at our recent conference on state and federal roles in climate policy, Mark Doms, Chief Economist at the Department of Commerce, explained that when the price of oil goes up by just $10 per barrel, it translates into a loss of tens of thousands of jobs per month, or up to a quarter of a million U.S. jobs per year. Instead of losing jobs in order to maintain our use of oil, we should focus on creating jobs by investing in domestically produced alternative fuels and vehicles. 


In June 2008, oil prices spiked to $145 per barrel, and Americans paid for it at the pump as gas prices reached $4 per gallon. We could be headed into a similar situation, as oil prices rose above $105 per barrel earlier this month and are expected to continue to rise in 2011 and 2012. Because we rely on oil, a resource that is concentrated in the Organization of the Petroleum Exporting Countries or OPEC, we face oil prices that are much higher than a competitive market would yield. This makes U.S. gasoline susceptible to price shocks, and American consumers pay more at the pump than they would in a competitive market.


Here we have highlighted two other important reasons why Americans should care about rising oil prices: they increase the U.S. trade deficit and can decrease domestic jobs. As oil prices continue to rise, these negative economic trends will also worsen. In order to mitigate the impacts of rising oil prices, we need to work towards a clean energy economy and promote the use of domestic alternative fuels and energy efficiency. This would decrease our oil dependence, making the United States less susceptible to rising oil prices while also creating more jobs here at home.


Monica Ralston is is the Innovative Solutions intern

Cogeneration / Combined Heat and Power (CHP)

Quick Facts

  • Cogeneration, also known as combined heat and power (CHP), refers to a group of proven technologies that operate together for the concurrent generation of electricity and useful heat in a process that is generally much more energy-efficient than the separate generation of electricity and useful heat.
  • The typical method of separate centralized electricity generation and on-site heat generation has a combined efficiency of about 45 percent whereas cogeneration systems can reach efficiency levels of 80 percent.
  • In the United States, cogeneration has a long history in the industrial sector. Globally, industry sites in the chemicals, metal, oil refining, pulp and paper, and food processing sectors represent more than 80 percent of total global electric CHP capacity.
  • Cogeneration is widely deployed outside the United States, with Denmark, the Netherlands, and Finland leading the world in cogeneration deployment as a fraction of total national electricity generation.    
  • In 2008, cogeneration accounted for 9 percent of total U.S. electricity generating capacity. A recent study by the Oak Ridge National Laboratory calculated that increasing that share to 20 percent by 2030 would lower U.S. greenhouse gas emissions by 600 million metric tons of CO2 (equivalent to taking 109 million cars off the road) compared to “business as usual.”

Background

Cogeneration is a system of commercially available technologies that decrease total fuel consumption and related GHG emissions by generating both electricity and useful heat from the same fuel input. Cogeneration is often called combined heat and power (CHP), since most cogeneration systems are used to supply electricity and useful heat. However, the heat energy from electricity production can also be used for cooling and other non-heating purposes, so the term “cogeneration” is more inclusive. Cogeneration is a form of local or distributed generation as heat and power production take place at or near the point of consumption. For the same output of useful energy, cogeneration uses far less fuel than does traditional separate heat and power production, which means lower greenhouse gas (GHG) emissions as fossil fuel use is reduced.

While this document focuses on the GHG emission reductions, cogeneration offers other benefits that include:

  • Reducing other air pollutants (e.g., SO2, NOX, Hg)
  • Providing on-site electricity generation that is resilient in the face of grid outages thus providing power for critical services in emergencies and avoiding economic losses
  • Avoiding or deferring investments in new electricity transmission and distribution infrastructure and relieving congestion constraints on existing infrastructure.
  • Using existing industrial and commercial sites for incremental power generation rather than building new power plant capacity at greenfield sites

The largest potential for increased utilization of cogeneration is in the industrial sector. In the United States, the industrial sector is responsible for approximately one third of the country’s total energy consumption.[1]  The industrial sector’s direct GHG emissions account for 20 percent of the U.S. total, and an additional 9 percent of U.S. GHG emissions come from centrally generated electricity consumed in the industrial sector.[2] Direct industrial emissions come from on-site combustion of fossil fuels and from non-energy related process emissions.

While the greatest potential for increasing cogeneration is in the industrial sector, the technology is also increasingly available for smaller-scale applications in residential and commercial facilities. Cogeneration systems appeal to business operations requiring a continuous supply of reliable power such as data centers, hospitals, universities, and industrial operations.  District heating and cooling (DHC) in cities and large institutions is one established use of cogeneration (and one widely employed in Europe) in the residential and commercial sectors. District heating can meet low and medium temperature heat demands, such as space heating and hot tap water preparation, by using waste heat from electricity generation to heat water that is transported through insulated pipes. District cooling takes advantage of natural cooling from deep water resources as well as the use of waste heat to cool water via absorption chillers. About 85 urban utilities and 330 campuses in the United States use district energy to reduce costs and GHG emissions, increase efficiency, and improve reliability.[3]     

Description

Separate heat and power (SHP) refers to the widespread practice of centrally generating electricity at large-scale power plants and separately generating useful heat onsite for applications such as industrial processes or space and water heating. SHP leads to energy losses in both processes. In the United States, conventional coal and natural gas power plants are, on average, 33 and 41 percent efficient, respectively, in converting the energy in their fuel into electricity; although, the efficiency rates vary by technology with new natural gas combined cycle plants capable of greater than 50 percent efficiency.[4] Typical SHP has a combined efficiency of about 45 percent while cogeneration systems that combine the power and heat generation processes can be up to 80 percent efficient.[5] Because cogeneration takes place on-site or close to the facility it also results in less energy lost during the transmission and distribution process (usually about 9 percent of net electricity generation).[6]    

Figure 1 provides a helpful comparison of illustrative CHP and SHP systems and shows the energy inputs each would require to ultimately produce the same amount of useful energy. 

Figure 1: CHP versus Separate Heat and Power (SHP) Production

Source: U.S. EPA: Combined Heat and Power Partnership, “Efficiency Benefits.”
Note: This figure shows an example where cogeneration uses only 100 units of fuel to produce an amount of electricity and useful heat that would require 154 units of fuel via separate heat and power production.

Cogeneration systems can be powered by a variety of fuels, including natural gas, coal, oil, and alternative fuels such as biomass. In recent years, natural gas has been the predominant fuel for CHP systems, but biomass and ”opportunity fuels” (i.e., wastes or by-products from industrial processes, agriculture, or commercial activities) are expected to gain a larger share with growing environmental and energy security concerns.[7],[8]  Some cogeneration technologies can operate with multiple fuel types, making the system less vulnerable to fuel availability and volatile commodity prices.    

Cogeneration is appropriate in situations where a facility has a continuous demand for heating or cooling as well as demand for electrical or mechanical power. Cogeneration systems can provide electricity or mechanical power (e.g., for driving rotating equipment like compressors, pumps, and fans) and heat energy that can be used for: steam or hot water; process heating, cooling and refrigeration; and dehumidification.[9]

Cogeneration Process
There are two types of cogeneration—“topping cycle” and “bottoming cycle.” The most common type of cogeneration is the “topping cycle” where fuel is first used to generate electricity or mechanical energy at the facility and a portion of the waste heat from power generation is then used to provide useful thermal energy. The less common “bottoming cycle” type of cogeneration systems first produce useful heat for a manufacturing process via fuel combustion or another heat-generating chemical reaction and recover some portion of the exhaust heat to generate electricity. “Bottoming-cycle” CHP applications are most common in process industries, such as glass and steel, that use very high temperature furnaces that would otherwise vent waste heat to the environment. The following description of cogeneration systems focus on “topping cycle” applications.

Each cogeneration system is adapted to meet the needs of an individual building or facility. System design is modified based on the location, size, and energy requirements of the site. Cogeneration is not limited to any specific type of facility but is generally used in operations with sustained heating requirements. Most CHP systems are designed to meet the heat demand of the energy user since this leads to the most efficient systems. Larger facilities generally use customized systems, while smaller-scale applications can use prepackaged units.  

Cogeneration systems are categorized according to their prime movers (the heat engines), though the systems also include generators, heat recovery, and electrical interconnection components. The prime mover consumes (via combustion, except in the case of fuel cells discussed below) fuel (such as coal, natural gas, or biomass) to power a generator to produce electricity, or to drive rotating equipment. Prime movers also produce thermal energy that can be captured and used for other on-site processes such as generating steam or hot water, heating air for drying, or chilling water for cooling. There are currently five primary, commercially available prime movers: gas turbines, steam turbines, reciprocating engines, microturbines, and fuel cells.

Steam turbines and gas, or combustion, turbines are the prime movers (heat engines) best suited for industrial processes due to their large capacity and ability to produce the medium- to high-temperature steam typically needed in industrial processes.[10]

Gas Turbines
Gas turbines typically have capacities between 500 kilowatts (kW) and 250 megawatts (MW), can be used for high-grade heat applications, and are highly reliable.[11]Gas turbines operate similarly to jet engines—natural gas is combusted and used to turn the turbine blades and spin an electrical generator. The cogeneration system then uses a heat recovery system to capture the heat from the gas turbine’s exhaust stream. This exhaust heat can be used for heating (e.g., for generating steam for industrial processes) or cooling (generating chilled water through an absorption chiller). About half of the CHP capacity in the United States consists of large combined cycle systems that include two electricity generation steps (the combustion turbine and a steam turbine powered by heat recovered from the gas turbine exhaust) that supply steam to large industrial or commercial users and maximize power production for sale to the grid. Figure 2 shows how a simple-cycle gas turbine cogeneration system recovers heat from the gas turbine’s hot exhaust gases to produce useful thermal energy for the site.

Figure 2: Gas Turbine or Engine with Heat Recovery Unit

Source: U.S. EPA – Combined Heat and Power Partnership: Basic Information.
Note: Figure 2 shows a gas turbine cogeneration system, with the heat recovery unit capturing exhaust heat from the turbine, and converting that to thermal energy for other uses.

Steam Turbines
Steam turbines systems can use a variety of fuels, including natural gas, solid waste, coal, wood, wood waste, and agricultural by-products. Steam turbines are highly reliable and can meet multiple heat grade requirements. Steam turbines typically have capacities between 50 kW and 250 MW and work by combusting fuel in a boiler to heat water and create high-pressure steam, which turns a turbine to generate electricity.[12]The low-pressure steam that subsequently exits the steam turbine can then be used to provide useful thermal energy, as shown in Figure 3. Ideal applications of steam turbine-based cogeneration systems include medium- and large-scale industrial or institutional facilities with high thermal loads and where solid or waste fuels are readily available for boiler use.

Figure 3: Steam Boiler with Steam Turbine

Source: US EPA – Combined Heat and Power Partnership: Basic Information.
Note: Figure 3 shows how a cogeneration system that is primarily heat based, can also be used to generate electricity.

Reciprocating Engines
In terms of the number of units, reciprocating internal combustion engines are the most widespread technology for power generation, found in the form of small, portable generators as well as large industrial engines that power generators of several megawatts; however, because of their small size, reciprocating engines account for only a small share (about 2 percent) of total U.S CHP capacity.[13]Spark ignition (SI) engines are the most common types of reciprocating engines used for CHP in the United States. SI engines (available in capacities up to 5 MW) are similar to gasoline-powered automobile engines, but they generally run on natural gas, though they can also run on propane or landfill and biogas. 

Reciprocating engines start quickly, follow load well, have good efficiencies even when operating at partial load, and generally have high reliabilities.[14]Reciprocating engines are well suited for CHP in commercial and light industrial applications of less than 5 MW. Smaller engine systems produce hot water. Larger systems can be designed to produce low-pressure steam. Multiple reciprocating engines can be used to increase system capacity and enhance overall reliability.

Microturbines
Microturbines are small, compact, lightweight combustion turbines that typically have power outputs of 30 to 300 kW. A heat exchanger recovers thermal energy from the microturbine exhaust to produce hot water or low-pressure steam. The thermal energy from the heat recovery system can be used for potable water heating, absorption cooling, dessicant dehumidification, space heating, process heating, and other building uses. Microturbines can burn a variety of fuels including natural gas and liquid fuels. 

Fuel Cells
Fuel cells are an emerging technology with the potential to serve power and thermal needs with very low emissions and with high electrical efficiency. Fuel cells use an electrochemical or battery-like process to convert the chemical energy of hydrogen into water and electricity. The hydrogen can be obtained from processing natural gas, coal, methanol, and other hydrocarbon fuels. As a less mature technology, fuel cells have high capital costs, an immature support infrastructure, and technical risk for early adopters. However, the advantages of fuel cells include low emissions and low noise, high power efficiency over a range of load factors, and modular design. A variety of fuel cell technologies are under development, with some targeted for small commercial markets, and other technologies focused on larger, industrial CHP applications. 

Environmental Benefit / Emission Reduction Potential

Cogeneration offers multiple environmental benefits. Since less fuel is burned per unit of useful energy output, cogeneration reduces GHG emissions and decreases air pollution compared to SHP systems. Currently installed cogeneration systems avoid the equivalent of 1.8 percent of annual U.S. energy consumption and annual CO2 emissions of 248 million metric tons (equal to 3.5 percent of total U.S. GHG emissions in 2007).[15],[16]A recent study by the Oak Ridge National Laboratory (ORNL) calculated that increasing cogeneration’s share of total U.S. electricity generation capacity to 20 percent by 2030 (which ORNL estimated would require deploying 156 GW of new cogeneration capacity compared to about 85 GW today) would lower U.S. GHG emissions by 600 million metric tons of CO2 (equivalent to taking 109 million cars off the road) compared to “business as usual.”[17]

While the ORNL analyzed an ambitious goal for expanding cogeneration by 2030, a 2009 study by McKinsey & Company sought to estimate the cost-effective potential for expanding cogeneration by 2020 (i.e., the potential to make NPV-positive investments in cogeneration).[18]McKinsey estimated that the potential exists in the United States for an additional 50.4 GW of cogeneration capacity by 2020, which would avoid an estimated 100 million metric tons of CO2 per year compared to “business as usual.” McKinsey found that the cost-effective incremental cogeneration capacity consisted primarily (70 percent) of large-scale (greater than 50 MW) industrial cogeneration systems. Figure 4 shows McKinsey’s estimates of the composition of cost-effective cogeneration potential for 2020.

Figure 4: McKinsey’s Estimates of Cost-Effective Cogeneration Potential for 2020 by Sector[19]

Cost

Cogeneration systems are major investments. For example, the capital cost of a 50 MW gas turbine cogeneration system might be on the order of $45 million, and such a cogeneration system might take 6-18 months to construct.[20] A 1 MW reciprocating engine cogeneration system (e.g., for a hospital) might have a capital cost of roughly $1.6 million.[21] The cost of a cogeneration system depends on the level of complexity of features beyond the basic prime mover – such as the heat recovery or emissions monitoring systems (as well as location, labor, and the financial carrying costs during construction). Generally, with the same fuel and configuration, costs for cogeneration systems per kilowatt of capacity decrease as size increases. Given the efficiency gains from cogeneration, some analysts estimate that GHG emission reductions can be achieved at a “negative cost” via cogeneration in many instances since cost savings from reduced expenditures on fuel (due to the higher efficiency of cogeneration compared to separate heat and power generation) will outweigh the capital and other costs of cogeneration projects.[22]

Current Status of Cogeneration

Cogeneration currently accounts for roughly 12 percent of total U.S. electricity generation and comprises about 9 percent (85 gigawatts at about 3,300 sites) of total generating capacity.[23] Figures 5-8 show how existing cogeneration capacity is distributed across different applications, system technology types, and fuel inputs. Only about 12 percent of existing cogeneration capacity is deployed at commercial or institutional facilities (as opposed to industrial or manufacturing facilities). Nearly three quarters of cogeneration capacity uses natural gas for fuel, and gas-fired combustion turbines and combined cycle systems dominate cogeneration capacity even though nearly half of all cogeneration sites use reciprocating engines (the reciprocating engines are much smaller in terms of capacity than the other systems). Large cogeneration systems (100 megawatts or more in capacity) account for roughly 65 percent of total cogeneration capacity.[24]

Figure 5: Existing Cogeneration Capacity by Application[25]

Figure 6: Existing Cogeneration Sites by System Type[26]

Figure 7: Existing Cogeneration Capacity by System Type[27]

Figure 8: Existing Cogeneration Capacity by Fuel Type[28]

 

Current U.S. cogeneration capacity is largely concentrated in states with large industrial heat consumption (see Table 1), such as for petrochemical and petroleum refining operations. Texas alone has one fifth of the total U.S. cogeneration installed capacity, and the top five states in terms of installed capacity account for half of the U.S. total.[29] State air pollution regulations that use output-based standards and state-level incentives for cogeneration also promote cogeneration in certain states.

Cogeneration projects multiplied in the United States following the passage of the Public Utilities Regulatory Policies Act (PURPA) in 1978. PURPA required utilities to interconnect with and purchase electricity from “qualified facilities” like cogeneration systems thus giving industrial and institutional users access to the grid and the ability to sell back excess electricity. Shortly after enactment of PURPA, Congress also created federal tax credits for CHP investments. Following the enactment of PURPA and the CHP tax credits, cogeneration grew dramatically with capacity increasing more than three-fold in two decades (from about 20 gigawatts in 1978).[30] 2006 through 2009 saw much lower levels of cogeneration deployment than historical growth rates owing in part to higher natural gas prices and economic uncertainty.[31] One factor affecting the growth of CHP was the change to PURPA regulations that resulted from the Energy Policy Act of 2005. As instructed by the act, the Federal Energy Regulatory Commission (FERC) issued new rules that no longer required utilities to buy electricity from larger “qualified facilities” when those facilities have access to competitive electricity markets, and FERC issued rules to ensure that new CHP “qualified facilities” were not mainly electricity-generating facilities taking advantage of the incentives offered to CHP facilities (so-called “PURPA machines”).[32]

Table 1: Cogeneration Installed Capacity by State, 2006[33]

Rank

State

Total Capacity (MW)

% of U.S. Total

1

TX

17,240

20%

2

CA

9,220

11%

3

LA

6,959

8%

4

NY

5,789

7%

5

FL

3,545

4%

6

NJ

3,493

4%

7

AL

3,362

4%

8

PA

3,242

4%

9

MI

3,104

4%

10

OR

2,523

3%

Rest of U.S.

26,523

31%

 

Recent federal legislation, including the Energy Improvement and Extension Act of2008 (EIEA) and the American Recovery and Reinvestment Act of 2009 (ARRA), encourages wider deployment of cogeneration with tax incentives for cogeneration projects (the CHP investment tax credit and accelerated depreciation) and substantial funding for select CHP projects.[34]

Globally, cogeneration is in widespread use, especially in the European Union (EU). Five EU countries rely on cogeneration for between 30 to 50 percent of their total power generation, andcogeneration has contributed to 57 million metric tons of CO2e, or 15 percent, of Europe’s overall GHG emission reductions from 1990 to 2005.[35],[36] Globally, industry sites in the chemicals, metal, oil refining, pulp and paper, and food processing sectors represent more than 80 percent of total global CHP capacity.[37]Cogeneration currently accounts for approximately 13 and 5 percent of total electricity generation capacity in China and India, respectively.[38] The International Energy Agency (IEA) projects that by 2030, Chinese and Indian cogeneration penetration could rise to 28 and 26 percent, respectively, with adequate policy and market incentives.[39] In China, cogeneration has significant growth potential given the country’s large industrial base. IEA projected that under aggressive international efforts to reduce GHG emissions, global industrial cogeneration could quadruple from 2005 to 2050 as compared to merely doubling under “business as usual.”[40]

Obstacles to Further Development or Deployment of Cogeneration

  • Capital Constraints

Cogeneration systems are large capital investments. Firms may be unwilling to undertake such significant capital investments even when they may offer positive returns. Another cost consideration for firms is business uncertainty. If a firm is not confident that it will continue operations for many years at a given facility, it may not invest in the high upfront costs of cogeneration since a project’s economic viability can depend on cost savings realized over several years. In addition, there can be costs associated with manufacturing downtime and siting and permitting issues.Also, seamless integration of components beyond the basic equipment can necessitate specialized parts and increase the cost of a cogeneration system.[41]

  • Utility Business Practices  

Many cogeneration systems maintain their connection to the utility grid for supplemental power needs beyond their self generation capacity and/or for standby and back-up service during routine maintenance or unplanned outages. Utility charges for these services (standby rates) can significantly reduce the money-saving potential of cogeneration.[42] However, cogeneration and other types of distributed energy allow the grid to function more efficiently by reducing baseload and peak demand, as well as reducing the need for transmission and distribution upgrades and construction. Pricing arrangements between utilities and cogeneration system operators that fairly account for utilities’ obligation to supply backup power as well as the benefits to the grid of cogeneration (e.g., avoided costs of building new generation and transmission capacity) can encourage cogeneration investments.   

  • Utility Interconnection

The economic viability of cogeneration systems depends on their ability to safely, reliably, and economically interconnect with the existing grid. Interconnection standards, including technical specifications as well as application processes and fees, between utilities and cogeneration systems are often state mandated and vary regionally. This lack of uniformity makes it difficult for manufacturers of cogeneration technologies to produce modular components and can make cogeneration system deployment more complicated and expensive. Improved interconnection policies could increase deployment of cogeneration systems.[43],[44]

  • Environmental Permitting Regulations

By generating both electricity and heat onsite, cogeneration can increase a facility’s onsite air emissions even as it reduces total emissions associated with the facilities heat and electricity consumption. Current environmental permitting regulations do not always recognize this overall emissions reduction benefit. For example, the Clean Air Act’s New Source Review (NSR) requires large, stationary sources to install best available pollution control equipment during construction or major modifications that increase onsite emissions. In some circumstances NSR requirements can discourage installation of CHP systems even when they would improve environmental outcomes.[45] The adoption of output-based emission standards, which allows cogeneration systems to benefit from their increased efficiency, is one way to encourage more cogeneration systems.   

  • Need for Further Research, Development, and Demonstration (RD&D)

To improve the performance of cogeneration technologies and reduce investment costs, further RD&D is warranted, specifically in the areas of: high-temperature CHP, small-scale systems (e.g., improving the efficiency of micro-turbines and their cost through improved manufacturing techniques), fuel cell research, heat & cold storage system optimization and integration, and medium-scale systems (e.g., increased demonstration of medium-scale turbines in various industrial settings).[46]

Policy Options to Help Promote Cogeneration

  • Price on Carbon

Policies that set a price on GHG emissions, such as a GHG cap-and-trade program (see Climate Change 101: Cap and Trade), can encourage investment in energy-efficient technology such as cogeneration. Carbon pricing policies (e.g., cap and trade allowance allocation) can be designed so as not to create disincentives for cogeneration.[47]

  • Renewable Portfolio and Energy Efficiency Resource Standards

Renewable Portfolio Standards and Energy Efficiency Standards require that energy providers meet a specific portion of their electricity demand through renewable energy and/or energy efficiency measures. Such policies specify eligible energy sources and technologies that count towards the requirements. More than a dozen states allow cogeneration to count toward renewable/alternative energy and efficiency standards.[48]  

  • Financial Incentives for Cogeneration

Certain states already offer investment tax credits (ITC), which are a form of subsidy to help offset the upfront capital cost of investments, for cogeneration, and the federal government also offers a 10 percent ITC for cogeneration (enacted in 2008) and accelerated depreciation.[49] Some states offer production incentives, which provide a financial benefit based upon the annual useful energy output of the cogeneration system.

  • Interconnection Standards

Coordination among state and federal regulators, utilizes, and stakeholder groups regarding best practices in cogeneration interconnection with the electric grid can help ensure cogeneration interconnection contributes to a safe and reliable grid and minimize the cost and complexity facing cogeneration technology providers and users designing and deploying systems for interconnection.

  • Environmental Permitting

Cogeneration is more readily deployed when environmental regulations do not penalize cogeneration systems that increase onsite air emissions (by using more fuel onsite to generate both electricity and heat) while also decreasing net air emissions by having higher efficiency (and thus less total fuel use) than separate heat and power generation.[50]

  • Research, Development, and Demonstration (RD&D)

Continued and increased funding for programs such as the Department of Energy’s Industrial Technologies Program (ITP)[51] would support RD&D for cogeneration technologies to improve reliability and efficiency and reduce costs. ITP’s public-private partnerships help future deployment of both integrated energy systems and component technologies (for upgrading and retrofits).

  • Technical Assistance for Potential Cogeneration Users

Many companies (especially small and medium-sized businesses) that would benefit from cogeneration systems are not aware of their financial or technical options. Expanding programs that work with companies such as the U.S. Environmental Protection Agency’s Combined Heat and Power Partnership,[52] the National Institute of Standards Manufacturing Extension Partnership,[53] and DOE’s Industrial Assessment Centers and CHP Regional Application Centers[54] would help further promote cogeneration.

Related Business Environmental Leadership Council (BELC) Company Activities

Air Products

Alstom

Cummins

Dow Chemical Company

GE

PG&E

Weyerhaeuser

Related C2ES Resources

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

Corporate Energy Efficiency Project

Further Reading / Additional Resources

American Council for an Energy Efficient Economy (ACEEE), “Combined Heat and Power (CHP)

Gas Technology Institute (GTI)

Hedman, Bruce, ICF International, “CHP: The State of the Market,” presentation to the U.S. EPA Combined Heat and Power Partnership 2009 Partners Meeting, 1 October 2009.

International Energy Agency, “Combined Heat and Power: Evaluating the Benefits of Greater Global Investment,” 2008.

McKinsey & Company

Reducing U.S. Greenhouse Gas Emissions: How Much at What Cost?, 2007

Unlocking Energy Efficiency in the U.S. Economy, 2009

New York State Energy Research and Development Authority (NYSERDA), “Combined Heat and Power Program Guide.”

Oak Ridge National Laboratory, Combined Heat & Power: Effective Energy Solutions for a Sustainable Future, 2008

U.S. Combined Heat and Power Association (USCHPA)

U.S. Department of Energy

Case Studies Database

Combined Heat and Power (CHP) Regional Application Centers (RACs)

Industrial Distributed Energy

U.S. Environmental Protection Agency

Catalog of CHP Technologies

CHP Partnership Program



[1]U.S. Energy Information Administration (EIA), Annual Energy Review 2009, Table 1.2a: Energy Consumption by Sector, Selected years 1949 – 2008.

[2]U.S. Environmental Protection Agency (EPA), Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007, Table ES-7, 2009.

[3]Environmental and Energy Study Institute, “The Role of District Energy/Combined Heat and Power in Energy and Climate Policy Solutions,” 2009.

[4]EIA, Electric Power Annual, 2010, see Table 5.3and Table 5.4. New natural gas combined cycle plant efficiency estimate comes from EIA’s Assumptions to the Annual Energy Outlook 2010 (see table 8.2).

[7]ORNL, 2008.

[8] For more information on “opportunity fuels,” see Resource Dynamics Corporation, 2004, Combined Heat and Power Market Potential for Opportunity Fuels, prepared for the Department of Energy.

[9]ORNL, 2008.

[13]ORNL, 2008.

[14]Part-load efficiency refers to the efficiency when equipment is running below its rated level of output.

[18]McKinsey & Company, Unlocking Energy Efficiency in the U.S. Economy, 2009. NPV refers to net present value, which, for a cogeneration project in McKinsey’s analysis, is the discounted value of future cost savings (e.g., from avoided electricity generation by utilities) net of incremental costs associated with cogeneration (e.g., up-front capital and installation costs, ongoing maintenance costs, and fuel costs).

[20]EPA, “Catalog of CHP Technologies: Gas Turbines,” 2008, see Table 3.

[23]ORNL, 2008.

[24]ORNL, 2008.

[25]ORNL, 2008.

[26]ORNL, 2008.

[27]ORNL, 2008.

[28]ORNL, 2008.

[29]ORNL, 2008.

[30]ORNL, 2008.

[31]Hedman, Bruce, ICF International, “CHP: The State of the Market,” presentation to the U.S. EPA Combined Heat and Power Partnership 2009 Partners Meeting, 1 October 2009.

[33]ORNL, 2008.

[35]Denmark, Finland, Russia, Latvia, and the Netherlands, IEA, “Combined Heat and Power,” 2008. 

[37]IEA, Energy Technology Perspectives 2008: Scenarios & Strategies to 2050, 2008.

[40]IEA, Energy Technology Perspectives 2008: Scenarios & Strategies to 2050, 2008.

[41]The necessitated tailoring of cogeneration systems due to a lack of factory-integrated components requires extensive project engineering, which adds to the costs and increases risk of assimilation errors.  Site-specific priorities determine the design-basis for sizing a CHP system.  NYSERDA, “Public Policy Issues and Hurdles to Implementing CHP in NYS.”

[42]ACEEE, “Standby Rates.”

[43]California Energy Commission (CEC), “Exploring Feed-in Tariffs for California.”

[44]The Economist, “Building the Smart Grid,”4 June 2009.

[45]ORNL, 2008.

[47]For example, investing in cogeneration will increase a facility’s direct GHG emissions even though it will reduce total emissions due to the improved efficiency of cogeneration. For a discussion of how to avoid creating disincentives for cogeneration under cap and trade, see Colvin, Michael, “Combined Heat and Power and Cap & Trade,” California Public Utilities Commission, presentation materials for ARB public meetings, 9 September 2009. 

[48]For more information on such state policies, see C2ES’s “Renewable and Alternative Energy Portfolio Standards.”

[49]For more information on the federal ITC for cogeneration and relevant state incentives, see the Database of State Incentives for Renewables and Efficiency (DSIRE).

[50]For more information on this topic, see EPA’s Output-Based Regulations: A Handbook for Air Regulators, 2004.

[51]DOE, Industrial Technologies Program web site.

[52]EPA, Combined Heat and Power Partnership web site.

[53]Manufacturing Extension Partnership web site.

[54]See the CHP Regional Application Centers web site

 

The combined genration of electricity and useful heat can substantially improve efficiency and lower GHG emissions compared to separate heat and power generation.
0
Teaser: 

The combined genration of electricity and useful heat can substantially improve efficiency and lower GHG emissions compared to separate heat and power generation.

What's The Car Of 2035?

This blog post also appeared on Edmunds Auto Observer


In movies like the iconic Demolition Man, we’re led to believe the future will be filled with cars well advanced from those on the road today (in the case of the Sylvester Stallone action flick, our cars will instantly fill with foam upon a collision). But what do the real experts think about the cars we’ll be driving in the future? For example, will our cars drive themselves like Google’s modified Toyota Prius?


We answer some of these questions in our recently released report that focuses on reducing the U.S. transportation sector's greenhouse gas emissions and oil use. The report details options available to automakers for building the cars of the future. It doesn’t attempt to predict the makeup of the car market in the future – that’s up to the consumer. Instead, the report highlights that many combinations of vehicles could significantly reduce oil use and greenhouse gas emissions in the future.

Event: 2011 Greening Your Business Conference

Promoted in Energy Efficiency section: 
Promoted in Energy Efficiency section
The Pew Center on Global Climate Change will moderate the Keynote presentation from 4 PM to 5PM. To register for the event, please visit Greening Your Business Conference website for more information.

The Minneapolis Regional Chamber of Commerce will host The 2011 Greening Your Business Conference on April 14, 2011. This conference provides the opportunity to reach business decision makers who are interested in learning more about sustainable and eco-friendly products and services that can be implemented in the workplace.

The Pew Center on Global Climate Change will moderate the Keynote presentation from 4 PM to 5PM. To register for the event, please visit Greening Your Business Conference website for more information.

Hydrogen Fuel Cell Vehicles

Quick Facts

  • Hydrogen fuel cell vehicles (FCVs) have a significant potential to reduce emissions from the transportation sector, because they do not emit any greenhouse gases (GHGs) during vehicle operation. Their lifecycle GHG emissions depend on how the hydrogen fuel is made.
  • A future mid-size car in the 2035-2045 time frame, powered by fuel cells and using hydrogen generated from natural gas, is projected to have lifecycle GHG emissions slightly lower than that for a hybrid electric vehicle (HEV), powered by gasoline. A fuel cell vehicle would produce 200 grams of carbon dioxide-equivalent per mi (CO2e/mi), compared to 235g CO2e/mi for a HEV. An FCV would have near-zero lifecycle GHG emissions if the hydrogen were made, for example, from electrolysis powered by renewable electricity.
  • Several major hurdles to commercial deployment must be overcome before any environmental benefits from FCVs are realized. These challenges include the production, distribution, and storage of hydrogen; fuel cell technology; and overall vehicle cost.

Background

Hydrogen FCVs are a potential option for reducing emissions from the transportation sector. Combusting fossil fuels to power conventional vehicles releases GHG emissions and other pollutants from the vehicle exhaust system (i.e., “tailpipe” emissions). In addition, there are also emissions associated with producing petroleum-based fuels (i.e., “upstream” emissions), notably emissions from oil refineries. FCVs emit no tailpipe GHGs or other pollutants during vehicle operation, and depending on how hydrogen is produced, there can be substantially lower upstream GHG emissions associated with producing hydrogen fuel.

Fuel cells are already used to generate electricity for other applications, including in spacecraft and in stationary uses, such as emergency power generators. Although the concept of a fuel cell was developed in England in the 1800s, the first workable fuels cells were not produced until much later, in the 1950s. During this time, interest in fuel cells increased, as NASA began searching for ways to generate power for space flights.[1]

Hydrogen FCVs are considered one of several possible long-term pathways for low-carbon passenger transportation (other options include vehicles powered by electricity and/or biofuels). The benefits of hydrogen-powered vehicles include the following:

  • High energy efficiency of fuel cell drivetrains, which use 40 to 60 percent of the energy available from hydrogen, compared to internal combustion engines, which currently use only about 20 percent of the energy from gasoline;[2]
  • Diverse methods by which hydrogen can be produced (see Box 1 below);
  • Unlike all-electric vehicles (EVs), comparable vehicle range and refueling time to gasoline vehicles;
  • Similar to EVs, quick starts due to high torque from the electric motor and low operating noise; and
  • Lack of any GHG emissions and few other air pollutants during vehicle operation[3]and the potential for very low or no upstream GHG emissions associated with hydrogen fuel production.

Yet several key hurdles must be overcome before the introduction of FCVs on a large scale can become possible. These challenges include the production, distribution, and storage of hydrogen; fuel cell technology; and overall vehicle cost.

Description

FCVs resemble normal gasoline or diesel-powered vehicles from the outside. Similar to EVs, they use electricity to power a motor that propels the vehicle. Yet unlike EVs, which are powered by a battery, FCVs use electricity produced from on-board fuel cells to power the vehicle.

An FCV includes four major components:[4]

  1. Fuel cell stack: The fuel cell is an electrochemical device that produces electricity using hydrogen and oxygen. In very simple terms, a fuel cell uses a catalyst to split hydrogen into protons and electrons, the electrons then travel through an external circuit (thus creating an electric current), and the hydrogen ions and electrons react with oxygen to create water.

To obtain enough electricity to power a vehicle, individual fuel cells, like the one described below, are combined in series to make a fuel cell stack. There are several different types of fuel cells, each of which is suited for a different application. Fuel cells are typically grouped according to their operating temperature and the type of electrolyte used.[5] The amount of power generated by a fuel cell is determined by several factors including fuel cell type, size, operating temperature, and pressure at which the gases are supplied to the cell.[6] The most common type of fuel cell used in FCVs is polymer electrolyte membrane (PEM).[7]

A fuel cell is composed of an electrolyte,[8] placed between an anode (a negative electrode) and a cathode (a positive electrode), with bipolar plates on either side. A fuel cell works as follows:[9]

  • First, the hydrogen gas flows to the anode. Here, a platinum catalyst is used to separate the hydrogen molecule into positive hydrogen ions (protons) and negatively charged electrons.[10]
  • The PEM allows only the protons to pass through to the cathode, while the electrons travel through an external circuit to the cathode. The flow of electrons through this circuit creates the electric current (or electricity) used to power the vehicle motor.
  • On the other side of the cell, oxygen gas, usually drawn from the outside air, flows to the cathode.
  • When the electrons return from the external circuit, the positively charged hydrogen ions and electrons react with oxygen in the cathode to form water, which then flows out of the cell. The cathode also uses a platinum catalyst to enable this reaction.

 

Figure 1: Diagram of a fuel cell. 

Source: http://www.fueleconomy.gov/feg/fcv_PEM.shtml

  1. Hydrogen storage tank: Instead of a gasoline or diesel tank, an FCV has a hydrogen storage tank. The hydrogen gas must be compressed at extremely high pressure at 5,000 to 10,000 pounds per square inch (psi) to store enough fuel to obtain adequate driving range. In comparison, compressed natural gas (CNG) vehicles use high-pressure tanks at only 3,000 to 3,600 psi.[11]

FCVs can also be powered by a secondary fuel – e.g., methanol, ethanol, or natural gas – which is converted into hydrogen onboard the vehicle. Vehicles powered through a secondary fuel emit some air pollutants during operation due to the conversion process.[12]

  1. Electric motor and power control unit: The power control unit governs flow of electricity in the vehicle. By drawing power from either the battery or the fuel cell stack, it delivers electric power to the motor, which then uses the electricity to propel the vehicle.
  2. Battery: Like HEVs, FCVs also have a battery that stores electricity generated from regenerative braking,[13] increasing the overall efficiency of the vehicle.[14]The size and type of these batteries, similar to those in HEVs, will depend on the “degree of hybridization” of the vehicle, i.e., how much of the power to propel the vehicle comes from the battery and how much comes from the fuel cell stack.[15]

Environmental Benefit/Emission Reduction Potential

Because FCVs are more energy efficient than vehicles powered by gasoline and because hydrogen as a transportation fuel can have much lower lifecycle GHG emissions than fossil fuels, FCVs have the potential to dramatically reduce GHG emissions and other air pollutants from the transportation sector.

FCVs are more energy efficient than gasoline-powered vehicles. A fuel cell uses about 40 to 60 percent of the available energy in hydrogen. Internal combustion engines use only about 20 percent of the energy available in gasoline, although this is expected to improve over the long term.[16] EVs are more efficient than FCVs, using about 75 percent of available energy from the batteries.[17]

There are two models of FCVs available currently but with limited distribution, and these models’ fuel economy ratings illustrate the higher efficiency of FCVs. The Honda FCX Clarity for model year 2011 has a fuel economy equivalent to 60 miles per gallon of gasoline (mpg), while the 2011 Mercedes-Benz F-Cell has a fuel economy of 53 mpg.[18] In comparison, the average fuel economy for passenger cars from model year 2010 is 33.8 mpg for a gasoline vehicle,[19] and the most efficient HEV from the same model year has a fuel economy rating of 50 mpg.[20]

In addition to being more energy efficient than gasoline-powered vehicles, FCVs can also have much lower lifecycle GHG emissions compared to vehicles fueled by petroleum-based fuels. FCVs emit only heat and water during operation (i.e., no tailpipe GHGs). Lifecycle GHG emissions from FCVs thus depend, mainly, on the process used to produce hydrogen. Hydrogen can be produced from fossil fuels (coal and natural gas), nuclear, renewable energy technologies (wind, solar, geothermal, biomass), and hydroelectric power (see Box 1 for more information).

Lifecycle GHG emissions for an FCV are the sum of emissions from the production and distribution of hydrogen, the production of the vehicle, and vehicle operation. Estimates made for the U.S. Department of Energy (DOE) project that a future mid-size FCV (in the years 2035 to 2045), powered by hydrogen from natural gas, will have lifecycle GHG emissions slightly lower than that for an HEV, powered by gasoline (200g CO2e/mi compared to 235g CO2e/mi).[21] Another study, from the Massachusetts Institute of Technology (MIT), found similar results: lifecycle emission from an FCV, using hydrogen produced from natural gas, would be comparable to those from a hybrid vehicle.[22]

With hydrogen produced using less carbon-intensive methods – coal gasification with CCS, biomass gasification, or electrolysis powered by nuclear power or renewable – lifecycle GHG emissions would drop significantly. With biomass gasification or electrolysis, lifecycle emissions for an FCV are lower than all other vehicle types, with the exception of EVs recharged using electricity from renewable sources.

Over the long term, the reduction of overall transportation sector emissions attributable to FCVs will depend on the total number of vehicles in use. A 2008 study by the National Academy of Sciences (NAS) provides one measure of the potential for GHG emission reductions from FCVs. The NAS study estimated the maximum practicable penetration rate for FCVs in the United States in the 2008 to 2050 time frame. The study projected that FCVs could account for approximately 2 million vehicles, out of a total of 280 million light duty vehicles, in 2020, and grow rapidly from then on, increasing to 25 million vehicles in 2030.


Box 1: Hydrogen Production Pathways

Natural gas: Nearly all of the hydrogen used in the United States (95 percent) is produced through a process called steam methane reforming. This process breaks down methane (CH4), a hydrocarbon, into hydrogen and carbon dioxide (CO2). The methane in natural gas is reacted with water (in the form of high-temperature steam) to produce carbon monoxide and hydrogen. These gases are reacted with water again, in a process called a water shift reaction, to produce more hydrogen and CO2.

Gasification: Gasification processes include a series of chemical reactions in which coal or biomass is “gasified” (i.e., converted into gaseous components) using heat and steam. A series of chemical reactions is then used to produce a synthesis gas (a gas mixture that contains varying amounts of carbon monoxide and hydrogen), which is reacted with steam to produce more hydrogen. Producing hydrogen via coal gasification is significantly more efficient than burning coal to produce electricity that is then used in electrolysis.

Although gasification technology is commercially available, the challenge is lowering the amount of CO2 emitted from the process to decrease upstream emissions from the use of FCVs. Coal gasification with carbon capture and sequestration (CCS) or biomass gasification can produce hydrogen with very low or no net GHG emissions, although both these technologies are only in the early stages of commercial-scale deployment. (See Climate Techbook: Carbon Capture and Storage)

Electrolysis: In electrolysis, an electric current is used to split water into hydrogen and oxygen. Electrolysis is in advanced stages of technological development and could play an important role in the near to mid term. Net GHG emissions from electrolysis for hydrogen production depend on the source of the electricity used. If powered by electricity from low-carbon sources (i.e., renewable technologies, nuclear, power, or fossil fuels coupled with CCS), the process generates little to no GHG emissions.

With nuclear high-temperature electrolysis, the efficiency of the process increases. In this type of electrolysis, the heat from the nuclear reactor is used to increase the water temperature and thereby reduce the amount of electricity needed for electrolysis.

High-Temperature Thermochemical Water-Splitting: This is another water-splitting method that uses high temperatures from nuclear reactors or from solar concentrators (lenses that focus and intensity sunlight) to generate a series of chemical reactions that split water, producing hydrogen. The process is in the early stages of development but considered a potential long-term technology, since it is powered by non-GHG emitting technologies and yields a very low-carbon hydrogen fuel.

Photobiological and Photoelectrochemical Processes: These processes use energy from sunlight to produce hydrogen, although both are currently in early stages of research. Photobiological processes use microbes, such as green algae and cyanobacteria. When these microbes consume water in the presence of sunlight, hydrogen is produced as a byproduct of their metabolic processes. Using special semiconductors and sunlight, photoelectrochemical systems produce hydrogen from water as well.

From U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Production.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_production.pdf, November 2008; and Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2008.

 

Figure 2: Well-to-Wheels GHG Emissions for Future FCV based on different hydrogen production processes in gCO2e/mi. 

Source: http://www.hydrogen.energy.gov/pdfs/10001_well_to_wheels_gge_petroleum_use.pdf

With these levels of market penetration, the study estimated that gasoline use would decrease by 24 percent in 2035 and by nearly 70 percent in 2050, compared to business-as-usual (BAU) levels. GHG emissions for light-duty vehicles would decline by 20 percent in 2035 and by more than 60 percent in 2050, as compared to BAU levels.[23]In this scenario, hydrogen is initially produced from natural gas, then from a mixture of sources – natural gas, biomass gasification, and coal gasification with CCS. These estimates assumed that all technical goals were met, consumers accepted FCV technology, and the appropriate policies were implemented for the market transition period.

There are multiple options for reducing GHG emissions from transportation over the long-term. The actual role that FCVs will play will depend on the relative costs of FCV and other low-carbon transportation options and measures adopted by policymakers to reduce GHG emissions.

Cost

Although the cost of fuel cells have decreased significantly, the cost for a fuel cell system is almost double that of an internal combustion engine.[24]

A study by Directed Technologies, Inc. for the DOE estimated the lowest production costs for an FCV with an 80 kilowatt (kW) system with production levels of 500,000 systems a year. The study found that current costs for a fuel cell system (in 2010) are approximately $51/kW, close to the DOE target of $45/kW. For 2015, the study projected that costs would decrease to $39/kW by 2015. The DOE goal for that year is $30/kW.[25]

In addition to system costs, the costs of hydrogen storage are still much higher than the target set for commercialization, which is $2 per kilowatt-hour (kWh). Currently, onboard storage costs are $15-18/kWh, depending on the level of storage pressure.[26]

 

Figure 3: Reduction in Fuel Cell System Cost, 2002 to 2010 (in 2002$). 

Source: http://www.hydrogen.energy.gov/pdfs/10004_fuel_cell_cost.pdf

Overall vehicle costs are also substantially higher than that for conventional vehicles. Toyota has announced plans to sell an FCV in 2015 for $50,000, approximately two times that for a comparable conventional vehicle.[27]In a 2008 study, the NAS estimated the average cost of an FCV from 2008 to 2023 at $39,000 per vehicle, including research, development, and deployment (RD&D) costs.[28] A study by MIT that examined energy and environmental impacts of fuel and vehicle technologies for light-duty vehicles indicated the costs would decrease over the long-term. The study estimates that a fuel cell car in 2035 will cost $5,300 more than its gasoline counterpart, which would have a retail price of $21,600 (in 2007$).[29]

Current Status

Some believe that FCVs are the most promising long-term solution to the challenge of low carbon transportation. Until recently, FCVs were one of the DOE's main areas of focus for long-term research. In 2010, DOE's proposed budget reduced funds for RD&D significantly to focus on nearer-term options for GHG reductions, such as plug-in electric vehicles (PEVs).[30]

FCVs are not yet commercially available, but manufacturers are producing small fleets of demonstration vehicles. Both Honda and Mercedes have FCVs available for lease currently but with limited distribution only in Southern California.[31] Significant penetration of FCVs will require a substantial development of hydrogen refueling infrastructure, as well as improvements in performance and reductions in costs.[32]Studies by the NAS and MIT project that FCVs will be available commercially by 2020, but only if technological and cost issues are resolved.[33]

The development of any new technology often exhibits a “chicken-and-egg” problem – vehicle manufacturers are unwilling to produce vehicles unless there is a guaranteed supply of hydrogen, while hydrogen producers will not supply fuel unless there is a demand for it. Currently, there is no nationwide hydrogen distribution infrastructure, which limits the use of FCVs to areas where filling stations do exist.


Box 2: Hydrogen Distribution

 Currently, there is no infrastructure for distributing hydrogen, like that for fossil fuels. Because hydrogen has less energy per unit volume, distribution costs are higher than those for gasoline or diesel. Most hydrogen is produced either on-site or near where it is used, usually at large industrial sites. It is then distributed by pipeline, high-pressure tube trailers, or liquefied hydrogen tankers. Pipeline is the least expensive way to distribute hydrogen; the last two, while more expensive, can be transported using different modes of transportation – truck, railcar, ship, or barge.

Building network of pipelines and filling stations for FCVs would require high initial capital costs. One potential solution is to produce hydrogen regionally or locally to limit issues with distribution. A second is to use a phased approach. At first, hydrogen distribution (and sales of FCVs) could be concentrated in a few key areas. The next phase would expand the distribution sales network by targeting geographic corridors (e.g., New York-Boston-Washington, D.C.) and then gradually expand to other regions. This phased approach would remove the need for stations all across the United States at the outset, and allow for a slower and affordable build-up in the number of stations and areas served over time.

From U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Distribution and Delivery Infrastructure.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_delivery.pdf November 2008; and Green, D., et al. “Analysis of the Transition to Hydrogen Fuel Cell Vehicles and the Potential Hydrogen Energy Infrastructure Requirements.” 

 

Obstacles to Further Development/Deployment

Fuel cell technology: Significant improvements in fuel cell durability and costs are needed for FCVs to achieve commercial success. These are limited by the properties of catalysts and available membrane materials. Targets set by industry aim for an operating life of 5,000-5,500 hours and 17,000 start/stop cycles for a fuel cell system. Achieving this target would allow FCVs to be competitive with conventional vehicles in terms of durability. To date, automotive fuel cells have not demonstrated this level of reliability.[34]

On-board hydrogen storage: Although hydrogen contains three times more energy per weight than gasoline, it contains one-third of the energy per volume. Storing enough hydrogen to obtain a vehicle range of 300 miles would require a very large tank, too large for a typical car.[35]Currently the most cost-effective option is using high-pressure tanks, yet these systems are large, heavy, and too costly to make FCVs cost-competitive.[36]Other options include storing hydrogen in metal- or chemical-hydrides[37] or producing hydrogen onboard.

Hydrogen production: Hydrogen can be produced using a variety of methods, with substantially different GHG footprints (see Box 1 above). For FCVs to be competitive as a GHG-reduction strategy, more development of low-cost and low-GHG hydrogen production methods will be needed.

Distribution infrastructure: There is currently no national system to deliver hydrogen from production facilities to filling stations, similar to that for diesel or gasoline. A completely new distribution infrastructure will be required to allow mass market penetration of FCVs (see Box 2 above).

Vehicle cost: For FCVs to become cost-competitive, high production volumes are needed to make vehicle plus fuel costs less than those for a gasoline vehicle.

Competition with other technologies: There is a range of potential alternative technologies available for use in the transportation sector, including higher efficiency gasoline- and diesel-powered vehicles, biofuels, HEVs, and PEVs. To be competitive with these technologies, FCVs will have to improve in terms of performance, durability, and cost.[38]

Safety and public acceptance: Safety concerns include the pressurized storage of hydrogen on-board vehicles. Hydrogen gas is odorless, colorless, and tasteless, and thus unable to be detected by human senses. Unlike natural gas, hydrogen cannot be odorized to aid human detection; furthermore, current odorants contaminate fuel cells and impair cell functioning. It is also more combustible than gasoline, although flames produce lower radiant heat which limits the chance of secondary fires.[39] Improved on-board storage will reduce safety concerns.

Consumers will have to become familiar with and embrace fuel cell technology before FCVs can become widespread.[40]In addition, the durability and reliability of fuel cells will need to be comparable to the lifetime of a conventional passenger vehicle, approximately 14 years.

Policy Options to Help Promote FCVs

Substantial policy support and investment is required for FCVs to achieve market readiness. Policies should initially focus on RD&D and then transition to policies to aid market penetration once key challenges are overcome.

  • Government support through research, development, and deployment initiatives and grants: Government support will need to deal with the “chicken-and-egg” problem by supporting both the development of FCV technology to bring it to market readiness, e.g., by helping manufacturers produce demonstration vehicles, and also build out of the infrastructure for hydrogen distribution. To achieve substantial market penetration of FCVs, the NAS estimates that the government support required will be approximately $55 billion from 2008 to 2023, with an investment from private industry of $145 billion over the same period.[41]
  • Tax and/or subsidy policies to reduce the high initial cost of FCVs compared to conventional vehicles: Government tax and/or subsidy policies are needed to reduce the high initial cost of FCVs, in order to make them more cost-competitive with gasoline vehicles. These policies can be directed at either producers – manufacturers of FCVs and suppliers of hydrogen – to reduce production and distribution costs, or consumers who purchase FCVs. There is currently a tax credit of $0.50/gallon for hydrogen sold for use in a motor vehicle, which expires in September 2014.[42]
  • GHG reduction policies: These policies can focus on reducing sectoral and/or economy-wide GHG emissions. For example, a sectoral performance standard (e.g., a low-carbon fuel standard, or LCFS) would set targets for reductions in GHG intensity for the entire transportation fuel supply and provide a level playing field for all transportation energy sources that may be used in the future, including biofuels, electricity, or hydrogen. Economy-wide policies that reduce oil use and GHGs can include GHG cap-and-trade systems and other policies that put a price on GHG emissions. These policies can encourage a broad array of cost-effective options for reducing GHG emissions across economic sectors. A reduction in economy-wide GHG emissions would ensure that hydrogen production generates less CO2 emissions (see Box 1 for hydrogen production pathways), reducing upstream emissions from the use of FCVs.

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.

 

Further Reading / Additional Resources

U.S. Department of Energy (DOE), Office of Energy Efficiency and Renewable Energy. Fuel Cell Technologies Program: Informational Resources (http://www1.eere.energy.gov/hydrogenandfuelcells/pubs_educational.html)

U.S. Department of Energy (DOE), Office of Energy Efficiency and Renewable Energy. Alternative and Advanced Fuels: Hydrogen. http://www.afdc.energy.gov/afdc/fuels/hydrogen.html

Bandivadekar, Anup, et al. “On the Road in 2035: Reducing Transportation’s Petroleum Consumption and GHG Emissions.” http://web.mit.edu/sloan-auto-lab/research/beforeh2/otr2035/ Massachusetts Institute of Technology, July 2008.

Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2008. http://www.nap.edu/catalog.php?record_id=12222



[1]              US DOD, Fuel Cell Test and Evaluation Center. “History.” http://www.fctec.com/fctec_history.asp. Accessed 31 December 2010.

[2]              U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Fuel Cells.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_fuelcell_fa..., November 2008.

[3]              As with conventional vehicles, FCVs may emit GHGs directly from air conditioning systems (a “direct” source of emissions). The refrigerant used in air conditioning systems is a pressurized gas (HFC-134a, a greenhouse gas), which can leak from small openings or cracks in the system.

[4]              U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles.” http://www.fueleconomy.gov/feg/fuelcell.shtml, 20 December 2010. Accessed 1 January 2011.

[5] The electrolyte is an ion conducting material that allows only the appropriate ions to pass between the anode and cathode. The type of electrolyte plays an important role in regulating the chemical reaction. If other substances or free electrons travel through the electrolyte, this could disrupt the chemical reaction.

[6]              U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Fuel Cells.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_fuelcell_fa..., November 2008.

[7]              U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Fuel Cells.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_fuelcell_fa..., November 2008.

[8]              In a fuel cell, the electrolyte is a non-metallic conductor of electrical ions in a solid membrane. NREL. “Fuel Cells.” http://www.nrel.gov/learning/eds_hydro_fuel_cells.html, 2 December 2009. Accessed 1 January 2011.

[9]              For an animation of the process, visit http://www.fueleconomy.gov/feg/animation/swfs/fuelcellframe.html.

[10]             U.S. DOE, Office of EERE, fueleconomy.gov. “How Fuel Cells Work.” http://www.fueleconomy.gov/feg/fcv_PEM.shtml, 20 December 2010. Accessed 1 January 2011.

[11]             Natural Gas Vehicles for America. “Technology.” http://www.ngvc.org/tech_data/index.html. Accessed 1 January 2011.

[12]             U.S. DOE, Office of EERE, Alternative & Advanced Vehicles. “What is a fuel cell vehicle.” http://www.afdc.energy.gov/afdc/vehicles/fuel_cell_what_is.html, 31 August 2010. Accessed 17 December 2008.

[13]             Regenerative braking slows a vehicle by converting its kinetic energy into stored energy in a battery, which can later be used to power the electric motor.

[14]             U.S. DOE, Office of EERE, Alternative & Advanced Vehicles. “What is a fuel cell vehicle.” http://www.afdc.energy.gov/afdc/vehicles/fuel_cell_what_is.html, 31 August 2010. Accessed 17 December 2008.

[15]             See the following for more on hybridization of FCVs: Pesaran, Ahmad. "Fuel Cell/Battery Hybrids: An Overview of Energy Storage Hybridization in Fuel Cell Vehicles." Presented at 9th Ulm Electrochemical Talks, Ulm, Germany, May 17-18, 2004.

[16]             U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Fuel Cells.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_fuelcell_fa..., November 2008.

[17]             U.S. DOE, Office of EERE, fueleconomy.gov. “Electric Vehicles.” http://www.fueleconomy.gov/feg/evtech.shtml, 20 December 2010. Accessed 1 January 2011.

[18]             U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles: Fuel Economy” http://www.fueleconomy.gov/feg/fcv_sbs.shtml 16 December 2010. Accessed 17 December 2010.

[19]             U.S. DOE. Office of EERE. “Transportation Data Book: Table 4.21 Car Corporate Average Fuel Economy (CAFE) Standards versus Sales-Weighted Fuel Economy Estimates, 1978–2010.” http://cta.ornl.gov/data/chapter4.shtml, 30 June 2010. Accessed 1 January 2011.

[20]             Toyota Prius. U.S. DOE, Office of EERE, fueleconomy.gov. “2010 Fuel Economy Guide.” http://www.fueleconomy.gov/feg/FEG2010.pdf. Accessed 7 February 2011.

[21]             Nguyen, T. and J. Ward. "Well-to-Wheels Greenhouse Gas Emissions and Petroleum Use for Mid-Size Light-Duty Vehicles." Program Record #10001. Offices of Vehicle Technologies & Fuel Cell Technologies, U.S. DOE. 25 October 2010.

[22]             Bandivadekar, A, et al. “On the Road in 2035: Reducing Transportation’s Petroleum Consumption and GHG Emissions.” Massachusetts Institute of Technology, Laboratory for Energy and the Environment, Report No. LFEE 2008-05 RP, July 2008.

[23]             The study used the 2008 EIA high-oil-price scenario, which was extended to 2050 by the committee, as the reference/BAU case for the analyses. Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2008.

[24]             U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles: Challenges.” http://www.fueleconomy.gov/feg/fcv_challenges.shtml 16 December 2010. Accessed 17 December 2010.

[25]             James, B., J. Kalinoski, and K. Baum. "Mass-Production Cost Estimation for Automotive Fuel Cell System: DOE H2 Program Review." Presentation. 9 June 2010.

[26]             U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles: Challenges.” http://www.fueleconomy.gov/feg/fcv_challenges.shtml 16 December 2010. Accessed 17 December 2010.

[27]             Ohnsman , A. “Toyota Plans $50,000 Hydrogen Fuel-Cell Sedan by 2015.” 6 May 2010, http://www.bloomberg.com/news/2010-05-06/toyota-targets-50-000-range-for-hydrogen-powered-sedan-planned-by-2015.html. Accessed 16 December 2009.

[28]             Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2008.

[29]             Bandivadekar, A, et al. “On the Road in 2035: Reducing Transportation’s Petroleum Consumption and GHG Emissions.” Massachusetts Institute of Technology, Laboratory for Energy and the Environment, Report No. LFEE 2008-05 RP, July 2008.

[30]             LaMonica, M. "DOE to slash fuel cell vehicle research." 8 May 2009, http://news.cnet.com/8301-11128_3-10236740-54.html#ixzz1Cq42Itga. Accessed on 2 February 2011.

[31]             In addition, General Motors, Hyundai, Kia, Nissan, Toyota, and Volkswagen are also in the process of testing FCV prototypes. For more information, visit http://www.fuelcellpartnership.org/progress/vehicles.

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

[33]             Bandivadekar, A, et al. “On the Road in 2035: Reducing Transportation’s Petroleum Consumption and GHG Emissions.” Massachusetts Institute of Technology, Laboratory for Energy and the Environment, Report No. LFEE 2008-05 RP, July 2008; and Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2008.

[34]             Kromer, M, and J. Heywood. "Electric Powertrains: Opportunities and Challenges in the U.S. Light-Duty Vehicle Fleet Massachusetts Institute of Technology, Laboratory for Energy and the Environment, Publication No. LFEE 2007-03 RP, May 2007.

[35]             U.S. DOE, Office of EERE, Alternative Fuels and Advanced Vehicles Data Center. “Hydrogen as an Alternative Fuel” http://www.afdc.energy.gov/afdc/fuels/hydrogen_alternative.html 19 February 2010. Accessed 17 December 2010.

[36]             U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles: Challenges.” http://www.fueleconomy.gov/feg/fcv_challenges.shtml 16 December 2010. Accessed 17 December 2010.

[37]             A binary compound of hydrogen with a metal.

[38]             U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles: Challenges.” http://www.fueleconomy.gov/feg/fcv_challenges.shtml 16 December 2010. Accessed 17 December 2010.

[39]             U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Safety.” http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/doe_h2_safety.pdf, November 2008.

[40]             U.S. DOE, Office of EERE, fueleconomy.gov. “Fuel Cell Vehicles: Challenges.” http://www.fueleconomy.gov/feg/fcv_challenges.shtml 16 December 2010. Accessed 17 December 2010.

[41]             Committee on Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies, National Research Council. Transitions to Alternative Transportation Technologies: A Focus on Hydrogen. Washington, DC: National Academies Press, 2008.

[42]             U.S. DOE, Office of EERE, Alternative Fuels and Advanced Vehicles Data Center. “Federal and State Incentives and Laws.” http://www.afdc.energy.gov/afdc/laws/law/US/8320. 25 October 2010. Accessed 17 December 2010.

 

Benfits and hurdles to deployment of hydrogen fuel cell vehicles.
0
Teaser: 

 

Benfits and hurdles to deployment of hydrogen fuel cell vehicles.

Syndicate content