Energy & Technology

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.”


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]     


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 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]


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]



Total Capacity (MW)

% of U.S. Total









































Rest of U.S.




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



Dow Chemical Company




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.

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 moderated the Keynote presentation.

The Minneapolis Regional Chamber of Commerce hosted The 2011 Greening Your Business Conference on April 14, 2011. This conference provided the opportunity to reach business decision makers 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 moderated the Keynote presentation.

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.


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.


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. 


  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.”, 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. 


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.


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$). 


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.” 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 (

U.S. Department of Energy (DOE), Office of Energy Efficiency and Renewable Energy. Alternative and Advanced Fuels: Hydrogen.

Bandivadekar, Anup, et al. “On the Road in 2035: Reducing Transportation’s Petroleum Consumption and GHG Emissions.” 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.

[1]              US DOD, Fuel Cell Test and Evaluation Center. “History.” Accessed 31 December 2010.

[2]              U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Fuel Cells.”, 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, “Fuel Cell Vehicles.”, 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.”, November 2008.

[7]              U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Fuel Cells.”, November 2008.

[8]              In a fuel cell, the electrolyte is a non-metallic conductor of electrical ions in a solid membrane. NREL. “Fuel Cells.”, 2 December 2009. Accessed 1 January 2011.

[9]              For an animation of the process, visit

[10]             U.S. DOE, Office of EERE, “How Fuel Cells Work.”, 20 December 2010. Accessed 1 January 2011.

[11]             Natural Gas Vehicles for America. “Technology.” Accessed 1 January 2011.

[12]             U.S. DOE, Office of EERE, Alternative & Advanced Vehicles. “What is a fuel cell vehicle.”, 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.”, 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.”, November 2008.

[17]             U.S. DOE, Office of EERE, “Electric Vehicles.”, 20 December 2010. Accessed 1 January 2011.

[18]             U.S. DOE, Office of EERE, “Fuel Cell Vehicles: Fuel Economy” 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.”, 30 June 2010. Accessed 1 January 2011.

[20]             Toyota Prius. U.S. DOE, Office of EERE, “2010 Fuel Economy Guide.” 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, “Fuel Cell Vehicles: Challenges.” 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, “Fuel Cell Vehicles: Challenges.” 16 December 2010. Accessed 17 December 2010.

[27]             Ohnsman , A. “Toyota Plans $50,000 Hydrogen Fuel-Cell Sedan by 2015.” 6 May 2010, 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, 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

[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” 19 February 2010. Accessed 17 December 2010.

[36]             U.S. DOE, Office of EERE, “Fuel Cell Vehicles: Challenges.” 16 December 2010. Accessed 17 December 2010.

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

[38]             U.S. DOE, Office of EERE, “Fuel Cell Vehicles: Challenges.” 16 December 2010. Accessed 17 December 2010.

[39]             U.S. DOE, Office of EERE, Fuel Cell Technologies Program. “Hydrogen Safety.”, November 2008.

[40]             U.S. DOE, Office of EERE, “Fuel Cell Vehicles: Challenges.” 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.” 25 October 2010. Accessed 17 December 2010.


Benfits and hurdles to deployment of hydrogen fuel cell vehicles.


Benfits and hurdles to deployment of hydrogen fuel cell vehicles.

Updated Climate Change 101 Series Released

Kicking off the new year, we released an update of its Climate Change 101 series. Climate Change 101: Understanding and Responding to Global Climate Change is made up of brief reports on climate science and impacts; adaptation measures; technological and business solutions; and international, U.S Federal, State, and local action. Last released in January of 2009, the updated reports highlight the significance of the global negotiations, climate-related national security risks, local efforts to address climate change, the most recent predictions on global temperature changes, and more.

Updated Website, Climate Change 101 Series Deliver Credible Information to Advance Climate Action

Press Release
March 3, 2011

Contact: Rebecca Matulka, 703-516-4146


Pew Center Updates Website and Climate Change 101 Series

WASHINGTON, DC – Public opinion continues to be divided on climate change and its causes, and as a result, public access to credible, digestible information about climate change is more critical than ever. To help advance a constructive dialogue that leads to climate action, the Pew Center on Global Climate Change refreshed its website and updated its landmark Climate Change 101 report series.

“Now more than ever, the public needs straight answers about climate change,” said Eileen Claussen, President of the Pew Center on Global Climate Change. “The Pew Center is continuing its work to demystify the issue, and our updated website and report series present straightforward and useful climate change information.”

With a fresh new design and easy-to-navigate organization, the Pew Center’s website provides access to the center’s first-rate analyses and publications of key climate issues. One new website feature is the publications library, which allows users to search for and order free copies of Pew Center reports. The website puts the Center’s Climate Compass blog front and center, and presents timely ideas and insights from science and policy experts on topics critical to the climate debate.

The fast-reading Climate Change 101: Understanding and Responding to Global Climate Change includes nine brief reports and helps inform the climate dialogue by providing a reliable and understandable introduction to global climate change. The updated reports highlight the significance of the global negotiations, climate-related national security risks, local efforts to address climate change, the most recent predictions on global temperature changes, and more.

For more information about global climate change and the activities of the Pew Center, visit

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The Pew Center on Global Climate Change was established in May 1998 as a non-profit, non-partisan, and independent organization dedicated to providing credible information, straight answers, and innovative solutions in the effort to address global climate change. The Pew Center is led by Eileen Claussen, the former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs.

Planning for our future

This blog post was co-authored by Deron Lovaas of the Natural Resources Defense Council and is also posted on NRDC's blog Switchboard.


If you were a resident of Washington, D.C., in 2000 and still live in the District today, you may have noticed the number of cars in the city has dropped significantly. Between 2000 and 2008, the population of D.C. grew 3 percent (more than 18,000), while the number of registered automobiles dropped almost 8 percent (nearly 19,000 cars and light trucks). A recent Center for Clean Air Policy (CCAP) report highlighted one of the reasons for this shift in how we get around: more and more people now prefer to live in walkable communities.

Pew Center on Global Climate Change Issues Transportation Papers as Congressional Hearings Rev Up

Press Release                                        
February 15, 2011

Contact: Tom Steinfeldt, 703-516-4146

Pew Center on Global Climate Change Issues Transportation Papers as Congressional Hearings Rev Up
Guides to Reauthorization, Highway Trust Fund, & Policies to Reduce Emissions & Oil Use

WASHINGTON, D.C. – The Pew Center on Global Climate Change today issued two papers that offer a primer on major federal transportation efforts and policies to advance a cleaner, more secure transportation system. The papers complement a comprehensive Pew Center report released in January that examines cost-effective solutions to reduce U.S. transportation emissions and oil use.  

The new papers offer an accessible overview of key transportation issues Congress is expected to debate in the weeks and months ahead. The papers, Primer on Federal Surface Transportation Authorization and the Highway Trust Fund, and Saving Oil and Reducing Greenhouse Gas Emissions through U.S. Federal Transportation Policy, are authored by Cynthia J. Burbank, Vice President of Parsons Brinckerhoff, and Nick Nigro, Solutions Fellow at the Pew Center.

Travel on U.S. roads and rail uses 10 million barrels of oil per day and is the source of more than 23 percent of the nation’s greenhouse gas (GHG) emissions. Faced with a real threat to national security from climate change and oil dependence, Congress has an opportunity to achieve significant oil savings and GHG reductions from the U.S. transportation sector.

The papers offer a guide to federal transportation reauthorization legislation and identify opportunities in that legislation and through existing legislative authority to save oil and reduce GHG emissions. The strategy focuses on five key elements: vehicles; fuels; vehicle miles traveled (VMT); system efficiency; and construction, maintenance, and other activities of transportation agency operations.

The papers follow up on the Pew Center’s report, Reducing Greenhouse Gas Emissions from U.S. Transportation. That study identifies reasonable actions across three fronts – technology, policy, and consumer behavior – that could deliver up to a 65 percent reduction in transportation emissions from current levels by 2050. 

The new papers can be accessed online at

For more information about global climate change and the activities of the Pew Center, visit


The Pew Center on Global Climate Change was established in May 1998 as a non-profit, non-partisan, and independent organization dedicated to providing credible information, straight answers, and innovative solutions in the effort to address global climate change. The Pew Center is led by Eileen Claussen, the former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs.

Barack Obama's EPA hit for what George W. Bush's EPA wanted

February 15, 2011

By Eileen Claussen

This op-ed first appeared in Politico


A vocal contingent in the House is now attacking the current Environmental Protection Agency administrator for the very thing her predecessor in the Bush administration wanted to do.

EPA Administrator Stephen Johnson wrote a letter to President George W. Bush laying out the legal and scientific rationale for regulating greenhouse gases under the Clean Air Act. Johnson explained steps that the EPA would take to begin to do so.

Johnson’s letter surfaced last week at the House Energy and Power subcommittee hearing on proposed legislation to strip EPA’s authority to regulate greenhouse gas emissions.

Remarkably, it proved that Bush’s EPA administrator had reached the same conclusions and planned almost identical actions to what the current EPA administrator, Lisa Jackson, has begun implementing.

What exactly does Johnson tell Bush? He insists that the EPA must respond to the Supreme Court’s 2007 decision in Massachusetts v. EPA with a finding that greenhouse gases represent a risk to public health or welfare. This is EPA’s “endangerment finding,” which would be overturned by legislation now being proposed in the House.

Johnson also noted, “the latest climate change science does not permit a negative finding, nor does it permit a credible finding that we need to wait for more research.”

What is most telling is that Johnson states that a positive endangerment finding was “agreed to at the Cabinet-level meeting.” Apparently senior Bush administration officials agreed that climate change poses a risk to our nation’s public health and welfare.

Johnson describes his plan as “prudent and cautious yet forward thinking,” and says it “creates a framework for responsible, cost-effective and practical actions.” Sound familiar?

Jackson, in her statement at the hearing last week, called EPA’s actions a “reasonable approach,” one that “will reflect careful consideration of costs and will incorporate compliance flexibility.”

Indeed, the step-by-step plan of action spelled out by Johnson could be a checklist for the EPA’s recent actions — largely the same actions being aggressively attacked today by some in Congress.

These actions include the endangerment finding; a joint rule-making with the Transportation Department to require more fuel-efficient cars; rules to modify the agency’s requirements for new sources to reduce the number of facilities that would be covered (EPA’s tailoring rule), and proposals to respond to specific petitions (EPA has acted on ones for the utility and oil refinery sectors).

Given these striking similarities, attacks on current EPA actions — that the agency is “an instrument of job destruction” and would “put the American economy in a straitjacket” — now resonate as particularly empty political rhetoric.

How could the right thing to do in the Bush administration suddenly become the wrong thing to do in the Obama administration?

Eileen Claussen served as assistant secretary of state for Oceans and International Environmental and Scientific Affairs. She is now president of the Pew Center on Global Climate Change.

by Eileen Claussen, President -- Published in Politico
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