Energy & Technology

Aviation

Quick Facts

  • The aviation sector accounts for approximately 1.5 percent of global anthropogenic greenhouse gas emissions per year. U.S. aviation activities account for nearly 40 percent of these emissions.
  • Gains in aircraft efficiency have been entirely offset by rapidly growing demand for air travel. From 2000 to 2006, global demand for passenger aviation grew at an average rate of 3.8 percent annually.
  • A combination of operational practices, lower-carbon fuels, and higher aircraft fuel efficiency could reduce annual greenhouse gas emissions from global aviation by more than 50 percent below “business-as-usual” projections, causing emissions from aviation to only double, as opposed to quadruple by 2050. Aggressive implementation of lower carbon fuels could improve that outlook considerably by replacing a larger share of traditional jet fuel more quickly.
  • The international component of air travel and international treaties affect the policies appropriate for reducing emissions from the aviation sector.

Background

Aviation has reshaped the world we live in—allowing for affordable and rapid travel to almost any point on the globe. In recent years, economic growth and rapid globalization have made air travel affordable to an even larger part of the global population. In this context, demand for aviation, in terms of passenger-miles flown, has grown at a rapid pace. In China, for example, domestic air transport grew at 15.5 percent annually from 2000 to 2006.[1] Globally, the rate of air travel increased at 3.8 percent per year over the same time period.[2] This growing demand for air travel has resulted in increasing levels of greenhouse gas (GHG) emissions from the aviation sector, despite efficiency improvements. Currently, the aviation sector—including both domestic and international travel—accounts for approximately 1.5 percent of global anthropogenic GHG emissions per year.[3] The U.S. accounts for nearly 40 percent of the global GHG emissions from aviation.Barring policy intervention, GHG emissions from aviation are projected to quadruple by 2050.[4]

A number of strategies can mitigate the rising level of GHG emissions from the aviation sector. In the near term, adopting navigation systems and air traffic control techniques that minimize fuel use and idling can reduce emissions by as much as 5 percent. Over the long term, advanced propulsion systems, utilization of lightweight materials, and improved aerodynamics and airframe designs hold the promise of further reducing aviation emissions. The development of cost-effective, lower-carbon alternative fuels could result in even deeper reductions. Strategies also exist to reduce the demand for aviation by switching to other modes of travel – such as high speed rail connections where high speed rail can compete with aviation on time, price, and convenience.

To be effective, policies to reduce GHG emissions from aviation will require a high degree of international coordination. The trans-national nature of airline ownership and travel complicates how responsibility for aviation emissions is assigned to individual countries. The International Civil Aviation Organization has taken some steps toward understanding these complexities, and policies to reduce emissions will need to adequately take account of international sovereignty issues. The industry has proposed a global sectoral approach where GHGs are managed at the sectoral level instead of on a country-by-country basis.

While the discussion herein focuses on CO2 emissions from aviation, there are other emissions and effects of aviation that also contribute to climate change.[5] In addition to CO2 from fuel combustion, airplanes can also emit methane (CH4), nitrous oxide (N2O), hydrocarbons (HC), particulate matter (PM), sulfur oxides (SOx), and nitrogen oxides (NOx). Moreover, certain high-altitude aviation emissions can spur heat-trapping cloud formation. Compared to these non-CO2 emissions and cloud formation, there is more scientific certainty regarding the impacts of CO2 emissions from aviation and greater consensus on the optimal policies for reducing aviation’s CO2 emissions.

Description

Strategies available to mitigate GHG emissions from aviation include the following:

  • Operational Efficiency
    Optimizing flight paths and reducing airport congestion could immediately reduce the aviation sector’s GHG emissions. Adopting advanced communication, navigation, and surveillance and air traffic management (CNS/ATM) systems can reduce the time aircraft spend idling on runways or circling airports waiting to land, thus reducing fuel use and associated emissions.[6]
  • Aircraft EfficiencyAircraft efficiency technologies reduce the amount of fuel aircraft use per unit of distance traveled. Several technological improvements exist to improve aircraft aerodynamics, such as applying laminar flow control to an aircraft to reduce drag and, as a result, fuel consumption.[7] More radical innovations include blended wing body aircraft that not only reduce drag but allow the entire aircraft to generate lift, as opposed to just the wings.[8] More fuel-efficient engines and incorporation of super-lightweight materials, such as fiber-metal laminate, into the airframe offer additional avenues to improving aircraft efficiency.[9],[10]
  • Alternative Fuels
    Alternative fuels have lower net GHG emissions than traditional petroleum-based aircraft fuel.[11] Biofuels, Fischer-Tropsch fuels,[12] and liquid hydrogen could all present feasible alternatives in the future. While these fuels do not present an immediate alternative, their adoption presents a long-term path toward lower carbon flight. To be seriously considered as a mitigation strategy, alternative fuels must be both cost-competitive and offer significant reductions in GHG emissions.
  • Alternative Modes of Transport
    Switching from aviation to less carbon-intensive modes of transport can also help mitigate GHG emissions. High speed rail (HSR) is especially suited to replace short-distance passenger air travel in some circumstances, such as in high density corridors. The energy use per passenger-mile for HSR could be as much as 65 to 80 percent less than air travel, but the overall reduction in GHG emissions would depend on a number of factors, including the design of the system (operating speeds and distances between stops) and passenger load factors (i.e., capacity utilization). The European and Japanese experience has shown high speed rail to generally be competitive with air travel on routes of up to 300-500 miles, where there is existing high demand for intercity travel and where several high-population areas can be connected along a single corridor. The total infrastructure and operations environmental impact should be considered for valid comparison of modes.

It is important to also focus on the timeframe in which these strategies are adopted. The operational lifetime of an aircraft ranges from 20-30 years. As such, it takes a number of years for any new technologies to penetrate through the entire fleet. It also takes many years to implement a new HSR route.

Environmental Benefit / Emission Reduction Potential

Combining all available mitigation strategies could reduce global GHG emissions from aviation by as much as 53 percent below “business-as-usual” (BAU) projections in 2050. As Figure 1 shows, owing to large projected increases in aviation demand, absolute emissions from aviation are projected to increase from current levels by mid-century even in the case of significant policies to limit emissions. However, policy interventions can limit global aviation emissions to about double current levels by 2050, as compared to a nearly four-fold increase under “business as usual” over the same timeframe.

While more easily implemented, adoption of a broad array of more efficient operational practices—from improved landing techniques to reduced taxiing times—would only produce emissions savings of 5 percent below the BAU projection in 2050.

Technological advances offer the potential for more significant reductions. Current trends in aviation efficiency improvements are expected to continue; the efficiency of the U.S. and global aircraft fleets will continue to improve as older, less efficient aircraft are retired and then replaced with new, more efficient aircraft. Under “business as usual,” a projected 30 percent decrease in aviation energy intensity will be achieved by utilizing currently known technologies: more efficient propulsion systems (engines), advanced lightweight materials, and improved aerodynamics (e.g., winglets, increased wingspans).[13] Added support through government sponsored research and development (R&D) and other policy interventions could yield an additional 35 percent reduction below BAU emissions in 2050. Much of this 35 percent would come from application of the more ambitious and therefore riskier technological alternatives.[14] Blended wing body or other innovative airframes, for example, could reduce fuel consumption by as much as 32 percent when compared to an Airbus A380 (a currently operating state-of-the-art aircraft model). Advanced laminar coatings that reduce drag could increase fuel efficiency by a further 16.5 percent.[15]

The emission reduction potential from alternative fuels is slightly less certain. While a number of technologies exist to produce alternative fuels, it is unclear at this time which technologies will prove viable in the long term. Conservatively, these alternative fuels could provide an additional 24 percent emission reduction against a BAU scenario.

The potential emissions reduction from shifting to alternative modes of transport is more difficult to quantify and likely the option with the smallest emission reduction potential.

Table 1. Global GHG Emissions Abatement for Aviation Sector

Category

Measure

Reductions from “Business as Usual” in 2050 (%)

Operations

Advanced CNS/ATM systems (e.g., NextGen, SESAR)

5

Aircraft Design and Propulsion

Unducted fan (open rotor) engines where feasible, greater application of advanced lightweight materials, improved aerodynamics (e.g., laminar flow control), new airframe designs (e.g., blended wing body)

35

Alternative Fuels

Medium term: Biofuels;

Long term: Biofuels, hydrogen

24

Total Reduction from BAU Emissions in 2050

53

Figure 1: Global GHG Mitigation Potential from the Aviation Sector

Source: McCollum, David, Gregory Gould, and David Greene, Greenhouse Gas Emissions from Aviation and Marine Transportation: Mitigation Potential and Policies, 2009. http://www.c2es.org/technology/report/aviation-and-marine

Cost

The cost of mitigating emissions from aviation depends on the strategy adopted. Not only do cost estimates vary among studies, but some costs are inherently uncertain, given the experimental nature of many of the technologies analyzed. A study that focused on European aviation fleets estimated that GHG abatement costs for the aviation sector range widely, depending on abatement option, spanning -$222 to $308 per metric ton of CO2, with most of the abatement options at costs below $110 per ton.[16]

At the lower end of the cost spectrum, operational innovations, such as CNS/ATM technologies, hold the potential to yield cost savings via reduced expenditures on fuel. More advanced technologies, such as laminar coating, come with higher costs, including significant R&D costs. It is especially difficult to estimate the costs of these longer-term solutions, as the estimated capital costs for development and implementation are often highly speculative.[17]

Similar uncertainty surrounds the costs of alternative fuels for the aviation sector. Existing biofuels cannot currently compete against jet fuel and are not expected to achieve significant penetration in the aviation sector through 2050 under “business-as-usual” conditions. Even in the event of significant improvements in biofuel technology, a number of cost barriers would remain. New fuel types might require re-engineering airplane propulsion systems, increasing the costs of fuel switching.

Building new HSR infrastructure for shifting transportation from air to rail is very capital-intensive. For example, constructing a proposed HSR line between Los Angeles and San Francisco has an estimated cost of $45 billion.[18] Reliable estimates of the dollars-per-ton cost of CO2 emissions reductions from transportation mode shifting are lacking, and some estimates of the marginal cost of emission reductions from HSR are very high.[19]

Current Status of Aviation Emissions Mitigation Efforts

Efforts are already underway to mitigate GHG emissions in the sector. For example, airlines regularly retire older aircraft and make adjustments to airframe design through the addition or repositioning of winglets. Future state-of-the-art aircraft, like the Boeing 787 and Airbus A350 (first deliveries of the former are expected in 2010 with the Airbus A350 about three years later), will combine a number of technologies—from lightweight materials to advanced propulsion systems—to achieve even greater fuel efficiency. Nonetheless, in terms of absolute emissions, these gains in efficiency are entirely offset by burgeoning demand.

Efforts to improve operational efficiency include the U.S. NextGen initiative, which uses satellites to track aircraft routes and uses the satellite data to shorten travel distances and reduce congestion.[20] A similar initiative known as the Single European Sky ATM Research (SESAR) project is underway in Europe.

Some airlines are also testing the possibility of blending jet fuel with alternative fuels. A number of commercial airlines, such as Continental Airlines, have conducted or plan to conduct test flights that make use of biofuels. The International Air Transport Association (IATA) has set a goal for its member airlines to use 10 percent “alternative” fuels by 2017.[21] Initial formal technical approval of these new low carbon biofuels is expected in 2010.

The European Union is on track to integrate the aviation sector into its GHG cap-and-trade system beginning in 2012. The EU regulations cover GHG emissions from all flights either landing at or departing from airports within the European Union.[22]

Obstacles to Further Development or Deployment of Aviation Emissions Mitigation Strategies

  • International Jurisdiction
    The international dimension of aviation emissions complicates their mitigation. In fact, no paradigm exists for assigning transnational GHG emissions to individual countries. While the International Civil Aviation Organization is analyzing options for curtailing global aviation emissions, little agreement exists on specific policy actions.
  • Lack of a Price on Carbon
    With the exception of future flights to and from the European Union (see above), businesses and consumers do not face a financial cost associated with GHG emissions from aviation. This means firms and consumers do not fully take into account the social cost of GHG emissions when considering investments in new technology or travel decisions.
  • High Level of Risk in Research and Development
    The most advanced mitigation technologies come with high capital costs and considerable investment risks. Many firms are reluctant to invest in developing advanced technology such as blended wing body or laminar coating, as the effectiveness and payoff of these technologies are unknown.
  • Government Regulations
    Many operational strategies are beyond the control of airlines and strongly dependent on government regulation and support.

Policy Options to Help Promote Aviation Emissions Mitigation Strategies

  • Carbon Price
    Government policies that put a price on carbon, such as a GHG cap-and-trade program, would guide firms and consumers in making cost-effective decisions regarding limiting emissions from aviation—ranging from blending lower-carbon fuels to choosing alternative transport modes or reducing consumption of aviation services—all relative to the cost of comparable avoided emissions from other sectors of the economy.[23]
  • Aviation Emission Standards
    Governments could mandate fuel efficiency standards for new aircraft or implement standards to limit the carbon intensity of the fuels used.
  • Regulatory Changes
    Policies that facilitate the transition to more advanced air traffic management systems would improve operational efficiency in the aviation sector. The revamping of government-mandated operational protocols could reduce congestion, thus saving fuel by reducing idling time and taxiing distance.
  • Government Sponsored R&D
    Government-sponsored R&D can be an effective driver of innovation, especially when it is targeted at basic research that is beneficial to many industries (e.g., low-carbon fuels and advanced lightweight materials) or is focused on risky projects (e.g., radical changes to airframe designs) that individual companies may not be willing to fund. Public R&D has been a particularly important driver of aviation innovation in the past, and an increase in government R&D funding could accelerate the rate of innovation and development of new technologies.
  • Supportive Agricultural Policy
    While the technical barriers to low carbon biofuel for aviation are rapidly being retired, the availability of feedstocks is a barrier to fuel capacity building. Policy that would reduce the risk of investing in new crops aimed at aviation biofuel could accelerate capacity and lessen reliance on fossil fuels.
  • Department of Defense Leadership
    As the single largest user of aviation fuels, the Department of Defense could help build capacity and mitigate risk of initial capital investment by implementing a program to “lead the fleet” in sourcing low carbon fuels. The assurance of market demand would help green entrepreneurs with initial start-up challenges.
  • Increased Government Spending on Infrastructure
    Strategic government spending could enhance efficiency within the aviation sector, such as funding airport expansion projects or improving air traffic control to reduce congestion. Governments could also invest in alternatives to air travel, such as high speed rail. The American Recovery and Reinvestment Act of 2009 (i.e., the economic stimulus package) includes more than $8 billion to help finance high speed rail corridors throughout the United States.[24]

Related Business Environmental Leadership Council (BELC) Company Activities

 

Related C2ES Resources

Climate TechBook Biofuels Overview

McCollum, David, Gregory Gould, and David Greene, Greenhouse Gas Emissions from Aviation and Marine Transportation: Mitigation Potential and Policies, 2009.

Further Reading / Additional Resources

Congressional Research Service (CRS) – Aviation and Climate Change, 2010

International Civil Aviation Organization (ICAO) - Aircraft Engine Emissions

National Aeronautics and Space Administration (NASA), Environmentally Responsible Aviation (ERA) Project

Partnership for AiR Transportation Noise and Emissions Reduction (PARTNER)

Transportation Research Board (TRB) of the National Academies - Aviation

Boeing, Current Market Outlook 2008-2027.

Karagozian, A., W. Dahm, et al., Technology Options for Improved Air Vehicle Fuel Efficiency: Executive Summary and Annotated Brief, United States Air Force Scientific Advisory Board, 2006.

Greener by Design, Mitigating the Environmental Impact of Aviation: Opportunities and Priorities. Report of the Greener by Design Science and Technology Sub-Group, 2005.



[2]Ibid.

[3]McCollum, David, Gregory Gould, and David Greene, Greenhouse Gas Emissions from Aviation and Marine Transportation: Mitigation Potential and Policies, 2009. Unless otherwise noted, all facts and figures in this document are drawn from this report.

[4]McCollum et al. 2009.

[5]For more detail on this topic, see the box on p.11-12 of McCollum et al. 2009.

[6]CNS/ATM refers to technologies that enhance the ability of air traffic control to monitor and direct multiple aircraft within an airspace. For example, satellites can more accurately pinpoint an aircraft’s location, allowing more planes to safely operate within close proximity. This allows for more fuel efficient routing and landing procedures, thus reducing GHG emissions.

[7]Laminar flow control (LFC) refers to technologies that modify the aircraft’s boundary layer (the layer of air that clings to the surface of the airframe). LFC increases fuel efficiency by reducing turbulence in this layer. There are two types of LFC technology: passive and hybrid. Passive LFC reduces aerodynamic drag by modifying the air-wing interaction through the shape of the front of the wing. Hybrid LFC removes a portion of the boundary layer (e.g. through slotted or porous wing designs) to reduce drag.

[8]Liebeck, R. H., “Design of the Blended Wing Body Subsonic Transport,” Journal of Aircraft 41(1):10-25, 2004.

[9]Karagozian, A., W. Dahm, et al., , Technology Options for Improved Air Vehicle Fuel Efficiency: Executive

Summary and Annotated Brief, United States Air Force Scientific Advisory Board, 2006.

[10]Greener by Design, Mitigating the Environmental Impact of Aviation: Opportunities and Priorities, Report of the Greener by Design Science and Technology Sub-Group, 2005.

[11]While the direct GHG emissions from combustion of biofuels or Fischer-Tropsch fuels will be similar to or the same as the direct GHG emissions from combustion of traditional petroleum-based aviation fuel, such alternative fuels can have significantly lower net lifecycle GHG emissions since they can be manufactured from biomass feedstocks so that, in effect, combustion of such alternative fuels emits CO2 that was earlier absorbed from the atmosphere by the biomass feedstocks. For more information on biofuels, see C2ES’s Climate TechBook “Biofuels Overview.”

[12]Fischer-Tropsch synthesis of transportation fuels involves gasification of a carbon-containing feedstock (e.g., biomass, coal) and production of a synthetic crude oil, which can then be processed into refined liquid fuel products.

[13]Winglets are vertical extensions of wingtips that reduce drag and increase fuel efficiency.

[14]Liebeck 2004

[15]Greener by Design, The Technology Challenge. Report of the Technology Sub-Group, 2001.

[16]Morris, J., A. Rowbotham, et al., A Framework for Estimating the Marginal Costs of Environmental

Abatement for the Aviation Sector, Omega and Cranfield University, 2009.

[17]Greener by Design, Annual Report 2007-2008.

[18]Government Accountability Office (GAO), High Speed Passenger Rail: Future Development Will Depend on Addressing Financial and Other Challenges and Establishing a Clear Federal Role, 2009.

[19]See, for example, Morris, Eric, “High-Speed Rail and CO2,” blog post, New York Times, 24 July 2009.

[20]GAO, Aviation and the Environment: NextGen and Research and Development Are Keys to Reducing

Emissions and Their Impact on Health and Climate, Statement of Gerald L. Dillingham, 2008.

[21]International Air Transport Association (IATA), “Fact Sheet: Alternative Fuels,” 2009.

[22]For more details, see C2ES’s brief, Climate Change Mitigation Measures in the European Union, 2009.

[23]For more information on cap and trade, see C2ES’s Cap and Trade 101.

[24]P.L.-111-5, American Recovery and Reinvestment Act of 2009 (H.R.1), 111th Congress.

 

Technologies and strategies for reducing emissions from the aviation sector
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Teaser: 

Technologies and strategies for reducing emissions from the aviation sector

Renewable Fuel Standard

Highlights

  • The renewable fuel standard (RFS) is a requirement that a certain percentage of petroleum transportation fuels be displaced by renewable fuels. RFS1 started with the Energy Policy Act of 2005. Congress updated the standard in the Energy Security and Independency Act of 2007 (EISA). This new renewable fuel standard is known as RFS2.
  • RFS2 is a renewable fuel standard for biofuels only that requires obligated parties to sell a certain amount of biofuels per year through 2022.
  • RFS2 contains a four-part mandate for lifecycle greenhouse gas emissions levels relative to a 2005 baseline of petroleum: for renewable fuel, advanced biofuel, biomass-based diesel, and cellulosic biofuel.
  • The EPA published the final rule for RFS2 on March 26, 2010.

Background

The Energy Policy Act of 2005 created a Renewable Fuel Standard (RFS1) in the U.S. that required 2.78 percent of gasoline consumed in the U.S. in 2006 to be renewable fuel. The EPA finalized this requirement for RFS1 in April of 2007.

Congress expanded U.S. renewable fuel usage with the Energy Independence and Security Act (EISA) of 2007. The Act included a provision for a new Renewable Fuel Standard (RFS2), which increased the required volumes of renewable fuel to 36 billion gallons by 2022 or about 7 percent of expected annual gasoline and diesel consumption above a business-as-usual scenario. The Act gave the EPA the authority to revise and implement regulations related to RFS2.

Figure 1: Renewable Fuel Standard requirements through 2022

The EPA issued a notice of the proposed rulemaking for RFS2 in May of 2009 and the final rule in March of 2010. Table 1defines the four categories of renewable fuel according to the EPA. In order to be classified under one of these categories, a fuel must meet the percentage reduction in life-cycle greenhouse gas emissions shown in the table. The EPA’s rule defined the renewable fuel volume requirements from 2008 through 2022. From Figure 1, one can see the RFS2 slowly ramps up advanced biofuels (cellulosic, biomass-based diesel, and non-cellulosic advanced) until they overtake conventional biofuels in consumption levels by 2022.

Table 1: Renewable fuel types in RFS2

Fuel

% reduction

from displaced gasoline/diesel

(2005 baseline)

Definition

Renewable fuel

 20%

Fuel produced from renewable biomass and that is used to replace or reduce the quantity of fossil fuel present in a transportation fuel.**

Advanced biofuel

50%*

Renewable fuel other than ethanol derived from corn starch.

Biomass-based diesel

 50%

Includes both biodiesel (mono-alkyl esters) and non-ester renewable diesel (including cellulosic diesel). It includes any diesel fuel made from biomass feedstocks. However, EISA included three restrictions. EISA requires that such fuel be made from renewable biomass. The statutory definition of “biomass-based diesel” excludes renewable fuel derived from co-processing biomass with a petroleum feedstock.

Cellulosic biofuel

 60%

Renewable fuel derived from any cellulose, hemicelluloses, or lignin each of which must originate from renewable biomass.

* EPA could have exercised the 10 percent adjustment allowance provided for in EISA for the advanced biofuels threshold to as low as 40% but did not do so. ** Transportation fuel includes gasoline, diesel, heating fuel, and jet fuel. It can also include electricity, natural gas, and propane if it can be determined that the source of the fuel is renewable and the fuel is used for transportation. Source: Federal Register. (2010, March 26). Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program: Final Rule. 74(99). Washington: National Archives and Records Administration.

RFS2 Impacts

  • On petroleum consumption, energy security, and fuel costs:
    • RFS2 will displace about 13.6 billion gallons of petroleum-based gasoline and diesel fuel in 2022; this represents about 7 percent of expected annual gasoline and diesel consumption in 2022.
    • RFS2 will decrease oil imports by $41.5 billion, and will result in additional energy security benefits of $2.6 billion by 2022.
    • By 2022, gasoline costs should decrease by 2.4 cents per gallon and diesel costs should decrease by 12.1 cents per gallon because of the increased use of renewable fuels.
  • RFS2 will reduce greenhouse gas emissions by 138 million metric tons in 2022; this is equivalent to taking about 27 million vehicles off the road.
  • Agriculture sector and related impacts:
    • RFS2 will increase net farm income by $13 billion dollars (or 36 percent) in 2022.
    • RFS2 will decrease corn exports by 8 percent and soybean exports by 14 percent in 2022.
  • RFS2 will increase the cost of food $10 per person in 2022.

Changes from RFS1

  • RFS2 peaks at 36 billion gallons of renewable fuel by 2022 instead of 7.5 billion gallons by 2012
  • RFS2 set volume requirements for newly defined renewable fuel types; see Figure 1.
  • RFS2 goes beyond gasoline replacement by also including biodiesel.
  • Added greenhouse gas reduction thresholds for different fuel types (see Table 1) and takes into account indirect land use change. From C2ES’s report, Reducing Greenhouse Gas Emissions from U.S. Transportation, “[i]f land is converted to another agricultural use to produce biofuel, this will tend to raise the price of the agricultural commodity displaced. The higher price will encourage land somewhere in the world to be converted to agricultural use. If the land is cleared, carbon sequestered in the biomass and in the soil will be released to the atmosphere. The release of sequestered carbon will offset some of the potential GHG benefit of biofuel use.”
  • RFS2 limits fuel from corn starch to 15 billion gallons by 2022; there are no limits from corn stover (waste).

Final EPA Analysis

  • Released in February, 2010.
  • Indirect land use change assumptions defined such that almost all corn ethanol qualifies for program as a conventional biofuel feedstock (see Figure 2).
  • Under the final rule, EPA must reduce the cellulosic biofuel requirements if there is insufficient supply. EPA did so for 2013 for the fourth year in a row (see Table 2).
  • Grandfather Clause: According to the final rule, renewable fuel from existing facilities, which commenced construction on or before December 19, 2007, is exempt from the percent reduction from displaced gasoline/diesel for “renewable fuel” defined in Table 1. Ethanol plants that use natural gas or biodiesel for process heat, which commenced construction on or before December 31, 2009 are also exempt.

Figure 2: Fuel Pathways from EPA in 2022

Source: Federal Register. (2010, March 26). Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program: Final Rule. 74(99). Washington: National Archives and Records Administration.

Final EPA Requirements

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

 

Cellulosic biofuel

Biodiesel

Advanced biofuel

Total Renewable fuel (Including Ethanol)

2011

6.6 million

0.8

1.35

13.95

2012

10.45 million

1

2

15.2

2013 (Proposed)

14 million

1.28

2.75

16.55

Note: Volumes are ethanol-equivalent, except for biodiesel, which is actual volume, Source: EPA, Renewable Fuel: Standards and Regulations,  http://www.epa.gov/otaq/fuels/renewablefuels/regulations.htm

Compliance Details

Obligated Parties

Refiners that produce gasoline or diesel as well as importers of gasoline or diesel in the lower 48 states and Hawaii are the obligated parties for RFS2. Parties that add renewable fuel to gasoline or diesel (blenders), the state of Alaska (which can opt in), small refiners (whose exemption could expire on December 31, 2010), and gasoline exporters are exempt from RFS2.

Renewable Fuel Requirements and Penalties

Each year, the EPA must determine how much renewable fuel an obligated party must sell in order to meet RFS2. The EPA does this by determining the percentage of each of the four types of renewable fuel (see Table 1) that must be in the entire market in order to achieve the volume required by the standard for that year. It then requires each obligated party to own RINs (see box below) representing the same percentage of each of the four types of renewable fuel (known as renewable volume obligations or RVOs). See Appendix A for a description of the formulas the EPA uses to calculate obligation requirements. A provider may acquire these RINs either through producing the biofuel or through purchasing RINs on the open market. Most obligated parties are not biofuel producers so they would be expected to meet their obligation through the purchase of RINs. Thus, RFS2 establishes a credit trading system to attain the lowest possible cost of compliance.

In order to track renewable fuel sold into the market, the EPA requires renewable fuel producers and importers to assign unique Renewable Identification Numbers (RINs) for each batch of renewable fuel sold where a batch is any amount less than 100 million gallons per month, unless the producer or importer processes less than 10,000 gallons per year.

If an obligated party is out of compliance, the EPA may impose fines up to $32,500 as specified under sections 205 and 211(d) of the Clean Air Act for every day the entity is in violation and the amount of economic benefit or savings resulting from each violation.

References

EPA. 2010. EPA Finalizes 2011 Renewable Fuel Standards. November. Accessed December 6, 2010. http://www.epa.gov/otaq/fuels/renewablefuels/420f10056.htm.

Federal Register. 2010. "Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program: Final Rule." Vol. 74. no. 99. Washington: National Archives and Records Administration, March 26.

Greene, David, and Steven Plotkin. 2011. Reducing Greenhouse Gas Emissions from U.S. Transportation. Arlington, Virginia: Pew Center on Global Climate Change.

Press Release: Pew Center Briefs Point to Clean Energy Jobs, Detail Carbon Market Oversight

Press Release
February 17, 2010
Contact: Tom Steinfeldt, (703) 516-4146


MARKET-BASED SOLUTIONS CAN GROW U.S. CLEAN ENERGY ECONOMY
Pew Center Briefs Point to Clean Energy Jobs, Detail Carbon Market Oversight

WASHINGTON, D.C. – The Pew Center on Global Climate Change has released two timely publications that make the case for market-based clean energy and climate solutions.

Clean Energy Markets: Jobs and Opportunities, a new brief, explains how investment in clean energy technologies will generate economic growth and create new jobs in the United States and around the world. Comprehensive, market-based national policy that attracts investment in clean energy markets can help create these economic benefits.

A second brief, Carbon Market Design & Oversight, assesses the opportunity now before Congress to create the optimal design and oversight mechanisms to ensure a viable, transparent, and robust carbon market.

“It’s in our economic self-interest to ramp up development and deployment of U.S. clean energy technologies so that we can compete in the rapidly growing global clean energy markets,” said Eileen Claussen, President of the Pew Center on Global Climate Change. “It’s not too late for the U.S. to position itself as a global clean energy leader, but we must act now. Passing comprehensive climate and energy legislation that prices carbon will give businesses the certainty needed to unleash millions of dollars in clean energy investments that will create U.S. jobs and expand economic opportunities.”

Worldwide, clean energy markets are already substantial in scope and growing fast, explains the Clean Energy Markets brief. Historically, regions where an industry gains an initial foothold are more likely to become a major center of growth for the industry. In the United States, comprehensive climate and energy policy can give nascent clean energy industries this initial start by attracting investment in clean energy markets and helping to create homegrown jobs.

In crafting sensible, market-based climate and energy policy, lawmakers should build on best practices and lessons from a number of existing markets to create the optimal carbon market design and oversight mechanisms. The Carbon Market brief provides policymakers a thorough yet concise assessment of the key considerations involved in establishing a sound, transparent U.S. carbon market. These include:

  • Roles and rationales of exchange-based and over-the-counter markets;
  • Options for improving oversight of these markets;
  • Assessments of potential regulatory agencies for a U.S. carbon market; and
  • Comparisons of carbon market oversight provisions in legislative proposals.

“Effective carbon market oversight will be critical, but it is fundamental and achievable,” said Claussen.
For more information about global climate change and the activities of the Pew Center, visit www.c2es.org.

###

The Pew Center 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.

Regulatory Uncertainty Hinders Business in Alaska and Nationwide

ANCHORAGE - Alaska is a big state, with big mountains, big wildlife, and big development projects.  It’s also a place of big changes: the state has warmed more than 4 degrees, creating tremendous pressures on the natural environment and society.  But in a place where the people are always looking for the next big economic driver, like a $40 billion Alaska natural gas pipeline, uncertainty about carbon regulation is an Alaska-sized problem.

Nuclear Waste Commission, Yucca Mountain, and Loan Guarantees

Recent news has cast a spotlight on nuclear power. We’ve blogged before about nuclear power and its potential to play a large role in decarbonizing the electricity sector.

First among the big news items related to nuclear power is the official naming by the Obama Administration of a much-anticipated Blue Ribbon Commission on America’s Nuclear Future to recommend a safe, long-term solution for used nuclear fuel and nuclear waste. The commission, announced on January 29, will issue its final report within 24 months. Energy Secretary Chu noted that the commission is not tasked with recommending a site for a long-term waste repository.

Building an Electric Vehicle Here in the USA

In tackling climate change, a diverse transportation sector can contribute greatly to reducing greenhouse gas (GHG) emissions. In 2008, the transportation sector accounted for 28% of U.S. GHG emissions, according to the EIA. In achieving the goal of reducing emissions, transportation policy must reduce GHG emissions from travel without compromising the mobility of Americans. To that end, electric vehicles provide a much-needed alternative to gasoline and diesel powered cars.

Carmakers are responding to this challenge by designing plug-in electric vehicles (PHEVs) and all electric vehicles (EVs). Nissan’s Leaf, a new electric vehicle, is slated to hit showrooms throughout the U.S in late 2010. One of two Leafs seen in public was on display last week at the Washington Auto Show where the Green Car Journal named the Leaf its 2010 Green Car Vision Award winner.

Nissan Leaf

At first, Nissan will likely place prospective buyers on a waiting list, but it anticipates ramping up Leaf production at a factory it is retooling in Smyrna, Tennessee. The company secured a $1.4 billion loan from the U.S. Department of Energy (DOE) last week to prepare the plant to manufacture the vehicles and the advanced batteries that will power them. DOE points out that the facility will “create up to 1,300 American jobs and conserve up to 65.4 million gallons of gasoline per year.” The 150,000 vehicle-per-year factory positions the U.S. as a leader in the next generation of low-emissions vehicle manufacturing.

At the DC auto show, the Nissan representative shared details about the vehicle along with the company’s program to distribute it worldwide. Nissan is partnering with Better Place, an innovative electric vehicle services provider, to sell the Leaf in Denmark and Israel in 2011. The company intends to make modifications to the Leaf’s chassis to support Better Place’s battery switch stations. The Leaf will also meet SAE’s J1772 standard for electric vehicle charging. Lastly, by laminating the lithium-ion battery packs in order to make them self-cooling, Nissan solved a complex technical problem without using a computer control system. More information about the Leaf is available on Nissan’s website.

The L.A. Time reports Nissan hints at a sticker price of less than $30,000, before accounting for the $7,500 federal tax credit for plug-in hybrid vehicles and electric vehicles provided in the Recovery Act. No pricing information was available at the auto show. 

The three most important issues to Americans today are the economy, jobs, and terrorism according to the Pew Research Center for the People & the Press. If one makes the logical connection between protecting against terrorism and promoting energy security, Nissan is timely in releasing the Leaf in 2010. With the Leaf, the company will create American jobs to manufacture an affordable vehicle that lowers U.S. dependence on foreign oil.

Nick Nigro is a Solutions Fellow

We Need an Innovation War, Not a Trade War

In a letter to Secretaries Clinton, Geithner, and Locke, Attorney General Holder, and US Trade Representative Kirk, 19 business groups, including the National Association of Manufacturers, argue that new “indigenous innovation” programs are designed by the Chinese government to find “national champions” of industry that can be advantaged in a variety of sectors, including green technology, and create "barriers to competition."  The Hillicon Valley technology blog over at The Hill notes that this concern comes in the context of rising trade conflicts between the United States and China. 

This attention comes on the heels of increasing concern over China’s leadership in clean energy technology. As noted in this weekend’s New York Times piece on the subject, the country has become the world’s largest manufacturer of wind and solar generation equipment.  Through industrial policy, China is trying to take advantage of the growing export market for power sector equipment of all types, especially clean energy.

We should have expected that China would be a strong competitor in the clean energy sector.  Regardless of the outcome of continuing international climate negotiations, countries from Europe to most U.S. states to China itself have already made unilateral policy choices to increase the use of clean energy technology in the coming decades for a multitude of reasons.  The demand will be tremendous for the manufacture of clean energy technologies, and there is potential for fortunes to be made in their export.

What should the appropriate policy response be?  As the authors of the letter suggest, the US should promote fair access for American goods and services in foreign markets.  Protectionist responses and trade wars have never helped any country grow its economy and create jobs.

But reducing protectionism is not enough to regain the American lead in the clean energy sector.  The US needs to have a policy of its own that encourages innovation and gives the right incentives for US companies to compete globally.  America is a land of innovation, and we should be the ones taking advantage of these new and growing markets, not ceding them to competitors.  Part of the answer is for the US to put a price on carbon. Doing so would encourage innovation in the private sector and provide regulatory certainty for companies to make investments here in clean energy technologies.  American ingenuity is second to none, and Congress needs to work on a climate and energy bill that provides the right framework for our businesses to flourish.

Michael Tubman is a Congressional Affairs Fellow

Natural Gas and Our Energy Future

We just added a brief on natural gas to its Climate TechBook that helps to explain why natural gas is unique among fossil fuels. Natural gas is both a contributor to climate change (natural gas combustion accounts for about 16 percent of total U.S. greenhouse gas emissions) and an option for reducing emissions since natural gas is less carbon-intensive than coal and petroleum. The United States could actually reduce total greenhouse gas emissions by burning more natural gas if it’s displacing other fossil fuel use (this is particularly the case for fuel switching from coal to gas in power generation).

Like coal, but unlike petroleum, natural gas is primarily a domestic energy resource, with net imports of natural gas constituting only about 13 percent of U.S. consumption and about 90 percent of imports coming from North America. Unlike coal (93 percent consumed for electricity generation) and petroleum (more than two thirds used for transportation), natural gas consumption is more evenly split across the electric power, industrial, residential, and commercial sectors.

The past few years have seen a “revolution” in the outlook for natural gas supply. Until recently, experts thought that the United States would become increasingly dependent on expensive imports of liquefied natural gas (LNG) from overseas, but the recent boom in domestic “unconventional” gas production (driven by shale gas) and the dramatically increased estimate of U.S. gas reserves have led to projections of increasing domestic natural gas production and declining imports.

Natural gas is receiving a lot of attention in the discussion about U.S. climate and energy policy. The gas industry is pressing for favorable treatment in possible climate and energy legislation, with a specific set of policy priorities recently put forth by a major industry lobby group.

While some tout natural gas as a “bridge fuel” to a low-carbon future others fear that a “dash for gas” (i.e., fuel switching by electric power generators) could increase demand for and the price of natural gas, thus negatively impacting manufacturers that rely on natural gas for energy and as a feedstock.

Recent analysis by the U.S. Energy Information Administration (EIA) of the climate and energy bill passed by the House in June 2009, illustrates how the projected role of natural gas in reducing U.S. greenhouse gas emissions depends in large part on the use of offsets under cap and trade and the relative cost and commercial availability of low-carbon technologies (e.g., wind, solar, carbon capture and storage, and nuclear power). When low-carbon technology deployment and offsets are constrained, EIA finds a much heavier reliance on natural gas for electricity generation under cap and trade, but the new outlook on U.S. natural gas supply means that even this pessimistic scenario does not lead to major increases in projected natural gas prices.

A new modeling analysis from Resources for the Future (RFF) sought to quantify the implications of the dramatically expanded U.S. natural gas supply. RFF researchers found that without new energy and climate policy, more abundant and less expensive natural gas could actually mean slightly higher U.S. greenhouse gas emissions in 2030 than would otherwise be the case (as cheaper natural gas competes with non-emitting energy sources and increases total energy consumption).

This last point brings us back to the overarching importance of implementing a policy that puts a price on carbon, as a greenhouse gas cap-and-trade program would do. Putting a price on carbon would harness market forces to drive the deployment of a portfolio of low- and lower-carbon technologies and fuels, including increased natural gas use to the extent it can cost-effectively reduce emissions.

Steve Caldwell is a Technology and Policy Fellow

Natural Gas

Quick Facts

  • In 2012, natural gas constituted 25 percent of total U.S. energy consumption[1] – and 24 percent total global energy consumption[2] – and provides roughly one fifth of all U.S. electricity generation.[3]
  • About 24 percent of U.S. carbon dioxide emissions are related to natural gas, 1,296 million metric tons in 2011.[4]
  • No one sector dominates natural gas consumption; rather, the electric power, industrial, residential, and commercial sectors are all significant end users.
  • Replacing diesel with natural gas could reduce fuel lifecycle greenhouse gas emissions from heavy-duty vehicles by up to 29 percent , depending on leakage rates.[5],[6]
  • Comparing coal to natural gas, natural gas power plants emit half as many greenhouse gas emissions.[7]
  • Natural gas-fired electricity power plants are expected to continue to increase in importance – accounting for 37 percent of the planned capacity for 2012 and 60 percent of capacity additions between 2010 and 2035.[8]
  • Natural gas can supplement intermittent energy sources such as solar and wind, potentially allowing for more opportunities for clean and renewable energy deployment.
  • The natural gas policy landscape is diverse; addressing fuel sourcing, distribution, power production, and end use consumption.
  • An estimated 36 gigawatts (GW) of coal generation is expected to be retired between 2014 and 2016, largely in response to lower natural gas prices and, to a lesser extent, new environmental regulations.[9]
     Proposed greenhouse gas emissions standards by the U.S. Environmental Protection Agency favor natural gas technologies for new fossil fuel power plants[10]

Background

Constituting 25 percent of total U.S. energy consumption, natural gas is important in almost every economic sector, used to produce heat and electricity, and as a feedstock in manufacturing (see Figure 1).[11] Natural gas is composed primarily of methane (CH4) – a very potent greenhouse gas. During various steps of natural gas extraction, transportation, and processing, methane is released to the atmosphere. These “fugitive” emissions can represent an opportunity to reduce greenhouse gas emissions, maximizing the potential climate benefits of using natural gas.

Recently, natural gas reserves have dramatically expanded because of technological advances allowing access to unconventional sources in shale formations, coal beds, and sandstone formations. For background information on natural gas not covered in this factsheet, including supply, demand, and pricing see C2ES Natural Gas Overview.

Figure 1: U.S. Natural Gas Consumption by Economic Sector (2011)

Source: Energy Information Administration, U.S. Department of Energy 2012.[12]

Description

In the last few years, the outlook for U.S. natural gas supply has changed dramatically, with predictions no longer showing the United States becoming increasingly reliant on natural gas imports (particularly imports of liquefied natural gas, or LNG); rather, technological advances in seismic imaging, horizontal directional drilling and hydraulic fracturing over the past 30 years have led to dramatically increasing economically recoverable North American shale gas. Because of this increase, the United States is expected to become a net exporter of natural gas in 2022.[13] Shale gas has been the primary source of U.S. natural gas growth since 2000, increasing from 2 percent to approximately 22 percent of the natural gas supply in 2011.[14] Shale gas is expected to grow fourfold by 2035, making up nearly 50 percent of total U.S. natural gas production.[15]

In 2012, U.S. natural gas consumption averaged 69.8 billion cubic feet per day (Bcf/d), a 4.8 percent increase (3.2 Bcf/d) from 2011 (see Figure 2).[16] Growth in natural gas consumption is expected in all sectors except the residential sector, with the most dramatic increase in transportation (an estimated 5.9 percent increase, though it is starting from a low baseline).[17]

Figure 2: Projected Total Natural Gas Consumption (2012-2035)

Source: EIA Annual Energy Outlook. 2012. Total Energy Supply, Disposition, and Price Summary.[18]

Natural Gas Applications

Natural gas has a wide range of applications in all economic sectors.

Electric Power: Natural gas can provide baseload, intermediate, and peak demand electricity. The electric power sector is using an increasing percentage of natural gas, over 31 percent in 2011, up from 17percent in 1990.[19] Natural gas-fired electric power plants are expected to continue to increase in importance – accounting for 37 percent of 23.5 GW of electric power generation planned for 2012 and 60 percent of capacity additions between 2010 and 2035 (for more, see C2ES resource Natural Gas in the U.S. Electric Power Sector).[20]

  • Besides the appeal of a low-cost domestic fuel source, natural gas power plants can be constructed in as little as 20 months for approximately one third the levelized capital cost for a typical coal plant.[21] Natural gas electricity generation relies on three basic technologies:
    • Steam turbine plants: These plants operate like traditional coal-fueled power plants where fossil fuel (in this case natural gas) combustion heats water to create steam. The steam turns a turbine, which runs a generator to create electricity. These typically have thermal efficiencies of 30 – 35 percent.
    • Combustion turbine plants: These plants are generally used to meet peak electricity demand. They operate similarly to jet engines: natural gas is combusted and used to turn the turbine blades and spin an electrical generator.[22] The typical size is 100 – 400 MW with a thermal efficiency around 35 – 40 percent.[23]
    • Combined cycle plants (NGCC): Combined cycle plants are highly efficient because they combine combustion turbines and steam turbines; the hot exhaust from a gas-fired combustion turbine is used to create steam to power a steam turbine.[24] High efficiency combined cycle plants emit less than half the CO2 per megawatt-hour as coal power plants, and operate with a 50 – 60 percent thermal efficiency range.[25] A typical natural gas combined cycle power plant has a heat rate (i.e., the amount of fuel used per unit of electricity generation) that is about one third lower than for a combustion turbine or gas-fired steam turbine plant.[26] The newest NGCC systems claim efficiencies of greater than 61 percent.[27]

Figure 3: Combined Cycle Power Plant

Source: Global-Greenhouse-Warming.com, 2010.

  • Alongside renewables: Natural gas can have an important relationship with renewable energy production because of its ability to respond quickly to short-term energy supply fluctuations. As a highly responsive energy source capable of providing baseload and short-term energy supply, it can supplement intermittent energy sources such as solar and wind, allowing for more opportunities for clean energy deployment.[28]
  • Greenhouse Gas Abatement options:
    • Fuel switching: Fuel switching refers to displacing traditional coal-fueled electricity generation with less carbon-intensive natural gas generation. Activities include: modifications to existing coal plants to instead utilize natural gas; operating fewer coal power plants; operating those plants at lower output levels; ramping up generation from natural gas power plants; and/or building new natural gas plants to replace coal generation. From 2002 to 2010, the number of natural gas electric utility power plants increased by 10 percent, from 699 to 775, while the number of coal electric utility power plants fell by 7 percent, from 363 to 333.[29]
    • Distributed Generation (DG): Traditionally, electricity is produced in large centralized power stations, which is transported to end-users over long distances. Contrarily, DG produces smaller amounts of electricity closer to the consumption site. DG benefits include fewer losses from long distance transmission lines, increased reliability, reduced peak power load, and increased responsiveness. Some technologies use less primary energy and emit fewer greenhouse gases than the centralized power system, especially when they are used in combined heat and power operations (see C2ES resource Distributed Energy and Emerging Technologies).[30]
    • Carbon capture and storage (CCS): Similar to its application with coal-fueled power plants, CCS can be coupled with natural gas power plants to capture and permanently sequester large percentages of the CO2 emissions from electricity generation (see Climate TechBook: Carbon Capture and Storage).
    • Supply Side Efficiency: Modern natural gas combined cycle power plants have higher efficiencies than gas-fired steam cycle plants; replacing the latter with the former can reduce the greenhouse gas emissions from gas-fired electricity generation.[31] Increasing the thermal efficiency of electricity production can reduce emissions, as higher thermal efficiencies mean less fuel is required to produce each kilowatt-hour of electricity (see C2ES resource Natural Gas in the U.S. Electric Power Sector).

Industrial Sector. Natural gas can be used in a diverse array of industrial sector applications, including heating and cooling, electricity generation, food processing, and as a feedstock in chemical products, plastics and fertilizers (see C2ES resource Natural Gas in the Industrial Sector).[32] In 2011, natural gas accounted for 58 percent of industrial electricity generation produced onsite, up from 51percent in 2005.[33] That year, the industrial sector consumed 6.91 quadrillion Btus of natural gas with 72 percent (4.98 quadrillion Btus) in heat and power operations.[34] Industrial sector usage resulted in the release of 433 million metric tons of CO2 that same year.[35]

  • Greenhouse Gas Abatement Options:
    • Boiler Efficiency: Because of the widespread use of natural gas in heat and power provision, upgrading boiler equipment to the highest efficiency possible can provide considerable emission benefits. For example, gas fueled boilers tend to have a long operational life; many in current operation are no longer considered efficient options. Replacing inefficient pre-1985 boilers, with average efficiency rates between 65 and 70 percent, with new boilers reaching efficiencies of up to 95 percent, could reduce emissions between 4,500 to 9,000 tons of CO2 per boiler.[36]
    • Combined heat and power (CHP, or cogeneration): In natural gas-fueled industrial CHP applications, natural gas is used to generate both useful heat and electricity. CHP has much higher efficiency than separate generation of heat and electricity from the same fuel supply. Therefore, replacing separate power and heat generation with CHP reduces fuel use and lowers emissions. As noted earlier, some of the most efficient uses of natural gas are in distributed generation applications in CHP operations. However, utility safety concerns, lack of additional expertise, lack of utility financial incentive to encourage its use, and the need to provide sufficient backup are barriers to CHP development.[37]
    • Other efficiency measures: Measures such as preventive maintenance and advanced steam systems process controls can lead to more efficient energy use and thus lower emissions.[38]

Natural Gas Industry Operations. Natural gas systems involve the production, processing, transmitting, and distributing as well as the storage of the resource.

  • Formation CO2: Often found in raw natural gas, formation CO2 is separated and generally vented to the atmosphere during natural gas processing.
  • Fugitive emissions: Fugitive emissions, also called “leakage”, are primarily from equipment or pipeline leaks as well as routine venting activities.[39] Estimates of leakage rates within the natural gas system are changing as more information becomes available. Greenhouse gas monitoring, measurement, and regulation in other sectors and the recent expansion of natural gas production and use have increased attention to the issue and spurred efforts to measure leakage.
    • Other CO2 emissions:[40] “Lease gas” is combusted to power gas and oil field operations (e.g., dehydration, compression). Flaring is the burning off of unwanted gas, which yields CO2 as a byproduct. “Plant fuel” is natural gas used to power gas processing plants; likewise, “pipeline fuel” is natural gas used to power natural gas transmission and storage operations.
  • Greenhouse Gas Abatement options
    • Carbon Capture and Storage (CCS): Natural gas processing facilities remove CO2 and other impurities from raw natural gas, generating highly-pure streams of CO2. [41] Such facilities offer some of the least expensive opportunities for deploying carbon capture technology at a commercial scale, since processing produces high purity streams of CO2 that can be captured with less difficulty than potential CO2 emissions from fossil fuel combustion. For several decades, CO2 from natural gas processing has been captured, transported via pipeline, injected underground for use in enhanced oil recovery (CO2-EOR) (see C2ES resource: National Enhanced Oil Recovery Initiative.[42]
    • Methane mitigation: Mitigating fugitive emissions provides an opportunity to maximize the potential climate benefits of using natural gas. Additional field testing should be performed to gather up-to-date, accurate methane leakage data. A better understanding and more accurate measurement of the emissions from natural gas production and use could identify additional cost-effective emission reduction opportunities along the natural gas value chain, and aid policymakers in creating effective regulations to address methane releases. Fugitive emissions can be reduced by upgrading equipment (e.g., valves), changing procedures to reduce venting, and improving leak detection and measurement efforts.[43]

Transportation: Natural Gas Vehicles (NGV): Natural gas can be compressed (CNG) or converted into liquid (LNG) fuel for use in place of conventional fuels in modified engines, or in fuel cell vehicles. Globally, there are more than 15 million NGVs; almost three quarters in just five countries (Pakistan, Argentina, Brazil, Iran, and India).[44] In 2010, compressed natural gas (CNG) and liquid natural gas (LNG) vehicles comprised about 0.05 percent (about 120,000 vehicles) of the U.S. vehicle stock (for more, see C2ES Natural Gas in the Transportation Sector)[45] – over 45 percent of which were medium- or heavy-duty vehicles.[46] Gas to liquid technology (GTL) is another fuel technology that converts natural gas into diesel or gasoline, able to be utilized in the existing fleet and fuel distribution infrastructure. Finally, electricity can be produced using natural gas that can in turn power electric vehicles.

  • Vehicle Types:
    • Dedicated: completely natural gas reliant
    • Bi-fuel: vehicles with separate fuel systems allowing them to run on conventional fuels or natural gas
    • Dual-Fuel: typically heavy-duty vehicles that use diesel for ignition but run on natural gas
  • Fuel types: to provide vehicle fuel, natural gas is most commonly used as either compressed natural gas (CNG) or as liquefied natural gas (LNG). Both CNG and LNG are less dense than gasoline and therefore require larger tanks in vehicles.
    • LNG is produced by super-chilling the natural gas to -260ºF. Usage requires vehicle tanks to be insulated to keep the fuel chilled, leading this technology to be primarily used in heavy-duty trucks.[47]
    • CNG is produced by compressing natural gas in cylinders at a pressure of 3,000 to 6,000 lbs per square inch and is used in light-, medium-, and heavy-duty vehicles. These vehicles get about the same fuel economy as a conventional gasoline vehicle.[48]
    • Fuel Cell vehicles can be fueled with hydrogen gas extracted from a secondary fuel that contains hydrogen, such as natural gas. The secondary fuel is first converted to hydrogen gas, for example, by an onboard reformer. These vehicles produce only small amounts of air pollution.[49]
  • Greenhouse Gas Abatement Options
    • Fuel substitution: Increasing the use of natural gas vehicles and decreasing other is an example of transportation-based fuel switching. Because of its lower carbon intensity, natural gas combustion can produce fewer lifecycle greenhouse emissions than gasoline or diesel.[50] In 2009, California Air Resources Board (CARB) found that substituting natural gas for diesel in heavy-duty vehicles could provide a 29 percent reduction in emissions. A higher leakage rate during the natural gas production and distribution process, however, would reduce these benefits.[51] Fuel substitution in heavy-duty vehicle fleets may present opportunities to reduce emissions in government and commercial fleets because of available technology and refueling options.[52]
    • Overcoming infrastructure barriers: Using natural gas in vehicles in place of gasoline or diesel reduces greenhouse emissions. Although widely dispersed fueling infrastructure remains a barrier to increasing use of natural gas, municipalities and certain scale commercial fleets could utilize centralized refueling stations. Intercity or regional heavy duty vehicles are ideal candidates, particular those with consistent travel requirements and predictable range such as buses and garbage trucks. A small number of refueling stations can serve a large percentage of this sector. For more, see C2ES resource Natural Gas in the Transportation Sector.

Residential and Commercial: Natural gas has extensive residential and commercial applications. As a fuel source consumed onsite, natural gas provides an option to increase fuel efficiency in buildings while decreasing emissions when compared with centrally produced electricity.

  • Residential: Natural gas is most commonly used in thermal applications, particularly space and water heating. Space heating use varies regionally, and natural gas provides a greater proportion in colder climates whereas homes in warmer climates tend to prefer electric heating. Natural gas is also used in various appliances such as clothes dryers, ovens and cooktop stoves. For more information on the residential applications see Climate TechBook: Buildings Overview and Residential End-use Efficiency.
  • Commercial: These buildings include offices, health care facilities, warehouses and storage, food service and preparation, and educational institutions, where natural gas is used to heat water, for large appliances, and most predominantly, space heating (see C2ES resource Natural Gas in Commercial Buildings).
  • Greenhouse Gas Abatement Options:
    • Codes, Standards, and Labeling. Mandatory or voluntary building codes and standards adopted by state and local governments can improve efficiency by encouraging equipment updates, improving building envelopes, and providing information resources to building managers and occupants about reducing fuel use. New appliance labeling efforts may offer an opportunity to inform consumers about energy efficiency and emissions benefits of different fuel choices, including natural gas.
    • Increased Deployment: Producing heat onsite from natural gas appliances is more efficient than producing heat through electricity transmitted from a central power plant. Assuming natural gas is displacing fossil fuel produced electricity, increased deployment of natural gas technology will increase energy efficiency and reduce greenhouse gas emissions by 40 to 60 percent per appliance (see C2ES resource Natural Gas in the Residential Sector).

Environmental Benefits / Emission Reduction Potential

Among fossil fuels, natural gas is the least carbon intensive and burns efficiently with fewer air pollutants (including particulates, nitrogen oxides, sulfur dioxide, lead, and mercury).[53] Combustion of natural gas emits approximately half as much carbon dioxide (CO2) as traditional coal and 33 percent less than oil.[54] As described natural gas heavy-duty vehicles could achieve a nearly 29 percent reduction when compared to diesel vehicles, depending on natural gas leakage rates.[55] While natural gas still produces significant emissions, when it displaces more carbon-intensive fuels like coal and oil, it can lower greenhouse gas emissions.

Natural gas emissions consist primarily of methane (CH4), which is a greenhouse gas about 21 times more powerful in terms of its heat-trapping ability than CO2 over a 100 year time frame.[56] Methane is emitted through venting and fugitive releases during the processing, transporting, and storage of natural gas.[57] Currently, venting and fugitive emissions from natural gas systems are around 3 percent of total U.S. greenhouse gas emissions. However, to fully realize the benefits of increased natural gas usage these fugitive emissions must be addressed. Fortunately, there are technologies that can help reduce emissions from oil and natural gas systems. Some analyses suggest these technology-based investment options for reducing greenhouse gas emissions have short payback times, depending on the price of natural gas.[58]

The role natural gas plays in overall greenhouse gas emission reductions depends on the extent to which natural gas is used to fulfill energy needs, the efficiency of the technology used, and the effectiveness of efforts to limit emissions. First, increasing direct use of natural gas in residential, commercial, and industrial sectors can reduce greenhouse gas emissions because of increased efficiency inherent in natural gas transmission and distribution when compared to electricity. A full fuel cycle assessment of the emissions impacts from all stages of fossil fuel production, processing, and end-use more accurately assesses its true climate impacts (see C2ES resource Natural Gas in the Commercial Buildings). Also, fuel switching from coal to natural gas in large power plants creates an opportunity for emissions reductions. Additionally, though no commercial-scale projects have been developed, natural gas power generation with carbon capture and storage (CCS) could provide further opportunity to diminish emissions (see C2ES Climate Techbook: CCS and C2ES resource Natural Gas in the U.S. Power Sector). Interest in building the world’s first commercial-scale natural-gas fired CCS power plant has grown in recent years. Notably, CO2 captured from natural gas processing or power generation can be used in enhanced oil recovery (CO2-EOR) and stored underground (see C2ES Enhanced Oil Recovery Overview).

However, inexpensive natural gas has the potential to outcompete renewables and nuclear projects, potentially hurting emission mitigation efforts.[59] Nuclear becomes less tenable because of its higher upfront capital costs when compared to natural gas (see Table 1).[60] Using natural gas in combination with renewables could provide lower emissions and a more flexible energy production system compared to centralized provision based on a single fuel source such as coal or nuclear power.

Cost

Price volatility is an important component of natural gas history, but it is unclear if this will remain so in the future (see Figure 4). Historically, natural gas cost fluctuations were due to regulatory changes, weather patterns, and large market trends (see C2ES resource U.S. Natural Gas: Overview of Markets and Uses). However, the market is expected to remain more stable in future years because of increased supply due to development of shale gas resources, advanced reserve identification and extraction techniques, and storage capabilities.[61]

Figure 4: U.S. Natural Gas Monthly Average Wellhead Prices (USD/mcf)

Source: U.S. Energy Information Agency, 2012.[62]

In the U.S. electric power sector, public utility commissions are approving natural gas power production based on fuel source economics, increasing deployment of natural gas electricity production. The degree of fuel switching is also dependent on cost differences in utilizing existing natural gas power plants compared with coal plants. For new construction, natural gas power plants can be built on a levelized cost basis for much less than competing fuel sources, including coal, nuclear, and renewable resources (see Table 1). When compared to traditional coal power production, new natural gas power plants provide a lower cost option to provide electricity with reduced carbon emissions.

Table 1: Levelized Comparisons of New Power Plants Entering Service in 2017

2010 USD($/MWh)

Levelized Capital Cost

Total System Levelized Cost

Coal

 

Conventional Coal

$64.9

$97.7

Advanced Coal (IGCC)

$74.1

$110.9

Natural Gas

 

Conventional Natural Gas (NGCC)

$17.2

$66.1

Advanced Combined Cycle

$17.5

$63.1

Wind

$82.5

$96.0

Nuclear

$87.5

$111.4

 

Source: Annual Energy Information Administration of the Department of Energy. 2012.[63]

Current Status of Natural Gas

Due to the range of applications, the natural gas policy landscape is diverse and addresses extraction, distribution, energy production, and end use consumption. The recent boom in shale gas extraction in areas of the country unaccustomed to this manner of industrial development has caused concerns in some communities and some calls for policy action. As part of this development, and particularly related to hydraulic fracturing, the U.S. Department of Energy’s Secretary of Energy Advisory Board (SEAB) recently released recommendations for improving operational safety and reducing potential environmental impacts in drilling operations.[64]

One area of policy attention is water quality impacts of shale gas development. The Environmental Protection Agency (EPA) is undertaking a study on the effects of hydraulic fracturing on drinking water, to be completed in 2014.[65] The Energy Policy Act of 2005 amended the Safe Drinking Water Act (1974) to exempt underground injection of fluids for hydraulic fracturing related to oil, gas, and geothermal production from regulation by the Environmental Protection Agency.[66] This lack of regulation has led to some concerns that water resources are not effectively protected from hydraulic fracturing activities.

Currently, 15 states have requirements for chemical disclosure in fracturing operations (see C2ES resource Hydraulic Fracturing Chemical Disclosure Map). Though requirements can vary widely, they generally outline what must be disclosed, identify the monitoring authority, set disclosure deadlines, and outline trade secret protections.[67] Regulations are changing quickly as states respond to new market conditions, recoverable gas resources, and potential environmental impacts. At the federal level, legislation has been put before Congress to promote transparency, particularly concerning the chemicals used in fracking operations.[68]

EPA, using its authority under the Clean Air Act (CAA), promulgated New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) for the oil and gas production sector in 2012. The NSPS requires facilities, including hydraulically-fractured wells to reduce emissions to a certain level that is achievable using the best system of pollution control, taking other factors into consideration, like cost.[69] Under the NESHAP program, the Agency sets technology-based standards for reducing certain hazardous air pollutants emissions using maximum achievable control technology. The regulations directly target the emission of volatile organic compounds, sulfur dioxide, and air toxics, but have the co-benefit of reducing emissions of methane by 95 percent.[70]

Also in 2012, EPA proposed a court-mandated NSPS to regulate greenhouse gas emissions from newly-constructed power plants. The rules would require that all new power plants meet the emission rates of highly efficient NGCC power plants. Therefore, NGCC power plants would comfortably meet the new standards, favoring new natural gas electricity generation in the future. Coal power plants can only meet the standard using CCS technologies. With an estimated 14 GW of coal generation being retired by 2015 because of other regulations and market forces, natural gas has an opportunity to capture an expanded percentage of power markets.[71] EPA is also required to set additional NSPS rules for greenhouse gas emissions from existing power plants, expected in the next few years. Additional pollution regulations impacting the power sector are found here.

Finally, proposals for a Federal Clean Energy Standard (CES) have been before Congress in recent years (see C2ES resource Clean Energy Standard). A CES would act similarly to state-level renewable portfolio standards (RPS) – which mandate a certain percentage of renewable-sourced electricity – by allowing credits for renewables as well as “clean” energy. “Clean” energy encompasses various technologies, such as NGCC and CHP, which create significantly less CO2 than traditional coal-fired power plants.[72] Currently, some states have policies that operate similarly to a CES in that they allow for some compliance through clean non-renewable energy resources (for more, see C2ES report Clean Energy Standards: State and Federal Options and Policy Implications.

Policy Options to Help Optimize Natural Gas Use

  • Putting a Price on Carbon. A policy that puts a price on greenhouse gas emissions would lead firms and households to make investment and operating decisions that reduce greenhouse gas emissions—ranging from fuel switching by electricity generators to investments in home insulation or programmable thermostats by households.
  • Policies to Address Impacts of Shale Gas Production. Abundant and low cost natural gas results from shale gas production. Local, state, federal, and corporate policies will be required to address concerns about water quality and availability, air pollution, community disruption, and climate change, among other topics, if this production is to continue at levels that maintain or expand supply. Policies such as public disclosure requirements regarding toxic chemicals used during hydraulic fracturing will improve understanding of risks, protect public safety, and boost confidence in shale gas drilling operations.
  • Alleviate Legal and Regulatory Barriers. Certain natural gas deployment options related to natural gas are constrained by legal and regulatory barriers. A policy of decoupling, which separates revenues from natural gas sales, can incentivize state-regulated local distribution companies to help customers pursue end-use efficiency measures. Another issue, the deployment of CCS with natural gas processing facilities, or natural gas-fueled electricity generation, requires a fully-developed regulatory and legal framework at the federal and state level to ensure the long-term safety of geological carbon storage (see Climate TechBook: Carbon Capture and Storage). Additionally, CHP deployment can face regulatory hurdles related to grid integration and electricity tariffs (see Climate TechBook: Combined Heat and Power).
  • Further control fugitive releases of methane through expanded policies. Policymakers have begun to create regulations that address fugitive releases, but better understanding and more accurate measurement of the emissions from natural gas production and use could potentially identify additional cost-effective emission reduction opportunities along the natural gas value chain.
  • Create Greenhouse Gas Reduction Credits or Offsets. Addressing fugitive methane emissions from oil and gas industry operations will prove administratively difficult to do directly under an emissions pricing policy such as cap and trade. Implementing a policy allowing projects that reduce methane emissions to qualify for offset credits to be traded under a cap-and-trade program would provide a financial incentive for firms to undertake such projects.
  • Enact Policies to Encourage Efficiency and Natural Gas. A range of proven policy interventions can improve natural gas implementation. Decoupling utility profits from sales ensures cost-recovery and a rate of return for energy efficiency investments, and state regulators can address the disincentive utilities face regarding promoting customer energy efficiency measures (see C2ES factsheet Decoupling in Detail). A lost-revenue adjustment policy can compensate utilities for lost revenue due to increased efficiency and can be particularly useful in encouraging CHP.[73]
    • Promote distributed generation and direct use. Distributed generation and direct use of natural gas can be more efficient than producing electricity at a centralized location. By incorporating these uses into all levels of building policy – industrial CHP, residential, and commercial – major gains in energy efficiency can be seen.
    • Energy Efficiency Product Standards. The government can and has set minimum efficiency standards for a variety of products including those that consume natural gas, such as furnaces, boilers, and water heaters (see C2ES resource Natural Gas in the Residential Sector).
    • Education Programs. Education and information programs can take forms such as voluntary labeling of energy-efficient household products (e.g., the ENERGY STAR program), publicly funded energy assessments, industrial energy efficiency case studies, and training (e.g., the Technology Deployment Activities program of the DOE’s Advanced Manufacturing Office). Policy intervention should address potential energy and cost savings, misaligned incentives, and bounded rationality (e.g., the use of rules-of-thumb that can lead to suboptimal decisions).[74]
  • Technological and infrastructure limitations. Policies should be implemented to expand infrastructure for natural gas applications, for example in buildings. In 2005, 71 percent of U.S. homes had access to natural gas, and yet only 61 percent of U.S. residences made use of natural gas in an appliance. Only 54 percent of new homes constructed in 2010 had natural gas service installed, and this access was primarily for heating.[75] Additionally, allowing for increased storage of natural gas and policies promoting CHP and district energy applications will also expand the role of the natural gas in energy provision.
  • Research, Development, and Demonstration (RD&D). Continued and increased government financial incentives and cooperation with the private sector related to RD&D could accelerate technology advances and market penetration, with possible technology areas of focus including advanced natural gas turbines with higher efficiencies and carbon capture technology on a commercial-scale with natural gas fired electricity generation. Additional important research topics are the potential environmental impacts of unconventional gas production, especially with respect to drinking water, regulatory safeguards, improved fuel efficiency technology, advancements in reducing leakage, and greenhouse gas lifecycle analysis.

Related C2ES Resources

Natural Gas in the Industrial Sector

Oil and Natural Gas Air Pollution Standards

U.S. Natural Gas Overview of Markets and Uses

Natural Gas Use in the Transportation Sector

Natural Gas in the U.S. Electric Power Sector

The Looming Natural Gas Transition in the United States

Natural Gas Infrastructure

Natural Gas in the Residential Sector

Natural Gas in Commercial Buildings

Distributed Generation and Emerging Technologies

State Maps

Further Reading / Additional Resources

Congressional Research Service (CRS)

U.S. Department of Energy

U.S. Energy Information Administration (EIA)

U.S. Environmental Protection Agency (EPA)

U.S. Department of the Interior, Bureau of Land Management

National Energy Technology Laboratory

Global CCS Institute

ICF International

Related Business Environmental Leadership Council (BELC) Company Activities

Air Products

ALCOA

ALSTOM

AREVA

Bayer

BP

Cummins

The Dow Chemical Company

DTE Energy

Duke Energy

Entergy

Exelon

Ontario Power Generation                                            

National Grid

NRG

PG&E Corporation

Royal Dutch/Shell

Endnotes

 


[1] U.S. Energy Information Administration (EIA), Annual Energy Outlook (AEO): Total Energy Supply, Disposition, and Price Summary Table (2012), http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=8-AEO2012&table=1-AEO2012&region=0-0&cases=ref2012-d020112c.

[2] EIA, International Energy Outlook 2009, see Table A2. (2009), http://www.eia.doe.gov/oiaf/ieo.

[3] EIA AEO, Electricity Supple, Disposition, Prices and Emissions Table (2012), http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=6-AEO2012&table=8-AEO2012&region=0-0&cases=ref2012-d020112c.

[4] Out of 5,481 million metric tons. EIA, Annual Energy Review (AER): Total Energy Emissions (2012), http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb1101.

[5] Alvarez, R., Pacala, S, Winebrake, J., Chameides, W., Hamburg, S. Greater focus needed of methane leakage from natural gas infrastructure (2012), http://www.pnas.org/content/early/2012/04/02/1202407109.full.pdf+html

[6] California Air Resources Board (CARB), Low Carbon Fuel Standard Fuel Pathways Analysis, http://www.arb.ca.gov/fuels/lcfs/workgroups/workgroups.htm#pathways; U.S. Department of Energy (DOE) Energy Efficiency and Renewable Energy (EERE), Fuel Economy.gov – Natural Gas, http://www.fueleconomy.gov/feg/bifueltech.shtml

[7] C2ES, Natural Gas in the U.S. Electric Power Sector (Electric Power Sector) (2012), http://www.c2es.org/publications/us-natural-gas-electric-power-sector.

[8] Ibid.

[9] EIA AEO, 2013, http://www.eia.gov/forecasts/aeo/er/index.cfm; EIA AEO, 2012, http://www.eia.gov/forecasts/archive/aeo12/index.cfm

[10] C2ES, Electric Power Sector, 2012; EPA, FACT SHEET: Proposed Carbon Pollution Standard for New Power Plants (2012), http://epa.gov/carbonpollutionstandard/pdfs/20120327factsheet.pdf.

[11] Ibid.

[12] EIA AEO, Total Energy Supply, Disposition, and Price Summary Table (2012), http://www.eia.gov/forecasts/aeo/er/pdf/tbla1.pdf.

[13] EIA AEO, Natural Gas Supply, Disposition, and Prices, Reference Case Table (2012) http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=8-AEO2....

[14] Ibid.

[15] C2ES, U.S. Natural Gas Overview of Markets and Uses (Markets and Uses) (2012), http://www.c2es.org/docUploads/natural-gas-markets-use.pdf

[16] EIA, Short-term Energy Outlook: September 2012 (2012), http://www.eia.gov/forecasts/steo/archives/sep12.pdf.

[17] EIA AEO, 2012.

[18] Ibid.

[19] Or, 7.6 MMCF in 2011. AER, Total Energy, (2012), http://www.eia.gov/totalenergy/data/annual/index.cfm#naturalgas.

[20] Planned in 2012 additions were 20 percent wind, 18 percent coal, 12 percent solar, 5 percent nuclear, and 8 percent other sources, including hydro, geothermal and biomass. C2ES, Electric Power Sector, 2012.

[21] EIA AEO, Levelized Cost of New Generation Resources (2012), http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.

[22] For a more detailed explanation, see DOE’s “How Gas Turbine Power Plants Work.” http://www.fossil.energy.gov/programs/powersystems/turbines/turbines_howitworks.html.

[23] EIA, Average Tested Heat Rates by Prime Mover and Energy Source, 2007 – 2011, http://www.eia.gov/electricity/annual/html/epa_08_02.html.

[24] For a more detailed explanation, see EGL’s Gas-Fired Combined Cycle Power Plants: How Do They Work? http://www.egl.ch/int/ch/en/about/Publications/Unternehmensbroschueren.-ContentLeft-0017-ContentLeftdownloadlist-l1227699492261-File.File.FileRef.pdf/Gas_Fired_Combined_Cycle_Power_PlantEN.pdf.

[25] A new natural gas combined cycle power plant is estimated to emit roughly 42-44 percent as much CO2 per unit of net electricity generation compared to a new pulverized coal power plant. National Energy Technology Laboratory (NETL), Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous Coal and Natural Gas to Electricity Final Report, see Exhibit ES-2 (2007), http://www.netl.doe.gov/energy-analyses/baseline_studies.html.

[26] Comparison based on heat rates assumed in EIA’s Assumptions to the Annual Energy Outlook (2009), Table 8.2, and EPA’s National Electric Energy Data System (NEEDS) 2006 database. http://www.eia.doe.gov/oiaf/aeo/assumption/index.html.

[27] GE Energy, “FlexEfficiency* 50 Combined Cycle Power Plant.” (2012), http://www.ge-energy.com/products_and_services/products/gas_turbines_heavy_duty/flexefficiency_50_combined_cycle_power_plant.jsp.

[28] ICF International, Integrating Renewable Electric Power Generators and the Natural Gas Infrastructure, (2011), http://www.icfi.com/insights/white-papers/2011/integrating-variable-renewable-electric-power-generators-natural-gas-infrastructure.

[29] This contributed to 64 percent increase in natural gas net generation, from 601 thousand GWhs in 2000 to 988 thousand GWhs in 2010. EIA, Electric Power Annual 2010 Data Tables (2011), http://www.eia.gov/electricity/annual/html/epa_04_01.html.

[30] C2ES, Electric Power Sector, 2012.

[31] IEA 2008, p.256.

[32] C2ES, Natural Gas in the Industrial Sector (Industrial Sector) (2012), http://www.c2es.org/docUploads/natural-gas-industrial-sector.pdf.

[33] EIA, “Industrial onsite generation increasingly relies on natural gas.” Today in Energy - October 26 (2012), http://www.eia.gov/todayinenergy/detail.cfm?id=8550.

[34] EIA AEO, Industrial Sector Key Indicators and Consumption (2012), http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=2-AEO2012&table=6-AEO2012&region=0-0&cases=ref2012-d020112c.

[35] EIA AEO, Energy-Related Carbon Dioxide Emissions by Sector and Source, US. (2012), http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2012&subject=1-AEO2012&table=17-AEO2012&region=1-0&cases=ref2012-d020112c.

[36] MIT Energy Initiative, The Future of Natural Gas: An Interdisciplinary MIT Study (2011), http://mitei.mit.edu/system/files/NaturalGas_Chapter5_Demand.pdf.

[37] C2ES, Industrial Sector, 2012.

[38] McKinsey & Company, Reducing U.S. Greenhouse gas Emissions: How Much at What Cost? (2007), http://www.mckinsey.com/clientservice/ccsi/pdf/US_greenhouse gas_final_report.pdf.

[39] IEA, Energy Technology Perspectives 2008: Scenarios and Strategies to 2050 (2008), http://www.iea.org/techno/etp/etp_2008_exec_sum_english.pdf.

[40] For detail on oil and gas operations emissions see Table 1 in Bluestein, 2008.

[41] DOE National Energy Technology Laboratory (NETL), Carbon Sequestration Through Enhanced Oil Recovery (2008), http://www.netl.doe.gov/publications/factsheets/program/Prog053.pdf.

[42] Global CCS Institute 2012, The Global Status of CCS: 2012, http://cdn.globalccsinstitute.com/sites/default/files/publications/47936/global-status-ccs-2012.pdf.

[43] IEA 2008.

[44] International Association for Natural Gas Vehicles (IANGV) Natural Gas Vehicle Statistics (2008), http://www.iangv.org/current-ngv-stats.

[45] DOE-EERE, Table 6.1 Estimates of Alternative Fuel Vehicles in Use,” Transportation Energy Data Book (2012), http://cta.ornl.gov/data/index.shtml.

[46] EIA, Renewable and Alternative Fuels: Alternative Fuel Vehicle Data, Yearly Estimates for 2010. (2012), http://www.eia.gov/renewable/afv/users.cfm?fs=a&ufueltype=cng%2clng&weightclass=ld&uyear=2010.

[47] C2ES, Natural Gas Use in the Transportation Sector (2012), http://www.c2es.org/publications/natural-gas-use-transportation-sector.

[48] DOE, Alternative Fuels Data Center (AFDC) (2012), http://www.afdc.energy.gov/fuels/natural_gas_basics.html.

[49] DOE, AFDC: Hydrogen Fuel Cell Vehicles (2012), http://www.afdc.energy.gov/vehicles/fuel_cell.html.

[50] GREET modeling incorporates full life cycle emissions from well (natural gas recovery) to wheel (vehicle fuel combustion) and includes fugitive and fuel distribution emissions. CARB, Lifecycle Analysis Workgroup (LCA) Fuel Pathways, http://www.arb.ca.gov/fuels/lcfs/workgroups/workgroups.htm#pathways.

[51] Alvarez, et al., 2012.

[52] C2ES, Transportation Sector, 2012.

[53] C2ES, Markets and Uses, 2012.

[54] Environmental Protection Agency, Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011. 2013. Chapter 3 and Annex 2. Available at: http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.

[55] CARB, Detailed GREET Pathway Modeling for North American Compressed Natural Gas (2009), http://www.arb.ca.gov/fuels/lcfs/022709lcfs_cng.pdf; CARB, Detailed GREET Pathway Modeling for North American and Remote Liquid Natural Gas (2009), http://www.arb.ca.gov/fuels/lcfs/092309lcfs_lng.pdf.

[56] Carbon dioxide equivalent is a metric used to compare the amounts and effects of different greenhouse gases. It is determined by multiplying the emissions of a gas (by mass) by the gas’s global warming potential (GWP), an index representing the combined effect of the length of time a given greenhouse gas remains in the atmosphere and its relative effectiveness in absorbing outgoing infrared radiation. CO2 is the standard used to determine the GWPs of other gases. CO2 has been assigned a 100-year GWP of 1 (i.e., the warming effect over a 100-year time frame relative to other gases). Methane (CH4) has a 100-year GWP of 21.

[57] Other sources of methane emissions include enteric fermentation, landfills, coal mines, and manure management. For more information on methane emission sources, see EPA, Methane: Sources and Emissions, http://epa.gov/climatechange/ghgemissions/gases/ch4.html.

[58] See the EPA Natural Gas STAR program’s estimates of payback periods for Recommended Technologies and Practices. http://www.epa.gov/gasstar/tools/recommended.html.

[59] Massachusetts Institute of Technology (MIT), Future of Nuclear Power (2009), http://web.mit.edu/nuclearpower/pdf/nuclearpower-update2009.pdf.

[60] MIT, 2009. EIA estimates Natural Gas-fired levelized system costs to be $66.1 per MWh and nuclear levelized system costs to be $111.4 per MWh, (2012), http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.

[61] EIA AEO, 2012.

[62] EIA, U.S. Natural Gas Wellhead Price, http://www.eia.gov/dnav/ng/hist/n9190us3m.htm.

[63] The assumed discount rate is 10 percent. EIA AEO, Levelized Cost of New Generation Resources (2012), http://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf.

[64] These would be implemented be the Department of Energy (DOE), EPA, and the Department of the Interior (DOI , C2ES, U.S. Natural Gas Overview of Markets and Uses (2012), http://www.c2es.org/docUploads/natural-gas-markets-use.pdf.

[65] EPA, Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources (2012), http://www.epa.gov/hfstudy.

[66] See Title III, Subtitle C, Sec. 322 of the Energy Policy Act of 2005.

[67] Ibid.

[68] The Fracturing Responsibility and Awareness of Chemicals (FRAC) Act, presented before the 111th and 112th Congresses, would have granted EPA the authority to regulate hydraulic fracturing under the Clean Water Act, Murrill, B., Vann, A. “Hydraulic Fracturing: Chemical Disclosure Requirements. Congressional Research Service (2012), http://www.fas.org/sgp/crs/misc/R42461.pdf.

[69] The NSPS regulates emissions of volatile organic compound from oil and gas production and processing facilities, including gas wells (including hydraulically fractured wells), compressors, pneumatic controllers, storage vessels, and leaking components at onshore natural gas processing plants.

[70] Environmental Protection Agency. “Methane Related[70] C2ES, Electric Power Sector, 2012.

Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews,” Proposed Rule”. August 23, 2011. Available at: http://s398369137.onlinehome.us/files/Regulation.gov/PublicSubmission/2011%2F12%2F19%2FEPA%2FFile%2FEPA-HQ-OAR-2010-0505-4460-55.pdf.

[71] C2ES, Electric Power Sector, 2012.

[72] C2ES, Electric Power Sector, 2012.

[73] C2ES, Industrial Sector, 2012.

[74] As an example of misaligned incentives, if a firm allocates energy costs across departments as an overhead cost, no department will realize the full benefit of its investments in energy efficiency thus reducing the incentive of any individual department to pursue energy efficiency.

[75] Census Bureau, 2010 Census Data, U.S. Census Bureau, U.S. Department of Commerce (2010).

Natural gas for electricity generation, heating, industrial operations, and other uses
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Teaser: 

Natural gas for electricity generation, heating, industrial operations, and other uses

Experts Debate Emissions and Driving

Transportation experts gathered in Washington last week for the Transportation Research Board’s 89th annual meeting. With over 10,000 participants and 600 sessions, it is hard to draw any crosscutting conclusions from the conference. With an eye on climate change, however, the TRB meeting indicated the transportation community is engaged and ready for reform. One of the conference’s hot topics addressed the potential to reduce greenhouse gas (GHG) emissions by limiting vehicle miles traveled (VMT). VMT is one of the four major influences on transportation GHG emissions. The others are vehicles, fuels, and the overall efficiency of our transportation system. We need policies to address all four.

At a session entitled “Vehicle Miles Traveled Reduction Targets: Will This Strategy Get the Desired Results?,” the participants debated the effectiveness of VMT targets on reducing GHG emissions. Reducing driving may have been unimaginable in the previous era of urban sprawl and Eisenhower’s interstate highway system, but a confluence of interests in promoting livability and combating climate change has ushered in a new way of thinking about transportation. The idea of limiting VMT is not without its critics, however. Research is ongoing as to how much VMT can really be reduced, on the precise relationship between VMT and GHG emissions, on the costs and benefits of transportation alternatives, and on the distribution of those costs and benefits geographically and by income class.

Perhaps it was the panelists’ connection to the glory days of transportation in the United States or their own economic analyses, but they were mostly skeptical with respect to the efficacy of using VMT targets to reduce GHG emissions. As one speaker put it, “VMT is about technology versus behavior,” meaning lawmakers would use VMT targets to affect behavior due to a lack of confidence in technology.

Another speaker defined VMT targets and the subsequent effects on land-use policy as a “blunt instrument.” They argued VMT reductions would force a reorientation of the population in the United States without necessarily reducing GHG emissions. Furthermore, one panelist claimed VMT targets would be highly regressive.

The lone advocate for VMT targets acknowledged some of these detractions, but strongly pushed for the policy as a “good starting point” towards greater land-use reform. His research showed an economic benefit (i.e., jobs) from spending less on transportation, since people tend to spend that extra money on more labor-intensive products. He also highlighted polls and recent trends indicating that people want to live closer together. Lastly, the co-benefits of reducing VMT including improved safety and reduced congestion make the policy worthwhile even without considering the environmental benefits.

The panelists agreed on some things – for example, that researchers do not fully understand transportation behavior, and that there are substantial co-benefits of reducing VMT. They also agreed that a VMT tax would be preferable to the current Federal gasoline tax as a means of maintaining the surface transportation system, though they disagreed over its effects on GHG emissions. Enacting that policy, however, is politically challenging.

A proposal by Rep. James Oberstar (D-Minn.) to reform fundamentally the current transportation system stalled in 2009, and the legislative prospects in 2010 are unclear. In the absence of comprehensive reauthorizing legislation, action by the Administration – for example, through the Federal budget and U.S. Department of Transportation (DOT) rulemaking – will be critical, as will state and local innovation. We could begin to see this needed leadership from the Administration in the form of the President’s budget, which is set for release on February 1st. DOT does have some discretion to improve federal transportation programs under its existing legislative authorities, and the President’s budget could include such reforms. The President could also propose more significant changes, but that would require Congressional approval.

Nick Nigro is an Innovative Solutions Fellow

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