Report: Leveraging Natural Gas To Reduce Greenhouse Gas Emissions

Leveraging Natural Gas to
Reduce Greenhouse Gas Emissions
Technology
June 2013

Leveraging Natural Gas to
Reduce Greenhouse Gas Emissions
June 2013

Center for Climate and Energy Solutionsii
© 2013, Center for Climate and Energy Solutions. All Rights Reserved.

Leveraging Natural Gas to Reduce Greenhouse Gas Emissions iii
Contents
Acknowledgements vi
Executive Summary vii
I. Overview Of Markets And Uses 1
Introduction 1
Context: A New Dominant Player 1
Climate Implications 2
About This Report 3
Background 3
A History of Volatility: 1990 to 2010 5
Supplies 5
Demand 7
Largely Regional Natural Gas Markets 8
The Rise of an Integrated Global Market 8
II. Price Effects of the Looming Natural Gas Transition 11
Introduction 11
Natural Gas Could Become Dominant in the United States within One to Two Decades 11
There Are Six Price Dichotomies with Natural Gas 13
Decoupling of Natural Gas and Petroleum Prices 13
Decoupling of U.S. and Global Prices 14
Prices for Abundant Supply vs. Prices for Abundant Demand 15
Low Prices for the Environment vs. High Prices for the Environment 16
Stable vs. Volatile Prices 16
Long-Term vs. Near-Term Price 17
Conclusion 17
III. Greenhouse Gas Emissions and Regulations associated
with Natural Gas Production 19
Introduction 19
Global Warming Potentials of Methane and CO2
19

Emissions from Natural Gas Combustion 20
Venting and Leaked Emissions Associated with Natural Gas Production 20
Regulation of Leakage and Venting 21
Federal Regulations 21
State Regulations 23
Conclusion 24

Center for Climate and Energy Solutionsiv
IV. Power Sector 25
Introduction 25
Advantages and Disadvantages of Natural Gas Use in the Power Sector 26
Opportunities for Further Greenhouse Gas Reductions 29
Key Policy Options for the Power Sector 32
Conclusion 32
Appendix A: Natural Gas Policy 33
Appendix B: Power Plant Technologies 34
V. Buildings Sector 37
Introduction 37
Energy Use in Residential and Commercial Buildings 38
Source-to-Site Efficiency, Site Efficiency, and Full-Fuel-Cycle Efficiency 41
Emissions Comparison: Natural Gas Versus Other Direct Fuels 45
The Role of Efficiency Programs and Standards 49
Barriers to Increased Natural Gas Access and Utilization 51
Conclusion 53
VI. Manufacturing Sector 54
Introduction 54
Natural Gas Use in Manufacturing 54
Potential for Expanded Use 56
Potential for Emission Reductions 57
Barriers to Deployment of CHP systems 59
Conclusion 60
VII. Distributed Generation in Commercial and Residential
Buildings and the Role of Natural Gas 61
Introduction 61
The Advantages of Distributed Generation 61
Microgrids 62
Fuel Cells 62
Microturbines 64
Residential Unit CHP 66
Policies to Encourage the Deployment of New Technologies 67
Barriers to Deployment 67
Conclusion 68

Leveraging Natural Gas to Reduce Greenhouse Gas Emissions v
VIII. Transportation Sector 69
Introduction 69
Available Natural Gas Transportation Technologies 69
Greenhouse Emissions of Natural Gas as a Transportation Fuel 72
Natural Gas in Buses and Medium- and Heavy-Duty Vehicle Fleets 72
Natural Gas in Passenger Vehicles 74
Conclusion 76
IX. INFRASTRUCTURE 77
Introduction 77
Elements of the U.S. Natural Gas System 77
Regional Differences in Infrastructure and Expansion 78
Direct Emissions from Natural Gas Infrastructure 80
Barriers to Infrastructure Development 81
Conclusion 83
X. Conclusions and Recommendations 84
Endnotes 87

Center for Climate and Energy Solutionsvi
Acknowledgements
Many individuals, companies, and organizations contributed to the development of this report. The Center for
Climate and Energy Solutions (C2ES) wishes to acknowledge all those who volunteered their time and exper-
tise, including James Bradbury of the World Resources Institute and the many members of the C2ES Business
Environmental Leadership Council that provided comments and guidance throughout the research process.
We would also like to thank the American Clean Skies Foundation and the American Gas Association for their
generous support of the project.

Leveraging Natural Gas to Reduce Greenhouse Gas Emissions vii
Executive Summary
Recent technological advances have unleashed a boom in U.S. natural gas production, with expanded supplies and substan-
tially lower prices projected well into the future. Because combusting natural gas yields fewer greenhouse gas emissions than
coal or petroleum, the expanded use of natural gas offers significant opportunities to help address global climate change.
The substitution of gas for coal in the power sector, for example, has contributed to a recent decline in U.S. greenhouse
gas emissions. Natural gas, however, is not carbon-free. Apart from the emissions released by its combustion, natural gas
is composed primarily of methane (CH4
), a potent greenhouse gas, and the direct release of methane during production,
transmission, and distribution may offset some of the potential climate benefits of its expanded use across the economy.
This report explores the opportunities and challenges in leveraging the natural gas boom to achieve further reduc-
tions in U.S. greenhouse gas emissions. Examining the implications of expanded use in key sectors of the economy, it
recommends policies and actions needed to maximize climate benefits of natural gas use in power generation, build-
ings, manufacturing, and transportation (Table ES-1). More broadly, the report draws the following conclusions:
• The expanded use of natural gas—as a replacement for coal and petroleum—can help our efforts to reduce
greenhouse gas emissions in the near- to mid-term, even as the economy grows. In 2013, energy sector emissions
are at the lowest levels since 1994, in part because of the substitution of natural gas for other fossil fuels, particu-
larly coal. Total U.S. emissions are not expected to reach 2005 levels again until sometime after 2040.
• Substitution of natural gas for other fossil fuels cannot be the sole basis for long-term U.S. efforts to address
climate change because natural gas is a fossil fuel and its combustion emits greenhouse gases. To avoid
dangerous climate change, greater reductions will be necessary than natural gas alone can provide. Ensuring
that low-carbon investment dramatically expands must be a priority. Zero-emission sources of energy, such as
wind, nuclear and solar, are critical, as are the use of carbon capture-and-storage technologies at fossil fuel
plants and continued improvements in energy efficiency.
• Along with substituting natural gas for other fossil fuels, direct releases of methane into the atmosphere must be
minimized. It is important to better understand and more accurately measure the greenhouse gas emissions from
natural gas production and use in order to achieve emissions reductions along the entire natural gas value chain.
Table ES-1: Sector-Specific Conclusions and Recommendations—continued
Power Sector
It is essential to maintain fuel mix diversity in the power sector. Too much reliance on any one fuel can expose a utility,
ratepayers, and the economy to the risks associated with commodity price volatility. The increased natural gas and
renewable generation of recent years has increased the fuel diversity of the power sector (by reducing the dominance of
coal). In the long term, however, concern exists that market pressures could result in the retirement of a significant portion
of the existing nuclear fleet, all of which could be replace by natural gas generation. Market pressures also could deter
renewable energy deployment, carbon capture and storage, and efficiency measures. Without a carbon price, the negative
externalities associated with fossil fuels are not priced by society, and therefore there will be less than optimal investment
and expansion of zero-carbon energy sources.
Instead of being thought of as competitors, however, natural gas and renewable energy sources such as wind and
solar can be complementary components of the power sector. Natural gas plants can quickly scale up or down their
electricity production and so can act as an effective hedge against the intermittency of renewables. The fixed fuel
price (at zero) of renewables can likewise act a hedge against potential natural gas price volatility.

Center for Climate and Energy Solutionsviii
Table ES-1: Sector-Specific Conclusions and Recommendations—continued
Buildings Sector
It is important to encourage the efficient direct use of natural gas in buildings, where natural gas applications have a lower
greenhouse gas emission footprint compared with other energy sources. For thermal applications, such as space and water
heating, onsite natural gas use has the potential to provide lower-emission energy compared with oil or propane and
electricity in most parts of the country. Natural gas for thermal applications is more efficient than grid-delivered electricity,
yielding less energy losses along the supply chain and therefore less greenhouse gas emissions. Consumers need to be
made aware of the environmental and efficiency benefits of natural gas use through labeling and standards programs and be
incentivized to use it when emissions reductions are possible.
Manufacturing Sector
The efficient use of natural gas in the manufacturing sector needs to be continually encouraged. Combined heat and power
systems, in particular, are highly efficient, as they use heat energy otherwise wasted. Policy is needed to overcome existing
barriers to their deployment, and states are in an excellent position to take an active role in promoting combined heat and
power during required industrial boiler upgrades and new standards for cleaner electricity generation in coming years. For
efficiency overall, standards, incentives, and education efforts are needed, especially as economic incentives are weak in
light of low natural gas prices.
Distributed Generation
Natural gas-related technologies, such as microgrids, microturbines, and fuel cells, have the potential to increase the amount
of distributed generation used in buildings and manufacturing. These technologies can be used in configurations that reduce
greenhouse gas emissions when compared with the centralized power system as they can reduce transmission losses and
use waste heat onsite. To realize the potential of these technologies and overcome high upfront equipment and installation
costs, policies like financial incentives and tax credits will need to be more widespread, along with consumer education
about their availability.
Transportation Sector
The greatest opportunity to reduce greenhouse gas emissions using natural gas in the transportation sector is through fuel
substitution in fleets and heavy-duty vehicles. Passenger vehicles, in contrast, likely represent a much smaller emission
reduction opportunity even though natural gas when combusted emits fewer greenhouse gases than gasoline or diesel.
The reasons for this include the smaller emission reduction benefit (compared to coal conversions), and the time it will
take for a public infrastructure transition. By the time a passenger fleet conversion to natural gas would be completed, a
new conversion to an even lower-carbon system, like fuel cells or electric vehicles, will be required to ensure significant
emissions reductions throughout the economy.
Infrastructure
Transmission and distribution pipelines must be expanded to ensure adequate supply for new regions and to serve
more thermal loads in manufacturing, homes, and businesses. Increased policy support and innovative funding
models, particularly for distribution pipelines, are needed to support the rapid deployment of this infrastructure.

Leveraging Natural Gas to Reduce Greenhouse Gas Emissions 1
I. Overview Of Markets And Uses
By Meg Crawford and Janet Peace, C2ES
Introduction
Recent technological advances have unleashed a boom in
natural gas production, a supply surplus, and a dramati-
cally lower price. The ample supply and lower price are
expected to continue for quite some time, resulting in a
relatively stable natural gas market. As a consequence,
interest in expanding the use of natural gas has increased
in a variety of sectors throughout the economy, including
power, buildings, manufacturing, and transporta-
tion. Given that combusting natural gas yields lower
greenhouse gas emissions than that of burning coal or
petroleum, this expanded use offers significant poten-
tial to help the United States meet its climate change
objectives. Expanded use of gas in the power sector, for
example, has already led to a decrease in U.S. greenhouse
gas emissions because of the substitution of gas for coal.
It is important to recognize, however, that natural gas,
like other fossil fuel production and combustion, does
release greenhouse gases. These include carbon dioxide
and methane; the latter is a higher global warming
greenhouse gas. Accordingly, a future with expanded
natural gas use will require diligence to ensure that
potential benefits to the climate are achieved. This report
explores the opportunities and challenges, sector by
sector throughout the U.S. economy, and delves into the
assortment of market, policy, and social responses that
can either motivate or discourage the transition toward
lower-carbon and zero-carbon energy sources essential
for addressing climate change.
Context: A New Dominant Player
Throughout its history, the United States has undergone
several energy transitions in which one dominant
energy source has been supplanted by another. Today,
as the country seeks lower-carbon, more affordable,
domestically sourced fuel options to meet a variety of
market, policy, and environmental objectives, the United
States appears poised for another energy transition.
Past energy transitions, for example, from wood to coal,
took place largely without well-defined policies and
were not informed by other big-picture considerations.
Transitions of the past were largely shaped by regional
and local economic realities and only immediate, local
environmental considerations. The potential next energy
transition can be more deliberately managed to achieve
economic and environmental goals. The United States
possesses the technological capacity and policy struc-
tures to do this. This report outlines, sector by sector,
those technological options and policy needs.
The history of energy consumption in the United States
from 1800 to 2010 moved steadily from wood to coal to
petroleum (Figure 1). In the latter half of the 19th century,
coal surpassed wood as the dominant fuel. Around 1950,
petroleum consumption exceeded that of coal.
Petroleum still reigns supreme in the United States;
however, due to a number of factors including improving
fuel economy standards for vehicles, its use since 2006
is in decline. At the same time, for reasons that this
report explores in depth, natural gas use is on the rise.
As these trends continue, it is entirely possible in the
coming decades that natural gas will overtake petroleum
as the most popular primary energy source in the
United States.1
Natural gas already plays a large role in the U.S.
economy, constituting 27 percent of total U.S. energy
consumption in 2012. Unlike other fossil fuels, natural
gas has applications in almost every sector, including
generating electricity; providing heat and power to
industry, commercial buildings, and homes; powering
vehicles; and as a feedstock in the manufacture of
industrial products.
By all accounts, the existing increase in natural gas
supply appears very certain, and the large domestic
supply is expected to keep natural gas prices relatively
low in the near to medium term. Furthermore, the
domestic supply already has and is forecasted to deliver

Center for Climate and Energy Solutions2
percent from peak levels of 6,020 million metric tons in
2007. This decrease is due to a number of factors, of which
the increased use of natural gas in the power sector is
prominent. Demand is increasing as new and significantly
more efficient natural gas power plants have been recently
constructed, existing natural gas power plants are being
used more extensively, and fuel-substitution from coal to
natural gas is taking place. Compared to coal, natural gas
is considered relatively clean because when it is burned in
power plants, it releases about half as much CO2
(and far
fewer pollutants) per unit of energy delivered than coal.
As the fraction of electric power generated by coal has
fallen over the last six years and been replaced mostly by
natural gas-fueled generation and renewables, total U.S.
CO2
emissions have decreased.
According to several sources, including the U.S.
Energy Information Administration (EIA), additions
in electric power capacity over the next 20 years are
expected to be predominantly either natural gas-
fueled or renewable (discussed further in chapter 4 of
substantial benefits to the U.S. economy, providing jobs
and increasing the gross domestic product. The primary
uncertainties for the natural gas market are how quickly
the expanded use will occur and the specific ways in
which specific sectors of the economy will be affected.
This report delves into the assortment of market, policy,
and social responses that can motivate or discourage
this transition. It places this energy transition firmly
in the context of the closely related climate impacts of
different types of energy use, and explores the interplay
between economic opportunities and the pressing need
to dramatically reduce the economy’s emissions of
greenhouse gases.
Climate Implications
The expanding use of natural gas is already reducing
emissions of carbon dioxide (CO2
), the primary green-
house gas, at a time in which the U.S. economy is growing.
In 2011, total U.S. CO2
emissions were down by nearly 9
EnergyConsumption[Quads]
20001980196019401920190018801860184018201800
0
10
20
30
40
Year
Wood
Coal
US Energy Consumption: 1800–2010
Wood
Coal
Petroleum
Natural Gas
Nuclear
Hydroelectric
Non-Hydro/Bio Renewables
Natural Gas
Petroleum
Nuclear
Hydroelectric
FIGURE 1: Total U.S. Energy Consumption, 1800 to 2010
Source: Energy Information Administration, “Annual Energy Review,” Table 1.3. September 2012. Available at: http://www.eia.gov/totalenergy/data/annual/index.
cfm#summary
Note: Wood, which was the dominant fuel in the United States for the first half of the 19th century, was surpassed by coal starting in 1885. Coal as the dominant
fuel was surpassed by petroleum in 1950. Within one to two decades, natural gas might surpass petroleum as the dominant energy provider.

this report). Therefore, as coal’s share of generation
continues to diminish, the implications for climate in the
near and medium term are reduced CO2
emissions from
the power sector. Further reductions in CO2
emissions
are possible if natural gas replaces coal or petroleum
in other economic sectors. In addition, wider use of
distributed generation technologies in the manufac-
turing, commercial, and residential sectors, namely
natural gas-fueled combined heat and power (CHP)
systems, has great potential to significantly reduce U.S.
CO2
emissions.
In the long term, however, the United States cannot
achieve the level of greenhouse gas emissions necessary
to avoid the serious impacts of climate change by relying
on natural gas alone. Also required is the development of
significant quantities of zero-emission sources of energy,
which economic modeling shows will require policy
intervention. Since many of these energy sources, such
as wind and solar, are intermittent and current energy
storage technology is in its infancy, natural gas will likely
also be needed in the long term as a reliable, dispatch-
able backup for these renewable sources.
Crucially, natural gas is primarily methane, which is
itself a very potent greenhouse gas. Methane is about 21
times more powerful in its heat-trapping ability than CO2
over a 100-year time scale. With increased use of natural
gas, the direct releases of methane into the atmosphere
throughout production and distribution have the
potential to be a significant climate issue. Regulations
have already been promulgated by the Environmental
Protection Agency (EPA) that address this key issue. For
example, “green completion” rules for production will
require all unconventional wells to virtually eliminate
venting during the flow-back stage of well completion
through flaring or capturing natural gas. Releases need
to be carefully managed, and EPA regulation of the
natural gas sector will ensure that the climate benefits
from transitioning to natural gas are truly maximized.
About This Report
To examine the possible ways in which this energy transi-
tion might unfold and the potential implications for the
climate, the Center for Climate and Energy Solutions
and researchers at The University of Texas prepared 9
discussion papers looking at individual economic sectors,
natural gas technologies, markets, infrastructure, and
environmental considerations. Then, two workshops
brought together dozens of respected thought leaders
and stakeholders to analyze the potential to leverage
natural gas use to reduce greenhouse gas emissions.
Stakeholders included representatives of electric and
natural gas utilities, vehicle manufacturers, fleet opera-
tors, industrial consumers, homebuilders, commercial
real estate operators, pipeline companies, independent
and integrated natural gas producers, technology
providers, financial analysts, public utility and other state
regulators, environmental nonprofits, and academic
researchers and institutions.
This report is the culmination of these efforts. First,
it provides background on natural gas and the events
leading to the present supply boom. Next, it lays out the
current and projected U.S. natural gas market, including
the forecast price effects during the transition. It details
the relationship between natural gas and climate change
and then explores the opportunities and challenges
in the power, buildings, and manufacturing sectors. It
looks at technologies for on-site (distributed) electricity
generation using natural gas, followed by prospects for
increasing natural gas consumption in the transportation
sector. Finally, the report examines the state of natural gas
infrastructure and the barriers to its needed expansion.
This report offers insight into ways to lower the
climate impact of natural gas while increasing its use
in the electric power, buildings, manufacturing, and
transportation sectors, and looks at infrastructure
expansion needs and what future technologies may
portend for low-emission natural gas use. This report is
the product solely of the Center for Climate and Energy
Solutions (C2ES) and may not necessarily represent
the views of workshop participants, the C2ES Business
Environmental Leadership Council or Strategic Partners,
or project sponsors.
Background
Natural gas is a naturally occurring fossil fuel consisting
primarily of methane that is extracted with small
amounts of impurities, including CO2
, hazardous air
pollutants, and volatile organic compounds. Most natural
gas production also contains, to some degree, heavier
liquids that can be processed into valuable byproducts,
including propane, butane, and pentane.
Natural gas is found in several different types of
geologic formations (Figure 2). It can be produced alone
from reservoirs in natural rock formations or be associ-
ated with the production of other hydrocarbons such as
oil. While this “associated” gas is an important source of

increase permeability, and release the natural gas. This
technique is known as hydraulic fracturing or “fracking.”
The remarkable speed and scale of shale gas develop-
ment has led to substantial new supplies of natural
gas making their way to market in the United States.
The U.S. EIA projects that by 2040 more than half of
domestic natural gas production will come from shale
gas extraction and that production will increase by 10
trillion cubic feet (Tcf) above 2011 levels (Figure 3).
The current increase was largely unforeseen a decade
ago. This increase has raised awareness of natural
gas as a key component of the domestic energy supply
and has dramatically lowered current prices as well
as price expectations for the future. In recent years,
the abundance of natural gas in the United States has
strengthened its competitiveness relative to coal and oil,
domestic supply, the majority (89 percent) of U.S. gas is
extracted as the primary product, i.e., non-associated.2
With relatively recent advances in seismic imaging,
horizontal drilling, and hydraulic fracturing, U.S.
natural gas is increasingly produced from unconven-
tional sources such as coal beds, tight sandstone, and
shale formations, where natural gas resources are not
concentrated or are in impermeable rock and require
advanced technologies for development and produc-
tion and typically yield much lower recovery rates than
conventional reservoirs.3
Shale gas extraction, for
example, differs significantly from the conventional
extraction methods. Wells are drilled vertically and then
turned horizontally to run within shale formations. A
slurry of sand, water, and chemicals is then injected into
the well to increase pressure, break apart the shale to
FIGURE 2: Geological Formations Bearing Natural Gas
Source: Energy Information Agency, “Schematic Geology of Natural Gas Resources,” January 2010. Available at: http://www.eia.gov/oil_gas/natural_gas/special/
ngresources/ngresources.html
Notes: Gas-rich shale is the source rock for many natural gas resources, but, until now, has not been a focus for production. Horizontal drilling and hydraulic
fracturing have made shale gas an economically viable alternative to conventional gas resources.
Conventional gas accumulations occur when gas migrates from gas rich shale into an overlying sandstone formation, and then becomes trapped by an overlying
impermeable formation, called the seal. Associated gas accumulates in conjunction with oil, while non-associated gas does not accumulate with oil.
Tight sand gas accumulations occur in a variety of geologic settings where gas migrates from a source rock into a sandstone formation, but is limited in its ability to
migrate upward due to reduced permeability in the sandstone.
Coalbed methane does not migrate from shale, but is generated during the transformation of organic material to coal.

has expanded its use in a variety of contexts, and has
raised its potential for reducing greenhouse gas emis-
sions and strengthening U.S. energy security by reducing
U.S. reliance on foreign energy supplies.
A History of Volatility: 1990 to 2010
U.S. natural gas markets have only been truly open and
competitive for about 20 years, when U.S. gas markets
were deregulated and price controls were removed in
the early 1990s. Before that time, government regula-
tion controlled the price that producers could charge
for certain categories of gas placed into the interstate
market (the wellhead price) as well as pipeline access to
market and in some cases specific uses of natural gas.
The results were price signals that periodically resulted
in supply shortages and little incentive for increased
production. Since deregulation, price fluctuations have
been pronounced, ranging from less than $2 to more
than $10 per thousand cubic feet (Mcf) (Figure 4).
Periods of high market prices have resulted from changes
in regulation, weather disruptions, and broader trends in
the economy and energy markets—but also from percep-
tions of abundance or scarcity in the market. A number
of supply-side factors also affect prices, including the
volume of production added to the market and storage
availability to hedge against production disruptions or
demand spikes. Looking forward, the average wellhead
price is expected to be much less volatile and remain
below $5 per Mcf through 2026 and rise to $6.32 per Mcf
in 2035, as production gradually shifts to resources that
are less productive and more expensive to extract.4
Supplies
Since 1999, U.S. proven reserves of natural gas have
increased every year, driven mostly by shale gas advance-
ments.5
In 2003, the National Petroleum Council
estimated U.S. recoverable shale gas resources at 35 Tcf.6
In 2012, the EIA put that estimate closer to 482 Tcf out
of an average remaining U.S. resource base of 2,543 Tcf,7
and in 2011, the Massachusetts Institute of Technology’s
mean projection estimate of recoverable shale gas
resources was 650 Tcf out of a resource base of 2,100 Tcf.8
By comparison, annual U.S. consumption of natural
gas was 24.4 Tcf in 2011.9
So, these estimates represent
nearly 100 years of domestic supply at current levels
of consumption.10
Figure 3: U.S. Dry Natural Gas Production, 1990 to 2040
Source: Energy Information Administration, “Annual Energy Outlook 2013 Early Release” December 2012. Available at http://www.eia.gov/forecasts/aeo/er/
executive_summary.cfm
0
5
10
15
20
25
30
35
Shale gas
Tight gas
Alaska
Non-associated offshore
Coalbed methane
Associated with oil
Non-associated onshore
2038
2034
2030
2026
2022
2018
2014
2010
2006
2002
1998
1994
1990
TrillionCubicFeetperYear

Game-Changing Technologies
Rising natural gas prices after deregulation offered
new economic incentives to develop unconventional
gas resources. Advances in the efficiency and cost-
effectiveness of horizontal drilling, new mapping tools,
and hydraulic fracturing technologies—enabled by
investments in research and development from the
Department of Energy and its national labs along with
private sector innovations—have led to the dramatic
increase in U.S. shale gas resources that can be economi-
cally recovered.
Even as supply estimates have increased, the cost
of producing shale gas has declined as more wells are
drilled and new techniques are tried. In one estimate,
approximately 400 Tcf of U.S. shale gas can be economi-
cally produced at or below $6 per Mcf (in 2007 dollars).11
Another estimate suggests that nearly 1,500 Tcf can be
produced at less than $8 per Mcf, 500 Tcf at less than $8
per Mcf, and 500 Tcf at $4 per Mcf.12
The Geography of Shale Gas Production
Shale gas developments are fundamentally altering the
profile of U.S. natural gas production (Figure 3). Since
2009, the United States has been the world’s leading
producer of natural gas, with production growing by
more than 7 percent in 2011—the largest year-over-year
volumetric increase in the history of U.S. production.13
The proportion of U.S. production that is shale gas
has steadily increased as well. In the decade of 2000
to 2010, U.S. shale gas production increased 14-fold
and comprised approximately 34 percent of total U.S.
production in 2011.14
From 2007 to 2008 alone, U.S.
shale gas production increased by 71 percent.15
Shale gas
production is expected to continue to grow, estimated
to increase almost fourfold between 2009 and 2035,
when it is forecast to make up 47 percent of total U.S.
production.16
The geographic distribution of shale gas
production is also shifting to new geologic formations
with natural gas potential, called “plays,” such as the
Barnett shale play in Texas and the Marcellus shale play
Figure 4: U.S. Natural Gas Monthly Average Wellhead Price History, 1976 to 2012
Source: Energy Information Administration, “Natural Gas Prices,” 2013. Available at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
Sep-2012
Jan-2011
May-2009
Sep-2007
Jan-2006
May-2004
Sep-2002
Jan-2001
May-1999
Sep-1997
Jan-1996
May-1994
Sep-1992
Jan-1991
May-1989
Sep-1987
Jan-1986
May-1984
Sep-1982
Jan-1981
May-1979
Sep-1977
Jan-1976
0
2
4
6
8
10
12
DollarperMcf

in the Midwest (Figure 5).17
Natural gas is currently
produced in 32 states and in the Gulf of Mexico, with
80.8 percent of U.S. production occurring in Texas,
the Gulf of Mexico, Wyoming, Louisiana, Oklahoma,
Colorado, and New Mexico in 2010. An increasing
percentage of production is coming from states new on
the scene, including Pennsylvania and Arkansas. This
new geography of production has particularly large
impacts for the development of natural gas infrastruc-
ture, as examined in chapter 9.
These dramatic increases in production, in combination
with a weak economy and the accompanying decrease in
demand for energy, are reflected in unexpectedly low and
less volatile market prices, prices that encourage energy
consumers to look at new uses for the fuel. Yet uncertain-
ties remain that could hinder future development and
production. For one thing, very low prices may result in
producers temporarily closing down wells, particularly if
the associated liquids produced along with the gas are not
sufficient to make up for low natural gas prices and make
well production economically viable.18
In the long term,
the dynamic nature of natural gas supply and demand
will determine the price levels and volatility. Of particular
importance is the extent and speed of demand expansion,
a topic explored in the following section.
Demand
Just as supply has implications for the price path
of natural gas, so does the demand. Natural gas is
consumed extensively in the United States for a multi-
tude of uses: for space and water heating in residential
and commercial buildings, for electricity generation
and process heat in the industrial sector, and as indus-
trial feedstock, where natural gas constitutes the base
ingredient for such varied products as plastic, fertilizer,
antifreeze, and fabrics.19
In 2012, natural gas use consti-
tuted roughly one-quarter of total U.S. primary energy
consumption and was consumed in every sector of the
Figure 5: Lower 48 Shale Plays
Source: Energy Information Administration, “Lower 48 States Shale Plays,” May 2011. Available at: http://www.eia.gov/oil_gas/rpd/shale_gas.pdf
Chattanooga
Eagle
Ford
Western
Gulf
TX-LA-MS
Salt Basin
Uinta Basin
Devonian (Ohio)
Marcellus
Utica
Bakken***
Avalon-
Bone Spring
San Joaquin
Basin
Monterey
Santa Maria,
Ventura, Los
Angeles
Basins
Monterey-
Temblor
Pearsall
Tuscaloosa
Big Horn
Basin
Denver
Basin
Powder River
Basin
Park
Basin
Niobrara*
Mowry
Niobrara*
Heath**
Manning
Canyon
Appalachian
Basin
Antrim
Barnett
Bend
New
Albany
Woodford
Barnett-
Woodford
Lewis
Hilliard-
Baxter-
Mancos
Excello-
Mulky
Fayetteville
Floyd-
Neal
Gammon
Cody
Haynesville-
Bossier
Hermosa
Mancos
Pierre
Conasauga
Michigan
Basin
Ft. Worth
Basin
Palo Duro
Basin
Permian
Basin
Illinois
Basin
Anadarko
Basin
Greater
Green
River
Basin
Cherokee Platform
San Juan
Basin
Williston
Basin
Black Warrior
Basin
Ardmore Basin
Paradox Basin
Raton
Basin
Montana
Thrust
Belt
Marfa
Basin
Valley & Ridge
Province
Arkoma Basin
Forest
City Basin
Piceance
Basin
Lower 48 states shale plays
0 200 400100 300
Miles
BasinsShale plays
Stacked plays
Basins
Current plays
Prospective plays
* Mixed shale &
chalk play
** Mixed shale &
limestone play
***Mixed shale &
tight dolostone-
siltstone-sandstone
Intermediate depth/ age
Shallowest/ youngest
Deepest/ oldest

U.S. economy (Figure 6). Total U.S. consumption of
natural gas grew from 23.3 Tcf in 2000 to 25.4 in 2012.20
Within the overall growth, consumption in several
sectors held steady, while consumption in the industrial
sector declined (due to increased efficiency and the
economic slowdown) and consumption in the power
sector grew at an annual average rate of 3.5 percent.
In the U.S. power sector in 2010, natural gas fueled
23.9 percent of the total generation. From 2000 to 2010,
electricity generation fueled by natural gas grew at a
faster rate than total generation (5.1 percent versus 0.8
percent per year) (Figure 7). This growth can be attrib-
uted to a number of factors, including low natural gas
prices in the early part of the decade that made natural
gas much more attractive for power generation. In addi-
tion, gas-fired plants are relatively easy to construct, have
lower emissions of a variety of regulated pollutants than
coal-fired plants, and have lower capital costs and shorter
construction times than coal-fired plants. Transportation
has remained the smallest sectoral user of natural gas,
with natural gas vehicles contributing to a significant
percentage of the total fleet only among municipal buses
and some other heavy-duty vehicles.
Largely Regional Natural Gas Markets
In contrast to oil, which is widely traded across national
boundaries and over long distances, natural gas has
been primarily a domestic resource. The low density of
natural gas makes it difficult to store and to transport
by vehicle (unless the gas is compressed or liquefied).
(See chapter 8 for an extended discussion of liquefied
and compressed natural gas.) Natural gas is therefore
transported via pipelines that connect the natural gas
wells to end consumers. Trade patterns tend to be more
regional (particularly in the United States), and prices
tend to be determined within regional markets. On the
world stage, resources are concentrated geographically.
Seventy percent of the world’s gas supply (including
unconventional resources) is located in only three
regions—Russia, the Middle East (primarily Qatar and
Iran), and North America. Within the United States, 10
states or regions account for nearly 90 percent of produc-
tion: Arkansas, Colorado, Gulf of Mexico, Louisiana,
New Mexico, Oklahoma, Pennsylvania, Texas, Utah,
and Wyoming. Significant barriers exist to establishing
a natural gas market that is truly global. While most
natural gas supplies can be developed economically
with relatively low prices at the wellhead or the point of
export,21
high transportation costs—either via long-
distance pipeline or via tankers for liquefied natural gas
(LNG)—have, until recently, constituted solid barriers to
establishing a global gas market.
In 2011, net imports of natural gas, delivered via
pipeline and LNG import facilities, constituted only 8
percent of total U.S. natural gas consumption (1.9 Tcf),
the lowest proportion since 1993.22
Of this amount,
about 90 percent came from Canada.23
(By contrast, 45
percent of U.S. oil consumption was imported in 2011,
of which 29 percent came from Canada.24
) Net imports
of natural gas have decreased by 31 percent since 2007,
with U.S. production growing significantly faster than
U.S. demand. These trends and greater confidence in
U.S. domestic gas supply suggest that prices between
crude oil and gas will continue to diverge, establishing a
new relationship that may fundamentally change the way
energy sources are used in the United States.
The Rise of an Integrated Global Market
Although most of the world’s gas supply continues to
be transported regionally via pipeline, the global gas
trade is accelerating because of the growing use of
LNG. Natural gas, once liquefied,25
can be transported
Figure 6: U.S. Natural Gas Consumption by
Sector, 2012
Source: Energy Information Administration, “Natural Gas Consumption by
End Use,” 2013. Available at http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_
nus_a.htm
Pipeline Fuel
3%Oil & Gas
Industry
Operations
6%
Electric
Power
36%
Vehicle Fuel
0%
Industrial
28%
Commercial
11%
Residential
16%
FIGURE 6: U.S. Natural Gas Consumption
by Sector, 2012

by tanker to distant destinations and regasified for use.
Between 2005 and 2010, the global market for LNG grew
by more than 50 percent,26
and LNG now accounts for
30.5 percent of global gas trade.27
From 2009 to 2011
alone, global capacity for gas liquefaction increased by
almost 40 percent, with global LNG trade set to rise by
30 percent by 2017.28
In the United States, prospects for exports of LNG
depend heavily on the cost-competitiveness of U.S.
liquefaction projects relative to those at other locations.
During 2000 to 2010, new investments were made in the
United States in infrastructure for natural gas importa-
tion and storage, prompted by lower supply expectations
and higher, volatile domestic prices. Since 2000, North
America’s import capacity for LNG has expanded from
approximately 2.3 billion cubic feet (Bcf) per day to
22.7 Bcf per day, around 35 percent of the United States’
average daily requirement.29
However by 2012, U.S.
consumption of imported LNG had fallen to less than
0.5 Bcf per day, leaving most of this capacity unused.30
The ability to make use of and repurpose existing U.S.
import infrastructure—pipelines, processing plants, and
storage and loading facilities—would help reduce total
costs relative to “greenfield,” or new, LNG facilities. Given
natural gas surpluses in the United States and substan-
tially higher prices in other regional markets, several U.S.
companies have applied for export authority and have
indicated plans to construct liquefaction facilities.31
The EIA projects that the United States will become a
net exporter of LNG in 2016, a net pipeline exporter in
2025, and a net exporter of natural gas overall in 2021.
This outlook assumes continuing increases in use of
LNG internationally, strong domestic natural gas produc-
tion, and relatively low domestic natural gas prices.32
In
contrast, a study done by the Massachusetts Institute of
Technology presents another possible scenario in which
a more competitive international gas market could
drive the cost of U.S. natural gas in 2020 above that of
international markets, which could lead to the United
States importing 50 percent of its natural gas by 2050.33
Yet while increased trade in LNG has started to connect
international markets, these markets remain largely
distinct with respect to supply, contract structures, market
regulation, and prices.
The increase in domestic production (supplies) of
natural gas, low prices, and forecasts of continued low
prices have not gone unnoticed. The implications for
energy consumption are far-reaching and extend across
all sectors of the economy. This report examines how
each sector may take advantage of this energy trans-
formation and evaluates the greenhouse gas emission
implications of each case.
Figure 7: Trends in U.S. Natural Gas Consumption by Sector, 2000 to 2010
Source: Energy Information Administration, “Natural Gas Consumption by End Use,” 2013. Available at http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm
0
2
4
6
8
10
Electric Power
Transportation
Industrial
Commercial
Residential
20102009200820072006200520042003200220012000
TrillionCubicFeet
Figure 6: U.S. Natural Gas Consumption by Sector, 2000–2010 (Tcf)

II. Price Effects of the Looming Natural Gas Transition
By Michael Webber, The University of Texas at Austin
Introduction
Given technology developments that have fundamentally
altered the profile of U.S. natural gas production and
recent low prices that have pushed demand for natural
gas in all sectors of the economy, the importance of
natural gas relative to other fuels is growing. If recent
trends continue, it seems likely that natural gas will over-
take petroleum as the most-used primary energy source
in the United States. in the next one to two decades.
Such a transition will be enabled (or inhibited) by a
mixed set of competing price pressures and a compli-
cated relationship with lower-carbon energy sources that
will trigger an array of market and cultural responses.
This chapter seeks to layout some of the key underlying
trends while also identifying some of these different axes
of price tensions (or price dichotomies). These trends
and price tensions will impact the future use of natural
gas in all of the sectors analyzed later in this report.
Natural Gas Could Become Dominant in the
United States within One to Two Decades
For a century, oil and natural gas consumption trends
have tracked each other quite closely. Figure 1 shows
normalized U.S. oil and gas consumption from 1920 to
2010 (consumption in 1960 is set to a value of 1.0). These
normalized consumption curves illustrate how closely
oil and gas have tracked each other up until 2002, at
which time their paths diverged: natural gas consump-
tion declined from 2002 to 2006, while petroleum use
grew over that time period. Then, they went the other
direction: natural gas consumption grew and oil produc-
tion dropped. That trend continues today, as natural
gas pursues an upward path, whereas petroleum is
continuing a downward trend.
The growing consumption of natural gas is driven by
a few key factors:
1. It has flexible use across many sectors, including
direct use on-site for heating and power; use at
power plants; use in industry; and growing use
in transportation.
2. It has lower emissions (of pollutants and green-
house gases) per unit of energy than coal and
petroleum
3. It is less water-intensive than coal, petroleum,
nuclear, and biofuels
4. Domestic production meets almost all of the
annual U.S. consumption
By contrast, the trends for petroleum and coal are
moving downwards. Petroleum use is expected to drop as a
consequence of price pressures and policy mandates. The
price pressures are triggered primarily by the split in energy
prices between natural gas and petroleum (discussed in
detail below). The mandates include biofuels production
targets (which increase the production of an alternative to
petroleum) and fuel economy standards (which decrease
the demand for liquid transportation fuels). At the same
time, coal use is also likely to drop because of projections
by the EIA for price doubling over the next 20 years and
environmental standards that are expected to tighten the
tolerance for emissions of heavy metals, sulfur oxides,
nitrogen oxides, particulate matter, and CO2
.
Petroleum use might decline 0.9 percent annually
from the biofuels mandates themselves. Taking that
value as the baseline, and matching it with an annual
growth of 0.9 percent in natural gas consumption (which
is a conservative estimation based on trends from the
last six years, plus recent projections for increased use
of natural gas by the power and industrial sectors),
indicates that natural gas will surpass petroleum in 2032,
two decades from now, as depicted in Figure 2. A steeper
projection of 1.8 percent annual declines in petroleum
matched with 1.8 percent annual increase in natural gas
consumption sees a faster transition, with natural gas
surpassing petroleum in less than a decade.
While such diverging rates might seem aggressive,
they are a better approximation of the trends over the

last six years than the respective 0.9 percent values. An
annual decline in petroleum of 1.8 percent is plausible
through a combination of biofuels mandates (0.9 percent
annual decline), higher fuel economy standards (0.15
percent annual decline), and price competition that
causes fuel-switching from petroleum to natural gas in
the transportation (heavy-duty, primarily) and industrial
sectors (0.75 percent annual decline). Natural gas growth
rates of 1.8 percent annually can be achieved by natural
gas displacing 25 percent of diesel use (for on-site
power generation and transportation) and natural gas
combined-cycle power plants displacing 25 percent of
1970s and 1980s vintage coal-fired power plants by 2022.
While this scenario is bullish for natural gas, it is not
implausible, especially for the power sector, whose power
plants face retirement and stricter air quality standards.
Coupling those projections with reductions in per-capita
energy use of 10 percent (less than 1 percent annually)
over that same span imply that total energy use would
stay the same.
These positive trends for natural gas are not to say
it is problem-free. Environmental challenges exist for
water, land, and air. Water challenges are related to
quality (from risks of contamination) and quantity (from
competition with local uses and depletion of reservoirs).
Land risks include surface disturbance from production
activity and induced seismicity from wastewater reinjec-
tion. Air risks are primarily derived from leaks on site,
leaks through the distribution system, and flaring at the
point of production. Furthermore, while natural gas
prices have been relatively affordable and stable in the
last few years, natural gas prices have traditionally been
very volatile. However, if those economic and environ-
mental risks are managed properly, then these positive
trends are entirely possible.
FIGURE 1: U.S. Oil and Gas Consumption, 1920 to 2010
Source: Energy Information Agency, “Annual Energy Review 2010” Technical Report, 2011.
Note: U.S. oil and gas consumption from 1920 to present day (normalized to a value of 1 in 1960) shows how oil and gas have tracked each other relatively
closely until 2002, after which their paths diverge. Since 2006, natural gas consumption has increased while petroleum consumption has decreased.
U.S.OilandGasConsumption
(Normalizedto1960=1)
20001980196019401920
0.0
0.5
1.0
1.5
2.0
Year
U.S. Oil and Gas Consumption 1920–2010 (Normalized to 1960 = 1)
Natural Gas Consumption Normalized to 1960
Petroleum Consumption Normalized to 1960
Natural Gas Consumption Normalized to 1960
Petroleum Consumption Normalized to 1960
Natural Gas
Petroleum

There Are Six Price Dichotomies with
Natural Gas
In light of the looming transition to natural gas as the
dominant fuel in the United States, it is worth contem-
plating the complicated pricing relationship that natural
gas in the United States has with other fuels, market
factors, and regions. It turns out that there are several
relevant price dichotomies to keep in mind:
1. Natural Gas vs. Petroleum Prices,
2. U.S. vs. Global Prices,
3. Prices for Abundant Supply vs. Prices for Abundant
Demand,
4. Low Prices for the Environment vs. High Prices for
the Environment,
5. Stable vs. Volatile Prices, and
6. Long-Term vs. Near-Term Prices.
The tensions along these price axes will likely play an
important role in driving the future of natural gas in the
United States and globally.
Decoupling of Natural Gas and
Petroleum Prices
One of the most important recent trends has been the
decoupling of natural gas and petroleum prices. Figure 3
shows the U.S. prices for natural gas and petroleum
(wellhead and the benchmark West Texas Intermediate
(WTI) crude at Cushing, Oklahoma respectively) from
1988 to 2012.34, 35
While natural gas and petroleum prices
have roughly tracked each other in the United States for
decades, their trends started to diverge in 2009 as global
oil supplies remained tight, yet shale gas production
increased. This recent divergence has been particularly
stark, as it’s driven by the simultaneous downward swing
in natural gas prices and upward swing in petroleum
prices. For many years, the ratio in prices (per million
BTU, or MMBTU) between petroleum and natural gas
oscillated nominally in the range of 1–2, averaging 1.6
for 2000–2008. However, after the divergence began in
2009, this spread became much larger, averaging 4.2 for
2011 and, remarkably, achieving ratios greater than 9
spanning much of the first quarter of 2012 (for example,
FIGURE 2: U.S. Oil and Gas Consumption and Projections
Source: Energy Information Agency, “Annual Energy Review 2010” Technical Report, 2011.
Note: Natural gas might pass petroleum as the primary fuel source in the United States within one to two decades, depending on the annual rate of decreases in
petroleum consumption and increases in natural gas consumption. Historical values plotted are from EIA data.
U.S.AnnualEnergyConsumption[Quads]Year
2025 20302020201520102005
20
25
30
35
40
45
Year
U.S. Oil and Gas Consumption & Projections
Historical Petroleum Consumption
Historical Natural Gas Consumption
Projected Petroleum Consumption at 0.9% annual decline
Projected Natural Gas Consumption at 0.9% annual increase
Projected Petroleum Consumption at 1.8% annual decline
Projected Natural Gas Consumption at 1.8% annual increase
Historical Projections Fast Transition Slow Transition
Declining Petroleum Consumption
Increasing Natural Gas Consumption

natural gas costs approximately $2/MMBTU today,
whereas petroleum costs $18/MMBTU).
This spread is relatively unprecedented and, if
sustained, opens up new market opportunities for gas to
compete with oil through fuel-switching by end-users and
the construction of large-scale fuel processing facilities.
For the former, these price spreads might inspire institu-
tions with large fleets of diesel trucks (such as municipali-
ties, shipping companies, etc.) to consider investing in
retrofitting existing trucks or ordering new trucks that
operate on natural gas instead of diesel to take advantage
of the savings in fuel costs. For the latter, energy compa-
nies might consider investing in multi-billion dollar
gas-to-liquids (GTL) facilities to convert the relatively
inexpensive gas into relatively valuable liquids.
Decoupling of U.S. and Global Prices
Another important trend has been the decoupling of
U.S. and global prices for natural gas. Figure 4 shows
the U.S. prices for natural gas (at Henry Hub) compared
with European Union and Japanese prices from 1992
to 2012.36, 37, 38, 39
In a similar fashion as discussed below,
while natural gas prices in the U.S. and globally (in
particular, the European Union and Japan) have tracked
each other for decades, their price trends started to
diverge in 2009 because of the growth in domestic gas
production. In fact, from 2003–2005, U.S. natural gas
prices were higher than in the EU and Japan because
of declining domestic production and limited capacity
for importing liquefied natural gas (LNG). At that time,
and for the preceding years, the U.S. prices were tightly
coupled to global markets through its LNG imports
setting the marginal price of gas.
Consequently, billions of dollars of investments were
made to increase LNG import capacity in the United
States That new import capacity came online concur-
rently with higher domestic production, in what can only
be described as horribly ironic timing: because domestic
production grew so quickly, those new imports were no
longer necessary, and much of that importing capacity
remains idle today. In fact, once production increased in
2009, the United States was then limited by its capacity
to export LNG (which is in contrast to the situation just
a few years prior, during which the United States was
limited by its capacity to import gas), so gas prices plum-
meted despite growing global demand. Thus, while the
United States was tightly coupled to global gas markets
FIGURE 3: U.S. Oil and Gas Prices, 1988 to 2012
Sources: Energy Information Administration, U.S. Natural Gas Prices, Tech. rep., April 2, 2012. Available at: http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
Energy Information Administration, Cushing, OK WTI Spot Price FOB (Dollars per Barrel), Tech. rep., April 4, 2012. Available at: http://tonto.eia.gov/dnav/pet/
hist/LeafHandler.ashx?n=PET&s=RWTC&f=M
Note: While natural gas and petroleum prices have roughly tracked each other in the U.S. for decades, their price trends started to diverge in 2009.
FuelPrice[U.S.NominalDollarsperMillionBTU]
2006 2008 2010 20122002 20041998 20001994 19961990 1992
0
5
10
15
20
Year
U.S. Oil and Gas Prices 1988 to 2012
WTI Cushing Oil
Wellhead Natural Gas

for well over a decade, it has been decoupled for the last
several years. At the same time, the European Union and
Japan are tightly coupled to the world gas markets, (with
the European Union served by LNG and pipelines from
the Former Soviet Union, and Japan served by LNG).
How long these prices remain decoupled will depend on
U.S. production of natural gas, U.S. demand for natural
gas, and the time it takes for these isolated markets to
connect again. In fact, LNG terminal operators are
now considering the investment of billions of dollars to
turn their terminals around so that they can buy cheap
natural gas in the U.S. that they can sell at higher prices
to the EU and Japan. Once those terminals are turned
around, these geographically-divergent market prices
could come back into convergence.
Prices for Abundant Supply vs. Prices for
Abundant Demand
Another axis to consider for natural gas prices is the
tension between the price at which we have abundant
supply, and the price at which we have abundant demand.
These levels have changed over the years as technology
improves and the prices of competing fuels have shifted,
but it seems clear that there is still a difference between
the prices that consumers wish to pay and producers wish
to collect. In particular, above a certain price (say, some-
where in the range of $4–8/MMBTU, though there is no
single threshold that everyone agrees upon), the United
States would be awash in natural gas. Higher prices make
it possible to economically produce many marginal plays,
yielding dramatic increases in total production. However,
at those higher prices, the demand for gas is relatively
lower because cheaper alternatives (nominally coal, wind,
nuclear and petroleum) might be more attractive options.
At the same time, as recent history has demonstrated,
below a certain price (say, somewhere in the range of
$1–3/MMBTU), there is significant demand for natural
gas in the power sector (as an alternative to coal) and
the industrial sector (because of revitalized chemical
manufacturing, which depends heavily on natural gas as a
feedstock). Furthermore, if prices are expected to remain
low, then demand for natural gas would increase in the
residential and commercial sectors (as an alternative
FIGURE 4: Natural Gas Prices in Japan, the European Union and the United States, 1992 to 2012
Sources: BP, “BP Statistical Review of World Energy,” Tech. rep., June 2011, Available at: bp.com/statisticalreview
Energy Information Administration, Henry Hub Gulf Coast Natural Gas Spot Price, Tech. rep., April 6, 2012. Available at: http://tonto.eia.gov/dnav/ng/hist/rngwh-
hdm.htm
Energy Information Administration, Price of Liquefied U.S. Natural Gas Exports to Japan, Tech. rep., April 6, 2012. Available at: http://www.eia.gov/dnav/ng/hist/
n9133ja3m.htm
YCharts, European Natural Gas Import Price, Tech. rep., April 6, 2012. Available at: http://ycharts.com/indicators/europe_natural_gas_price
Note: While natural gas prices in the U.S. and globally (EU and Japan) have tracked each other for decades, their price trends started to diverge in 2009.
FuelPrice[U.S.DollarsperMillionBtu]
2008 201220102004 20062002200019981994 1996
0
5
10
15
Year
European Union
Japan
United States

to electricity for water heating, for example) and in the
transportation sector (to take advantage of price spreads
with diesel, as noted above).
The irony here is that it is not clear that the prices
at which there will be significant increases in demand
will be high enough to justify the higher costs that will
be necessary to induce increases in supply, and so there
might be a period of choppiness in the market as the
prices settle into their equilibrium. Furthermore, as
global coal and oil prices increase (because of surging
demand from China and other rapidly-growing econo-
mies), the thresholds for this equilibrium are likely to
change. As oil prices increase, natural gas production
will increase at many wells as a byproduct of liquids
production, whether the gas was desired or not. Since
the liquids are often used to justify the costs of a new
well, the marginal cost of the associated gas production
can be quite low. Thus, natural gas production might
increase even without upward pressure from gas prices,
which lowers the price threshold above which there will
be abundant supply. At the same time, coal costs are
increasing globally, which raises the threshold below
which there is abundant demand. Hopefully, these
moving thresholds will converge at a stable medium,
though it is too early to tell. If the price settles too high,
then demand might retract; if it settles too low, the
production might shrink, which might trigger an oscil-
lating pattern of price swings.
Low Prices for the Environment vs.
High Prices for the Environment
Another axis of price tension for natural gas is whether
high prices or low prices are better for achieving envi-
ronmental goals such as reducing the energy sector’s
emissions and water use. In many ways, high natural gas
prices have significant environmental advantages because
they induce conservation and enable market penetration
by relatively expensive renewables. In particular, because
it is common for natural gas to be the next fuel source
dispatched into the power grid in the United States, high
natural gas prices trigger high electricity prices. Those
higher electricity prices make it easier for renewable
energy sources such as wind and solar power to compete
in the markets. Thus, high natural gas prices are useful
for reducing consumption overall and for spurring
growth in novel generation technologies.
However, inexpensive natural gas also has important
environmental advantages by displacing coal in the
power sector. Notably, by contrast with natural gas
prices, which have decreased for several years in a row,
prevailing coal prices have increased steadily for over
a decade due to higher transportation costs (which are
coupled to diesel prices that have increased over that
span), depletion of mines, and increased global demand.
As coal prices track higher and natural gas prices track
lower, natural gas has become a more cost-effective
fuel for power generation for many utility companies.
Consequently, coal’s share of primary energy consump-
tion for electricity generation has dropped from 53
percent in 2003 to less than 46 percent in 2011 (with
further drops in the first quarter of 2012), while the
share fulfilled by natural gas grew from 14 percent to
20 percent over the same span. At the same time, there
was a slight drop in overall electricity generation due to
the economic recession, which means the rise of natural
gas came at the expense of coal, rather than in addition
to coal. Consequently, for those wishing to achieve the
environmental goals of dialing back on power generation
from coal, low natural gas prices have a powerful effect.
These attractive market opportunities are offset in
some respects by the negative environmental impacts
that are occurring from production in the Bakken and
Eagle Ford shale plays in North Dakota and Texas. At
those locations, significant volumes of gases are flared
because the gas is too inexpensive to justify rapid
construction of the pricey distribution systems that
would be necessary to move the fuel to markets.40, 41
Consequently, for many operators it ends up being
cheaper in many cases to flare the gas rather than to
harness and distribute it.
And, thus, the full tension between the “environ-
mental price” of gas is laid out: low prices are good
because they displace coal, whereas high prices are
good because they bring forward conservation and
renewable alternatives. This price axis will be important
to watch from a policymaker’s point of view as time
moves forward.
Stable vs. Volatile Prices
One of the historical criticisms of natural gas has been
its relative volatility, especially as compared with coal
and nuclear fuels, which are the other major primary
energy sources for the power sector. This volatility is a
consequence of large seasonal swings in gas consump-
tion (for example, for space and water heating in the
winter) along with the association of gas production with

oil, which is also volatile. Thus, large magnitude swings
in demand and supply can be occurring simultane-
ously, but in opposing directions. However, two forces
are mitigating this volatility. Firstly, because natural
gas prices are decoupling from oil prices (as discussed
in above), one layer of volatility is reduced. Many gas
plays are produced independently of oil production.
Consequently, there is a possibility for long-term supply
contracts at fixed prices. Secondly, the increased use of
natural gas consumption in the power sector, helps to
mitigate some of the seasonal swings as the consumption
of gas for heating in the winter might be better matched
with consumption in the summer for power generation
to meeting air conditioning load requirements.
Between more balanced demand throughout the year
and long-term pricing, the prospects for better stability
look better. At the same time, coal, which has histori-
cally enjoyed very stable prices, is starting to see higher
volatility because its costs are coupled with the price of
diesel for transportation. Thus, ironically, while natural
gas is reducing its exposure to oil as a driver for volatility,
coal is increasing its exposure.
Long-Term vs. Near-Term Price
While natural gas is enjoying a period of relatively stable
and low prices at the time of this writing, there are
several prospects that might put upward pressure on the
long-term prices. These key drivers are: 1) increasing
demand, and 2) re-coupling with global markets.
As discussed above, there are several key forcing
functions for higher demand. Namely, because natural
gas is relatively cleaner, less carbon-intensive, and less
water-intensive than coal, it might continue its trend of
taking away market share from coal in the power sector
to meet increasingly stringent environmental standards.
While this trend is primarily driven by environmental
constraints, its effect will be amplified as long as natural
gas prices remain low. While fuel-switching in the power
sector will likely have the biggest overall impact on
new natural gas demand, the same environmental and
economic drivers might also induce fuel-switching in
the transportation sector (from diesel to natural gas),
and residential and commercial sectors (from fuel oil
to natural gas for boilers, and from electric heating to
natural gas heating). If cumulative demand increases
significantly from these different factors but supply does
not grow in a commensurate fashion, then prices will
move upwards.
The other factor is the potential for re-coupling U.S.
and global gas markets. While they are mostly empty
today, many LNG import terminals are seeking to reverse
their orientation, with an expectation that they will be
ready for export beginning in 2014. Once they are able
to export gas to EU and Japanese markets, then domestic
gas producers will have additional markets for their
product. If those external markets maintain their much
higher prevailing prices (similar to what is illustrated in
Figure 4), re-coupling will push prices upwards.
Each of these different axes of price tensions reflects
a different nuance of the complicated, global natural
gas system. In particular, they exemplify the different
market, technological and societal forces that will
drive—and be driven by—the future of natural gas.
Conclusion
Overall, it is clear that natural gas has an important
opportunity to take market share from other primary
fuels. In particular, it could displace coal in the power
sector, petroleum in the transportation sector, and
fuel oil in the commercial and residential sectors. With
sustained growth in demand for natural gas, coupled
with decreases in demand for coal and petroleum
because of environmental and security concerns, natural
gas could overtake petroleum to be the most widely used
fuel in the United States within one to two decades.
Along the path towards that transition, natural gas will
experience a variety of price tensions that are manifesta-
tions of the different market, technological and societal
forces that will drive—and be driven by— the future of
natural gas. How and whether we sort out these tensions
and relationships will affect the fate of natural gas and
are worthy of further scrutiny.

III. Greenhouse Gas Emissions and Regulations associated
with Natural Gas Production
By Joseph Casola, Daniel Huber, and Michael Tubman, C2ES
Introduction
Natural gas is a significant source of greenhouse gas
emissions in the United States. Approximately 21
percent of total U.S. greenhouse gas emissions in 2011
were attributable to natural gas.42
When natural gas is
combusted for energy, it produces carbon dioxide (CO2
),
which accounts for most of greenhouse gas emissions
associated with this fuel. Natural gas is composed
primarily of methane (CH4
), which has a higher global
warming potential than CO2
. During various steps of
natural gas extraction, transportation, and processing,
methane escapes or is released to the atmosphere.
Although this represents a relatively smaller portion
of the total greenhouse gas emissions associated with
natural gas production and use, vented and leaked
or “fugitive” emissions can represent an opportunity
to reduce greenhouse gas emissions, maximizing the
potential climate benefits of using natural gas.
Total methane emissions from natural gas systems
(production, processing, storage, transmission, and
distribution) in the United States have improved
during the last two decades, declining 13 percent from
1990 to 2011, driven by infrastructure improvements
and technology, as well as better practices adopted by
industry. This has occurred even as production and
consumption of natural gas has grown. Methane emis-
sions per unit of natural gas consumed have dropped
32 percent from 1990 to 2011. Since 2007, methane
emissions from all sources have fallen almost 6 percent,
driven primarily by reductions of methane emissions
from natural gas systems. Nevertheless, given its impact
on the climate, emphasis on reducing methane emis-
sions from all sources must remain a high priority. This
chapter discusses the differences between methane and
CO2
, emission sources, and state and federal regulations
affecting methane emissions.
Global Warming Potentials of Methane
and CO2
On a per-mass basis, methane is more effective at
warming the atmosphere than CO2
. This is represented
by methane’s global warming potential (GWP), which
is a factor that expresses the amount of heat trapped
by a pound of a greenhouse gas relative to a pound of
CO2
over a specified period of time. GWP is commonly
used to enable direct comparisons between the warming
effects of different greenhouse gases. By convention, the
GWP of CO2
is equal to one.
The GWP of a greenhouse gas (other than CO2
)
can vary substantially depending on the time period
of interest. For example, on a 100-year time frame, the
GWP of methane is about 21.43
But for a 20-year time
frame, the GWP of methane is 72.44
The difference
stems from the fact that the lifetime of methane in the
atmosphere is relatively short, a little over 10 years, when
compared to CO2
, which can persist in the atmosphere
for decades to centuries.
Since models that project future climate conditions
are often compared for the target year of 2100, it is
often convenient to use 100-year GWPs when comparing
emissions of different greenhouse gases. However, these
comparisons may not accurately reflect the relative
reduction in radiative forcing (the extent to which a gas
traps heat in the atmosphere) arising from near-term
abatement efforts for greenhouse gases with short
lifetimes. Whereas near-term reductions in CO2
emis-
sions provide reductions in radiative forcing benefits
spread out over a century, near-term abatement efforts
for methane involve a proportionally larger near-term
reduction in radiative forcing. In light of potential
climate change over the next 50 years, the control of
methane has an importance that can be obscured when
greenhouse gases are compared using only their 100-year

GWPs. Accordingly, reducing methane emissions from
all sources is important to efforts aimed at slowing the
rate of climate change.
Emissions from Natural Gas Combustion
On average, natural gas combustion releases approxi-
mately 50 percent less CO2
than coal and 33 percent
less CO2
than oil (per unit of useful energy) (Figure 1).
In addition, the combustion of coal and oil emits other
hazardous air pollutants, such as sulfur dioxides and
particulate matter. Therefore, the burning of natural gas
is considered cleaner and less harmful to public health
and the environment than the burning of coal and oil.
The U.S. Energy Information Administration (EIA)
has projected that U.S. energy-related CO2
emissions
will remain more than 5 percent below their 2005 level
through 2040, a projection based in large part on the
expectation that: 1) natural gas will be steadily substi-
tuted for coal in electricity generation as new natural
gas power plants are built and coal-fired power plants
are converted to natural gas, and 2) state and federal
programs that encourage the use of low-carbon tech-
nologies will continue.45
The EIA predicts that natural
gas—fired electricity production in the United States
will increase from 25 percent in 2010 to 30 percent in
2040, in response to continued low natural gas prices
and existing air quality regulations that affect coal-fired
power generation.
Venting and Leaked Emissions Associated
with Natural Gas Production
In 2011, natural gas systems contributed approximately
one-quarter of all U.S. methane emissions (Figure 2), of
which over 37 percent are associated with production.46
In the production process, small amounts of methane
can leak unintentionally. In addition methane may be
intentionally released or vented to the atmosphere for
safety reasons at the wellhead or to reduce pressure
from equipment or pipelines. Where possible, flares
can be installed to combust this methane (often at the
wellhead), preventing much of it from entering the
atmosphere as methane but releasing CO2
and other air
pollutants instead.
These methane emissions are an important, yet not
well understood, component of overall methane emis-
sions. In recent years greenhouse gas measurement and
reporting requirements have drawn attention to the need
for more accurate data. This uncertainty can be seen
in the revisions that have accompanied sector emission
Figure 1: CO2
Emissions from Fossil Fuel
Combustion
Source: 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
Notes: CO2
content for petroleum has been calculated as an average of repre-
sentative fuel types (e.g., jet fuel, motor gasoline, distillate fuel) using 2011 data.
This graphic does not account for the relative efficiencies of end-use
technologies.
0
10
20
30
40
50
60
70
80
90
100
Natural GasPetroleumCoal
TgCO2equivalent
perQuadrillionBtu
Figure 2: Sources of Methane Emissions in
the United States, 2011
Source: Environmental Protection Agency, Draft U.S. Greenhouse Gas
Inventory Report, 2013. Available at: http://www.epa.gov/climatechange/
ghgemissions/usinventoryreport.html
Other
6%
Wastewater
Treatment
3%
Petroleum
Systems
5%
Manure
Management
9%
Coal Mining
11%
Landfills
18%
Enteric
Fermentation
24%
Natural Gas
Systems
24%

estimates. Just recently for example, EPA revised down-
ward the estimated level of methane emissions attribut-
able to production of natural gas. In 2010, it estimated
about 58 percent of methane emission in the natural gas
system came from production. In 2013, EPA reduced that
number to 37 percent. A major reason for this revision
was a change in EPA’s assumption about emission
leakage rates. Based on EPA’s GHG inventory data, the
assumed leakage rate for the overall natural gas system
was revised downward from 2.27 percent in 2012 to 1.54
percent in 2013.47
Independent studies have estimated
leak rates ranging from 0.71 to 7.9 percent.48, 49, 50
EPA
and others are trying to better understand the extent of
leakage and where this leakage is occurring.
Given the climate implications of methane, consider-
able effort is also being focused on reducing leakage and
methane emissions overall. According to EPA, methane
emissions from U.S. natural gas systems have declined
by 10 percent between 1990 and 2011 even with the
expansion of natural gas infrastructure.51
This decline
is largely the result of voluntary reductions including
greater operational efficiency, better leakage detection,
and the use of improved materials and technologies
that are less prone to leakage.52
In particular, the EPA’s
Natural Gas Star Program has worked with the natural
gas industry to identify technical and engineering
solutions that minimize emissions from infrastructure,
including zero-bleed pneumatic controllers, improved
valves, corrosion-resistant coatings, dry-seal compressors,
and improved leak-detection and leak-repair strategies.
The EPA has tracked methane reductions associated with
its Natural Gas STAR program (Figure 3) and estimates
that voluntary actions undertaken by the natural gas
sector reduced emissions by 94.1 billion cubic feet (Bcf)
in 2010. Notably, many of the solutions identified by this
voluntary program have payback periods of less than
three years (depending on the price of natural gas).53
The success of the Natural Gas STAR program further
highlights the importance of understanding where
emission leakage is occurring because without accurate
data, it is difficult to prioritize reduction efforts or
make the case for technologies and processes like those
highlighted by the program.
Regulation of Leakage and Venting
Regulations applicable to methane leakage and venting
from natural gas operations have been implemented at
both the federal and state level. Although air pollution
from natural gas production has been regulated in
various forms since 1985 (e.g., toxic substances such as
benzene and volatile organic compounds that contribute
to smog formation), over the past few years, due to
the recent increase in natural gas production and the
use of new extraction methods (particularly hydraulic
fracturing), natural gas operations have come under
renewed scrutiny from policy-makers, non-governmental
organizations, and the general public. In response to
potential environmental and climate impacts from
increased natural gas production including deployment
of new technologies, new state and national rules are
being developed.
Federal Regulations
EPA released new air pollution standards for natural
gas operations on August 16, 2012. The New Source
Performance Standards and National Emissions
Standards for Hazardous Air Pollutants are the first
federal regulations to specifically require emission
reductions from new or modified hydraulically fractured
and refractured natural gas wells. The New Source
Performance Standards require facilities to reduce
emissions to a certain level that is achievable using the
best system of pollution control, taking other factors
Figure 3: Annual and Cumulative Reductions
in Methane Emissions Associated with the
Environmental Protection Agency’s Natural
Gas STAR Program, 2004 to 2010
Source: Environmental Protection Agency, “Accomplishments,” July 2012.
Available at http://www.epa.gov/gasstar/accomplishments/index.html
-1,000
-800
-600
-400
-200
0
2010200920082007200620052004
BillionCubicFeet
Cumulative
Annual

into consideration, such as cost.54
Under the National
Emissions Standards for Hazardous Air Pollutants
program, EPA sets technology-based standards for
reducing certain hazardous air pollutant emissions using
maximum achievable control technology. The regula-
tions 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 from well
completions and recompletions.55
Among several emission controls, these rules also
require the use of “green completions” at natural gas
drilling sites, a step already mandated by some jurisdic-
tions and voluntarily undertaken by many companies.
In a “green completion,” special equipment separates
hydrocarbons from the used hydraulic fracturing fluid,
or “flowback,” that comes back up from the well as it
is being prepared for production. This step allows for
the collection (and sale or use) of methane that may
be mixed with the flowback and would otherwise be
released to the atmosphere. The final “green comple-
tion” standards apply to hydraulically fractured wells that
begin construction, reconstruction, or modification after
August 23, 2011, estimated to be 11,000 wells per year.
The “green completion” requirement will be phased-in
over time, with flaring allowed as an alternative compli-
ance mechanism until January 1, 2015.
While the “green completion” regulations are
expected to reduce methane emissions from natural gas
wells, concern has been expressed that the regulations
do not apply to onshore wells that are not hydraulically
Figure 4: Venting Regulations by State
Source: Resources for the Future. “A Review of Shale Gas Regulations by State.” July 2012. Available at: http://www.rff.org/centers/energy_economics_and_
policy/Pages/Shale_Maps.aspx
Specific venting restrictions
Aspirational standards
Notice and approval required
No venting allowed
No evidence of regulation
Not in study
No natural gas wells as of 2010

fractured, existing hydraulically fractured wells until
such time as they are refractured, or oil wells, including
those that produce associated natural gas.56
However,
geologic and market barriers may limit the applicability
of this type of rule to other sources of natural gas.
State Regulations
Numerous states have also implemented regulations that
address venting and flaring from natural gas exploration
and production. Some states with significant oil and gas
development, such as Colorado, North Dakota, Ohio,
Pennsylvania, Texas, and Wyoming, already have venting
and/or flaring requirements in place. For example, Ohio
requires that all methane vented to the atmosphere be
flared (with the exception of gas released by a properly
functioning relief device and gas released by controlled
venting for testing, blowing down, and cleaning out
wells). North Dakota allows gas produced with crude oil
from an oil well to be flared during a one-year period
from the date of first production from the well. After that
time period, the well must be capped or connected to a
natural gas gathering line.57
These regulations may be
changed or upgraded as the national “green completion”
rules come into effect. Maps produced by Resources for
the Future, show the diversity of state regulations that
apply to venting and flaring in natural gas development
in 31 states (Figures 4 and 5).
Figure 5: Flaring Regulations by State
Source: Resources for the Future. “A Review of Shale Gas Regulations by State.” July 2012. Available at: http://www.rff.org/centers/energy_economics_and_
policy/Pages/Shale_Maps.aspx
Specific flaring restrictions
Aspirational standards
Notice and approval required
Flaring required
No evidence of regulation
Not in study
No natural gas wells as of 2010

Conclusion
The climate implications associated with the production
and use of natural gas differ from other fossil fuels (coal
and oil). Natural gas combustion yields considerably
lower emissions of greenhouse gases and other air pollut-
ants; however, when methane is released directly into the
atmosphere without being burned—through accidental
leakage or intentional venting—it is about 21 times more
powerful as a heat trapping greenhouse gas than CO2
when considered on a 100-year time scale. As a result,
considerable effort is underway to accurately measure
methane emission and leakage. Policy-makers should
continue to engage all stakeholders in a fact-based
discussion regarding the quantity and quality of available
emissions data and what steps can be taken to improve
these data and accurately reflect the carbon footprint
of all segments of the natural gas industry. To that end,
additional field testing should be performed to gather
up-to-date, accurate data on methane emissions. Policy-
makers have begun to create regulations that address
methane releases, but a better understanding and more
accurate measurement of the emissions from natural gas
production and use could potentially identify additional
cost-effective opportunities for emissions reductions
along the entire natural gas value chain.

IV. Power Sector
By Doug Vine, C2ES
Introduction
The U.S. power industry produces electricity from a
variety of fuel sources (Figures 1 and 2). In 2012, coal-
fueled generation provided a little more than 39 percent
of all electricity, down from 50 percent in 2005. Nuclear
power provided around 19 percent of net generation.
Filling the gap left by the declining use of coal, natural
gas now provides nearly 29 percent of all electricity and
renewables, including wind and large hydroelectric
power, provide about 12 percent. Petroleum-fueled
generation is in decline, providing less than 1 percent of
electricity in 2012.
Natural gas use in the power sector during the 1970s
and 1980s was fairly consistent and low, contributing a
declining share of total electricity generation as coal and
nuclear power’s share of total electricity significantly
increased. In 1978, in response to supply shortages (the
result of government price controls), Congress enacted
the Power Plant and Industrial Fuel Use Act.58
The
law prohibited the use of oil and natural gas in new
industrial boilers and new power plants, with the goal
of preserving the (thought to be) scarce supplies for
residential customers.59
As a consequence, the demand
for natural gas declined during the 1980s, contributing
to an oversupply of gas for much of the decade. The
falling natural gas demand and prices spurred the repeal
in 1987 of sections of the Fuel Use Act that restricted the
use of natural gas by industrial users and electric utili-
ties.60
(For an overview of key policies impacting natural
gas supply, see Appendix A). Continued low natural gas
prices in the 1990s stimulated the rapid construction of
gas-fired power plants.61
In the early 2000s, the building
boom in natural gas-fired generation was tempered
Figure 1: U.S. Electricity Generation by Fuel Type, 1973 to 2012
Source: Energy Information Administration, “Electricity Net Generation: Total (All Sectors). Table 7.2a,” March 2013. Available at: http://www.eia.gov/totalenergy/
data/monthly/#electricity
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
20122009200620032000199719941991198819851982197919761973
Conventional Hydroelectric
Nuclear
Natural Gas
Petroleum
Coal
Non-Hydroelectric Renewables

somewhat by price spikes, although natural gas-fired
generating capacity continues to be added more than any
other fuel type. Since 1990, electricity generation from
natural gas has increased from around 11 percent to 29
percent of the total net generation in 2012 (Figure 1). In
2006, natural gas surpassed nuclear power’s share of the
total generation mix, and in April 2012, natural gas and
coal each contributed a little more than 32 percent of
total generation.
This chapter explores the combination of factors
driving change in the power sector. It examines the
advantages and disadvantages of natural gas use, the
competitive nature of alternative energy sources, and
the synergy between natural gas and renewable energy
generation. Finally, it explores relevant policy options
that could lower greenhouse gas emissions in the sector.
Advantages and Disadvantages of Natural
Gas Use in the Power Sector
From the perspective of an electrical system operator,
a power plant owner, or an environmental perspective,
natural gas-fueled power generation has many advan-
tages. Natural gas can provide baseload, intermediate,
and peaking electric power, and can thus meet all types
of electrical demand. It is an inexpensive, reliable,
dispatchable source of power that is capable of supplying
firm backup to intermittent sources such as wind and
solar.62
Natural gas power plants can be constructed rela-
tively quickly, in as little as 20 months.63
Air emissions are
significantly less than those associated with coal genera-
tion, and compared to other forms of electric generation,
natural gas plants have a small footprint on the land-
scape. However, even though combustion of natural gas
produces lower greenhouse gas emissions than combus-
tion of coal or oil, natural gas does emit a significant
amount of carbon dioxide (CO2
), and its direct release
into the atmosphere, as discussed in chapter 3, adds
quantities of a greenhouse gas many times more potent
than CO2
. Finally, natural gas-fired power plants must be
sited near existing natural gas pipelines, or else building
new infrastructure may significantly increase their cost.
Cost of Building Natural Gas-Fired Power Plants
Natural gas-fired combined-cycle electricity generation
(see Appendix B for a list of power plant technologies)
is projected to be the least expensive generation tech-
nology in the near and mid-term, taking into account
a range of costs over an assumed time period. These
costs include capital costs, fuel costs, fixed and variable
operation/maintenance costs, financing costs, and
an assumed utilization rate for the type of generation
plant (Figure 3). The availability of various incentives
including state or federal tax credits can also impact the
cost of an electricity generation plant, but the range of
values shown in Figure 3 do not incorporate any such
incentives. Based purely on these market forces, utilities
looking at their bottom lines and public utility commis-
sions looking for low-cost investment decisions will favor
the construction of natural gas-fired technologies in the
coming years.
Emissions
For each unit of energy produced, a megawatt-hour
(MWh) of natural gas-fired generation contributes
around half the amount of CO2
emissions as coal-fired
generation and about 68 percent of the amount of CO2
emissions from oil-fired generation (Table 1).
While combustion of natural gas produces lower
greenhouse gas emissions than combustion of coal or
oil, natural gas does emit a significant amount of carbon
dioxide (CO2
). In 2011, the power sector contributed
about 33 percent of all U.S. CO2
emissions.64
Since 2005,
total greenhouse gas emissions from the electricity sector
have decreased, even as net electricity generation has
remained steady, a result of natural gas-fired electricity
Figure 2: U.S. Electricity Generation by
Fuel Type, 2012
Source: Energy Information Administration, “March 2013 Monthly Energy Re-
view. Table 7.2b. Electricity Net Generation: Electric Power Sector,” Available
at: http://www.eia.gov/totalenergy/data/monthly/#electricity
Petroleum
1%
Non-hydro
Renewables
5%
Hydropower
7%
Nuclear
20%
Natural Gas
29%
Coal
39%

generation displacing petroleum- and coal-fired genera-
tion and an increase in the use of renewable generation.
In 2012, CO2
emissions from power generation were at
their lowest level since 1993 (Figure 4).
Future Additions to Electricity Generation Capacity
There is strong evidence that the trends toward more
natural gas in the power sector will continue in the near
and medium term. With natural gas prices expected to
stay relatively low and stable and the increasing likeli-
hood of a carbon-constrained future, natural gas has
become the fuel of choice for electricity generation by
utilities in the United States.65, 66
In 2012, the electric
power industry planned to bring 25.5 gigawatts (GW)
of new capacity on line, with 30 percent being natural
gas-fired (and the remainder being 56 percent renewable
energy and 14 percent coal.67
Between 2012 and 2040,
the U.S. electricity system will need 340 GW of new
generating capacity (including combined heat and power
additions), given rising demand for electricity and the
planned retirement of some existing capacity.68
Natural
gas-fired plants will account for 63 percent of cumulative
capacity additions between 2012 and 2040 in the Energy
Information Administration (EIA) Annual Energy
Outlook 2013 reference case, compared with 31 percent
for renewables, 3 percent for coal, and 3 percent for
nuclear (Figure 5).
Federal tax incentives and state programs will
contribute substantially to renewables’ competitive-
ness in the near term.69
For example, with the wind
production tax credit, wind generation is expected to
increase more than 18 GW from 2010 to 2015. Similarly
Figure 3: Estimated Levelized Cost of New Generation Resource, 2020 and 2040
Source: Energy Information Administration, “Annual Energy Outlook 2013,” April 15, 2013. Available at: http://www.eia.gov/forecasts/aeo/MT_electric.cfm#cap_
addition
Note: Price in 2011 cents per kilowatt-hour.
0 3 6 9 12 15
Natural Gas
combined cycle
Wind
Nuclear
Coal
Natural Gas
combined cycle
Wind
Nuclear
Coal
20402020
Levelized Cost (2011 cents per kilowatthour)
Incremental Transmission Costs
Variable Costs, Including Fuel
Fixed Costs
Capital costs
Table 1: Average Fossil Fuel Power Plant Emission Rates (pounds per Megawatt Hour)
GENERATION FUEL TYPE
CO2
LB/MWH
SULFUR DIOXIDE
LB/MWH
NITROGEN OXIDES
LB/MWH
Coal 2,249 13 6
Natural Gas 1,135 0.1 1.7
Oil 1,672 12 4
Source: Environmental Protection Agency, “Clean Energy—Air Emissions,” 2012. Available at: http://www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html

with the solar investment tax credit, utility and end-use
solar capacity additions are forecast to increase by 7.5
GW through 2016.70
In addition to federal incentives,
state energy programs mandate increased renewable
energy capacity additions in thirty-eight states. These
states have set standards specifying that electric utilities
deliver a certain amount of electricity from renewable or
alternative energy sources. Increasing the deployment
of zero-carbon energy technologies such as renewables,
nuclear, and carbon capture and storage needs to be a
priority in order for the United States (and the rest of the
world) to address climate change.
Figure 4: U.S. Emissions in the Power Sector, 1990 to 2012
Source: Energy Information Administration, “Monthly Energy Review,” Table 12.6, March 27, 2013. Available at: http://www.eia.gov/forecasts/archive/aeo11/index.cfm
0
500
1000
1500
2000
2500
3000
201220102008200620042002200019981996199419921990
Emissions(MillionMetricTonsCO2
)
Other
Petroleum
Fuel Oil
Natural Gas
Coal
Figure 5: Additions to Electricity Generation Capacity, 1985 to 2040
Source: Energy Information Administration, “Annual Energy Outlook 2013,” April 15, 2013. Available at: http://www.eia.gov/forecasts/aeo/MT_electric.cfm#cap_
addition
Gigawatts
0
10
20
30
40
50
60
204020302020
2011
200519951985
History Projections
Natural Gas/Oil
Nuclear
Hydro/Other
Coal
Other Renewables
Solar
Wind

Fuel Mix Diversity
Since 1990 the share of generation from natural gas
has increased from around 11 percent to 29 percent of
the total net generation in 2012 (Figure 1), substantially
increasing the diversity of the fuel mix. Natural gas-fired
generation is expected to constitute just over 27 percent
of the total generation mix in 2020, rising to 30 percent
in 2035.71
Fuel diversity is an important consideration
for utilities looking to reduce their reliance on any
particular energy source, as too much reliance on any
one fuel can expose utilities or other power generation
owners to the risks associated with price volatility. From a
national perspective, fuel diversity is projected by EIA to
remain about the same through 2040 with no single fuel
being dominant.72
Two things could change this outlook,
however. One is a scaling back or reversal of the state
and federal policies supporting zero-carbon generation,
such as state renewable portfolio standards and federal
tax incentives.73
The other is a change in the outlook for
the U.S. nuclear generation fleet. Competitive pressures
from low natural gas prices have already caused one
small, older (1974) plant—the 586 MW Kewaunee plant
in Wisconsin—to announce its closure (even though its
operating license does not expire until 2033).74
Should
more nuclear generation follow suit, these would likely
be replaced by natural gas-fired generation. Given that
19 percent of U.S. electricity comes from nuclear power,
there is concern that replacing these with natural gas
and decreasing the emphasis on renewable energy
deployment would push the U.S. power sector into a
situation where fuel diversity is significantly reduced.
Opportunities for Further Greenhouse
Gas Reductions
Beyond the increased use of lower-emitting fuels in the
traditional, centralized power-generation system, certain
fundamental changes in where and how electricity is
generated have the potential to dramatically reduce
greenhouse emissions from the sector. These opportuni-
ties and challenges are detailed below and are crucial if
long-term emission reductions are to be made.
Distributed Generation
Generating electricity at or near the site where it is used
is known as distributed generation. A common example
is solar panels on the rooftops of homes and businesses,
but natural gas is also used in conjunction with distrib-
uted generation technologies. For example, natural gas
combined heat and power (CHP) systems in industrial,
commercial, and residential settings are becoming a more
commonplace type of distributed generation.
Traditionally, the power sector functions with centrally
located power stations generating large quantities of
electricity, which is transported to end users via electrical
transmission and distribution lines. With distributed
generation systems (also referred to as on-site generation
or self-generation, and described in more detail in chapter
7), smaller quantities of electricity are generated at or near
the location where it will be consumed, obviating the need
for long electrical transmission lines. Additionally, natural
gas CHP systems (discussed in more detail in chapter
6) are able to use waste heat from electricity produc-
tion for practical purposes. Switching from a primarily
centrally generated power generation system to a more
efficient distributed system that captures waste heat avoids
electrical transmission losses, requires less electricity to
be generated, and uses less fossil fuel in aggregate, and
therefore lowers greenhouse gas emissions.
Supply Side Efficiency
For a host of practical and economic reasons, centralized
power generation will not be going away in the near or
medium term. Basically, there are three categories of
natural gas-fueled central power station: steam turbines,
combustion turbines, and combined-cycle power plants
(Appendix B). Each of these plant types has an average
thermal efficiency. Thermal efficiency measures how well
a technology converts the fuel energy input (heat) into
electrical energy output (power). A higher thermal effi-
ciency, other things being equal, indicates that less fuel
is required to generate the same amount of electricity,
resulting in fewer emissions. Steam turbines have the
lowest efficiency at around 33 to 35 percent. Combustion
turbines are around 35 to 40 percent efficient, and
combined-cycle plants have thermal efficiencies in the
range of 50 to 60 percent.
More efficient designs should be considered as new
natural gas-fired capacity is added to the power sector.
The Electric Power Research Institute (EPRI) asserts that
it is technologically and economically feasible to improve
the thermal efficiencies of steam turbine technology by
3 percent, increase combustion turbines to 45 percent
efficient, and construct combined-cycle plants with 70
percent efficiency by 2030.75
Higher thermal efficiencies
translate into less fuel required to generate the same
amount of electricity. EPRI’s 2009 analysis estimates a

potential CO2
emissions reduction in 2030 of 3.7 percent
from the power sector as a result of increasing the effi-
ciency of new and existing fossil fuel-fired generation.76
Carbon Capture and Storage
In a carbon-constrained future, and with natural gas
potentially playing a greater role in the future of the
total generation mix natural gas plants with carbon
capture and storage capability will need to be deployed
to ensure greenhouse gas emissions are reduced over
the long term. Carbon capture and storage projects have
already been initiated, and several projects are planned
in the next several years to demonstrate the feasibility
of the technology, such as the Texas Clean Energy
Project and the Kemper County integrated-gasification,
combined-cycle (IGCC) project.77
To date, these projects
have been undertaken almost exclusively in conjunction
with coal-fired power plants or industrial sources.78
However, one international project in Norway, set to
begin in 2012, endeavors to capture CO2
from a natural
gas CHP plant (similar to a combined-cycle plant) and
sequester the CO2
in an underground saline formation.79
In addition to sequestering CO2
in saline formations,
CO2
is currently being injected into oil wells as part
of tertiary, or enhanced, oil production (CO2
-EOR).80
This storage option has the added benefit of providing
an economic incentive, that is, compensation from the
oil-field operator to the captured-CO2
provider. In 2011,
the National Enhanced Oil Recovery Initiative (NEORI)
was formed to help realize CO2
-EOR’s full potential as a
national energy security, economic, and environmental
strategy. In addition, NEORI suggests federal- and state-
level action to support CO2
-EOR.81
Economics and Fuel Selection
For power plant operators, the economics of switching
from coal to natural gas ultimately depend on underlying
fuel prices, which in turn depend on individual location,
operational and reliability requirements, and environ-
mental regulations. In mid-2011, natural gas prices fell
below coal prices on a dollar-per-energy-output basis.
As the gap between the two fuels widened, the share of
natural gas-fired power generation increased. However, by
July 2012, natural gas prices had rebounded above $3.10
per thousand cubic feet, the cost point for coal at the time.
Accordingly, coal-fired generation increased relative to
natural gas-fired generation.82
Future fuel substitution will
depend on the variable prices of both coal and natural gas.
Competitive electric power markets, in some form,
exist in 43 states. In competitive power markets, elec-
tricity is bid into the market based on production costs.
Typically, fuel cost is the main driver of production cost,
but fuel costs can vary depending on a plant’s location.
Other factors such as plant efficiency will also affect
production cost, with newer more efficient plants able
to bid into the market at lower prices than older plants.
Renewable technologies such as hydro and wind have the
lowest production costs (Figure 6), and can be bid into
a market at near zero dollars. Next in the merit or price
order is nuclear power, followed by lignite, a cheaper,
softer coal with a high moisture content. Hard coal
plants and natural gas combined-cycle plants are in the
middle of the supply curve or bid stack. Finally, natural
gas combustion turbine plants and oil and diesel plants
are the most expensive plants to run and are basically
only used during times of peak demand. Electricity
system operators employ a least-cost dispatch meth-
odology. The point at which the quantity of electricity
demanded at any point in time crosses the price-ordered
supply curve is known as the marginal generator, and
this sets the market price. Coal- or natural gas-fired
plants are the marginal generator in most competitive
power markets. Even though other suppliers such as
wind and nuclear have bid into the market at a price
lower than the marginal generator, all units receive the
marginal or market price for that time period.
Lower natural gas prices and greater quantities of
low variable cost renewables are contributing to lower
prices in competitive electricity markets. Current and
forecast low natural gas prices were cited as one of the
reasons behind the recently announced decision to shut
down a 556 megawatt (MW) Wisconsin-based nuclear
power station.83
Additionally, there is evidence to suggest
that lower natural gas prices suppress the development
of renewables.84
In this situation, government policies
are undoubtedly necessary to ensure that zero-carbon
generation sources are a growing, rather than declining,
share of the U.S. energy mix.
Relationship Between Natural Gas and Renewables
There is a complicated relationship between natural gas
and renewables in the power sector, stemming from two
aspects: 1) competition in the dispatch order between
natural gas and renewables, and 2) the potential to
produce renewable forms of natural gas.

For the most part, the relationship between natural gas
and renewables is interpreted as competition in the power
sector, by which renewables are seen as a threat to natural
gas because they push natural gas-fired power plants
off the bid stack. This phenomenon occurs because the
power markets take bids on marginal costs rather than
all-in costs. Because the marginal cost of wind is zero, it
bids zero (or negative in some cases, reflecting the effect
of production tax credits for wind power). Consequently,
it is a price-taker in the markets, and it displaces the
highest bidders, which are the price-setters. Historically,
those price-setters are natural gas power plants, and so
wind power displaces natural gas. Consequently, the
relationship between gas and wind is one of rivalry.
Natural gas interests audibly complain about this rivalry,
with the criticism that policy supports for wind give it an
unfair advantage in this competition. Renewable energy
supporters counter that natural gas interests are not
required to pay for their pollution (which is a form of
indirect subsidy) and have enjoyed government largesse
in one form or another for many decades.
Despite the perception that wind and natural gas
are vicious competitors in a zero-sum game where the
success of one must come at the demise of the other, the
relationship is actually more nuanced. In fact, wind and
gas benefit from each other because they both mitigate
each other’s worst problems. For wind, intermittency
is a problem, and for natural gas, price volatility has
been a problem historically. It turns out that the ability
for natural gas power plants to serve as rapid response
firming power is an effective hedge against wind’s
intermittency. And, it turns out the fixed fuel price (at
zero) of wind farms is an effective hedge against natural
price volatility. Thus, they are complementary partners
in the power markets.
Almost all natural gas used today comes from geologic
reserves formed many millions of years ago. Therefore,
many people seeking a long-term sustainable energy
option reject natural gas automatically because it is
widely considered a fossil fuel that has a finite resource
base. It is important to note that there are also renewable
forms of natural gas, known as biogas or biomethane.
This form of gas is mostly methane (CH4
) with a balance
of CO2
, and is created from the anaerobic decomposition
of organic matter. While renewable natural gas is a small
fraction of the overall gas supply, it is not negligible. For
example, landfill gas is already an important contributor
to local fuel supplies at the local scale. And, recent
studies have noted that the total potential supply avail-
able from wastewater treatment plants and anaerobic
digestion of livestock waste is over 1 quadrillion British
thermal units annually in the United States, which is
more than 10 percent of the amount of renewable energy
consumed in the United States in 2011.85, 86, 87
FIGURE 6: Generalized Representation of a Competitive Power Market
Source: Adapted from Rawls, Patricia, U.S. Department of Energy: National Energy Technology Laboratory, “The PJM Region: A GEMSET Characterization for
DOE.” December 13, 2002. Available at http://www.netl.doe.gov/energy-analyses/pubs/200220DecPJMregionHandout.pdf
ProductionCost($/MWh)
Demand
Supply
60,00050,00020,000 30,000 40,00010,0000
Installed Generation (MW)
Market Price
Hydro/wind Nuclear Lignite
Coal CCGT
GT
Oil
$0
$20
$40
$60
$80
$100
$120
$140
$160

Key Policy Options for the Power Sector
Significant policy decisions affecting the U.S. power
sector today include regulations to address the interstate
air pollution transport, the National Emissions Standards
for Hazardous Air Pollutants, and the proposed New
Source Performance Standards issued by the U.S.
Environmental Protection Agency (EPA). For electricity
generation plants to comply with the Cross State Air
Pollution Rule and National Emissions Standards for
Hazardous Air Pollutants, they will need to install pollu-
tion control technologies, a requirement that will affect
coal-fired plants in particular.88
PJM, the operator of the
world’s largest wholesale electricity market, located in
the eastern United States, predicts that approximately 14
GW of coal-fired generation (out of an installed capacity
of 78.6 GW of coal-fired generation) could be retired by
2015, largely due to these rules.89
Questions have been
raised about the implications of these retirements on the
electricity system’s capacity and ability to meet demand
and specifically reserve margins. Reserve margins are the
spare capacity that electricity system or market opera-
tors are required to maintain above the projected peak
loads in order to ensure system reliability. While reserve
margins appear sufficient in the short run, new, reliable
baseload generation will be required in the next 10 to 20
years to fill the gap.
In late March 2012, EPA proposed CO2
pollution
standards for new electric power plants as part of its New
Source Performance Standards program. The proposed
standard is 1,000 pounds of CO2
per megawatt-hour,
and under this new standard all new power plants would
need to match the CO2
emissions performance currently
achieved by highly efficient natural gas combined-cycle
power plants. While new efficient natural gas, nuclear, or
renewable energy plants would meet this standard easily,
new coal-fired power plants could meet the standard only
by capturing and permanently sequestering their green-
house gas emissions using carbon capture and storage
technologies. If adopted, this standard would favor new
natural gas-fired generation over coal in the future.90
In the past few years, there has also been some interest
in a federal-level renewable portfolio standard and, more
recently, in a broader federal clean energy standard.
Whereas a renewable portfolio standard typically credits
only 100 percent-renewable generation such as wind,
solar, geothermal, or new hydro power, a clean energy
standard would create a mechanism to credit “cleaner”
electricity generation as well, that is, generation that
emits some CO2
although less than a reference power
plant technology such as a generic coal power plant.
Under a clean energy standard proposal, credits would
be available to new and incremental (upgrades and
improvements to) natural gas-fired generation, natural
gas with carbon capture and storage, and other rela-
tively cleaner forms of electricity production.91
Indiana
and West Virginia have alternative energy portfolio
standards, similar to a renewable portfolio standard;
however, these standards allow natural gas-fueled
generation to be a part of their clean energy goals. In
this way, some policy-makers have recognized that there
are significant emissions benefits to natural gas use.
There is a need, however, to continue moving the
power generation sector to even cleaner generation (zero-
emission sources), to reduce CO2
emissions to levels that
will stave off the worst effects of climate change.
A price on carbon is a highly effective policy that
can provide an incentive for zero-emission sources
but it is not the only option. Tax credits for renewable
generation, carbon capture and storage, nuclear loan
guarantees, and policies that promote energy efficiency
are all being used, to some extent, in the United States to
acccelerate the deployment of low-carbon energy.
Conclusion
Market forces are driving greater use of natural gas in
the power sector, and the inherent qualities of natural
gas combustion are leading to lower greenhouse gas
emissions. Adoption of distributed generation technolo-
gies, more efficient technology, and carbon capture
and storage with natural gas have the potential to lower
greenhouse gas emissions further. Market forces are
joined by policy decisions, enacted and pending, that
impact coal-fired generation and will further discourage
its use. In addition, some states’ alternative energy
portfolios count natural gas-fueled generation toward
their medium-term clean energy goals.
Low natural gas prices are having an impact on the
diversity of the fuel mix used in electricity generation. In
the near term, the diversity of the fuel mix is increasing
as fuel-switching from coal to natural gas proceeds;
however, in the long term, a sustained low natural gas
price may discourage investment in nuclear generation
and renewables. Policy is necessary to ensure that the
percentage of zero carbon-emission power generation
is growing sufficiently to mitigate the most dangerous
effects of climate change.

Appendix A: Natural Gas Policy
1938 The Natural Gas Act of 1938 establishes federal authority over interstate pipelines, including the
authority to set “just and reasonable” rates. It also establishes a process for companies seeking to build
and operate interstate pipelines. Oversight of The Act is given to the Federal Power Commission.
1954–1978 Natural gas price controls eventually lead to scarcity and shortage.
1978 In response to supply shortages, Congress enacts the Power Plant and Industrial Fuel Use Act. The law
prohibits the use of natural gas in new industrial boilers and new electric power plants. The goal is to
preserve “scarce” supplies for residential customers.
1985 The Federal Power Commission is replaced by the Federal Energy Regulatory Commission, which
issues Order 436, intended to provide for open access to interstate pipelines that would offer transpor-
tation service for gas owned by others.
1987 President Reagan signs into law the repeal of the remaining Fuel Use Act restrictions and incremental
pricing, believing that the country’s natural gas resources should be free from regulatory burdens,
which some saw as costly and counterproductive.
1990 On April 3rd, trading on natural gas futures begins at the New York Mercantile Exchange.
2005 The Energy Policy Act 2005 is passed, a bill exempting fluids used in the natural gas extraction process
of hydraulic fracturing from protections under the Clean Air Act, Clean Water Act, Safe Drinking Water
Act, and Comprehensive Environmental Response, Compensation, and Liability Act. The Act exempts
companies drilling for natural gas from any requirement to disclose the chemicals involved in fracking
operations, normally required under federal clean water laws. The proposed Fracturing Responsibility
and Awareness of Chemicals Act would repeal these exemptions.
2011 Tough pollution limits (Cross State Air Pollution Rule) and limits on mercury, sulfur oxides (SOx
), and
nitrogen oxides (NOx
) emissions (National Emissions Standards for Hazardous Air Pollutants) begin to
drive older inefficient coal plants out of the market.
2011 A proposed Federal Clean Energy Standard credits natural gas relative to a coal reference power plant.
2012 New Source Performance Standard for CO2
is proposed by EPA.

Appendix B: Power Plant Technologies
Steam Turbines
A common method of generating electricity is with steam
turbines (Figure B-1). A power plant uses a combustible
fuel—coal, oil, natural gas, wood waste—or nuclear
fission to heat water in a boiler, which creates steam. The
high-temperature, high-pressure steam is piped toward
turbine blades, which move and rotate the attached
turbine shaft, spinning a generator, where magnets
within wire coils produce electricity.92
Steam units have
a relatively low efficiency. Only about 33 to 35 percent
of the thermal energy used to generate the steam is
converted into electrical energy, and the remaining
heat is left to dissipate. Baseload electricity generation
commonly relies on large coal- and nuclear-powered
steam units on the order of 500 to 1000 MW or greater,
as they can supply low-cost electricity nearly continuously.
Combustion Turbine
Combustion turbines are another widespread tech-
nology for centralized power generation (Figure B-2).
In a combustion turbine, compressed air is ignited
by burning fuel (e.g., diesel, natural gas, propane,
kerosene, or biogas) in a combustion chamber. The
resulting high-temperature, high-velocity gas flow is
directed at turbine blades, which spin a turbine driving
the air compressor and the electric power generator.
Combustion turbine plants are typically operated to
meet peak load demand, as they can be switched on
relatively quickly. Another advantage is their ability to be
a firm backup to intermittent wind and solar power on
the grid, if needed. The typical size is 100 to 400 MW,
and their thermal efficiency is slightly higher than steam
turbines at around 35 to 40 percent.
Combined Cycle
A basic combined-cycle power plant combines a combus-
tion turbine and a steam turbine in one facility (although
there are other possible configurations) (Figure B-3).
Combined-cycle plants waste considerably less heat
than does either turbine alone. As combustion turbines
became more advanced in the 1950s, they began to
operate at ever-higher temperatures, which created
increasing amounts of exhaust heat.93
In a combined-
cycle power plant, this waste heat is captured and used
to boil water for a steam turbine generator, thereby
creating additional generation capacity from the same
amount of fuel. Combined-cycle plants have thermal
efficiencies in the range of 50 to 60 percent. Historically,
Ash collection
Coal
Boiler Precipitator
Scrubber
Stack
Turbine
Generator
Transformer
Pulverizer
Air fan
Electricity
Cool water source
Pump
Steam lines
Condenser
Figure B-1: Steam Turbine

Generator
Transformer
Electricity
Air intake
Compressor
Combustionchambers
Natural gas
Oil
Heat exhaust
Turbine
Water
Cool water source
Generator
Transformer
Steam turbine
Generator
Transformer
Natural gas or oil
Pump
Condenser
Electricity
Heat exhaust
Electricity Heat recovery steam generator
Condensed water
Steam line
Air intake
Turbine
Figure B-2: Combustion Turbine
Figure B-3: Combined-Cycle Power Plant
they have been used as intermediate power plants,
supporting higher daytime loads; however, newer plants
are providing baseload support. Cutting edge natural
gas combined-cycle power plants are coming online with
thermal efficiencies at 61 percent with a correspondingly
smaller emission of greenhouse gases; these plants are
able to cycle on and off more frequently (than most
of the installed power plant fleet) to more efficiently
complement intermittent renewable generation.94

V. Buildings Sector
By Fred Beach, The University of Texas at Austin
Introduction
In 2009, the U.S. buildings sector accounted for about
41 percent of primary energy consumption.95
Energy was
delivered to more than 113 million residences and 4.8
million commercial and institutional buildings by four
primary means: electricity, natural gas, district heat, and
fuel oil. In both residential and commercial building
sectors, natural gas and electricity have been the domi-
nant fuel sources over the last 30 years. In the residential
sector the proportion of electricity used has grown
rapidly compared to other energy sources, largely driven
by the proliferation of home electronics (Figure 1). In
2003 in the commercial sector, electricity and natural gas
accounted for 87 percent of all energy used (Figure 2).96
In 2011, residential and commercial buildings accounted
for 34 percent of greenhouse gas emissions in the United
States. Among fuels typically used in residential and
commercial buildings, electricity usage accounted for
74 percent of carbon dioxide (CO2
) emissions from
fossil fuel combustion, which accounts for the majority
of greenhouse gas emissions from the buildings sector.
Natural gas and other fuel combustion accounted for the
remaining 26 percent.97
The fuel mix in the buildings sector heavily influences
its greenhouse gas emissions. Natural gas consumed
on site has relatively low emissions compared with the
average emissions associated with liquefied petroleum gas
(propane), fuel oil, or electricity. Electricity in particular
typically has emissions far above those of natural gas. In
2011, more than 40 percent of U.S. electricity produc-
tion came from coal-fired power plants, which create
more CO2
per unit of energy delivered than natural gas,
Figure 1: U.S. Residential Energy
Consumption On-Site During 1980 and 2005,
by Source
Source: Energy Information Administration, “Residential Energy Consumption
Survey 2005, Table US3,” 2005. Available at: http://www.eia.gov/consumption/
residential/data/2005/ce/summary/pdf/tableus3.pdf
0%
10%
20%
30%
40%
50%
60%
PropaneFuel Oil
and
Kerosene
ElectricityNatural Gas
2005
1980
Figure 2: U.S. Commercial Energy
Consumption by Source, 2003
Source: Energy Information Administration, “Overview of Commercial Build-
ings, 2003,” 2003. Available at: http://www.eia.gov/emeu/cbecs/cbecs2003/
overview1.html
Fuel Oil
3%
District Heat
10%
Natural Gas
32%
Electricity
55%

propane, and fuel oil used on site.98
Coal-fired electricity
also produces sulfur dioxide (SO2
), nitrogen oxides
(NOX
), and mercury, which are associated with environ-
mental damage and harmful health effects.
Because of the significant amounts of primary energy
and greenhouse gas emissions associated with electricity
generation and consumption, and the relatively higher
greenhouse gas emissions footprint associated with
fuel oil, switching from inefficient electricity or fuel
oil to high-efficiency natural gas in buildings can yield
significant emission reductions. This chapter provides
an overview of energy consumption in residential and
commercial buildings, which is driven by climate zone,
business needs and activities, building size, and, in large
part, consumer behavior. It explains why consideration of
primary and “source-to-site” energy, a measure of energy
consumption that occurs prior to consumer energy
use on site, contributes to a more complete picture of
energy consumed and emissions emitted. Accordingly,
this chapter makes use of the concept of full-fuel-cycle
efficiency, which is the appropriate energy and efficiency
metric with which to compare consumer fuel choices and
consequences for greenhouse gas emissions. It demon-
strates how using natural gas appliances could lead to
dramatic reductions in fuel consumption and green-
house gas emissions. Finally, the chapter looks at how
policy support, including efficiency programs, consumer
information, and innovative funding models, can help
to overcome the barriers to increased natural gas access
and utilization in the buildings sector.
Energy Use in Residential and
Commercial Buildings
There are strong regional variations in the types of
energy available to and used in buildings. A significant
factor affecting energy use is where a building is located.
Homes in colder climates tend to consume more energy,
driven by heating (often called thermal) requirements.
Nationally, 61 percent of residential energy is used for
space heating and water heating (41 percent and 20
percent, respectively), while air conditioning (space
cooling) consumes only 8 percent. Overall, thermal uses
are dominant in all regions of the country (Figure 3). In
the commercial sector as well, the dominant energy uses
are thermal loads (space and water heating), followed by
lighting (Figure 4).
Energy Use in Commercial Buildings
Energy use among U.S. commercial buildings is quite
diverse. Among commercial buildings, significant
variation exists in the purpose and size of buildings,
energy use, and emission profiles. Office space is the
largest energy consumer, consuming 719 trillion Btu of
electricity on site. Educational facilities are the second
largest commercial consumer, using 371 trillion Btu of
electricity on site. These two types of commercial build-
ings account for 36 percent of all the electricity used in
buildings. Because they rely on relatively inefficient grid-
delivered electricity rather than on-site generation (see
below), they also have the highest emissions profiles.99
Commercial buildings vary in terms of energy
intensity, measured in Btu consumption per square
foot. The three most energy-intensive building sectors
are food service, food sales, and health care, which
use 258, 200 and 188 Btu per square foot per year,
respectively.100
While 84 percent of food service square
footage is served by natural gas, only 60 percent of food
sales square footage uses this fuel. The food service
sector requires a large amount of thermal energy for
cooking and cleaning, while energy use for food sales is
predominantly for refrigeration. Thermal demands for
in-patient healthcare are also heavy, with large amounts
of food preparation, water heating, and cleaning. With
these demands, 95 percent of building stock used for
in-patient health care is served by natural gas, while only
59 percent of outpatient health care facilities use natural
gas where are there are lower thermal loads.101
Building size also plays an important role in energy
consumption and fuel source. Commercial buildings of
more than 100,000 square feet account for only 2 percent
of the total number of buildings, but they account for
more than 34 percent of total floor space and more than
40 percent of total energy use (Figure 5). Clearly, this
segment exhibits a higher concentration of high energy
consumption, while being less fragmented in owner-
ship than smaller buildings. Among large buildings of
over 100,000 square feet, 77 percent use natural gas for
space heating.102, 103
The predominance of natural gas
for heating in the largest of buildings, food service, and
in-patient hospitals can be directly attributed to the
greater overall efficiency and lower cost of natural gas
over electricity for thermal applications such as space
heating, water heating, and cooking.

The types of activities carried out in commercial
buildings also influence the type of energy used. Office
buildings tend to utilize electricity rather than natural
gas because many of their primary loads, such as
lighting, elevators, personal computers, servers, scanners,
and printers, cannot be served by natural gas. Lodging,
health care, and food service, in contrast, can more
easily use natural gas for cooking, hot water, cleaning,
and laundry, and, consequently, they use proportionally
more natural gas than office buildings.
Local climate plays a large role in determining
what type of energy is used, and how. The majority of
commercial (and residential) buildings are located in
colder climate zones (zones 1 to 4), which encompass
much of the country except for the Deep South and the
Southwest. In colder zones, winters are cold enough for
frequent, substantial space heating, and the average
amount of energy needed to heat a building during
the winter, measured in heating degree days, is two to
four times the average amount of energy needed to cool
a building during the summer (measured in cooling
degree days) (Figure 6). Still, space and water heating
account for the greatest energy use in buildings regard-
less of climate zone (Figures 3 and 4).
Figure 3: U.S. Home Energy Consumption By End Use, 2005
Source: Energy Information Administration, “Annual Energy Review 2009,” Table US12. Available at http://www.eia.gov/consumption/residential/
data/2009/#consumption-expenditures
Lighting
and Other
Appliances
19%
Refrigerators
3%
Air
Conditioning
3%
Water
Heating
17%
Space
Heating
58%
Lighting
and Other
Appliances
31%
Refrigerators
6%
Air
Conditioning
17%
Water
Heating
20%
Space
Heating
26%
Lighting
and Other
Appliances
23%
Refrigerators
4%
Air
Conditioning
5%
Water
Heating
18%
Space
Heating
50%
Lighting
and Other
Appliances
31%
Refrigerators
5%
Air
Conditioning
6%
Water
Heating
27%
Space
Heating
31%
Northeast South
Midwest West

Energy Use in Residential Buildings
The prevalence of natural gas access and use in homes
varies across U.S. climate zones, even though natural gas
is a more efficient fuel choice for thermal loads. Natural
gas appliances tend to be underrepresented in use, even
when there is access to the fuel. In the two coldest regions
in the country, natural gas is the preferred fuel for heating
water in 23.7 million homes, while electricity is used in
10.8 million homes. The numbers suggest that nearly all of
the homes using gas for space heating are also using it for
water heating.104
Nationwide, the story is different. Forty
percent of households with natural gas access used electric
appliances for space heating, water heating, or both in
2009, and that number has increased in recent years,
with a four-million-household increase in residences with
natural gas access using electric space heating.105
In warmer climates, natural gas use is less common
than electricity for space heating—12.3 million resi-
dences use natural gas compared with 16.5 million using
electricity.106
However, natural gas and electricity are
equally popular for water heating with an even split at
16 million homes each.107
In these areas, more than 3
million homes had access to natural gas (as indicated by
water heating usage) but did not use it for space heating.
Appliances, such as clothes dryers, ovens, and
cooktops, are available in either electric, natural gas,
propane, or fuel oil models, with electric and natural
Figure 4: U.S. Commercial Energy Consumption by End Use, 2003
Source: Energy Information Administration, Commercial Buildings Energy Consumption Survey 2009, “Building Characteristics,” Table E1a. Available at: http://
www.eia.gov/emeu/cbecs/cbecs2003/detailed_tables_2003/detailed_tables_2003.html#consumexpen03
Other
16%
Cooking
3%
Lighting
17%
Ventilation
5%
Cooling
4%
Water
Heating
7%
Space
Heating
48%
Other
19%
Cooking
4%
Lighting
24%
Ventilation
8%
Cooling
14%
Water
Heating
8%
Space
Heating
23%
Other
16%
Cooking
2%
Lighting
17%
Ventilation
6%
Cooling
4%
Water
Heating
6%
Space
Heating
49%
Other
21%
Cooking
3%
Lighting
23%
Ventilation
7%
Cooling
8%
Water
Heating
10%
Space
Heating
28%
Northeast South
Midwest West

gas models being the most common by far (Figure 7).
Nationwide, electric dryers outnumber gas models 4 to
1 (71.8 million compared to 17.5 million). For cooking
appliances, whether ovens or cooktops, the ratio is
almost 2 to 1 (68.1 million homes use electricity and
38.4 million use natural gas).108
In theory, the use of
these appliances should be independent of climate zone
variations since they operate within the heated and
cooled space of homes. Yet, natural gas appliances are
significantly underrepresented in all climate zones.109
In the two coldest regions, zones 1 and 2, natural gas
is the dominant space heating fuel, heating 24.8 million
homes in 2005. In contrast, only 5.6 million homes used
electric space heating in the same year (Figure 4).110
Nationally, natural gas is also the chief fuel source for
heating in commercial buildings. In 2003 in colder
climate zones, it provided heat for 69 to 75 percent of all
commercial floor space, but only 47 percent in zone 5,
the warmest region.111
Source-to-Site Efficiency, Site Efficiency,
and Full-Fuel-Cycle Efficiency
Building energy consumption can be measured in terms
of fuel use on site: kilowatts of electricity, cubic feet of gas,
and gallons of propane or fuel oil. This site energy is the
total of all energy consumed at a building as measured
by the electric and natural gas meters as it enters the
building and/or by fuel oil or propane delivery. However,
site energy does not tell the full energy story, because
energy, whatever the source, must be extracted and
delivered to the point of use, incurring losses along the
way that are not reflected in the readings on customers’
meters or delivery bills. As discussed in chapter 4, fossil
fuels, such as coal or natural gas, are most often used to
generate electricity. The term “source-to-site” generally
refers to the total energy consumed in the course of
extracting, processing, and delivering a unit of energy to
a building, and in the case of electricity, energy associated
with generation, transmission, and distribution. In other
Figure 5: Number of Non-Mall Commercial Buildings, Floor Space and Consumption by Size, 2003
Source: Energy Information Administration, “Natural Gas Consumption and Conditional Energy Intensity by Building Size for All Buildings, 2003” Table C31. Avail-
able at: http://www.eia.gov/consumption/commercial/data/archive/cbecs/cbecs2003/detailed_tables_2003/2003set16/2003html/c31a.html
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Total Consumption
(trillion BTU)
Total Floorspace
(million square feet)
Total Buildings
(thousand)
 Over 500,000 square feet 8 5,908 906
 200,001 to 500,000 square feet 26 7,176 751
 100,001 to 200,000 square feet 74 9,064 1,064
 50,001 to 100,000 square feet 147 9,057 913
 25,001 to 50,000 square feet 261 8,668 742
 10,001 to 25,000 square feet 810 11,535 899
 5,001 to 10,000 square feet 948 6,585 563
 1,001 to 5,000 square feet 2,586 6,789 685

words, source-to-site efficiency is the energy required—
accounting for losses—to bring usable energy to the
consumer. Source-to-site efficiency varies widely by fuel.
Often, direct fuel consumption has much higher source-
to-site efficiencies compared with electricity, where energy
is lost in the conversion and transmission of primary fuels
to electrical energy. To assess the efficiency of total energy
use, the source-to-site efficiency must be multiplied by the
efficiency of the end-use appliances and equipment—the
site efficiency. Combining source-to-site efficiency and site
efficiency leads to the third—important and often over-
looked—measure of efficiency, full-fuel-cycle efficiency.
Source-to-Site Efficiency
Electricity generation has the lowest source-to-site
efficiency of all energy types. Centralized electricity
generation and distribution through power lines is on
average 32 percent efficient in the United States. The
process of generating electricity incurs substantial losses,
such that for every unit of electricity registered at a build-
ing’s meter, three times the amount of primary energy
was required to generate and distribute it. The majority
of energy losses occur at the power plant, especially
at cooling towers that emit waste heat into the atmo-
sphere in the form of steam. The Western Electricity
Figure 6: U.S. Climate Zones, Heating Degree Days vs. Cooling Degree Days
Source: Energy Information Administration, “U.S. Climate Zones,” 2004. Available at http://www.eia.gov/emeu/recs/climate_zone.html
Zone 1 is less than 2,000 CDD and greater than 7,000 HDD
Zone 2 is less than 2,000 CDD and 5,500–7,000 HDD
Zone 3 is less than 2,000 CDD and 4,000–5,499 HDD
Zone 4 is less than 2,000 CDD and less than 4,000 HDD
Zone 5 is 2,000 CDD or more and less than 4,000 HDD
Climate Zones

Coordinating Council, which covers the western United
States, has the highest efficiency, at 38 percent, primarily
due to its high percentage of hydropower, which has
a higher conversion efficiency than coal- or natural
gas-fired generation. The Midwest Reliability Council
region in the Upper Midwest has the lowest efficiency,
at 28 percent, due to a large percentage of coal plants
using older, less efficient technology.112
Transmission and
distribution over power lines results in additional losses
and reduces the source-to-site efficiency even further,
by roughly an additional 7 percent, with longer lines
experiencing greater losses. In total, up to two-thirds
of the fuel that is burned for electricity production is
wasted. In addition to providing no useful work in the
economy, it releases significant greenhouse gas emissions
in the process.
The production and distribution of natural gas, fuel
oil, and propane also have inefficiencies. These fuels
must be extracted from the ground, processed or refined
to remove impurities and other liquids and gases, and
finally transported to the building. During each of these
steps, energy is used and a small amount of energy is
lost but, in total, these losses are considerably less than
the losses associated with electricity production and
distribution. The source-to-site efficiency of natural gas
is approximately 92 percent, around three times higher
Figure 7: Appliance Fuel Sources by Number of Units in U.S. Homes, 2009
Source: Energy Information Administration, “Residential Energy Consumption Survey 2009,” Table HC3.1, Available at: http://www.eia.gov/consumption/
residential/data/2009/
Propane
5%
Natural Gas
34%
Electric
61%
Propane
1%
Natural Gas
19% Electric
80%
Other
6%
Fuel Oil
6%
Propane
5%
Natural Gas
49%
Electric
34%
Fuel Oil
3%Propane
4%
Natural Gas
52%
Electric
41%
Ovens and Cooktops Space Heating
Clothes Drying Water Heating

than the source-to-site efficiency of centrally generated
electricity.113
Other fuels commonly consumed onsite in
residential buildings, fuel oil and propane, are also much
more efficient than electricity. The average source-to-site
efficiency of fuel oil is about 88 percent, and of propane,
about 89 percent.114
Considering the source-to-site efficiency of different
fuels offers a more accurate comparison of the fuel
used in buildings. For example, in 2008, the total site
consumption by residential and commercial buildings
was 9.37 quadrillion Btu for electricity and 8.28 quadril-
lion Btu for natural gas. However, the amounts of
primary energy consumed differed dramatically between
electricity and natural gas, because of their different
source-to-site efficiencies (compare Figures 8 and 9).
About three times as much primary energy is used to
generate and transmit electricity than is ultimately
consumed onsite in buildings.
The relative efficiencies of on-site fuel use and
grid-supplied electricity have major consequences for
the greenhouse gas emissions associated with the U.S.
building stock. Only accounting for site energy consump-
tion misses energy losses and resulting greenhouse
gas emissions associated with energy production and
delivery. These losses account for a significant portion
of total greenhouse gas emissions from the residential
and commercial sector and should be accounted
for when comparing fuel options. The use of grid-
supplied electricity is growing, while direct natural gas
consumption by residential and commercial buildings
remains relatively flat. Increasing the amount of natural
gas instead of electricity used in buildings would require
fewer resources to provide the same amount of on-site
energy and would lower the greenhouse gas emissions
per unit of useful energy consumed.
Site Efficiency and Full-Fuel-Cycle Efficiency
Once energy is delivered to a building, it is used in an
appliance or piece of equipment that has its own distinct
efficiency level. Taken together, the source-to-site efficiency
of the fuel delivered and the site efficiency of its use give a
more complete picture of the total efficiency of consumer
fuel and appliance choice and the resulting emissions.
Source-to-site efficiency considered along with site effi-
ciency yields an appliance’s full-fuel-cycle efficiency.
To find the full-fuel-cycle efficiency of an appliance
or piece of equipment, the efficiency of the source-to-site
energy is multiplied by the efficiency of the appliance and
associated equipment. For example, energy efficiency stan-
dards established in 2012 by the Department of Energy
(DOE) for water heaters with storage tanks are 93 percent
for electric-resistance units and 62 percent for natural gas
models.115
However, when these models’ respective source-
to-site efficiency is factored in, their full-fuel-cycle efficien-
cies are 30 percent for the electric model and 75 percent
for the natural gas model. Therefore, despite the higher
site efficiency rating of the electric-resistance water heater,
it requires the use of significantly more primary energy
Figure 8: Residential Site Energy Consumption, 1950 to 2010
Source: Energy Information Administration, “Today in Energy,” March 6, 2013. Available at: http://www.eia.gov/todayinenergy/detail.cfm?id=10251
0
2
4
6
8
10
12
14
16
2010200019901980197019601950
QuadrillionBTU
Site Energy Consumption
Petroleum
Electricity
Natural Gas

and leads to the emission of more greenhouse gases than
does the natural gas appliance for the same level of output
in the building. Consequently, electric-resistance water
heaters consume roughly twice the primary energy of the
natural gas models.
Source efficiencies and site efficiencies can vary even
further. Minimum efficiency standards for appliances
promulgated by DOE are continuing to push the site
efficiency ratings of new appliances higher. While this
discussion compares widely used electric and natural
gas water heaters, newer technologies such as electric
heat-pump water heaters are also available that are two to
three times more efficient than the conventional electric-
resistance models analyzed here,116
and solar water heating
technologies offer high full-fuel-cycle efficiencies and
can be a cost-effective option.117
Furthermore, the source
efficiencies and associated greenhouse gas emissions vary,
because of the regional differences in source efficiency of
power generation. It is clear that, despite geographic varia-
tion, a natural gas water heater yields significant energy
savings compared with an electric-resistance water heater
in every North American Electric Reliability Corporation
Region in the country (Figure 10).118
Emissions Comparison: Natural Gas Versus
Other Direct Fuels
In addition to the energy savings delivered by the higher
full-fuel-cycle efficiency of appliances using natural gas,
there is also a large difference in greenhouse gas emissions.
Residential energy use has been a growing contributor
to CO2
emissions for the last two decades, and the trend
is expected to continue (Figure 11).119
The negative
consequences in terms of emissions of this upward trend in
electricity use are exacerbated by the low average efficiency
of grid electricity and the high average carbon fuel intensity
of the U.S. electricity generation portfolio. Furthermore,
given the high level of coal use in U.S. electricity produc-
tion, increased electricity use leads to significant increases
in sulfur dioxide, nitrogen oxides, and mercury emissions,
where pollution controls are not in place.
Greenhouse gas emissions can be reduced by switching
from lower-efficiency fuels and appliances such as an elec-
tric-resistance water heater to higher efficiency fuels and
appliances such as a natural gas water heater. However,
the reductions will vary by region. The relative percentage
reductions of greenhouse gas emissions by switching
appliances or fuels is a combination of the full-fuel-
cycle efficiency of the appliances and the CO2
-emission
intensity of the electricity generation portfolio in a given
region. The varied carbon intensities of electric genera-
tion in each North American Reliability Council (NERC)
region offer different relative benefits from switching an
electric-resistance water heater to a natural gas model
(Figure 12). The relative benefits are most clearly demon-
strated in the following examples. In the NERC region
overseen by the Northeast Power Coordinating Council
in the northeast United States and Eastern Canada,
where a large percentage of the electricity comes from
Figure 9: Residential Primary Energy Consumption, 1950 to 2010
0
2
4
6
8
10
12
14
16
2010200019901980197019601950
QuadrillionBtu
Petroleum
Electricity
Natural Gas
Source Energy Consumption (Includes Losses)

less carbon-intensive hydroelectric and nuclear power,
switching from an electric to natural gas water heater
results in CO2
reductions of 30 percent. By contrast, the
same switch results in emissions reductions of 70 percent
in the Midwest Reliability Organization region in the
Midwest where substantial amounts of older coal-fired
power generation contributes to a significantly more
carbon-intensive electric generation mix.
Figure 10: Consumption of Source Energy by Water Heaters by North American Electric
Reliability Corporation Region, 2005
Source: Gas Technology Institute, “Source Energy and Emission Factors for Building Energy Consumption” 2009, Tech. rep., Natural Gas Codes and Standards
Research Consortium, American Gas Foundation. Available at: http://www.aga.org/SiteCollectionDocuments/KnowledgeCenter/OpsEng/CodesStandards/
0008ENERGYEMISSIONFACTORSRESCONSUMPTION.pdf
SourceEnergy,MMBtu
PercentReductionvs.ElectricWaterHeater
TRE WECC U.S.
AVERAGE
SPPSERCRFCNPCCMROHICCFRCCASCC
0
10
20
30
40
60
50
0%
10%
20%
30%
40%
60%
50%
Electric Water Heater Source MBtu
Gas Water Heater Source MBtu
Percent Reduction vs. Electric Water Heater
Figure 11: Residential CO2
Emissions from Energy Consumption, 1950 to 2010
0
200
400
600
800
1,000
2010200019901980197019601950
MillionMetricTonsofCO2
Petroleum
Electricity
Natural Gas

An average U.S. home using natural gas for space
heating, water heating, cooking, and clothes drying is
responsible for substantially fewer greenhouse gas emis-
sions than homes using other fuel sources (Figure 13).
In this example, natural gas use produces an average of
44 percent fewer emissions than electricity use.120
Such
a difference in energy use and CO2
emissions is true
for all energy uses in buildings where natural gas is an
alternative to grid electricity as well as the direct use of
propane and fuel oil. The two main factors determining
the efficiency and emissions benefits from appliance to
appliance are the full-fuel-cycle efficiency of the appli-
ance and the emission-intensity of the primary fuel.
Emissions associated with natural gas use compared
with electricity are lower for CO2
and some pollutants.
Considering the lower emissions of natural gas and its
higher full-fuel-cycle efficiency, residential natural gas
use results in 40 to 65 percent lower emissions of CO2
,
90 to 98 percent lower emissions of SO2
, and 50 to 88
percent lower emissions of NOX
. Residential natural gas
use is free of any mercury emissions.121
Figure 12: CO2
Emissions from Water Heaters by North American Electric Reliability
Corporation Region, 2005
Source: Gas Technology Institute, “Source Energy and Emission Factors for Building Energy Consumption” 2009, Tech. rep., Natural Gas Codes and Standards
Research Consortium, American Gas Foundation. Available at: http://www.aga.org/SiteCollectionDocuments/KnowledgeCenter/OpsEng/CodesStandards/
0008ENERGYEMISSIONFACTORSRESCONSUMPTION.pdf
CO2
Emission,1000lb.
PercentReductionvs.ElectricWaterHeater
TRE WECC U.S.
AVERAGE
SPPSERCRFCNPCCMROHICCFRCCASCC
0
2
1
4
3
6
5
8
7
10
9
0%
20%
10%
40%
30%
60%
50%
80%
70%
100%
90%
Electric Water Heater CO2
Gas Water Heater CO2
Percent Reduction vs. Electric Water Heater
Figure 13: Full-Fuel-Cycle Greenhouse Gas
Emissions for Average New Homes
Source: Source: American Gas Association, “A Comparison of Energy Use,
Operating Costs, and CO2
Emissions of Home Appliances,” October 20, 2009.
Available at: http://www.aga.org/Kc/analyses-and-statistics/studies/demand/
Pages/Comparison-Energy-Use-Operating-Costs-Carbon-Dioxide-Emissions-
Home-Appliances.aspx
Note: Assumes fuel used for space heating, water heating, cooking, and
clothes drying. All appliances are assumed to meet federal minimum efficiency
standards. The fuel oil home assumes electricity is used for cooking and clothes
drying. The new home assumes a one-story single-family detached home with
2,072 square feet of conditioned space and 4,811 heating degree days.
0
2
4
6
8
10
12
HotelsNatural
Gas
PropaneFuel
Oil
Electricity
(based on 2007
generating mix)
MetrictonsofCO2
eper
AverageHouseholdEnergyUse
Fuel Source

Reducing Emissions Through Fuel Substitution
and On-Site Energy Production
Natural gas can provide a means to increase a building’s
total full-fuel-cycle efficiency and decrease its emissions
profile in many cases. This improvement is most readily
achieved in thermal applications, such as natural gas
space heating and water heating. While buildings with
older natural gas- or oil-fired boilers and furnaces can
improve their efficiency and lower their emissions by
upgrading to newer models, greater emission reductions
may be achieved by removing electric appliances and
replacing them with models using natural gas. While
natural gas appliances have a comparable or slightly
lower site efficiency than electric-resistance appliances,
natural gas is often, on a full-fuel-cycle basis, two to
three times more efficient than electricity.122
Significantly greater benefits can be realized when
grid power is replaced by power produced on site.
Combined heat and power (CHP) systems provide
a means for buildings with high electrical demand
to increase their efficiency and reduce emissions. A
CHP system uses a fuel such as natural gas to generate
electricity on site, capturing waste heat to meet on-site
thermal loads (Table 1). (For a more extensive treatment
of CHP see chapter 6.) Fuel cells and micro-turbine
technologies provide another means for buildings to
generate their own electrical power on site using natural
gas. The waste heat generated by these devices can then
be used for space heating, water heating, and other
thermal loads to raise the overall full-fuel-cycle efficiency
of these devices to greater than 80 percent.123
(These
technologies and others are explained in chapter 7.)
The potential for CHP in commercial settings may
be quite large, with office buildings/retail, education
buildings, and hospitals having the greatest potential
(Figure 14). However, practical limits on thermal load
matching and the utilization of waste heat may affect
the potential of different building types. Hospitals are
an ideal application, but hotels and other commercial
buildings may be more difficult—though not impos-
sible. The use of CHP microturbines has gained
acceptance primarily in in-patient hospitals, hotels,
and resorts. These facilities have large electrical loads
and nearly as high thermal loads, for space heating,
water heating, cooking, and laundry. These large and
year-round thermal loads (in the case of all but space
heating) provide a ready use for the waste thermal
energy provided by the microturbine, allowing them
to operate at near peak efficiency not only around the
clock but 365 days per year. Nevertheless, there are many
challenges to commercial CHP operations. To expand
commercial CHP potential, policy is needed to support
advanced technologies and innovative business models
in this arena.
Table 1: Technology Comparisons
Category
10 MW
Natural Gas CHP
10 MW
Photovoltaic
Array
10 MW Wind
Farm
Centralized
Natural Gas
Combined Cycle
Power Plant
(10 MW Portion)
Annual Capacity Factor 85% 25% 34% 67%
Annual Electricity 74,446 MWh 21,900 MWh 29,784 MWh 58,692 MWh
Annual Useful Heat 103,417 MWht 0 0 0
Capital Cost $24 million $60.5 million $24.4 million $10 million
Annual Energy Savings 343,747 MMBtu 225,640 MMBtu 306,871 MMBtu 156,708 MMBtu
Annual CO2 Savings 44,114 Tons 20,254 Tons 27,546 Tons 27,023 Tons
Source: ICF International 2012
Notes: A 10 MW Gas Turbine CHP –is assumed to have 30 percent electric efficiency and 70 percent total efficiency.
Electricity generation onsite is assumed to displace grid-supplied electricity generation of 9,720 Btu/kWh, with emissions of 1,745 lbs. CO2
/MWh; includes
assumed 6 percent transmission and distribution losses.
Thermal generation on-site is assumed to displace an 80 percent efficient onsite natural gas boiler.

Technological advances in gas-fired equipment are
also needed. More affordable tank-less water heaters
and combination space and water heating appliances
can help reduce the market barriers to natural gas.
Demonstration and deployment of such technologies can
help natural gas utilities design the next generation of
gas efficiency programs, provide whole-building solu-
tions, and make natural gas service more attractive to
customers and builders.
The Role of Efficiency Programs
and Standards
Current efficiency programs and federal efficiency
codes and standards reduce greenhouse gas emissions
from buildings in two important ways: by reducing
the overall amount of energy used in buildings and by
improving the baseline efficiency of specific appliances,
equipment, and building stock. A third strategy could
be to encourage the use of certain fuels, taking into
account the total energy consumption of an appliance,
the fuel used (full-fuel-cycle efficiency), and the associ-
ated greenhouse gas emissions. Historically, efficiency
programs and standards have not considered full-fuel-
cycle efficiency or the emissions reductions that could
be achieved comparing across fuel types, although this is
beginning to change, as in the case of appliance labeling
described later in this chapter.
Conservation
At the broadest level, increasing the overall efficiency of
new and existing buildings reduces the amount of fuel
used of any type and is therefore beneficial. Energy effi-
ciency minimizes energy use, and thus lowers greenhouse
gas emissions. The United States has made remarkable
progress in this regard. Energy use in buildings between
1972 and 2005 increased at less than half the rate of
growth of gross domestic product, despite the growth in
home size and the increased demand for energy from air
conditioning and electronic equipment. But although
great strides have been made, numerous untapped
opportunities exist for further reductions in energy use
and greenhouse gas emissions. Many of these require
only modest levels of investment. Advances such as
energy-efficient building designs and appliances provide
quick payback to consumers through reduced energy
bills. For example, new wall designs can minimize heat
loss in buildings by as much as 50 percent by reducing
the amount of framing used and by optimizing the use of
insulated materials. The result is a diminished need for
space heating—the largest energy use in a home.124
State and Local Building Codes
Building codes for new construction can improve the
efficiency of buildings by ensuring that new technolo-
gies and methods are used that will reduce a building’s
energy use. Although new buildings constitute only 2
to 3 percent of the existing building stock in any given
year, new construction practices have a compounding
impact over time.125
New construction can more easily
incorporate novel energy efficiency technologies and
is therefore often a harbinger of future trends. New
building technologies are often introduced in the new
construction market and then spill over into the arena of
retrofits and renovation. Building codes can even affect
a building’s fuel options, for example, by encouraging or
discouraging natural gas access by facilitating or slowing
the approval of new, easier-to-install and less expensive
indoor natural gas piping materials.126.
Low adoption rates for building codes are a barrier to
the development of higher efficiency and lower emis-
sions buildings. For example, in 1992 the commercial
building code requirements of the Federal Energy Policy
Act, which were based on 1989 industry standards, were
met by only five states. By 2008, 40 states had statewide
commercial building codes that met or exceeded the
1989 federal standards, but only 27 met the higher
Figure 14: CHP Potential for Systems
Greater than 1 MW to 33 GW, Percent of
Potential Capacity
Source: ICF International 2012
Other
7%Multi-Family
Housing
4%
Hotels
6%
Government
8%
Prisons
8%
Hospitals
13%
Colleges
15%
Office/Retail
39%

standards issued by DOE in 2004. This lead/lag effect
in the setting and meeting of standards is indicative of
a non-owner-operated building market that still places
operating costs at a lower priority than construction
costs. However, federal requirements are not the only
drivers. California, for example, has set standards higher
than those of the federal government, and some utilities,
such as Austin Energy in central Texas, have worked with
city governments to push standards and building codes
beyond the industry norm.
Traditionally, building codes have been designed to
look at the overall on-site energy usage of buildings.
Accordingly, they are typically fuel-neutral, favoring
neither natural gas nor electric appliances. As a result,
building codes do little to take into consideration the
full-fuel-cycle climate impacts of electricity versus natural
gas and other fuels. Likewise, Leadership in Energy and
Environmental Design (LEED) standards fail to take
into account the relative full-fuel-cycle efficiencies of
electricity, natural gas, and other fuels. LEED standards,
developed by the U.S. Green Building Council, have
been adopted by many municipalities, school districts,
counties, and states for their new buildings, leading to
an exponential growth in the number of LEED-certified
buildings.127
However, the U.S. Green Building Council
is investigating ways to take these benefits into account,
with particular focus on performance standards and
nationwide applicability.
Appliance Standards
DOE is required by law to set minimum efficiency
standards for appliances, and currently has standards
that cover appliances and equipment responsible for 82
percent of home energy use and 67 percent of commer-
cial energy use.128
Appliance standards, first instituted in
the 1980s and repeatedly strengthened since then, have
greatly contributed to reducing appliance energy use and
associated greenhouse gas emissions. However, appli-
ance standards are based on the site efficiency of the
appliance and do not consider the efficiency of the fuel.
While this works well to encourage improved efficiency
for each type of appliance, it does have implications for
efficiency labeling programs and the ability of consumers
to compare the true environmental performance of
appliances using differing energy sources.
Appliance Labeling
Labeling programs such as ENERGY STAR strive to
inform consumers about the energy consumption
and energy cost implications associated with use of
each appliance. ENERGY STAR uses a market-based
approach having four parts: 1) using the ENERGY STAR
label to clearly identify which products, practices, new
homes, and buildings are the most energy efficient;
2) empowering decision-makers by making them aware
of the benefits of products, homes, and buildings that
qualify for ENERGY STAR, and by providing tools to
assess energy performance and guidelines for efficiency
improvements; 3) helping retail and service companies
to easily offer energy-efficient products and services;
and 4) partnering with other energy efficiency programs
to leverage national resources and maximize impacts.
The Environmental Protection Agency (EPA) estimates
that in 2012 the ENERGY STAR program helped avoid
more than 150 million tons of greenhouse gas emissions
through encouraging the purchase of efficient products,
with the amount of avoided greenhouse gas emissions
increasing annually.129
While appliance labeling efforts like ENERGY STAR
have educated consumers about the annual operating
costs and site efficiency of appliances, current labels
do not accurately or sufficiently connect consumers’
economic interests with the environmental impacts of
appliance use. Specifically, current labels do not inform
consumers of the full-fuel-cycle efficiency of appliance
models because the efficiency calculations are based on
the appliance standards program, which again is based
on site efficiency. As a result, consumers cannot compare
the true quantity of energy required by each appliances
or the true climate implications associated with using
that appliance.
In 2009, the National Research Council released a
report that recommended the gradual conversion of
current labeling efforts to ones that would take full-
fuel-cycle efficiencies into consideration. Full-fuel-cycle
labeling will certainly be more challenging because it will
require more data and analysis from appliance manu-
facturers, and the efficiency of an appliance will vary
by geographical location because of different regional
climates and power generation fuel mixes. However, as
discussed earlier in this chapter, such information is
essential to understanding the total amount of energy

required to operate an appliance and the associated
greenhouse gas emissions and will better equip consumers
to make more informed choices when evaluating their
appliance options.130
In June 2011, DOE took the first
steps toward a more regionalized labeling program with
standards for furnaces and central air conditioning units
that had a variable regional component.131
In addition, in
August 2012, DOE issued a policy amendment stating that
it would begin consideration of full-fuel-cycle efficiency in
setting future appliance standards and would work with
the Federal Trade Commission to educate consumers
about the full fuel cycle.132
While no appliance standards based on the full fuel
cycle have yet been issued, if the success of current appli-
ance standards and related labeling are any indication,
moving to standards and labels based on full-fuel-cycle
efficiency could move consumers to purchase appliances
that use significantly less energy and provide a significant
benefit to the climate.
ENERGY STAR for Buildings
In addition to having labels for appliances, EPA’s
ENERGY STAR program also assesses the efficiency of
buildings and provides labels that allow comparison
of energy usage across buildings. To be an ENERGY
STAR-certified building, a variety of energy performance
standards must be met and these differ by facility type.
EPA provides tools to assess energy systems and manage-
ment, building design, and a host of energy-related
benchmarks to help building owners, architects, and
even prospective tenants assess and make public the
energy and cost implications of a building. In contrast to
the appliance program, the ENERGY STAR program for
commercial buildings does use primary or full-fuel-cycle
efficiency to compare energy usage across building types.
Utility-Based Incentive Programs
Utility-based financial incentive programs have been
used since the early 1980s, when it became clear that
information and education alone produced only limited
energy and demand savings. Utilities have offered rebates,
low-interest loans, and direct installation programs, and
these have led to the accelerated market penetration of
many energy-efficient building products such as attic
insulation and high-efficiency appliances. However,
these programs represent only a partial solution because
not all states or all utilities offer such programs. More
importantly, these incentives are based on site efficiency
and are fuel-specific—since buildings are often served by
separate electric and natural gas utilities, meaning that
while incentive programs can encourage the efficient site
use of a fuel, they do not allow consumers to compare
fuel options based full-fuel-cycle efficiency. Thus, most
utility-based incentive programs miss an opportunity to
help consumers further reduce emissions.
Barriers to Increased Natural Gas Access
and Utilization
The emissions benefits of natural gas use in homes and
businesses will require greater access to the fuel for and
within buildings. In 2005, 71 percent of U.S. homes had
access to natural gas, and yet only 61 percent of U.S. homes
made use of natural gas in an appliance. In addition, only
54 percent of new homes constructed in 2010 had natural
gas service installed, and this access was primarily for
heating and not necessarily for other natural gas appli-
ances.133
Similarly, in commercial buildings approximately
half had natural gas access in 2003 (49 percent) and, as
with homes, the use was primarily for heating.134
Annual consumption of natural gas in the residential
sector has been declining since 1996 in spite of a growing
residential customer base (Figure 15). Analysis by the
Energy Information Administration suggests that the
cause of this decrease is a combination of historically
high natural gas prices from 2000 to 2009, which
Figure 15: Residential Natural Gas
Consumption, 1990 to 2009
Source: Energy Information Administration, “Trends in U.S. Residential Natural
Gas Consumption,” 2010. Available at: http://www.eia.gov/pub/oil_gas/
natural_gas/feature_articles/2010/ngtrendsresidcon/ngtrendsresidcon.pdf
0
4.5
5.0
5.5
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
Consumption(TrillionCubicFeet)

discouraged consumers from buying natural gas model
appliances, a general migration of Americans to warmer
climate zones with lower thermal loads, and an increase
in home construction standards and appliance efficiency
that reduced the amount of fuel consumed for the
same purposes.135
Barriers to the Use of Natural Gas in Homes
The United States has, as a policy, pursued universal
residential access to electricity for decades. Through
taxpayer-funded rural electrification programs and
customer-funded electric utility grid extension programs,
the United States has achieved greater than 99.5 percent
residential access to public or private electricity.136
The
same policy has not been implemented for natural gas.
When municipalities approve planning and develop-
ment for new buildings, electric utility access is almost
universally required through developer or utility
funding, or a combination of the two. In contrast,
running natural gas lines in new developments is often
viewed as merely an option, and, as such, only 54 percent
of new homes have natural gas access. In many cases, the
decision is determined by financial analysis conducted
by a local gas distribution company, or the combination
local electric and gas utility, based on narrow first-cost
criteria with little concern for the occupants’ energy
efficiency, operating cost, or greenhouse gas emissions.
Prospective building owners often have little participa-
tion in this decision process. If the decision is made not
to supply natural gas, retrofitted access to and within the
building is significantly more expensive.
Even when natural gas infrastructure has been
included in a new residential development, a homeowner
may still be unable to choose how natural gas will be used
in her home. Often, during architectural design and
construction, the builder decides which appliances will
have natural gas lines run to them, thereby “locking in”
the decision and limiting consumer choice. In cases where
the homeowner enters the process prior to construction,
he may be offered a choice of appliance fuel options, but
choosing natural gas may come at a cost premium for both
the appliance and the cost of running the gas lines. In this
choice, one between higher up-front costs of purchasing
a home with gas appliances, on the one hand, and a lower
long-term cost of operation (subject to gas prices), on the
other, the immediacy of a slightly lower purchase price
for electric appliances may prevail, even as low natural
gas prices may lead to consumer savings in just a few years
when compared to electric models.
Natural gas access, regulation, and price play impor-
tant roles in residential fuel choice. The trend over the
last decade, toward a lower percentage of new homes
using natural gas, will have a long-term effect. Even
though the trend was likely influenced by temporarily
high gas prices, it effectively locks out the option for
these “all electric” homeowners to benefit economically
from what may be several decades of low natural gas
prices as well as to benefit environmentally by lowering
greenhouse gas emissions.
Moving beyond infrastructure constraints, an essen-
tial component shaping residential fuel choice is public
education. For nearly a century, industry and government
have portrayed electricity as a clean and efficient fuel,
and it is—on site at the point of use.137
Perceptions of
natural gas are similarly affected by public opinion and
government policy that focus on the point of use, which
has not received the promotional policy that electricity
has. This point-of-use perception is reinforced by the way
in which most people interact with electricity and natural
gas in their everyday lives: flipping a switch, turning on
a burner, and paying a monthly bill. They rarely see or
understand the generation side of electricity, the power
plant, or the extraction and transportation of natural
gas. Generally, the public has little basis for comparisons
among fuels on issues of health, the environment, and
the economy. Moreover, culture and family history can
be important drivers of consumer choice, as individuals
may be most comfortable with appliance types that they
grew up with. Public education is critical for helping
consumers understand the issues of efficiency and
emissions and how they relate to common life choices,
and to know what questions to ask when purchasing an
appliance, renting an apartment, or buying a home.
Use of Natural Gas in Commercial Buildings
A significant barrier to the increased use of natural gas is
the high percentage of non-owner-occupied commercial
buildings, particularly office and warehouse floor space.
On a floor-space basis, 49 percent of private commercial
buildings are owner-occupied and 51 percent are
non-owner-occupied.138
Non-owner-occupied buildings
are designed and built by real-estate developers who
then rent or lease the space to tenants. The “for lease”
building sector is extremely competitive, and rental cost

per square footage is a key metric in attracting renters.
In addition to paying rent, tenants may also pay utility or
maintenance costs that may increase each year because
of rising operating expenditures. Energy costs are a
meaningful portion of these operating expenditures, but
for billing purposes they are often combined with other
costs, such as labor, water, and snow removal. Therefore,
it can be difficult for tenants to discern specific financial
benefits of energy efficiency upgrades, leaving building
owners without a financial incentive to make such
upgrades. This situation prevents lower operating costs
from being reflected in market rental prices, since only
exceptionally sophisticated tenants consider long-term
gains from efficiency in rental decisions. In new build-
ings, owners’ focus on achieving low rental costs can
drive builders to prioritize construction cost over oper-
ating costs. This approach can preclude the installation
of high-efficiency and lower-emission systems, including
those that use natural gas on site for both electricity
generation and heating applications.139
When energy efficiency upgrades are proposed for
existing, occupied buildings, building owners may have
the opportunity to recover capital outlays according to
the terms of the leases. Most leases allow the installa-
tion of energy savings equipment or systems with cost
recovery through amortization of the improvement over
the life of the equipment installed. However, if a tenant
does not renew her lease, a newly signed tenant cannot
be charged the amortization; therefore, a portion of
the cost of the project cannot be recovered. Since rents
are based largely on market conditions and not by the
operating costs incurred by the building owner, before
owners undertake an energy efficiency project, they must
evaluate what portion of the tenant base might leave
before the project costs are recovered and what enduring
benefits might accrue to the owner.140
Some low-cost energy efficiency upgrades can be
treated as repair costs and added to the operating
expenses within an existing lease. These stand-alone
efficiency projects are very often subsidized with incen-
tives from utilities. Projects of this nature usually have
relatively short payback periods. The tenants see the
benefit of the improvements very quickly, and the owner
can justify the expense to the tenant regardless of
whether the lease is renewed.141
In 2003, 46 percent of commercial buildings were
owner-occupied, meaning they are designed and
constructed for the owner’s own use.142
Compared
to owners of leased buildings, owner-operators are
more inclined to factor in the operating costs of their
buildings because they have a long-term interest in the
building and are concerned less with competitive rental
markets. Therefore, they tend to install more energy-effi-
cient systems and subsystem components as long as these
have a payback period of 10 years or less. The govern-
ment owners of 635,000 public buildings in the United
States in 2003 share this focus on long-term operational
costs and the advantage of higher efficiency systems;
they may also have legal mandates or executive orders to
reduce energy use and/or greenhouse gas emissions.143
Owners constructing new buildings or performing retro-
fits, when faced with longer-term decisions about energy
use and costs, will see expanded natural gas use as an
attractive option, and large numbers of owner-occupied
and government buildings using natural gas instead of
electricity could yield significant emission reductions.
Conclusion
This chapter identified the full-fuel-cycle efficiency
benefits and lower greenhouse gas emissions of the
direct use of natural gas when compared to electricity,
particularly for thermal loads. There is significant
potential for increased direct use of natural gas in homes
and businesses both in terms of increased access to new
buildings and additional applications within buildings
that already have access. In order for this potential to be
fully realized, building standards, appliance standards,
and appliance labels must take full-fuel-cycle energy use
and associated emissions into account, and greater atten-
tion must be given to consumer education, regulatory
changes, and increased access.

VI. Manufacturing Sector
By Michael Tubman, C2ES
Introduction
With prospects for cheap, abundant natural gas in the
near and medium term virtually certain, demand for
natural gas from manufacturing industries is expected
to grow. In 2010, natural gas supplied 30 percent of
the U.S. manufacturing sector’s direct energy use, for
combustion as well as non-combustion uses.144
The
U.S. Energy Information Administration forecasts that
natural gas use in the industrial sector will increase by 16
percent between 2011 and 2025, from 6.8 to 7.8 trillion
cubic feet.145
Recent estimates indicate that $45 billion
in new investment has recently occurred in chemical
manufacturing alone. Lower natural gas prices are likely
to provide a real economic advantage to U.S. manufac-
turing in the near and medium term.
The entire industrial sector (manufacturing and
non-manufacturing industries combined) consumed 32
percent of all natural gas in the United States in 2011.
This energy use emitted 401 million metric tons of
carbon dioxide (CO2
).146
This chapter examines the role
of natural gas in the manufacturing sector today as well
as its likely expansion, given forecasts of low and stable
prices. With a resurgent and changing manufacturing
sector comes the opportunity to reduce these emissions.
This chapter also looks at promising strategies for
reducing emissions include replacing older, less efficient
industrial boilers and expanding the use of combined
heat and power (CHP) systems.
Natural Gas Use in Manufacturing
The manufacturing sector includes diverse industries
such as bulk chemicals, oil refining, and the production
of steel, aluminum, cement, glass, paper, and food. It
does not include the industrial activities of mining,
construction, and oil and gas extraction. Natural gas
usage within these industries varies significantly. It is
used for heating and cooling; for process heat to melt
glass, process food, preheat metals, and dry various
products; and for on-site electricity generation (fueling
boilers and turbines). Natural gas is also used as a
feedstock (a material input) to make chemical products,
fertilizers, plastics, and other materials.147
Overall, the largest direct use of energy by the manu-
facturing sector is for process heating, the production
of heat directly from fuel sources, electricity, or steam
that is used to heat raw material inputs during manufac-
turing. Natural gas is the dominant fuel used to generate
heat, and process heating accounts for 42 percent of the
natural gas use in the industrial sector overall (Figure 1).
In 2010, process heating using all fuel sources produced
315.4 million metric tons of CO2
, which represents 40
percent of the CO2
emissions for the entire manufac-
turing sector.148
Industrial boilers generating heat and steam are
another large consumer of natural gas. Eighty-three
percent of boilers run on natural gas, and they consume
22 percent of this fuel used in manufacturing.149
While
some are fueled by coal or other fuel, the dominant fuel
Figure 1: Natural Gas Use in Manufacturing,
2009
Source: Energy Information Administration, “Manufacturing Energy Consump-
tion Survey,” June 2009, Tables 2.2 and 5.2. Available at http://www.eia.gov/
emeu/mecs/mecs2006/2006tables.html
Other
15%
Feedstock
7%
CHP and
Other Power
14%
Boilers
22%
Process
Heating
42%

source is natural gas. Boilers are commonly used for a
variety of purposes by chemical manufacturers, food
processors, pulp and paper manufacturers, and the
petroleum- and coal-derivatives industries (including
chemicals, coke, and coal tar) (Figure 2).150
CHP—also known as cogeneration—is a third major
use of natural gas in the manufacturing sector.151
Natural
gas is used to generate electricity on site, with the waste
heat being captured and used for a variety of industrial
purposes, greatly increasing the efficiency of the system
overall. Additional efficiencies and emission reductions are
also achieved through avoided transmission losses.152
In
2010, 14 percent of natural gas used in manufacturing was
consumed by CHP and other power systems. Natural gas is
the most common fuel used for CHP systems. Nationwide,
the added efficiencies of these systems avoid the emission
of 35 million metric tons of CO2
equivalent annually.153
Feedstock is raw material used as an input in manu-
facturing for creating value-added products. Natural gas
production and its byproducts provide feedstock for the
bulk chemicals industry, constituting a non-combustion
use of natural gas. Methane—pure natural gas—is the
source for hydrogen used in industrial processes, in
fuel cells, and in the production of ammonia. Liquids
extracted in association with natural gas, including
ethane, propane, and butane, are processed and trans-
formed to become other intermediate and final products
including adhesives, insulation, paint, plastics, and vinyl.154
Figure 2: Direct Consumption of Fuels in the Manufacturing Sector, 2009
Source: Energy Information Administration, “Manufacturing Energy Consumption Survey,” June 2009, Tables 2.2 and 5.2. Available at http://www.eia.gov/emeu/
mecs/mecs2006/2006tables.html
Other
9%
Coal
8% Natural Gas
83%
Other
3%
Electricity
11%
Coal
10%
Natural Gas
76%
Other
5%
Coal
32%
Natural Gas
63%
Direct Consumption of Fuel in Boilers Direct Consumption of Fuel in Process Heating
Direct Consumption of Fuel in CHP and Other Power

Chemical companies are the largest consumers of natural
gas-associated liquids, and they commonly use up to two-
thirds of their delivered natural gas as feedstock.155
The emissions implications of using natural gas as a
feedstock are very different from its other uses because
feedstock use transforms hydrocarbon molecules into
other products, rather than burning them. When natural
gas is used as a feedstock, therefore, very low greenhouse
gases emissions are produced. These low-emitting uses
are enhancing U.S. competitiveness in the manufac-
turing sector. Whereas U.S. companies are reliant on
low-cost natural gas liquids as a feedstock, European
competitors use more expensive, oil-based naphtha.156
In 2010, for example, domestic ethane sold at half the
price of imported naphtha in Europe, and, consequently,
U.S. chemical manufacturers have reaped a competitive
advantage in international markets for intermediate and
final goods.157
Potential for Expanded Use
Increased availability and low prices of natural gas have
significant implications for domestic manufacturing.
Large manufacturers dependent on natural gas for
production are vulnerable to resource availability and
price volatility. Accordingly, they have historically been
concerned about policies or technologies that may impact
these factors. Recently, abundant supply and low prices
have led to greater confidence and an increase in domestic
manufacturing, creating new jobs and economic value.158
Numerous companies have cited natural gas supply and
price in announcing plans to open new facilities in the
chemicals, plastics, steel, and other industries in the
United States,159
including $41.6 billion worth of industrial
investments that are planned between 2012 and 2018. One
analysis has noted that the number of firms disclosing
the positive impact of new gas resources for facility power
generation and feedstock use increased substantially
just between 2008 and 2011.160
In 2010, exports of basic
chemicals and plastics increased 28 percent from the
previous year, yielding a trade surplus of $16.4 billion.161
Continued low natural gas prices could have significant
long-term economic benefits. A study by the American
Chemistry Council estimates that a 25 percent increase in
ethane supplies, for example, could yield a $32.8 billion
increase in U.S. chemical production.162
EIA’s Annual Energy Outlook 2013 Early Release of
projections to 2040 reflects the expected increase in
industrial natural gas demand. Total industrial consump-
tion of natural gas for heat and power is projected to rise
by 19 percent between 2010 and 2021 before increasing
at a slower rate through 2040 (Figure 3). Efficiency
measures are forecasted keep the amount of natural gas
used per dollar of output declining over the same period
(Figure 4).
Total industrial consumption of feedstock (natural gas
liquids) is projected to rise by 23 percent between 2010
and 2023 before declining from peak levels (Figure 5).
Feedstock growth will be tempered by long-term changes
in the natural gas market, including higher prices and
international competition in chemicals manufacturing
and future energy efficiency improvements expected to
offset increased demand for feedstock while maintaining
output levels (Figure 6). The use of CHP is projected to
increase by 113 percent over the same period (Figure 7).
Increases in the use of on-site electricity generation
through CHP systems would partially reduce facilities’
Figure 3: Projected Total Industrial Consumption of Natural Gas for Heat and Power,
2010 to 2040
Source: Energy Information Administration, “Annual Energy Outlook 2013 Early Release,” 2013. Available at: http://www.eia.gov/forecasts/aeo/er/pdf/tbla2.pdf
5.0
5.5
6.0
6.5
7.0
7.5
8.0
Quadrillion Btu
2035
2035
2036
2038
2039
2040
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
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2017
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2015
2014
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2010

reliance on grid-supplied electricity while providing heat
for industrial uses. CHP systems are designed to balance
heat production with electric power needs within a
facility; electricity can be bought from the grid if needed,
or sold to the grid if there is excess on-site production.163
These changes in the manufacturing sector will have
mixed impacts on greenhouse gas emissions. Absolute
increases in natural gas used for heat and power opera-
tions are likely to increase total emissions coming from
the sector. However, improvements in energy efficiency
and especially the substantial deployment of CHP opera-
tions will allow the manufacturing sector to increase
output with relatively smaller increases in the amount of
natural gas input.
Potential for Emission Reductions
Even as the manufacturing sector expands, opportuni-
ties exist to reduce its emission intensity—the amount
of CO2
emitted per unit of output. Replacement of
lower-efficiency boilers and greater deployment of CHP
systems are ways to reduce emission intensity while using
more natural gas.
Replacement of Lower-Efficiency Boilers
Improving the efficiency of industrial boilers is one such
opportunity to reduce emission intensity. Boilers tend to
have a low turnover rate, and older units are typically less
efficient than newer ones. The pre-1985 fleet of boilers
has an average efficiency of 65 to 70 percent, while new
boilers have efficiency rates of 77 to 82 percent, and new,
super-high-efficiency units can reach efficiencies of up to
95 percent.164
Figure 4: Projected Energy Consumption of Natural Gas for Heat and Power per Dollar of
Shipments, 2010 to 2040
0.0
0.2
0.4
0.6
0.8
1.0
1.2
Thousand Btu
per 2005 dollar
2035
2035
2036
2038
2039
2040
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
Figure 5: Projected Total Industrial Consumption of Natural Gas Liquids Feedstock,
2010 to 2040
Sources: Energy Information Administration, “Annual Energy Outlook 2013 Early Release,” 2013. Available at: http://www.eia.gov/forecasts/aeo/er/pdf/tbla2.pdf
0.0
0.5
1.0
1.5
2.0
2.5
3.0
Quadrillion Btu
2035
2035
2036
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2039
2040
2034
2033
2032
2031
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2029
2028
2027
2026
2025
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2019
2018
2017
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2015
2014
2013
2012
2011
2010

Analysis performed by the Massachusetts Institute
of Technology found that replacing older natural gas
boilers with high-efficiency or super-high-efficiency units
would decrease CO2
emissions by 4,500 to 9,000 tons
or more per year per boiler. The analysis also found a
strong economic incentive to make these replacements,
highlighting annualized monetary savings of 20 percent
(given certain assumptions, including 2010 natural gas
prices) with a payback period for the new equipment of
1.8 to 3.6 years.165
While natural gas is the most commonly used fuel
source for industrial boilers, 17 percent of boilers
use coal or other fuels (Figure 2). Because of the air
pollutants released from coal-fired boilers, these boilers
are now subject to the U.S. Environmental Protection
Agency (EPA) 2012 Maximum Achievable Control
Technology standard (also known as the Boiler MACT).
This standard requires the largest and highest-emitting
boilers at industrial facilities, typically coal-fired boilers,
to meet numeric pollution limits for the emission of
air toxics, although it does not specifically require
reductions in greenhouse gas emissions.166
An analysis
was performed to determine the results of replacing
the Boiler MACT-affected coal boilers with efficient or
super-high-efficiency natural gas boilers (natural gas
boilers are not regulated under the new rule because of
their already low emissions of the specified air toxics).
This analysis found that replacement of coal boilers with
natural gas boilers would reduce annual CO2
emissions
by 56 to 59 percent, or about 52,000 to 57,000 tons per
year per boiler.167
Figure 6: Projected Energy Consumption Natural Gas Liquids Feedstock per Dollar of
Shipments, 2010 to 2040
0.00
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.09
Thousand Btu
per 2005 dollar
2035
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2013
2012
2011
2010
Figure 7: Projected Total Industrial CHP Generation for All Fuels, 2010 to 2040
0
50
100
150
200
250
300
Generation
(billionkilowatthours)
2035
2035
2036
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2019
2018
2017
2016
2015
2014
2013
2012
2011
2010

Expanded Use of Onsite CHP
Increasing the use of CHP also has the potential to
reduce emissions produced in the manufacturing sector.
An Oak Ridge National Laboratory study in 2008 calcu-
lated that increasing CHP’s share of total U.S. electricity
generation capacity from 9 percent in 2008 to 20 percent
by 2030 would lower U.S. CO2
emissions by 600 million
metric tons compared with business as usual.168
A study
by McKinsey Company in 2009 estimated that the
potential exists for an additional 50.4 gigawatts of CHP
capacity by 2020, which would avoid an estimated 100
million metric tons of CO2
emissions per year compared
with business as usual. Additionally, this study found that
70 percent of the potential cost-effective CHP capacity
was through large-scale industrial cogeneration systems
greater than 50 megawatts (MW).169
CHP units at industrial facilities have the added
benefit of bolstering system reliability during a period
of transition in the electric sector. Recent years have
seen a wave of announced coal plant retirements, and
power generation from natural gas-fueled CHP units
could make up for some of this lost generation—with
lower emissions than centralized coal power plants. A
study from the American Council for an Energy-Efficient
Economy found that natural gas-fueled CHP at industrial
facilities could quickly and cost-effectively replace some
of the electric power from retiring coal plants. In South
Carolina and Kansas, it could replace all of the expected
lost capacity, while in industrial, coal-dependent states
such as Ohio and North Carolina, it could replace 16 and
56 percent of lost capacity, respectively.170
Figure 8 compares conventional, centralized power
generation augmented with a boiler (left side) with
a CHP system (right side). Each system is required to
provide 30 units of electricity and 45 units of usable
heat. However, the power station and boiler together
require 154 units of fuel, and the CHP system requires
only 100 units of fuel. Therefore, the power station is 49
percent efficient and the CHP unit is 75 percent efficient.
At least 7 percent of the electricity delivered from the
conventional power station to the industrial facility is lost
during transmission. Although most of the losses occur
as primary fuel-to-electricity conversion heat losses at
the power plant, this heat is unable to be captured for
useful purposes. Consequently, a boiler is required on
the industrial site to create the necessary heat, which
consumes additional fuel. In contrast, the CHP system
is able to generate the electricity and heat together
with far fewer losses. Since less fuel is required, overall
emissions are lower. Some operations also use waste heat
in an absorptive chiller to provide cooling services as
well. Such operations are referred to as trigeneration or
combined cooling, heating, and power. These operations
offer even greater efficiencies and opportunities for
emissions reductions.
Barriers to Deployment of CHP systems
Although CHP systems have dramatically higher efficien-
cies than grid power combined with simple natural gas
combustion, and they result in much lower greenhouse
gas emissions, barriers currently limit their application.
Electric utilities often cite safety concerns as a barrier
to deployment, specifically, perceived risks related to
electricity being added to the grid outside of the central
power plant. For example, some utilities cite the concern
that miscommunication could occur between CHP
operators and the utilities in the event of an emergency
such as a storm causing downed power lines, which
utilities say could lead to dangerous situations in which
their line workers are not certain whether lines are
energized or not. In addition, utilities may be concerned
about risk and liability involved as their employees could
On the right,100 units of fuel are converted into 30 units of elec-
tricity and 45 units of useful heat by a single CHP unit; 75/100 = 75
percent efficiency. On the left, 91 units of fuel are converted into
30 units of electricity by a large power plant and 56 units of fuel
are converted into 45 units of useful heat by a separate boiler; 75/
(91 + 56) = 51 percent efficient.
Source: Environmental Protection Agency, “Efficiency Benefits,” 2012. Avail-
able at: http://www.epa.gov/chp/basic/efficiency.html.
Figure 8: CHP versus Conventional
Generation

be affected by safety and technical decisions of CHP
operators, decisions they are concerned could be made
independently of utilities.171
Other concerns have to do
with CHP systems’ potential need for backup power.
Many utilities are concerned about the need to provide
backup power to industrial facilities if CHP systems are
taken offline or are otherwise unavailable. For utilities,
the ability to provide backup power requires capacity; to
pay for investments in new or maintenance of existing
capacity, utilities often charge CHP operators higher
rates than other customers and additional interconnec-
tion fees to compensate for these necessary investments.
From the standpoint of industry, technical and
economic considerations also may need to be taken into
account when considering the installation of a CHP
system. Some facilities may face shortages of trained
CHP installers and operators. Another challenge is that
CHP retrofits can be costly. Installation is easier during
new construction or a major redesign of a facility. Lastly,
some industrial users may face difficulties finding buyers
for excess heat or power not needed for their own use.
However, if buyers are found, the project may be not only
environmentally sound, but economically viable as well.
Current regulatory and electric utility policies have
inhibited the growth of CHP capacity, with its attendant
climate benefits, because they prevent the alignment
of financial interests between electricity producers and
energy consumers. Power sector regulation in many
states leads utilities to view CHP as unprofitable.172
This
negative view of CHP is often reflected in regulations
established by public utility commissions that do not
encourage new CHP deployment. However, innovative
policy approaches can overcome this conflict between
competing goals among utilities and CHP operators.
One approach is decoupling, removing or modifying the
link between a utility’s volume of sales and its profits.
Decoupling makes it profitable for utilities to encourage
CHP systems.173
Another potential policy solution is
a lost-revenue adjustment policy, which compensates
utilities through a charge on customer bills for revenues
lost because efficiency measures were effective.174, 175
State
incentives can also encourage the use of CHP. State-level
policies include standardizing grid-interconnection
guidelines, offering tax incentives, and including CHP
as a compliance mechanism for the state’s clean-energy
standards.176
Some states have enacted these policies,
and, as with many state-led policies, there is a diversity of
approaches to (and success with) their implementation.177
An example of a state working to overcome barriers
to CHP deployment is Ohio. The U.S. Department of
Energy (DOE) estimates Ohio has a potential CHP
capacity of up to 8,000 MW if CHP systems are installed
and limited from selling power into the broader power
market, and up to 11,000 MW if sales into the market
are allowed. However, despite this vast potential, by 2011
only 766 MW of CHP was installed in the state.178
Many of
the boilers in Ohio will be affected by the new EPA 2012
Boiler MACT rule, making them candidates for upgrades
or complete conversions to CHP systems. At the same
time, new CHP facilities have the potential to address
state regulators’ concerns about several announced coal
plant retirements affecting system reliability. In response
to the benefits of CHP systems in Ohio at this time and
to this technology’s current underutilization, the Public
Utilities Commission of Ohio launched a pilot project
with DOE to encourage installation of CHP systems.
This project identifies candidate systems and assists in
the dialogue between potential CHP operators, utilities,
and the electric market operator to facilitate installa-
tions while working to overcome regulatory and other
barriers.179
In 2012, the state legislature also added CHP
systems as a qualifying resource in the state’s clean-
energy standard.180
Conclusion
The increased availability of low-priced natural gas has
had positive economic impact on U.S. manufacturing
and sector expansion is expected to continue. Given
that natural gas is a feedstock and a fuel source for this
industry, the efficient use of natural gas needs to be
continually encouraged. Options to increase efficiency
include the replacement of older boilers with more
efficient ones and the expansion of CHP. CHP systems
are highly efficient, as they use heat energy otherwise
wasted. Policy is needed to overcome barriers to
expanded deployment. States are in an excellent position
to take an active role in promoting CHP when required
industrial boiler upgrades and new standards for cleaner
electricity generation are implemented.

VII. Distributed Generation in Commercial and Residential
Buildings and the Role of Natural Gas
By Doug Vine, C2ES
Introduction
Distributed generation is the production of electricity
from smaller sources at or near the location where the
energy will be consumed. Slightly more than 6.5 percent
of electricity in the United States is generated at distrib-
uted locations outside of central generation plants.181
Distributed generation using natural gas has a number of
potential benefits, including the potential to capture heat
associated with electricity generation that can be put to
use on site. When waste heat is captured and used and/or
highly efficient generation technologies are used, distrib-
uted generation decreases the total demand for primary
fuels, thereby decreasing greenhouse gas emissions.
This chapter explores the potential climate-related
benefits of distributed generation technologies as they
apply to the residential and commercial sectors. (For a
discussion of combined heat and power (CHP) systems
in the manufacturing sector, see chapter 6.) The chapter
discusses three major technologies for distributed
generation: microgrids, fuel cells, and microturbines.
Next, it explores policies that encourage the deployment
of these technologies, and, lastly, it discusses barriers
to deployment.
Electricity is the most widely used form of energy
by residential and commercial buildings on a primary-
energy basis (Figure 1). Since the majority of electricity
generation emits greenhouse gases, it makes sense to
consider technologies with lower emissions. Several prom-
ising technologies make use of natural gas as the primary
fuel, and many of these technologies could significantly
reduce greenhouse gas emissions from electricity use
in the residential and commercial sectors. Distributed
generation technologies either can be placed on site at a
home or business or can be located a short distance away,
serving several buildings together. While the majority
of existing natural gas-fueled distributed generation
technologies are not as efficient as central generation, the
ones discussed in this chapter are highly efficient, can be
used in highly-efficient configurations with CHP, and/
or facilitate the deployment of renewable energy sources.
Distributed generation technologies that supply power to
multiple locations include microgrids. On-site or end-use
technologies include natural gas-fueled electricity (and
heating) devices such as fuel cells and microturbines,
which can also be used as small CHP systems.
The Advantages of Distributed Generation
In 2010, natural gas-fueled electricity comprised
approximately 54 percent of the total net U.S. distributed
generation (Figure 2). These figures are for industrial
and commercial sector distributed generation only and
represent approximately 3.5 percent of the total elec-
tricity generated in that year.
Figure 1: Projected U.S. Residential and
Commercial Buildings Primary Energy
Consumption, 2010
Source: Energy Information Administration, Residential Energy Consump-
tion Survey, 2009. Available at http://www.eia.gov/consumption/residential/
data/2009/
Renewable
1%
Coal
0%
Petroleum
5%
Natural Gas
21%
Electricity
73%

Distributed generation has many advantages over
centralized electricity generation, including end-users’
access to waste heat, easier integration of renewable
energy, heightened reliability of the electricity system,
reduced peaking power requirements, lower greenhouse
gas emissions, and less vulnerability to terrorism due to
more geographically dispersed, smaller power plants.182
In
addition, producing electricity closer to where it is used
reduces the amount of electricity lost as it is delivered over
long distances from power stations to end users. Annual
electricity transmission and distribution losses in the
United States average about 7 percent of the electricity
transmitted.183
Lowering transmission (or line) losses
means less electricity generation (less fuel and fewer emis-
sions) is required to serve the same electrical demand.
Generally, natural gas-fueled distributed generation
technologies are not as efficient in producing electricity
as natural gas-fired generation from the grid. In general,
distributed generation only improves efficiency and
reduces greenhouse gas emissions when it includes CHP.
By definition, distributed generation is physically located
close to loads, so use of heat is often an option. However,
CHP requires tight matching, in space and especially in
time, between power generation and thermal loads. This
matching can make CHP technologies difficult to effec-
tively install. Nevertheless, where possible, this technology
is significantly more efficient and should be deployed.
Microgrids
One increasingly employed distributed generation
technology is the microgrid. A microgrid is a small power
system composed of one or more electrical genera-
tion units that can be operated either in conjunction
with or independently from the central power system
(Figure 3).184
Microgrids can serve a small grouping of
buildings. Additionally, microgrids offer the potential to
integrate renewable sources of electricity with fossil fuel-
based backup power; they are able to integrate distrib-
uted, dispatchable natural gas-fueled electricity (or CHP
systems) with local renewable power and energy storage.
Furthermore, since the electricity is generated close to
where it will be used, it becomes feasible to use the waste
heat in a productive manner, such as for heating water or
space in nearby homes and businesses. Microgrids can be
particularly attractive if new or upgraded long-distance
electricity transmission cannot be developed in a timely
or cost-effective fashion.185
Fuel Cells
Fuel cells are another promising distributed generation
technology. Natural gas-powered fuel cells use natural
gas and air to create electricity and heat through an
Figure 2: Distributed Generation by Fuel
Source, 2009
Source: Source: Energy Information Administration, Residential Energy
Consumption Survey, 2009. Available at http://www.eia.gov/consumption/
residential/data/2009/
Other
2%
Petroleum
2%Other
Gaseous Fuels
7%
Coal
13%
Renewable
Sources
22%
Natural Gas
54%
Figure 3: Microgrid Concept
Source: Siemens, “The Business Case for Microgrids,” 2011. Available at:
http://www.energy.siemens.com/us/pool/us/energy/energy-topics/smart-grid/
downloads/The%20business%20case%20for%20microgrids_Siemens%20
white%20paper.pdf
Note: Individual microgrid elements will vary.

electrochemical process rather than combustion.186
First,
natural gas is converted into hydrogen gas inside the
fuel cell in a process known as reformation. When the
hydrogen passes across the anode of the fuel cell stack
(Figures 4 and 5), electricity, heat, water, and carbon
dioxide (CO2
) are created.
Fuel cell technology has been around for many
decades; it has been used by the National Aeronautics
and Space Administration on space projects for nearly
50 years. Commercially available fuel cells operate in a
wide range of climates, from very cold to very warm (-20°
to 110°F), and they have electrical efficiencies of around
40 to 60 percent (Table 1). They are quiet devices with a
fairly small footprint. The only greenhouse gas emitted
is a pure stream of CO2
, which could allow for capture
and sequestration. Despite these benefits, skeptics
question the durability, cost (see below) and reliability
of fuel cells. In the past, materials have corroded within
months or a few years. Bloom Energy estimates that its
current devices will have a 10-year life as long as the fuel
stacks are replaced at least twice. However, since Bloom’s
introduction is recent, there are currently no operational
fuel cell systems that have approached this age.187
There are many types of fuel cells, each with its
unique chemistry, operating temperature, catalyst,
and electrolyte.188
Phosphoric acid fuel cells, molten
carbonate fuel cells, and solid oxide fuel cells, among
others, have been commercialized for stationary elec-
trical power generation. Since many units operate at
high temperatures and contain corrosive materials, a
key concern is their durability or stack life. For example,
natural gas-fueled phosphoric acid fuel cells operate at
temperatures of around 450°F, and solid oxide fuel cells
operate at temperatures of about 1,800°F.189
Phosphoric
acid fuel cells are the most durable type in the less-than-
one megawatt (MW) range and have a demonstrated
stack life of more than 10 years, although designs of
many other fuel cell types are improving rapidly.190
Figure 4: Fuel Cell Stack
1) Anode: As hydrogen flows into the fuel cell anode, a catalyst
layer on the anode helps to separate the hydrogen atoms into pro-
tons (hydrogen ions) and electrons. 2) Electrolyte: The electrolyte
in the center allows only the protons to pass through the electro-
lyte to the cathode side of the fuel cell. 3) External Circuit: The
electrons cannot pass through this electrolyte and, therefore, must
flow through an external circuit in the form of electric current. This
current can power an electric load. 4) Cathode: As oxygen flows
into the fuel cell cathode, another catalyst layer helps the oxygen,
protons, and electrons combine to produce pure water and heat.
Source: ClearEdge Power
Figure 5: How Fuel Cells Work
Source: ClearEdge Power
Notes: 1) Fuel Processor: Converts natural gas fuel to hydrogen. 2) Fuel Cell
Stack: Generates direct current (DC) power from hydrogen and air. 3) Power
Conditioner: Converts DC power to high-quality alternating current (AC)
power 4) Heat Recovery: On-board heat exchangers for recovering useful
thermal energy.

ClearEdge Power and Bloom Energy are among a
handful of manufacturers of stationary fuel cells. Their
main products are described below for illustrative
purposes. There are an additional half-dozen or so
manufacturers of non-stationary fuel cells (fuel cells
for vehicles).
ClearEdge Power, based in Oregon and established
in 2003, manufactures refrigerator-sized fuel cell units
that generate baseload or backup electric power as well as
provide useable heat for hot water and/or space heating
in a CHP configuration. These units are scalable to suit
the energy requirements of individual homes, apartment
buildings, hotels, and other commercial businesses,
and can be installed indoors or outdoors. They have
efficiencies of up to 90 percent. They are 50 to 60 percent
efficient in natural gas conversion to electricity, in
addition to providing useful heat. Therefore, they require
considerably less natural gas to generate the same amount
of energy provided from a combination of centrally gener-
ated electricity and a heating appliance.191
In February
2013, ClearEdge Power acquired UTC Power, an early
pioneer in fuel cell research that conducted experiments
with many types of fuel cells beginning in the late 1950s.192
Stationary fuel cell products from UTC Power, now
ClearEdge Power, are deployed in residential, commercial,
and industrial applications around the world.193
Bloom Energy, based in California and founded in
2001, markets energy servers that consist of arrays of fuel
cell boxes in various sizes that must be installed outdoors
(Figure 6). The energy servers are scalable and are used
by large corporate customers such as Wal-Mart, eBay, and
FedEx, and not residential consumers.194
These servers
achieve conversion efficiencies above 60 percent. These
are very high-temperature devices, but the heat is not
used for water or space heating. The average emissions
are 773 pounds of CO2
per megawatt-hour (MWh), which
is just below the average U.S. natural gas power plant at
800 to 850 pounds of CO2
/MWh.195, 196
Microturbines
Microturbines are small combustion turbines approxi-
mately the size of a refrigerator with individual unit
outputs of up to 500 kilowatts (kW).197
These devices can
be fueled by natural gas, hydrogen, propane, or diesel. In
a cogeneration configuration (Figure 7), the combined
thermal-electrical efficiency can be as high as 90 percent.198
Like fuel cells, microturbines can achieve much higher
energy efficiencies, because the electricity is generated
close to the location where it will be used, and the heat
byproduct can be captured and utilized on site or nearby.
Microturbines are an established technology, and
there are more than 20 companies worldwide involved
Figure 6: Bloom Energy Server Outdoor
Installation
Source: Bloom Energy
Table 1: Fuel Cells Summary
Company
Electrical
efficiency Usable Heat
Total Efficiency
for CHP system Markets
ClearEdge 50-60 percent Yes 90 percent Residential,
Commercial,
Industrial
Bloom Energy 60 percent No 60 percent Commercial
Source: Clear Edge, Bloom Energy

in the development and commercialization of microtur-
bines for distributed generation applications.
Los Angeles-based Capstone Turbine Corporation is a
global market leader in the commercialization of microtur-
bines.199
The company offers individual units in the range
of 30 kW to 200 kW, and greater quantities of power can be
achieved by using multiple units, with electrical efficiencies
from 25 to 35 percent (Figure 8). Using the heat produced
by a microturbine for water or space heating, space cooling
(in conjunction with absorption chillers) and/or process
heating or drying, increases the efficiency of these units to
70 to 90 percent.200
Capstone products service the commer-
cial and industrial sectors, and they have installations
all over the world, including universities, a winery, and a
35-story office tower in New York City (Figure 9).201
Flex Energy, also headquartered in California, is
Capstone’s main competitor. Its 250 kW microturbine
has an electrical efficiency of 30 percent, and it too
provides useful heat energy, which when used would
improve the overall efficiency of the system.202
Flex
Energy and Capstone microturbines can use low-quality
Figure 7: Microturbine Schematic
Fuel enters the combustor and the hot gases ejected from the combustor spin a turbine, which is connected to a generator that creates
electricity. The exhaust gases transfer heat to the incoming air. A recuperator captures waste heat and helps improve the efficiency of
the compressor.
Source: Capstone Turbine Corporation
Figure 8: Microturbine Unit

and unrefined natural gas, making them capable of
generating electricity at landfills and hydraulic frac-
turing sites.203
Using unrefined natural gas at a well site
for power requirements can reduce the need for diesel
power generation and utilize natural gas that may have
been flared otherwise.
Micro Turbine Technology, a company in the
Netherlands, is developing a 3 kW electrical with 15 kW
thermal microturbine CHP for homes and small businesses
that is expected to be ready for market in early 2013.204
At 31 percent average electrical efficiency, much
lower than a modern natural gas combined-cycle plant
or fuel cell (both around 50 percent), microturbines
produce 1,290 pounds of CO2
/MWh, about 50 percent
higher emissions than a modern combined-cycle
plant.205
However, due to their ability to capture and
use waste heat onsite, they are capable of achieving
thermal efficiencies of up to 85 percent. When this heat
is captured and used, the total efficiency of the system
offsets the lower efficiency of electricity generation part
of the system, reducing overall greenhouse gas emis-
sions per MWh. Additional strengths of microturbines
include their compact size, small number of moving
parts, generally lower noise than other engines, and long
maintenance intervals. Weaknesses include parasitic load
loss from running a natural gas compressor and loss of
power output and efficiency with higher ambient temper-
atures and elevation.206
According to U.S. Environmental
Protection Agency data, at an 80°F outdoor air tempera-
ture, the microturbines are about 3 percent less efficient
than at a 50°F outdoor air temperature.207
Residential Unit CHP
There are even smaller systems than the microturbines
discussed that can provide CHP to individual residential
units. At less than 50 kW, these microCHP units are small
enough to provide electric power for a residential or
commercial building while also supplying heat for thermal
applications or absorption cooling (Figure 10). Common
in Europe and Japan, microCHP is rare in the United
States. These small units may use a variety of engine types,
including combustion, steam, Brayton, and Stirling.208
For
example, the WhisperGen, developed in New Zealand, is
a microCHP technology based on the Stirling engine. The
company is currently headquartered in Spain, where the
product is being marketed to European customers. The
washing machine-sized technology is designed to produce
hot water and space heating. Under normal operation the
unit will provide around 1 kW of electrical power.209
Other
companies, such as Japan’s Honda, also offer microCHP
units to consumers.210
Figure 9: Microturbine Installation
Table 2: Microturbine Summary
Company
Electrical
efficiency Usable Heat
Total Efficiency
for CHP system Markets
Capstone 25-35 percent Yes 70-90 percent Commercial,
Industrial
Flex Energy 30 percent Yes Not Available Commercial,
Industrial
MTT N/A Yes Not Available Residential
Source: Capstone, Flex Energy, MTT

Policies to Encourage the Deployment of
New Technologies
Although these new technologies have great potential
to use less primary energy and to reduce greenhouse
gas emissions from energy use in the residential and
commercial sectors, there are some hurdles to overcome.
Higher upfront capital costs hinder investment in distrib-
uted generation technologies overall. In addition, utility
regulations often do not encourage, and in some case
actively discourage, distributed generation technologies.
Some state and federal incentive programs help home-
and business-owners with upfront costs. At least 10 states
provide financial incentives for self-generation.211, 212
The
federal Investment Tax Credit, designed to help defray
capital expenditure costs, applies to fuel cells, CHP, and
microturbines for use in the commercial, industrial,
utility, and agricultural sectors.213
Another potential incentive for consumer invest-
ment in on-site energy generation is net metering. Net
metering allows customers to receive retail prices for
their excess generation; the electricity meter turns back-
wards (literally or digitally) when the site generates more
electricity than it consumes. 214
Forty-three states and the
District of Columbia have rules enabling net metering.215
Eligible generation technologies vary. Fuel cells using
any fuel type often qualify, and CHP sometimes qualifies,
although less often.
Sites using distributed generation often rely on
a grid interconnection as a source of backup power.
Establishing a connection between an on-site system
and the power grid can be difficult, confusing for the
on-site operator, and lengthy. Standard interconnection
rules greatly simplify this process, establishing clear and
uniform processes and technical requirements that apply
to all utilities within a state. These rules reduce uncer-
tainty and prevent delays that installers and operators
of distributed generation systems can encounter when
obtaining approval for electric grid connection, and thus
make the prospect of installing a system less daunting to
newcomers. 216
As of April 2012, 34 states had intercon-
nection standards for fuel cells, and 29 states had such
standards for microturbines.217
A final area where policies could encourage the instal-
lation of more distributed generation systems pertains to
utility charges. As mentioned above, distributed genera-
tion systems rely on a grid connection for backup power
during outages, whether scheduled or emergency. Standby
rates are charges levied by utilities when a distributed
generation system must purchase all of its power from the
grid. These charges generally include an energy charge,
reflecting the actual energy provided, and a demand
charge, which is a way for the utility to recover its costs
in maintaining the capacity to meet the facility’s peak
demand whenever that may be required. Utilities often
argue that the demand charges act as a strong incen-
tive for system owners to manage their peak demand.
However, the likelihood of unplanned outages during
times of peak demand is very low, and the use of demand
charges likely discourages the expansion of distributed
generation. Regulators should carefully weigh the discour-
aging effect of demand charges against the substantial
benefits of distributed generation, including increased
system reliability, reduced distribution losses, and the
climate benefits of the higher system efficiencies.218
Barriers to Deployment
A variety of factors converge to discourage potential
owners of distributed generation systems. First,
consumers are largely unfamiliar with these technolo-
gies. Moreover, they are not compelled to search for
innovative strategies to generate energy. Their utility
bills are stable, due to low wholesale electricity prices (a
result of lower natural gas prices). Local building and
fire codes may also provide disincentives or even make
it impossible for consumers to consider distributed
Figure 10: Residential CHP Unit
Residential CHP unit (bottom left outside of house) is capable of
supplying hot water and heating as well as electricity to several ap-
pliances. Home is still grid connected for any consumption unable
to be met by the CHP unit and excess power generated by the unit
can be sold back to the electric utility.
Source: Fuel Cell Today

generation. And the limited availability of many distrib-
uted generation products in the United States is a barrier
to even those with natural gas access.219
Even if these hurdles are removed, the cost of many
distributed generation technologies can be a barrier.
According to the National Institute of Building Sciences,
microturbine capital costs were $700 to $1,100 per kW in
2010, with installation costs adding 30 to 50 percent of the
total installed cost. Combining heat recovery technology
to units increased the cost by $75 to $350 per kW. A future
cost below $650 per kW may be possible with future
economies of scale.220
Fuel cells could be cost-competitive
with grid electricity if they were to reach an installed cost
of $1,500 or less per kW; however, the current installed,
unsubsidized cost is at least $4,000 per kW.221
Nevertheless,
a combination of state and federal incentives, low natural
gas prices, and high grid-electricity prices could result in
a 100 kW energy server making economic sense, as shown
in an analysis by Seattle City Light (Figure 11). Similarly,
natural gas microCHP units could be cost competitive
with a 1.5- to two-year payback period at an installed cost
of $1,500 for a 1 kW unit.222
Conclusion
To realize the potential of distributed generation tech-
nologies, policies such as financial incentives and tax
credits will need to be more widespread. Additionally, net
metering, grid interconnection requirements, and standby
rate issues will need to be worked through. Also, low
consumer awareness and higher costs of these emerging
technologies will slow their deployment. Finally, utilities
may perceive distributed generation technologies as a
threat, as they have the potential to capture a large share
of utilities’ electricity sales business. Nevertheless, some
supporters of distributed generation have claimed that
their technology will replace the grid and have designed
their business strategies accordingly.223
Figure 11: Bloom Energy Server Cost Depends on Gas Price and Subsidies
Source: Seattle City Light, “Integrated Resource Plan.” 2010. Available at: http://www.seattle.gov/light/news/issues/irp/docs/dbg_538_app_i_5.pdf
Cost($/kWh)
$13 $15$14$11 $12$10$9$8$6$5 $7
$0
$20
$25
$30
$5
$10
$15
Gas Price ($/MMBtu)
Federal Subsidies Only
Fully Costed—No Subsidies
California Federal Subsidies

VIII. Transportation Sector
By Fred Beach, The University of Texas at Austin
Introduction
Historically, natural gas has not been widely used as
an energy source for transportation; rather, the sector
has long been dominated by petroleum use. In 2010
(Figure 1), the U.S. transportation sector used 27.47
quadrillion British thermal units (Btu) of energy, of
which 25.59 quadrillion came from petroleum and just
0.72 quadrillion came from natural gas—93 percent and
3 percent of the sector, respectively.224
Natural gas used
in the transportation sector resulted in the emission of
just 40.1 million metric tons of carbon dioxide equivalent
(CO2
e) in 2010, out of a total 1,746 million metric tons
emitted by all fuel sources in the transportation sector.225
As in other sectors of the economy, fuel substitution
from other fossil fuels to natural gas in some parts of the
transportation sector has the potential to yield climate
benefits. In addition, it would benefit U.S. national
security by decreasing reliance on the global oil market.
Although the potential for natural gas use is less in the
transportation sector than in others, the potential does
exist, primarily for medium- and heavy-duty trucks as
well as fleet vehicles and buses.
A main driver of the increased interest natural gas
fleets and passenger vehicles is the relative abundance and
low price of domestic natural gas in comparison to oil. On
April 30, 2012, the national average price of diesel fuel
was $4.07 per gallon and gasoline cost $3.83 per gallon,226
while a gasoline-gallon-equivalent of natural gas cost only
$2.09.227
On the same day, the price of petroleum was
$104.87 per barrel,228
and the price of natural gas was only
$12 on an energy-equivalent basis.229
In recent years, oil
prices rose while natural gas prices decreased, creating an
ever-widening gulf (Figure 2). This differential has made
natural gas vehicles increasingly economical.230
This chapter looks at the currently available natural
gas technologies for vehicles. Next, it explores the
barriers to adoption for various types of vehicles. Finally,
it examines the potential implications of broader direct
use of natural gas in the transportation sector for
greenhouse gas emissions.
Available Natural Gas Transportation
Technologies
A variety of available vehicle technologies allow natural
gas to be used in light-, medium-, and heavy-duty
vehicles. Most commonly, natural gas is used in a highly
pressurized form as compressed natural gas (CNG) or
as liquefied natural gas (LNG). While CNG and LNG
are ultimately burned in the vehicle, natural gas can
also power vehicles in other ways. Natural gas can be
converted into liquid fuel such as gasoline and diesel
(distinct from LNG) that can be used in conventional
internal combustion engines, reformed into hydrogen
for use in fuel-cell vehicles, or be used to generate elec-
tricity for electric vehicles. Despite the existence of these
FIGURE 1: Energy Sources in the U.S.
Transportation Sector, 2010
Source: Energy Information Administration, “Annual Energy Review,”
Table 2.1e. October 2011. Available at: http://www.eia.gov/totalenergy/data/
annual/showtext.cfm?t=ptb0201e
Biomass
4%
Natural Gas
3%
Petroleum
93%

technologies, only about 117,000 of the more than 250
million vehicles on the road in 2010 (about 0.05 percent)
were powered directly by natural gas.231
The majority of
natural gas-powered vehicles are buses and trucks.232
Compressed and Liquefied Natural Gas
CNG is the most common natural gas fuel used in
transportation today. There were 115,863 compressed-
natural gas vehicles on U.S. roads in 2010, using
988 fueling sites.233
The majority is found in larger
transportation fleets. Although Honda offers a CNG
passenger vehicle, only 4,000 vehicles were scheduled
for production in 2012.234
Public transit buses are the
largest users of natural gas in the transportation sector,
with about one-fifth of buses running on CNG or LNG.
Some commercial fleets use natural gas-powered trucks,
including thousands of trucks at FedEx, UPS, and
ATT.235, 236
Waste Management has the largest fleet of
natural gas vehicles in the country with 1,700 trucks that
can run partially on biogas supplied from its own landfill
assets.237
The low cost and environmental benefits of this
biogas are encouraging the company to continue conver-
sions and to open some of its refueling infrastructure
to the public.
To a lesser extent than CNG vehicles, vehicles powered
by LNG (primarily heavy-duty trucks) are also used on
U.S. roads and a fueling infrastructure has begun to
develop. LNG is created by chilling natural gas to -260°F
at normal pressures, at which point it condenses into
a liquid that occupies 0.0017 percent of the volume of
the gaseous form.238
The conversion of natural gas to
LNG removes compounds such as water, carbon dioxide
(CO2
), and sulfur compounds from the raw material,
leaving a purer methane product whose combustion
results in less air pollution.239
The stable, non-corrosive
form also makes LNG more easily transportable, and it
can be moved by ocean tankers or trucks.240
Use of LNG
requires large, heavy, and highly insulated fuel tanks to
keep the fuel cold, which adds a significant cost to the
vehicle.241
Today, LNG is mainly used as a replacement
for diesel fuel in heavy-duty trucks because they can
accommodate this hefty storage system and can use
LNG fueling infrastructure currently limited to trucking
routes.242
In 2010, there were only 40 public and private
LNG refueling sites,243
serving 3,354 LNG vehicles.244
Recently, the Clean Energy Fuels network launched the
development of an interstate LNG refueling network,
mainly taking advantage of existing diesel fueling
FIGURE 2: Oil Price as a Multiple of Natural Gas Prices, 1986 to 2012
Source: Energy Information Administration, “Annual Energy Outlook 2012 Early Release,” 2012. Available at: http://www.eia.gov/oiaf/aeo/tablebrowser/#release=
EARLY2012subject=0-EARLY2012table=7-EARLY2012region=0-0cases=full2011-d020911a,early2012-d121011b
0
2
4
6
8
10
12
Jan-2012
Jan-2011
Jan-2010
Jan-2009
Jan-2008
Jan-2007
Jan-2006
Jan-2005
Jan-2004
Jan-2003
Jan-2002
Jan-2001
Jan-2000
Jan-1999
Jan-1998
Jan-1997
Jan-1996
Jan-1995
Jan-1994
Jan-1993
Jan-1992
Jan-1991
Jan-1990
Jan-1989
Jan-1988
Jan-1987
Jan-1986

stations along highways and trucking distribution
centers. Seventy stations were opened in 2012, with plans
for 70 to 80 more in 2013.245
CNG and LNG are less dense forms of energy than
conventional gasoline and diesel fuel (Figure 3),
requiring vehicles running on them to have larger fuel
tanks in order to store the same amount of energy. CNG
requires special storage because the gas is compressed to
less than 1 percent of its volume at standard atmospheric
pressure.246
Vehicles use cylindrical storage tanks capable
of fuel pressures of up to 3,600 pounds per square inch.
These tanks are significantly larger and heavier than
conventional gasoline or diesel fuel tanks, and their
placement in passenger vehicles can take up valuable
passenger or trunk space.247, 248
The energy density of
CNG is so low that CNG vehicles with ranges greater
than 300 miles are unlikely to be produced unless
current space and weight limitations are overcome.
Therefore, CNG is primarily suitable for fleet passenger
vehicles, municipal buses, and other vehicles where travel
distances are shorter. The greater energy density of
LNG, however, makes it practical for long-haul tractor-
trailers that can accommodate larger fuel tanks.249
Despite being less energy-dense than gasoline or diesel,
both CNG and LNG can be an attractive fuel source
for certain applications, from both an economic and
environmental perspective.
Fuel Cell-Powered Vehicles
Natural gas also plays a role in supplying fuel cell vehicles
(see chapter 7 for a discussion of stationary fuel cells in
distributed generation). Fuel cells produce electricity
through an electrochemical process rather than through
combustion, resulting in heat and water and far lower
emissions of greenhouse gases and other pollutants.
Fuel cells are fueled by hydrogen, and the most common
source of hydrogen today is natural gas. Hydrogen can
be extracted on board the vehicle using a reformer,
or it can be externally extracted and subsequently
added to the vehicle.250
Today, no light-duty fuel cell
vehicles are commercially available in the United States,
although there are certain test vehicles on the road as
well as rudimentary hydrogen fueling infrastructure in
California.251
Companies are working to introduce fuel
cell vehicles to the market. In the United States, Hyundai
plans to build 1,000 fuel cell vehicles for distribution in
2013,252
and Toyota has suggested that production costs
are decreasing such that it should be able to sell fuel cell
vehicles for $50,000 by 2015.253
Gas to Liquids
While CNG and LNG are today the most common
forms of natural gas fuels in vehicles, other available
technologies could increase the use of natural gas in the
broader transportation system. Gas-to-liquids technology
refines natural gas into gasoline or diesel hydrocarbons,
which can be used in existing vehicles and moved
through existing infrastructure. Gas-to-liquids products
have energy densities similar to those of traditionally
produced gasoline and diesel, properties that allow for
better engine performance and potentially fewer emis-
sions of greenhouse gases and regulated pollutants,254
although more empirical study is needed on emissions.
Conversion technologies typically require 10 thousand
cubic feet (Mcf) of natural gas to produce one barrel of
oil-equivalent product output, such as diesel, naphtha,
and other petrochemical products.255
Using $4 per Mcf
of natural gas as inputs to this conversion, the outputs
are equivalent to $40 per barrel of oil-equivalent.
Gas-to-liquids products have been produced at facilities
elsewhere in the world, and new facilities in the United
States are being developed. Several companies are
considering gas-to-liquids facilities on the Gulf Coast
because of favorable natural gas supplies and current
domestic prices.256
FIGURE 3: Comparison of the Energy Density
of Natural Gas and Diesel Fuel
Source: Energy Information Administration, “Annual Energy Outlook 2010 with
Projections to 2035,” 2010. Available at: http://www.eia.gov/oiaf/aeo/
otheranalysis/aeo_2010analysispapers/factors.html
0.0
0.2
0.4
0.6
0.8
1.0
1.2
CNGLNGGasolineDiesel
RatioofDensityComparedtoDiesel

Electric Vehicles
Natural gas also plays a role in electric vehicles, which
are becoming more common on U.S. roads. These
vehicles use electricity from the electrical grid, which
is increasingly powered by natural gas as a fuel source.
From January 2011 to December 2012, Americans
purchased more than 60,000 plug-in electric vehicles,
including Chevrolet Volts, Nissan LEAFs, and Toyota
plug-in Priuses.257
Additionally, plug-in electric vehicles
are now available from BMW, Ford, Tesla, Mitsubishi,
and Daimler.258
When fueled by electricity generated by
a combined-cycle natural gas power plant, such natural
gas-powered electric vehicles offer significant efficiency
and emissions benefits over conventional diesel- or
gasoline-powered vehicles.259
Greenhouse Emissions of Natural Gas as a
Transportation Fuel
Transportation accounts for more than 25 percent of
U.S. greenhouse gas emissions and is an important focus
of U.S. emission reduction efforts. Natural gas emits
fewer greenhouse gases than gasoline or diesel when
combusted or used in fuel cells (Figure 4). Fuel Cells
offer the greatest potential emission reduction benefit
but today are also the most expensive. CNG offers the
next largest greenhouse gas reduction potential and can
be used in many transportation options including fleets,
heavy-duty vehicles and passenger vehicles. The barriers
and potential for emission reductions associated with
fuel switching to natural gas in major segments of the
transportation sector are described below.
Natural Gas in Buses and Medium- and
Heavy-Duty Vehicle Fleets
Buses produce a very small share of overall greenhouse
gases, contributing only 1 percent of emissions from
on-road vehicle transportation in 2011, but as previously
mentioned, they are the most common use of natural gas
in vehicles today.260
In contrast, long-haul tractor-trailers
play a more important role in U.S. energy consumption
and greenhouse gas emissions. These vehicles account
for two-thirds of all fuel consumption for freight trucks
(medium- and heavy-duty trucks), and freight trucks’
emissions are increasing more rapidly than those of
other transportation sources. Over time, freight trucks
will likely account for an even larger percentage of the
sector’s greenhouse gas emissions, as they will take on
a greater portion of deliveries for consumer products,
using more vehicles for just-in-time shipping and taking
advantage of lower labor costs and changing land use
patterns.261
Consequently, reducing the carbon intensity
of freight trucks will be critical to reducing transporta-
tion sector greenhouse gas emissions, and increased
natural gas use is one opportunity to do so.
Barriers to Expanded Natural Gas Use
Significant barriers exist for the expansion of natural gas
use in medium- and heavy-duty vehicles. Currently, trucks
utilizing CNG or LNG have shorter ranges, fewer refueling
options, and lower resale value than traditional diesel-
powered trucks. A diesel truck with a 150-gallon tank and
FIGURE 4: Full Lifecycle, Total Carbon
Intensity of Selected Transportation Fuel
Options as a Percentage Reduction from
Gasoline Carbon Intensity
Source: California Air Resources Board, “Proposed Regulation to Implement
the Low Carbon Fuel Standard,” March 5, 2009. Table ES-8. Available at:
http://www.arb.ca.gov/fuels/lcfs/030409lcfs_isor_vol1.pdf
Notes: The carbon intensities compared above were calculated specifically for
California’s Low Carbon Fuel Standard program using the GREET model.
Results from the GREET model rely on the assumptions included in the model.
Other models may use other assumptions and yield different results. Models
are useful for insights, but their results depend on the assumptions made.
-60%
-50%
-40%
-30%
-20%
-10%
0%
Hydrogen
for Fuel Cells
CNGLNGDieselGasoline
%ChangefromGasoline
Fuel

a 6 to 7 miles-per-gallon fuel economy can travel about
1,000 miles on one tank, which is significantly more than
its natural gas-powered counterparts. Depending on the
mounting of the cylindrical storage tanks, CNG trucks can
travel between 150 miles and 400 miles between fueling,
while LNG trucks can travel around 400 miles.262
The limited availability of fueling infrastructure also
hampers the deployment of natural gas-powered trucks,
and better infrastructure is required for greater use.263
In May 2012, there were 1,047 fueling stations for CNG
and 53 fueling stations for LNG in the United States, and
53 percent of the CNG stations and 57 percent of the
LNG stations were closed to the public.264
Also, speed of
fueling can be a barrier to deployment in certain fleet
types, as the more common and less expensive fueling
technology requires long filling times. On-time delivery
operations of trucking fleets may not be able to accom-
modate long filling. Slow filling is more appropriate for
trucks such as waste trucks or buses that may idle for
long periods overnight or between uses.265
Fuel pricing differentials are a clear driver for natural
gas conversions in the transportation sector since fuel
costs are a significant portion of the overall operating
budgets for fleet owners. Medium-duty trucks use about
6,000 gallons of fuel per year, while heavy-duty trucks
use about 18,000 gallons. At $3.50 per gallon of diesel
fuel, annual fuel costs are $21,000 for a medium-duty
truck and $63,000 for a heavy-duty truck. Natural gas
fuel costs are substantially lower than diesel fuel. At a
price of $2.80 per diesel gallon equivalent—a typical
price for LNG or retail CNG—annual fuel costs would
fall to $16,800 per medium-duty truck and $50,400 per
heavy-duty truck. At a slow-fill CNG cost of $1.00 per
diesel-gallon-equivalent, costs drop to less than one-third
the cost of diesel, to $6,000 per medium-duty truck and
$18,000 per heavy-duty truck. These fuel savings offer
great incentives for fuel-switching.266
However, fleet economics are often more complex,
extending beyond just fuel costs. Natural gas trucks are
about $30,000 to $50,000 more expensive than their
diesel counterparts, a substantial additional capital cost.
Adoption of natural gas trucks also requires fleet owners
to invest in additional maintenance capacity for natural
gas vehicles, requiring investments in new materials and
job training. Complying with standards for maintaining
natural gas trucks, such as those required under
Occupational Safety and Health Administration regula-
tions for compressed gases, adds costs.267
These costs
may further rise as regulations for this nascent industry
develop and change. Resale value of natural gas trucks is
another important factor for some fleet owners. Trucks
from some large fleets may be resold in as little as three
to four years, often to smaller trucking companies that
may not be able to use natural gas vehicles due to a lack
of available infrastructure or a skilled workforce. As a
consequence, even with the potential fuel savings, many
fleet owners may have little economic incentive to switch
to natural gas trucks.
Overcoming Barriers
The cost-benefit ratio of CNG vehicles for fleet owners
depends on the many variables inherent in the composi-
tion and use of vehicle fleets and the costs of refueling
infrastructure. For fleet owners, range requirements
may not be a significant issue, since fleet vehicles travel
regular and known paths. Refueling can take place at
a centralized facility or along a set route.268
The U.S.
Department of Energy’s National Renewable Energy
Laboratory conducted research into three different
types of CNG fleets that might be used by municipal
governments—transit buses, school buses, and refuse
trucks—and possible refueling infrastructures. This
segment was targeted based on the potential for long-
term cost-effectiveness, consistency of operational costs,
lower greenhouse gas emissions, and other factors.269
The research led to the creation of a model for fleet
profitability that highlighted the importance of fleet
size and vehicle miles driven in calculating the cost and
benefits of CNG vehicles. It estimated payback periods of
three to 10 years that were sensitive to the costs related
to refueling stations and vehicle conversion, operations,
and maintenance.
This model includes the cost of building and oper-
ating centralized fleet-specific refueling infrastructure
and thus avoids the “chicken versus egg” refueling quan-
dary that is challenging to non-municipal fleet applica-
tions, such as small private trucking operations. The
lack of a public CNG refueling infrastructure hinders
fleet owners’ decisions to convert heavy-duty vehicles to
CNG. Conversely, the low numbers of heavy-duty vehicles
converted to CNG dampens private and public sector
investor motivation to build CNG refueling infra-
structure. Were it not for the lack of a public refueling
infrastructure, the rationale for fleet owners to convert
heavy-duty vehicles would be much more compelling, as
their high annual miles driven provide a much quicker

return on the upfront cost of vehicle conversion than do
the annual miles driven of municipal fleet vehicles.
One approach that may help to overcome the vehicle-
conversion-versus-refueling-infrastructure hurdle is to
focus on one subset of the high-mileage, heavy-duty
tractor-trailer industry segment, namely, intercity (as
opposed to interstate) transport. In intercity regions with
areas of high tractor-trailer usage, a very small number
of public CNG refueling stations can serve a large
number and percentage of the heavy-vehicle transporta-
tion segment. The United States has 11 “Megaregions”
where tractor-trailers travel tens of thousands of miles
annually but never leave the confines of a relatively small
geographic area (Figure 5). Natural gas infrastructure
can be built out in these Megaregions, such as through
the proposed Texas Clean Transportation Triangle
(Figure 6). Nearly 75 percent of the intrastate heavy and
medium transport in Texas occurs within the triangle,
making it an excellent candidate for CNG infrastruc-
ture.270
Nominal public refueling infrastructure for CNG
vehicles in the 11 Megaregions could also prove sufficient
to service the interstate CNG tractor-trailer segment for
a significant portion of the nation and create enough
consumer demand to encourage the installation of
refueling capability throughout the nation’s network of
commercial truck stops.
Natural Gas in Passenger Vehicles
Passenger vehicles account for nearly three-fifths of the
total energy use and greenhouse gas emissions in the
transportation sector. The lower price of natural gas and
the energy security benefits of reducing U.S. consump-
tion of oil have both contributed to recent interest in
using natural gas in passenger vehicles.
FIGURE 5: Emerging Megaregions with High Tractor-Trailer Usage
Source: Regional Plan Association, “Maps,” 2012. Available at: http://www.america2050.org/maps/
6 million +
3 to 6
million
1 to 3
million
150,000 to
1 million
Metro Area Population
Northeast
Great
Lakes
Cascadia
Northern
California
Front
Range
Southern
California
Arizona Sun
Corridor
Florida
Piedmont
AtlanticGulf Coast
Texas
Triangle
© 2008 by Regional Plan Association
The Emerging Megaregions

Barriers to Deployment
Potential barriers to wider deployment of natural gas-
powered passenger vehicles include lack of access to
refueling sites and the vehicles’ limited ranges.271
Home
refueling is one way to potentially increase the number
of refueling sites. While there are 159,006 retail gasoline
stations in the United States,272
more than 65 million U.S.
homes have natural gas service.273
Home refueling of a
CNG vehicle requires the installation of a wall-mounted
electric compressor to deliver the low-pressure gas from
the residential system into the high-pressure CNG vehicle
tank. The compressors are small and unobtrusive, but
require several hours to fill the vehicle’s tank.274
Home
refueling options may, in addition to providing lower fuel
prices, persuade some consumers to consider purchasing
CNG passenger cars or to convert existing ones from
gasoline-powered cars. Yet, home fueling infrastructure
has remained expensive. Home fueling appliances, such
as Phil, can cost more than $4,000,275
not including the
construction and permitting costs of extending home
natural gas pipe access to the garage or carport. Other
barriers to adoption exist. CNG vehicles, when compared
with conventional gasoline vehicles, have a reduced range
because of CNG’s lower energy density (the maximum
range of the Honda Civic GX NG is 248 miles),276
higher
up-front costs, and smaller trunk capacity.
Fleets including taxis, business, and government
vehicles may offer the greatest potential for natural gas use
in passenger vehicles. In 2012, 22 states signed a memo-
randum of understanding to jointly solicit automaker
proposals to produce seven categories of natural gas
vehicles for purchase by state, local, and municipal fleets.
The intention of this joint effort is to stimulate the market
for natural gas vehicles and eventually expand opportuni-
ties for market growth in the private sector for passenger
natural gas vehicles, as well as to decrease the fleets’
associated air pollution.277
Combined, the barriers associ-
ated with the deployment of light-duty natural gas vehicles
are noticeably larger and more costly than those associated
with CNG- and LNG-powered heavy-duty vehicles.
Energy Security
Increased use of these vehicles offers significant poten-
tial benefits to U.S. energy security. Energy security is
the adequacy and resiliency of the energy system as it
relates to energy production, delivery, and consumption.
The U.S. transportation sector relies on a global oil
market that is currently dominated by an oligopoly—the
Organization of the Petroleum Exporting Countries
(OPEC)—as well as national oil companies. OPEC’s
ability to constrain supplies results in oil prices higher
than a competitive market would produce. Monopoly
power, combined with oil price shocks, mean that the
U.S. economy loses hundreds of billions of dollars per
year in productivity. Researchers at the Oak Ridge
National Laboratory estimate that the combined total
of these costs has surpassed $5 trillion (in 2008 dollars)
since 1970.278
Moreover, most experts believe that rising
demand in emerging market economies coupled with
supply-side challenges can be expected to lead to future
volatility in oil prices, which would be highly damaging
for U.S. consumers and businesses. Replacing oil with
domestically produced natural gas would have significant
benefits for U.S. energy security.
FIGURE 6: Texas Clean Transportation
Triangle
Source: Gladstein, Neandross Associates / America’s Natural Gas Alliance

Conclusion
The transportation sector has long relied on petroleum
fuels for the vast majority of its energy needs. While
utilizing natural gas as a fuel source in this sector offers
greenhouse benefits, in total these benefits are less likely
than in other sectors of the economy, given the difficulty,
cost and speed of converting passenger vehicles to
natural gas. Moreover, in the near and medium term,
fuel economy for gasoline-powered passenger vehicles is
set to rise due to new Corporate Average Fuel Efficiency
Standards, which could reduce the emissions advantage
of natural gas vehicles. Hybrid and electric passenger
vehicles are also becoming more common, and given
the widespread availability of electricity compared to the
availability of natural gas, they require less infrastructure
investment than do natural gas vehicles. These factors
indicate that, considering the need for substantial
long-term reductions in greenhouse gas emissions from
the transportation sector, by the time a fleet conversion
to natural gas would be completed for passenger vehicles,
a new conversion to an even lower-carbon fuel will be
required. A passenger vehicle fleet conversion to natural
gas would be short-lived and yield a low return on invest-
ment from a climate perspective.279
As in other sectors of the economy, fuel substitution
from other fossil fuels to natural gas in some parts of the
transportation sector has the potential to yield climate
benefits. In addition, it would benefit U.S. national
security by decreasing our reliance on a global oil market
dominated by outside forces. Although the potential for
natural gas use is less in the transportation sector than
in others, the potential does exist, primarily for medium-
and heavy-duty trucks as well as fleet vehicles and buses.

IX. INFRASTRUCTURE
By Michael Tubman, C2ES
Introduction
The United States has the world’s most extensive infra-
structure for transporting natural gas from production
and importation sites to consumers all over the country.
This transport infrastructure is made up of three main
components: gathering pipelines, transmission pipelines,
and distribution pipelines.280
Though fundamentally
similar in nature, each type of pipeline is designed for a
specific purpose, operating pressure and condition, and
length. These components are linked in networks to form
the U.S. natural gas infrastructure system (Figure 1).
Rising demand for natural gas in the electric power,
manufacturing, buildings, and transportation sectors
requires significant expansion of the natural gas infra-
structure system if these sectors are to reap the potential
cost savings and energy security benefits. Increased use
of natural gas, when substituted for other fuels, also can
significantly reduce greenhouse gas emissions, as long as
methane leakage emissions from natural gas systems are
minimized. This chapter describes the elements of the
U.S. natural gas system and how they function together.
Next, it highlights the regional natural gas flows from
producing basins to areas of consumption. Then, it
discusses the critical issue of methane emissions. Finally,
it explores the barriers to infrastructure development
and outlines recent innovations in funding models.
Elements of the U.S. Natural Gas System
Almost all natural gas consumed in the United States is
produced in North America, from onshore or offshore
wells or, to a much lesser extent, biogas production sites.
Natural gas first enters the transport network through
gathering pipelines that collect it from the point of
production, most commonly the wellhead at the point of
extraction, and carry it to processing facilities. Gathering
pipelines are usually short and small in diameter and
operate at low pressures. In 2011, there were almost
20,000 miles of gathering pipelines in the United States,
originating at more than 460,000 wellheads.281
Once gathered from well sites, natural gas is processed
to remove impurities such as sulfur and carbon dioxide
Figure 1: U.S. Natural Gas System
Source: American Gas Association, “About Natural Gas,” 2013. Available at: http://www.aga.org/Kc/aboutnaturalgas/Pages/default.aspx
Producing
Wells
Natural Gas
Delivery System
Processing
Plant
Compressor
Station
1,700 Electric
Power Plants
Transmission
Underground
Storage
Utility
Underground
Storage
65 Million
Households
5 Million Commercial Customers
Offices, Hospitals, Hotels and Restaurants
City Gate Station
Regulator/
Meter Regulator/
Meter
Regulator/
Meter
Regulator/
Meter
Regulator/
Meter
Local Utility
Regulator
Supplemental Fuels
Liquefied Natural Gas,
Propane Air for peak
demand days
195,000 Factories and
Manufacturers
Gathering
Lines

(CO2
) and is dehydrated to remove any water. It is
then piped to where there is consumer demand, often
hundreds of miles away, through transmission pipelines.
Large-diameter (20- to 42-inch), high-pressure transmis-
sion pipelines, often called interstate pipelines or trunk
lines, efficiently move the gas over vast distances. In 2011,
there were 304,087 miles of transmission pipeline in the
United States.282
To ensure pressure in the pipeline and
keep the natural gas flowing, compressor stations are
placed every 40 to 100 miles. These stations apply pres-
sure to the gas and often filter the gas again to maintain
purity. Meters are placed along transmission pipelines to
monitor the flow, and valves located at regular intervals
can be used to stop flow if needed.283
At various points along the gathering and transmis-
sion networks, natural gas can be stored temporarily
underground in depleted oil or natural gas fields, aqui-
fers, and salt caverns. Storage is used to enhance supply
reliability and serves as a physical hedge against the
seasonality of natural gas demand. Traditionally, excess
supplies of natural gas are stored during the summer
and then withdrawn to serve heating demand during
the winter or when there are unforeseen supply disrup-
tions. However, as natural gas demand has increased for
power generation, including for cooling needs in the
summer months, the seasonality of natural gas demand
has diminished to some extent. Natural gas can also
be stored when purchased at low prices and withdrawn
when prices rise, to be sold or consumed. In 2010, there
were 400 storage facilities across the United States.284
To reach homes and businesses, natural gas leaves
the transmission pipeline network and enters the “city
gate station,” where local distribution companies (local
gas utilities) add odorant and lower the pressure before
distributing it to residential and commercial customers.
Local distribution companies move the gas through
a series of larger distribution pipelines, called mains,
throughout their service territory, and individual service
lines branch off of the mains to reach each consumer.
Natural gas regulators, devices in homes and commercial
buildings, accept the incoming gas from the highly
pressured pipelines and employ a series of valves to lower
the pressure of the gas to meet appliance specifications.
Distribution pipelines are much smaller pipelines, often
only 0.5 to 2 inches in diameter, with pressures at a small
fraction of those of the larger transmission pipelines.
They may be made of plastic, which is less likely to
leak than metal. Distribution networks used by local
distribution companies are extensive, having more than
2 million miles of main and individual service pipelines
as of 2011.285
Together, these components of natural gas infra-
structure comprise an important asset that provides
access to energy for all sectors of the economy. However,
it is a large, dispersed asset that is mostly out of sight.
Gathering and transmission pipelines are often in
remote locations, while distribution pipelines, though
located near the customers they serve, are buried
underground. Some pipelines exist within rights-of-
way occupied by other users, such as roads or private
property, and pipelines often cross local, state, and even
national boundaries. These factors make monitoring
and regulating pipelines the responsibility of multiple
jurisdictions and many levels of government.
Pipelines are regulated by both the federal and state
governments. In 2007, 81 percent of natural gas in the
United States flowed through transmission pipelines that
cross state boundaries. The Federal Energy Regulatory
Commission regulates the rates and services of these
interstate pipelines as well as the construction of new
interstate pipelines. Other pipelines located within states
(intrastate pipelines) are regulated by state regulatory
commissions. State regulatory commissions regulate
both transmission lines and local distribution companies
for pipeline siting, construction, operation, and expan-
sion, as well as consumer rate structure.286
The federal government also regulates and
enforces pipeline safety through the Department of
Transportation, which works closely with state govern-
ments on pipeline inspection and safety protocols.
Corrosion and defects can lead to leaks that have serious
safety and environmental implications. Visual inspection
of natural gas infrastructure is difficult, and complete
replacements are nearly impossible given the vast extent
of the network and its location underground. Instead,
robotic inspection tools, often called “pigs,” can be sent
through pipelines to detect leaks, check pipeline condi-
tions, and monitor for weaknesses.287
Regional Differences in Infrastructure
and Expansion
The capacity, extensiveness, and flow direction of existing
natural gas infrastructure varies across the country,
reflecting historical supply and demand for the fuel as well
as disparate state and local policies that enabled infra-
structure expansion. Gathering line networks are most
extensive from wellheads in traditional gas-producing

states such as Texas, Oklahoma, and Louisiana, and
most existing intrastate transmission lines take the fuel
from those states to manufacturers and consumers in the
Midwest and Northeast (Figure 2).
Recent supply increases, lower prices, and increased
demand have all led to a need for expanded infrastruc-
ture, including gathering, transmission, and distribution
pipelines that can bring natural gas to users and may
allow natural gas to replace higher-carbon fuel sources
and achieve climate benefits. Changes in supply and
demand will require that 28,000 to 61,900 miles of new
pipelines be constructed in North America by 2030, and
$108 to $163 billion worth of investment will be needed.
Additional storage capacity of 371 to 598 billion cubic
feet (Bcf) will also be needed over the same time period,
at a cost of $2 to $5 billion.288
Current trends in natural
gas supply and demand indicate that expansion is likely
to fall on the higher ends of these estimates.
Infrastructure needs related specifically to shale gas
are growing across the country, reflecting the location of
the shale gas resources. Significant investments related
to shale gas have been made in states such as Texas
and Louisiana that have historically been supply states
for conventional gas deposits. Significant additional
infrastructure expansion is also needed in parts of the
country that have not historically produced natural
gas but have been traditional destinations, such as
Ohio, Pennsylvania, North Dakota, and West Virginia.
Furthermore, new sources of biogas need infrastructure
to collect, process, and either transport the gas to
existing transmission infrastructure or use it on site.
Although the potential of renewable biogas to reduce
greenhouse gas emissions is large, further research
is needed to ensure that it can be processed properly
and safely added to the existing system, which was built
specifically to withstand the constituents of geologically
formed natural gas.289
In sum, several of the new supply
sources require new infrastructure, and in other cases,
existing infrastructure may be repurposed and deployed
to bring new sources to market. As more new sources are
Figure 2: Interstate Pipelines, 2013
Source: Interstate Natural Gas Association of America and PennWell

tapped, the existing transmission pipeline infrastructure
must continue to be creatively deployed and expanded to
serve regional market needs.
Similarly, local distribution networks will need to be
expanded, with new demand for natural gas appliances,
industrial uses, distributed generation, and vehicle
fueling in homes and businesses. Investments are neces-
sary in new mains, service lines, meters, and regulators
that can service new customers. Indirect investments will
also be required to enhance the capacity of the overall
system, including for control rooms, main reinforce-
ments, and improved flow design.290
Direct Emissions from Natural Gas
Infrastructure
In 2011, methane emissions from transmission pipelines
and storage totaled 44 million metric tons of CO2
equiva-
lent (CO2
e), while emissions from distribution networks
totaled 27 million metric tons CO2
e.291
These figures have
been fairly consistent over time as network expansion has
been offset by better system management (including leak
detection), more energy-efficient technology, and the
replacement of equipment with new materials that are
less subject to leakage, including replacing cast iron and
steel pipe with plastics.292, 293
While methane emissions
from natural gas infrastructure are a very small portion
of the nation’s total greenhouse gas emissions (Figure 3
and Figure 4), methane is a potent greenhouse gas, as
described in chapter 3. Given methane’s potency, it is
critical to reduce leakage to ensure that its climate benefits
are maximized when compared with other fossil fuels that
it may replace.294
Leaked Methane
Throughout the transportation of the fuel from gathering
at the well to distribution to end-use consumers, there
is potential for methane to leak into the atmosphere.
Potential leakage points include production wells, valves,
compressor stations, faulty seals, pressure regulators, and
even broken pipes. Because methane leakage and accu-
mulation can be an important safety issue, natural gas
operators have robust safety programs in compliance with
federal and state pipeline safety requirements to detect
and repair leaks that pose safety risks. Methane emissions
that do not pose safety concerns nevertheless can have
significant implications for the climate and for the relative
benefits of substituting natural gas for other fuel sources.
At natural gas storage facilities, methane emissions may
leak from compressors and dehydrators. At the local
distribution level, methane emission leakage can occur at
city gate station valves, seals, and pressure regulators, or
from the joints of cast iron or unprotected steel pipe.295
The majority of all greenhouse gas emissions from natural
gas infrastructure are due to leaked emissions.296
Figure 3: Historical Emissions from
Transmission, Storage and Distribution,
2007 to 2011
Source: Environmental Protection Agency, “U.S. Greenhouse Gas Inventory
Report,” 2013. Available at: http://www.epa.gov/climatechange/Downloads/
ghgemissions/US-GHG-Inventory-2011-Chapter-3-Energy.pdf
Figure 4: Emissions from Natural Gas
Infrastructure as a Percentage of Total U.S.
Greenhouse Gas Emissions, 2011
Source: Environmental Protection Agency, “U.S. Greenhouse Gas Inventory
Report,” 2013. Available at: http://www.epa.gov/climatechange/Downloads/
ghgemissions/US-GHG-Inventory-2011-Chapter-3-Energy.pdf
Distribution
0.42%
Transmission
and Storage
0.65%
All Other
Sources
98.93%
0
10
20
30
40
50
60
70
80
20112010200920082007
AnnualEmissionsin
MillionMetricTonsofCO2
Equivalent
Distribution
Transmission and Storage

Venting and Flaring
In addition to leaked emissions, methane can be inten-
tionally released or vented as part of the production
process at the wellhead or to reduce pipeline pressure. For
safety and environmental reasons, however, intentionally-
released methane is often burned off in a process called
flaring. Flaring combusts the methane on site, forming
CO2
, a less potent, though very significant, greenhouse
gas.297
(The climate implications of CO2
and methane
are compared in chapter 3.) Flaring of methane most
often occurs when natural gas is found as a byproduct or
co-product of other fossil fuel production and insufficient
gathering pipeline infrastructure or market incentives
exist to take the natural gas to market. In 2012 in Texas,
where gathering pipeline networks are well developed, less
than 1 percent of the natural gas produced was flared.298
In North Dakota, where oil production from the Bakken
Shale formation is a much newer phenomenon, almost 32
percent of the associated natural gas is flared, primarily
because of a lack of gathering infrastructure.299
With
relatively low natural gas prices, there is less economic
incentive for companies to build gathering infrastructure
and monetize the resource.
In August 2012, a new federal requirement to
minimize venting and flaring was established as part
of the Environmental Protection Agency’s New Source
Performance Standards for oil and gas wells. The new
regulations require that all new natural gas wells flare
rather than vent, and as of 2015 use “green completion”
technology that will allow excess natural gas from the
well completion process to be taken to market. Many
natural gas producers already use such technology.300
However, for the “green completion” rule to apply to
the gathering of natural gas from the Bakken Shale or
other primarily oil production sites, it would have to be
expanded from its present form (see the discussion of
“green completion” rules in chapter 3).
Reducing Emissions from Infrastructure
Many technologies and process improvements can
reduce methane emissions from natural gas infra-
structure. The federal Natural Gas STAR program, for
example, has worked with industry to identify technical
and engineering solutions to vented, leaked, and combus-
tion-related emissions, including zero-bleed pneumatic
controllers, improved valves, corrosion-resistant coatings,
and dry-seal compressors, as well as improved leak detec-
tion and repair strategies. The solutions identified by this
voluntary program often have payback periods of less
than three years, depending on the price of natural gas.
Participants in Natural Gas STAR reported that methane
emissions from infrastructure were reduced by 15.9 Bcf
in 2010, and overall, a total of 276.5 Bcf of greenhouse
gases have been avoided since the program began in
1993.301
Local distribution companies have reduced emis-
sions from their low-pressure networks by continuing to
replace cast iron and steel pipes with inexpensive and
durable plastic pipes; however, this plastic is not strong
enough to be used in high-pressure transmission lines.302
Barriers to Infrastructure Development
As other chapters in this report explain, natural gas
may be used to reduce greenhouse gas emissions in
multiple sectors of the economy, including electric
power, manufacturing, buildings, and transportation.
While new pipelines are being built every day, there is a
dramatic need for new pipeline investment to move new
sources of natural gas supply to new regions and new
users. Distribution pipeline networks, in particular, are
challenged by financial and other barriers to expansion
and improvement.
Funding Distribution Pipeline Expansion
For local distribution networks, the cost of expansion
varies considerably depending on whether the network
is being expanded to new or existing communities, the
density of the neighborhood, and the terrain. For new
distribution pipelines in urban areas, challenges include
costly repairs of overlaying roads and landscaping,
negotiations with entities holding surface and other
subsurface rights-of-way, and public inconveniences.
Accordingly, new urban pipelines can cost five times
as much as rural ones.303
Costs can be lowered when
buildings are designed and constructed to be ready for
natural gas access; retrofitting existing buildings with
internal piping and hook-ups to natural gas supplies is
more expensive.
Funding local distribution networks can be chal-
lenging and is typically dealt with through a formal regu-
latory proceeding called a rate case where public utility
commissions determine allowable utility rates based on
factors including utility operation costs, depreciation,
investment, and consumer needs. Traditionally, expan-
sion costs are considered during the rate case proceed-
ings, but costs can only be recovered after investments
are made. This time lag discourages or prevents utilities

from investing in infrastructure. State-level regulatory
innovations have provided some policy options to
overcome these investment challenges. Some states, such
as Nevada, allow the use of a deferred accounting mecha-
nism so that costs can be better aligned temporally with
ratemaking cases before state regulatory commissions.
Seven southern states, including Texas, have decoupled
gas consumption and cost recovery to create what is
known as a “rate stabilization method.” This method
allows rates to adjust annually for infrastructure replace-
ment and construction rather than simply the amount of
natural gas throughput.304
Funding models that can foster greater access to
natural gas are being explored throughout the country.
For example, in North Carolina, rules established by the
public utilities commission allow for dedicated funds for
new distribution pipelines. A local distribution company
may petition the public utilities commission to establish
a Natural Gas Expansion Fund to help pay for the
otherwise economically infeasible expansion of distribu-
tion pipelines. Additional money may be added to the
Natural Gas Expansion Fund, including refunds from
natural gas suppliers to the local distribution company,
expansion surcharges, and other resources, and then,
with approval by the public utilities commission, the
company may pay for the specified distribution pipeline
construction projects.305
In 2011, the Vermont Public
Service Board approved a plan by Vermont Gas Systems
to use $17.6 million previously planned for ratepayer
refunds to instead support expansion of its distribution
network over four years, although these funds will cover
only part of the needed finance.306
This plan transferred
some of the costs of expansion onto existing customers
and offered the reduction of statewide greenhouse gas
emissions as one rationale.307
A 2012 law passed by the
Maine Legislature authorizes the Finance Authority
of Maine to issue up to $275 million in loans and $55
million in bonds for natural gas distribution system
expansions. The funds will be available only if the
applicant contributes at least 25 percent of the expected
cost of the project.308
Municipal utilities can also offer
innovative solutions. For example, the municipal natural
gas utility in Sunrise, Florida, will install main and
service lines to neighborhoods at no cost as long as 25
percent of residents commit to installing a natural gas
space or water heater, range, or clothes dryer within six
months. Natural gas piping within the homes must be
paid for by residents.309
Funding Upgrades and Replacements
Other innovative policy mechanisms are being developed
to pay to upgrade and replace existing pipelines. Some
states, such as Colorado, authorize tracker mechanisms
allowing rates to change in response to the utility’s
operating costs and conditions outside of a complex rate
case proceeding, specifically in response to federal and
state safety requirements. A similar process outside the
rate case in states such as Kentucky permits temporary
surcharges for partial program cost recovery. The
Georgia Public Services Commission has permitted
Atlanta Gas Light Company to institute a surcharge on
customer bills throughout its service territory to help
fund pipeline replacement, improvement, and pressure
increases through the Georgia Strategic Infrastructure
Development and Enhancement (STRIDE) Program.
The Georgia Public Services Commission reviews the
surcharge and related plans every three years, thereby
eliminating the need for rate cases and associated
regulatory lag. Also, from 2009 to 2012, a pilot program
called the Customer Growth Program was paid for
through the STRIDE surcharge. It helped fund new
pipeline construction and extensions, including strategic
development corridors to regions far removed from
existing Atlanta Gas Light Company infrastructure. It
also helped overcome the barrier of high upfront costs
for new natural gas pipelines.310
However, the STRIDE
program has not been renewed. The Atlanta Gas Light
Company Universal Service Fund can also be used to
pay for distribution pipeline expansion, and its monies
may contribute up to 5 percent of Atlanta Gas Light
Company’s capital budget during a fiscal year.
Other Challenges
Beyond questions of funding, pipelines are affected by a
number of project-specific requirements and regulations
at the federal, state, and local levels. These requirements
pertain to route selection, siting, and project approval by
regulatory agencies that may all be affected by envi-
ronmental, safety, community, operation, construction
timing, and cost concerns. The size of the challenge for
any individual project will vary significantly depending
on the pipeline and the jurisdictions it crosses.311
For
natural gas to realize its climate benefits, infrastructure
projects must meet these requirements, allowing the
system to expand for greater low-emission use across
the economy.

Conclusion
Natural gas is transported from areas of production to
final consumers through networks of gathering pipelines,
transmission pipelines, and distribution pipelines. These
extensive networks are necessary to provide opportunities
for low-emission end uses of natural gas. Given the recent
surge in natural gas supply, the new source regions, and
new uses, infrastructure must rapidly adapt. Gathering
pipelines must be brought to more points of production,
including areas where associated gas can be captured for
use. Transmission pipelines must be expanded to ensure
adequate supply can reach new regions of the country.
Distribution pipeline networks must be built out to serve
more manufacturing facilities, homes, and businesses.
Increased policy support and innovative funding, particu-
larly for distribution pipelines, are needed to support the
rapid deployment of this infrastructure.

X. Conclusions and Recommendations
Natural gas plays a role in all sectors of the U.S. economy,
constituting 27 percent of total U.S. energy use in 2012.
Its prominence is expected to grow as the supply boom
unleashed by new drilling technologies continues in
coming decades. Expectations of sustained abundance
and correspondingly low and relatively stable natural gas
prices are sparking widespread interest in additional ways
that this domestic energy resource can replace oil and
coal as the major fuel undergirding a growing economy.
Indeed, natural gas is projected to displace petroleum
as the dominant fuel used in the United States within a
few decades.
In these early days of this energy transition, it is impera-
tive to set a course for using this increasingly abundant
domestic resource in ways that help meet, rather than
aggravate, the challenge of climate change. This report
examines ways that natural gas can be leveraged to reduce
greenhouse gas emissions across a growing economy and
reaches three crosscutting conclusions.
First, substitution of natural gas for other fossil fuels
can contribute to U.S. efforts to reduce greenhouse gas
emissions in the near to mid-term, even as the economy
grows. At the beginning of 2013, energy sector emissions
are at the lowest levels since 1994, in part because of the
substitution of natural gas for coal in the power sector.
Substitution of natural gas for coal, petroleum, and
grid-supplied electricity is underway in other parts of the
economy and will bring similar benefits to the climate
and air quality. In the buildings sector, for example, a
large reduction in emissions is possible through greater
direct use of natural gas in an array of more efficient
appliances and expanded use of CHP. The manufac-
turing sector also has a significant opportunity to reduce
emissions even as it expands. Manufacturers can increase
their consumption of natural gas as feedstock and an
energy source, while reducing the emissions intensity of
production. Finally, in the transportation sector, natural
gas fuel substitution can reduce greenhouse gas emis-
sions when used in fleets and heavy-duty vehicles.
Second, in the long term, the United States cannot
achieve the reduction in greenhouse gas emissions
necessary to address the serious challenge of climate
change by relying on fuel substitution to natural gas
alone. Low-carbon investment must be dramatically
expanded. Zero-emission sources of energy such as wind,
nuclear, and solar are critical, as are the use of carbon
capture and storage technologies at fossil fuel plants and
continued improvements in energy efficiency. Given that
many renewable energy sources are intermittent, natural
gas can serve as a complementary and reliable backup.
In addition, because fossil fuels will likely be part of
the energy fuel mix for the foreseeable future, carbon
capture and storage will need to be deployed. Without a
price on carbon emissions, alternative policy support will
be needed to ensure optimal investment in zero-carbon
energy sources and technologies.
Third, direct releases of methane into the atmosphere
must be minimized. The primary component of natural
gas is methane, which is a very potent greenhouse gas.
Total methane emissions from natural gas systems in the
United States have improved during the last two decades,
declining 13 percent from 1990 to 2011. Nevertheless,
given its impact on the climate, especially in the short
term, it is important to better understand and more
accurately measure the greenhouse gas emissions from
natural gas production and use in order to achieve emis-
sions reductions along the entire natural gas value chain.
The basis for these cross-cutting conclusions is a
detailed examination of the current and potential role
of natural gas in major sectors of the economy. Sector-
specific conclusions and recommendations include:
Expanded use of natural gas has improved fuel diver-
sity in the power sector. From 2003 to 2012, the share
of primary energy consumption from coal for electricity
generation dropped from 53 percent to 37 percent, while
the share fulfilled by natural gas grew from 14 percent
to 29 percent. Accordingly, the fuel mix in electricity
generation has become more diverse in recent years.
However, concern exists that some regions may become
too dependent upon natural gas in the long term,
especially as market pressures affect nuclear and renew-
able energy generation. Too much reliance on any one

fuel can expose utilities, ratepayers, and the economy
to the risks associated with commodity price volatility.
Furthermore, natural gas-fired generation should not
displace investment in zero-carbon generation, carbon
capture and storage, and energy efficiency measures. If
this occurs, the United States will not be able to meet its
long-term goals for reducing greenhouse gas emissions.
Natural gas can be complementary with renewable
energy. Instead of being thought of as competitors,
natural gas and renewable energy sources such as wind
and solar can be complementary components of the
power sector. Natural gas plants have the ability to
quickly scale up or down their electricity production and
so can act as an effective hedge against the intermittency
of renewables. The fixed fuel price (at zero) of renew-
ables can likewise act as a hedge against potential natural
gas price volatility. Low natural gas prices can also
help facilitate an increase in renewable energy in some
regions. In order for this mutually beneficial relationship
to flourish, carefully designed policy that allows the
addition of both sources to the grid in a complementary
fashion must come into play and be encouraged by
public utility commissions. Natural gas plants expansion
should be leveraged to enable the expansion of renew-
able generation.
Natural gas can increase the overall efficiency of
buildings through use of equipment with higher full-
fuel-cycle efficiency. Thermal applications of natural
gas in buildings have a lower greenhouse gas emission
footprint compared with other fossil energy sources.
Natural gas for thermal applications is more efficient
than grid-delivered electricity, yielding less energy losses
along the supply chain and therefore fewer greenhouse
gas emissions. Information and incentives should be
modified to inform consumers of the environmental
benefits of natural gas use and to encourage its increased
use when it has the potential to reduce greenhouse gas
emissions—particularly its direct use in buildings and
manufacturing settings. At present, labeling, building
codes, and economic incentives are not aligned to
maximize the use of natural gas in low-emitting ways.
Aligning incentives is particularly important in the
building sector, as consumers and developers seeking
to minimize up-front cost often do not realize that
operating costs and environmental costs may be much
higher for electric appliances. In addition, although
current energy efficiency programs aim to reduce green-
house gas emissions from appliances and buildings in
two important ways—by setting standards and efficiency
labeling programs—these standards are based solely
on site efficiency, which is reflected in the energy and
cost savings identified on efficiency labels. But efficiency
labels based only on site efficiency do little to educate
consumers about the total energy needed to power
appliances and the greenhouse gases associated with
that energy and, as such, often steer consumers toward
electric appliances even if a natural gas appliance may be
more efficient overall and produce fewer greenhouse gas
emissions. It is important, therefore, that the source-to-
site efficiency of an appliance also be taken into consid-
eration, and in regions with fossil fuel-dominated grid
electricity, natural gas appliances should be encouraged.
The efficient use of natural gas in the manufacturing
sector needs to be encouraged. Replacing old coal-fired
boilers with more efficient natural gas boilers can yield
significant emissions benefits. CHP systems should
also be deployed to make use of waste heat and avoid
transmission losses. The incentives for CHP are often not
properly aligned. Specifically, while CHP has significant
environmental benefits, it can significantly decrease the
demand for grid-supplied electricity, which can impact
the rate base remaining on the grid. Policies are needed
to overcome this and other barriers to expanded CHP
deployment. States are in an excellent position to take an
active role in promoting CHP during required industrial
boiler upgrades and new standards for cleaner electricity
generation in coming years.
Distributed generation technologies can offer
options for using natural gas and reducing emis-
sions. Distributed generation technologies, such as
microgrids, microturbines, and fuel cells, can be used
in configurations that reduce greenhouse gas emissions
when compared with the centralized power system
because they can reduce transmission losses and use
waste heat onsite. Distributed generation has many
other advantages over centralized electricity genera-
tion, including end-users’ access to waste heat, easier
integration of renewable energy, heightened reliability
of the electricity system, reduced peaking power require-
ments, and less vulnerability to terrorism due to more
geographically dispersed, smaller power plants. To
realize the potential of these technologies and overcome
high upfront equipment and installation costs, policies
like financial incentives and tax credits need to be more
widespread, along with consumer education about
their availability.

Fuel substitution in fleets and heavy-duty vehicles
offers the greatest opportunity to reduce greenhouse
gas emissions in the transportation sector. Passenger
vehicles, in contrast, likely represent a much smaller
emission reduction opportunity even though natural
gas emits fewer greenhouse gases than gasoline or
diesel when combusted. The reasons for this include
the smaller emission reduction benefit (compared to
coal conversions), and the time it will take for a public
infrastructure transition. By the time a passenger fleet
conversion to natural gas could be completed, a new
conversion to an even lower-carbon system, like fuel cells
or electric vehicles, will be required to ensure significant
emissions reductions throughout the economy.
Natural gas infrastructure expansion is needed
to ensure access for low-emitting uses. New domestic
supplies of natural gas require significant investment in
infrastructure. Additional gathering and transmission
pipeline capacity is needed in parts of the country that
have not historically produced natural gas but have been
traditional destinations, such as Ohio, Pennsylvania,
North Dakota, and West Virginia. Expanded distribution
pipeline networks are needed to serve greater numbers
of commercial, industrial, and residential natural gas
customers throughout the U.S. Moreover, expanding
natural gas delivery systems within homes and businesses
that have existing access will be necessary to support a
greater number of end-use applications, such as natural
gas-fueled space and water heating. Innovative funding
models and support are needed to make the expansion
and upgrading of natural gas infrastructure economi-
cally feasible for customers and utilities.
In the coming years, abundant natural gas will play an
increasingly prominent role across all sectors of the U.S.
economy. Increased availability of natural gas can yield
economic opportunities and lower greenhouse gas emis-
sions. Yet, natural gas is not carbon-free. A future with
expanded natural gas use will require diligence to ensure
that potential benefits to the climate are achieved.

Endnotes
1 Primary energy sources include petroleum, natural gas, coal, renewable energy, and nuclear power.
2 Massachusetts Institute of Technology Energy Initiative, The Future of Natural Gas: An Interdisciplinary MIT Study,
June 2011, page 17. Available at http://web.mit.edu/mitei/research/studies/natural-gas-2011.shtml.
3 Unconventional resource accumulations tend to be distributed over a larger area than conventional resources,
require greater pressure for extraction (have “low permeability”), and they usually require advanced technologies and
techniques such as horizontal wells or artificial stimulation in order to be economically productive.
4 Energy Information Administration, “Annual Energy Outlook 2013 Early Release,” December 2012. Available at
http://www.eia.gov/forecasts/aeo/er/index.cfm.
5 In economic terms, the supply of natural gas is often referred to as reserves and is classified with two primary
categories, proven and unproven. Proven reserves are those that are economically recoverable from known resources using
currently available technology. Unproven reserves are those considered not economically or technically recoverable or
somehow not producible for regulatory reasons.
6 National Petroleum Council, “Balancing Natural Gas Policy–Fueling the Demands of a Growing Economy,”
National Petroleum Council, September, 2003. Available at Balancing Natural Gas Policy–Fueling the Demands of a
Growing Economy.
7 Energy Information Administration, “Annual Energy Outlook 2012: Early Release Overview,” Report Number
DOE/EIA-0383ER(2012), January 23, 2012, page 9. Available at http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2013).pdf.
Note: EIA’s estimated technically recoverable resource of U.S. shale gas was reduced from 827 Tcf in 2010 to 482 Tcf
in 2011. The decline mostly reflects changes in the assessment for the Marcellus shale, from 410 Tcf to 141 Tcf, based on
better data provided from the rapid growth in drilling in the Marcellus over the past two years.
June 2011. Available at http://web.mit.edu/mitei/research/studies/natural-gas-2011.shtml.
9 Energy Information Administration, “AEO2013 Early Release,” December 2012. Available at http://www.eia.gov/
forecasts/aeo/er/pdf/0383er(2013).pdf.
10 Energy Information Administration, “Total Energy: Natural Gas Consumption by Sector, 1949–2011,”
September 2012. Available at http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb0605.
12 ICF International for the Ontario Energy Board, “2010 Natural Gas Market Review,” August 2010, page 50.
Available at http://www.ontarioenergyboard.ca/OEB/_Documents/EB-2010-0199/ICF_Market_Report_20100820.pdf.
13 The White House, “The Blueprint for a Secure Energy Future: Progress Report,” March 2012, page 2. Available
at http://www.whitehouse.gov/sites/default/files/email-files/the_blueprint_for_a_secure_energy_future_oneyear_
progress_report.pdf.

14 Energy Information Administration, “Annual Energy Outlook 2011: Reference Case,” December 2012. Available
at http://www.eia.gov/forecasts/aeo/er/executive_summary.cfm.
15 C2ES, “Fact Sheet: Natural Gas,” accessed April 2013. Available at http://www.c2es.org/technology/factsheet/
natural-gas#7.
16 Energy Information Administration, “Annual Energy Outlook 2011,” April 26, 2011, Report Number DOE/
EIA-0383(2011), page 2. Available at http://www.eia.gov/forecasts/aeo/pdf/0383%282011%29.pdf.
June 2011. Available at http://web.mit.edu/mitei/research/studies/natural-gas-2011.shtml.
Note: In addition to the Barnett, since 2005 producers have begun intensively developing plays in the Woodford,
north of the Barnett in Texas and Oklahoma; the Fayetteville in Arkansas; and the Haynesville in Louisiana/East Texas.
During this time, development also began in the Marcellus Shale of the eastern United States.
Note: Natural gas and natural gas liquids are a principal feedstock in the chemicals industry and a growing source
of hydrogen production for petroleum refining. Natural gas liquids products can add value for gas producers, especially
important in a low-price environment. The liquid content of a gas—the “condensate ratio”—is expressed as barrels of liquid
per million cubic feet of gas (bbls/MMcf). In a typical Marcellus well, assuming a liquids price of $80/bbl for a condensate
ratio in excess of approximately 50 bbls/MMcf, the liquid production alone can provide an adequate return on the invest-
ment, even if the gas were to realize no market value.
19 Naturalgas.org, “Uses in Industry,” 2004. Available at http://www.naturalgas.org/overview/uses_industry.asp.
20 Energy Information Administration, “Natural Gas Consumption by End Use,” 2013. Available at http://www.eia.
gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm.
21 A set of global supply curves describing the gas resources that can be developed economically at given prices is
provided in MIT Energy Initiative, The Future of Natural Gas: An Interdisciplinary MIT Study, June 2011, page 25. Available at
http://web.mit.edu/mitei/research/studies/natural-gas-2011.shtml.
22 Energy Information Administration, “Natural Gas Year-in-Review: Imports and Exports,” December 9, 2011.
Available at http://www.eia.gov/naturalgas/review/imports_exports.cfm
23 Energy Information Administration, “U.S. Natural Gas Imports by Country,” accessed March 2013. Available at
http://www.eia.gov/dnav/ng/ng_move_impc_s1_a.htm.
24 Energy Information Administration, “Annual Energy Review 2010,” Report Number: DOE/EIA-0384(2010),
October 2011, pages 7, 134 and 193. Available at http://www.eia.gov/totalenergy/data/annual/pdf/aer.pdf.
25 The liquefaction process for natural gas involves removal of certain components, such as dust, acid gases,
helium, water, and heavy hydrocarbons. The natural gas is then condensed into a liquid by cooling it to approximately
-162°C (-260°F). The energy density of liquified natural gas is 60 percent that of diesel fuel.
26 International Gas Union, “World LNG Report,” 2010, page 5. Available at http://www.igu.org/igu-publications-2010/
IGU%20World%20LNG%20Report%202010.pdf.
27 BP, “Statistical Review of World Energy,” June 8, 2011, page 4. Available at http://www.bp.com/liveassets/
bp_internet/globalbp/globalbp_uk_english/reports_and_publications/statistical_energy_review_2011/STAGING/
local_assets/pdf/statistical_review_of_world_energy_full_report_2011.pdf.
28 International Energy Agency, “QA on Global Liquefied Natural Gas Markets,” September 6, 2011. Available at
http://www.iea.org/newsroomandevents/news/2011/september/name,19860,en.html.

June 2011, pages 5 and 143. Available at http://web.mit.edu/mitei/research/studies/natural-gas-2011.shtml.
30 Energy Information Administration, “Natural Gas U.S. Natural Gas Imports by Country,” accessed March 2013.
Available at http://www.eia.gov/dnav/ng/ng_move_impc_s1_a.htm.
31 Each terminal needs permits from the U.S. Environmental Protection Agency and the U.S. Federal Energy
Regulatory Commission, and export authorization from the U.S. Department of Energy. Houston-based Cheniere Energy
Inc. won approval to be the first company to export natural gas from the lower 48 states. See Saqib Rahim, “Cheniere Walks
Financial Tightrope as It Banks on LNG Export Boom,” Energywire, March 27, 2012. Available at http://eenews.net/public/
energywire/2012/03/27/1.
32 Energy Information Administration, “Annual Energy Outlook 2012: Early Release Overview,” 2011, page 2.
34 EIA, U.S. Natural Gas Prices, Tech. rep., Energy Information Administration, U.S. Department of Energy,
Available at http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm (April 2, 2012).
35 EIA, Cushing, OK WTI Spot Price FOB (Dollars per Barrel), Tech. rep., Energy Information Administration,
U.S. Department of Energy, Available at http://tonto.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PETs=RWTCf=M
(April 4, 2012).
36 BP, BP Statistical Review of World Energy, Tech. rep., British Petroleum, Available at bp.com/statisticalreview
(June 2011).
37 EIA, Henry Hub Gulf Coast Natural Gas Spot Price, Tech. rep., Energy Information Administration, U.S.
Department of Energy, Available at http://tonto.eia.gov/dnav/ng/hist/rngwhhdm.htm (April 6, 2012).
38 EIA, Price of Liquefied U.S. Natural Gas Exports to Japan, Tech. rep., Energy Information Administration, U.S.
Department of Energy, Available at http://www.eia.gov/dnav/ng/hist/n9133ja3m.htm (April 6, 2012).
39 YCharts, European Natural Gas Import Price, Tech. rep., Available at http://ycharts.com/indicators/europe_
natural_gas_price (April 6, 2012).
40 Kraus, Clifford, “In North Dakota, flames of wasted natural gas light the prairie,” New York Times, September 26,
2011. Available at http://www.nytimes.com/2011/09/27/business/energy-environment/in-north-dakota-wasted-natural-gas-
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41 Driver, Anna and Bruce Nichols, “Shale oil boom sends waste gas burn-off soaring,” Reuters, July 24, 2011.
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42 Environmental Protection Agency, “Draft Inventory of Greenhouse Gas Emissions and Sinks: 1990–2011,” 2013.
Available at http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html
43 Twenty-one is the global warming potential (GWP) used in the calculations associated with the state-
ments involving the CO2
-equivalence of methane emissions. It appears in the Second Assessment Report (1996) of the
Intergovernmental Panel on Climate Change (IPCC) and is used by the U.S. Greenhouse Gas Inventory reports prepared
by EPA. Although the IPCC has since updated the GWP for methane (and other non-CO2
gases), the older value is used to
maintain comparability among Inventories.
44 Intergovernmental Panel on Climate Change, “Climate Change 2007: Working Group I: The Physical Science
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46 Environmental Protection Agency, “Inventory of Greenhouse Gas Emissions and Sinks: 1990–2011,” 2013.
Available at http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2013-Chapter-3-Energy.pdf.
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48 Bradbury, James, et al., “Clearing the Air: Reducing Upstream Greenhouse Gas Emissions from U.S. Natural
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49 Alvarez, Ramon, et al., “Greater Focus Needed on Methane Leakage from Natural Gas Infrastructure,”
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50 Pétron, Gabrielle, et al., “Hydrocarbon Emissions Characterization in the Colorado Front Range: A Pilot Study,”
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53 Environmental Protection Agency, “Accomplishments,” July 2012. Available at http://www.epa.gov/gasstar/
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54 The New Source Performance Standard 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.
55 Environmental Protection Agency, “Methane Related Comments on EPA’s “Oil and Natural Gas Sector: New
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57 Government Accountability Office, “Unconventional Oil and Gas Development: Key Environmental and Public
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60 Energy Information Administration, “Repeal of the Powerplant and Industrial Fuel Use Act (1987),” January
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61 Union of Concerned Scientists, “Clean Energy: How Natural Gas Works–Uses of Natural Gas,” August 2010.
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62 MIT Energy Initiative, The Future of Natural Gas: An Interdisciplinary MIT Study, June 2011, page 65. Available at
63 Balling, Lothar, Heinz Termuelhen, and Ray Baumgartner, “Forty Years of Combined Cycle Power Plants,”
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64 Environmental Protection Agency, “Sources of Greenhouse Gas Emissions,” 2013. Available at http://www.epa.
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65 Dominion Power, “Integrated Resource Plan,” September 1, 2011. Available at http://dom.com/about/pdf/irp/
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66 Duke Energy Carolinas, “Integrated Resource Plan,” September 1, 2011.
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68 Energy Information Administration, “Annual Energy Outlook,” April 15, 2013, Table 9. Available at http://www.
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69 Energy Information Administration, “Annual Energy Outlook 2011: Electricity,” page 74. April 26, 2011.
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70 Energy Information Administration, “Annual Energy Outlook 2013,” April 15, 2013. Available at http://www.eia.
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71 Energy Information Administration, “AEO2013 Early Release Overview,” December, 2012. Available at http://
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72 Energy Information Administration, “AEO2013 Early Release Overview,” December 2013. Available at http://
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73 Sliverstein, Ken, “Would Efforts Backfire to Repeal Renewable Portfolio Standards,” EnergyBiz, November 26,
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75 Electric Power Research Institute, “The Power to Reduce CO2
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95 Energy Information Administration, “Buildings Energy Databook,” March 2012. Available at http://buildings-
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96 2009 was the last time the US Energy Information Administration (EIA) conducted the Residential
Energy Consumption Survey (RECS). 2003 was the last time that the EIA conducted the Commercial Building Energy
Consumption Survey (CBECS) and the next survey is scheduled to begin in April 2013. These surveys provide data on
building energy consumption and sources. However, data is gathered a multiyear intervals, unlike some other EIA data
collected annually. This chapter uses relevant data from the years that the data were collected.
97 Environmental Protection Agency, “Draft U.S. Greenhouse Gas Inventory Report,” 2013, Tables ES-8 and 2-5.
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Characteristics,” 2003, Table B7. Available at http://www.eia.gov/emeu/cbecs/cbecs2003/detailed_tables_2003/detailed_
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114 American Gas Association, “A Comparison of Energy Use, Operating Costs, and Carbon Emissions of Home
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128 Department of Energy, “Appliance and Equipment Standards Translate to Huge Energy Savings,” May 18, 2012.
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June 25, 2012. Available at http://www.eia.gov/forecasts/aeo/sector_transportation_all.cfm#heavynatgas.
265 NGV America, “CNG 101,” 2011. Available at http://www.ngvamerica.org/mktplace/cng101.html.
266 C. Randal Mullett, Vice President Government Relations and Public Affairs, Con-way, personal interview,
May 17, 2012.
267 Occupational Safety and Health Administration, 29 CFR 1910, 1996. Available at http://www.osha.gov/pls/
oshaweb/owadisp.show_document?p_table=STANDARDSp_id=9747.
268 Krupnick, Alan J., “Energy, Greenhouse Gas, and Economic Implications of Natural Gas Trucks,” Resources for
the Future, June 2010. Available at http://www.rff.org/rff/documents/rff-bck-krupnick-naturalgastrucks.pdf.
269 National Renewable Energy Laboratory, “Business Case for Compressed Natural Gas in Municipal Fleets,”
Technical Report, NREL/TP-7A2-47919, June 2010. Available at http://www.afdc.energy.gov/pdfs/47919.pdf.

270 Kent Butler, et al., “Reinventing the Texas Triangle: Solutions for Growing Challenges,” Center for Sustainable
Development, School of Architecture, The University of Texas at Austin, 2009. Available at http://soa.utexas.edu/files/csd/
ReinventingTexasTriangle.pdf.
271 Whyatt, G.A., “Issues Affecting Adoption of Natural Gas Fuel in Light- and Heavy-Duty Vehicles,” September
2010. Available at http://www.pnl.gov/main/publications/external/technical_reports/PNNL-19745.pdf.
272 National Association of Convenience Stores, “Fueling America: Key Facts and Figures,” December 2008.
Available at http://www.nacsonline.com/NACS/Resources/campaigns/GasPrices_2011/Documents/GasPriceKit2011.pdf.
273 American Gas Association, “Facts about Natural Gas,” 2012. Available at http://www.aga.org/Newsroom/fact-
sheets/Documents/Facts%20About%20Natural%20Gas%20(JAN%202012).pdf.
274 CNGnow, “Refueling: Refueling at Home,” 2012. Available at http://www.cngnow.com/vehicles/refueling/
Pages/refueling-at-home.aspx.
275 Greenmyfleet.com, “Phil Home CNG Fueling Station,” 2012. Available at http://greenmyfleet.com/shop.
html?page=shop.product_detailsflypage=flypage.tplproduct_id=59category_id=37vmcchk=1.
276 Cunningham, Wayne, “2012 Honda Civic GX: Unsung Green Hero,” November 2011. Available at
http://www.cngnow.com/vehicles/refueling/Pages/refueling-at-home.aspx.
277 Hurdle, Jon, “Natural Gas Vehicles: 22 States Stand Behind a Growing Market,” AOL Energy, August 15, 2012.
Available at http://energy.aol.com/2012/08/16/natural-gas-vehicles-22-states-stand-behind-a-growing-market/.
278 Greene, David, “Costs of Oil Dependence,” June 8, 2008. Available at http://www1.eere.energy.gov/
vehiclesandfuels/facts/2008_fotw522.html.
279 Greene, David, “Testimony to the United States Senate Committee on Energy and Natural Resources,” July 24,
2012. Available at http://www.energy.senate.gov/public/index.cfm/files/serve?File_id=96dc4c8c-4fbc-41f1-a33d-81201ad4f7cd.
280 Beyond U.S. borders, the national network is tightly connected to Canada and Mexico via many land connec-
tions and more loosely to global liquified natural gas markets via a few terminals on the coasts. However, for the purposes
of this report, it will be referred to as the national or U.S. network.
281 Pipeline and Hazardous Materials Safety Administration, “Pipeline Basics,” 2011. Available at http://primis.
phmsa.dot.gov/comm/PipelineBasics.htm?nocache=1423.
282 Pipeline and Hazardous Materials Safety Administration, “Pipeline Basics,” 2011. Available at http://primis.
phmsa.dot.gov/comm/PipelineBasics.htm?nocache=1423.
283 NaturalGas.org, “The Transportation of Natural Gas,” 2011. Available at http://www.naturalgas.org/naturalgas/
transport.asp.
284 Energy Information Administration, “Underground Natural Gas Storage Capacity,” November 30, 2012.
Available at http://www.eia.gov/dnav/ng/ng_stor_cap_dcu_nus_a.htm.
285 Pipeline and Hazardous Materials Safety Administration, “Natural Gas Pipeline Systems,” 2011. Available at
http://primis.phmsa.dot.gov/comm/NaturalGasPipelineSystems.htm?nocache=9698.
286 Energy Information Administration, “Intrastate Natural Gas Pipeline Segment,” June 2007. Available at
http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/intrastate.html.
287 NaturalGas.org, “The Transportation of Natural Gas,” 2011. Available at http://www.naturalgas.org/naturalgas/
transport.asp.
288 ICF International for the Interstate Natural Gas Association of America Foundation, “Natural Gas Pipeline and
Storage Infrastructure Projections through 2030,” October 2009. Available at http://www.ingaa.org/File.aspx?id=10509.

289 Kemp, Kimberly, “An Approach to Evaluating Gas Quality Issues for Biogas Derived from Animal Waste and
Other Potential Sources,” April 2010. Available at http://www.aga.org/SiteCollectionDocuments/Presentations/OPS%20
Conf/2010/1005KEMP.pdf.
290 National Petroleum Council, “Balancing Natural Gas Policy: Fueling the Demands of a Growing Economy,
Volume V Transmission and Distribution Task Group Report and LNG Subgroup Report,” September 2003. Available at
http://www.npc.org/reports/Vol_5-final.pdf.
293 Environmental Protection Agency, “PRO Fact Sheet No. 402: Insert Gas Main Flexible Liners,”2011. Available at
http://www.epa.gov/gasstar/documents/insertgasmainflexibleliners.pdf.
294 Alvarez, Ramon, et al., “Greater Focus Needed on Methane Leakage from Natural Gas Infrastructure,”
Proceedings of the National Academies of Science, February 2012. Available at http://www.pnas.org/content/109/17/6435.
297 Interstate Natural Gas Association of America, “Greenhouse Gas Emissions Estimation Guidelines for Natural
Gas Transmission and Storage,” September 2005. Available at http://www.ingaa.org/cms/33/1060/6435/5485.aspx.
298 Fielden, Sandy, “Why will Bakken Flaring Not Fade Away,” Oil and Gas Financial Journal, September 10, 2012.
Available at http://www.ogfj.com/articles/2012/09/why-will-bakken-flaring-not-fade-away.html.
299 Fielden, Sandy, “Why will Bakken Flaring Not Fade Away,” Oil and Gas Financial Journal, September 10, 2012.
Available at http://www.ogfj.com/articles/2012/09/why-will-bakken-flaring-not-fade-away.html.
300 Environmental Protection Agency, “Overview of Final Amendments of Regulations for the Oil and Natural Gas
Industry,” August 2012. Available at http://www.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf.
301 Environmental Protection Agency, “Accomplishments,” July 2012. Available at http://www.epa.gov/gasstar/
accomplishments/index.html.
303 National Petroleum Council, “Balancing Natural Gas Policy: Fueling the Demands of a Growing Economy,
Volume V Transmission and Distribution Task Group Report and LNG Subgroup Report,” September 2003. Available at
http://www.npc.org/reports/Vol_5-final.pdf.
304 American Gas Association, “Natural Gas Rate Round-Up: Infrastructure Cost Recovery Update,” June 2012.
Available at http://www.aga.org/our-issues/RatesRegulatoryIssues/ratesregpolicy/rateroundup/Documents/2012%20
Jun%20Update%20%20Infrastructure%20Investment.pdf.
305 North Carolina Utilities Commission, “Commission Rules and Regulations,” Chapter 6, Article 12, accessed
January 2, 2013. Available at http://www.ncuc.commerce.state.nc.us/ncrules/Chapter06.pdf.
306 Gram, Dave, “Shumlin Backs Gas Expansion,” Burlington Free Press, April 3, 2011. Available: http://www.
vermontgas.com/addison/Burlington%20Free%20Press%20of%20David%20Gram%20April%203,%202011.pdf.

307 Vermont Gas Systems, “Addison Natural Gas Project,” accessed January 2, 2013. Available at
http://www.vermontgas.com/addison/index.html.
308 Maine Legislature, “An Act To Expand the Availability of Natural Gas to Maine Residents,” 2012. Available at
http://www.mainelegislature.org/legis/bills/bills_125th/billtexts/SP054301.asp.
309 City of Sunrise, Florida, “Gas Main Extension Program,” accessed January 2, 2013. Available at
http://www.sunrisefl.gov/index.aspx?page=546.
310 Atlanta Gas Light Company, “Joint Petition of Atlanta Gas Light Company and Scana Energy Marketing, Inc.
for Approval of an Integrated Customer Growth Program Under The Georgia Strategic Infrastructure Development
and Enhancement Program,” Document Filing #123800, Oct. 23, 2009. Available at http://www.psc.state.ga.us/factsv2/
Document.aspx?documentNumber=123800.
311 American Gas Association, “Natural Gas Rate Round-Up: Infrastructure Cost Recovery Update,” June 2012.
Available at http://www.aga.org/our-issues/RatesRegulatoryIssues/ratesregpolicy/rateroundup/Documents/2012%20
Jun%20Update%20%20Infrastructure%20Investment.pdf.

2101 Wilson Blvd., Suite 550
Arlington, VA 22201
P: 703-516-4146
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www.C2ES.org
This report provides an overview of natural gas production, the climate implications of expanded natural gas use, potential
uses and benefits in key sectors, and related infrastructure issues.
The Center for Climate and Energy Solutions (C2ES) is an independent non-profit, non-partisan organization promoting
strong policy and action to address the twin challenges of energy and climate change. Launched in 2011, C2ES is the succes-
sor to the Pew Center on Global Climate Change.

Report: Leveraging Natural Gas To Reduce Greenhouse Gas Emissions

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