[Senate Hearing 111-276]
[From the U.S. Government Publishing Office]



                                                        S. Hrg. 111-276

                              NATURAL GAS

=======================================================================

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                     ONE HUNDRED ELEVENTH CONGRESS

                             FIRST SESSION

                                   TO

  RECEIVE TESTIMONY ON THE ROLE OF NATURAL GAS IN MITIGATING CLIMATE 
                                 CHANGE

                               __________

                            OCTOBER 28, 2009


                       Printed for the use of the
               Committee on Energy and Natural Resources





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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                  JEFF BINGAMAN, New Mexico, Chairman

BYRON L. DORGAN, North Dakota        LISA MURKOWSKI, Alaska
RON WYDEN, Oregon                    RICHARD BURR, North Carolina
TIM JOHNSON, South Dakota            JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana          SAM BROWNBACK, Kansas
MARIA CANTWELL, Washington           JAMES E. RISCH, Idaho
ROBERT MENENDEZ, New Jersey          JOHN McCAIN, Arizona
BLANCHE L. LINCOLN, Arkansas         ROBERT F. BENNETT, Utah
BERNARD SANDERS, Vermont             JIM BUNNING, Kentucky
EVAN BAYH, Indiana                   JEFF SESSIONS, Alabama
DEBBIE STABENOW, Michigan            BOB CORKER, Tennessee
MARK UDALL, Colorado
JEANNE SHAHEEN, New Hampshire

                    Robert M. Simon, Staff Director
                      Sam E. Fowler, Chief Counsel
               McKie Campbell, Republican Staff Director
               Karen K. Billups, Republican Chief Counsel













                            C O N T E N T S

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                               STATEMENTS

                                                                   Page

Bingaman, Hon. Jeff, U.S. Senator From New Mexico................     1
Fusco, Jack, President and Chief Executive Officer, Calpine 
  Corporation, Houston, TX.......................................    32
McConaghy, Dennis, Executive Vice President, Pipeline Strategy 
  and Development, TransCanada Pipelines, Ltd., Calgary, Canada..    25
McKay, Lamar, Chairman and President, BP America, Inc., Houston, 
  TX.............................................................    10
Murkowski, Hon. Lisa, U.S. Senator From Alaska...................     2
Newell, Richard, Ph.D., Administrator, Energy Information 
  Administration, Department of Energy...........................     3
Stones, Edward, Director of Energy Risk, The Dow Chemical Company    20
Wilks, David, President, Energy Supply Business Unit, Xcel 
  Energy, Inc., Minneapolis, MN..................................    15

                               APPENDIXES
                               Appendix I

Responses to additional questions................................    61

                              Appendix II

Additional material submitted for the record.....................   117

 
                              NATURAL GAS

                              ----------                              


                      Wednesday, October 28, 2009

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 10:05 a.m. in 
room SD-366, Dirksen Senate Office Building, Hon. Jeff 
Bingaman, chairman, presiding.

OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW 
                             MEXICO

    The Chairman. Why don't we go ahead and get started.
    Today's hearing regards the significant increase in 
estimates of technically recoverable natural gas resources as 
reported by the Energy Information Administration and other 
experts, such as the Potential Gas Committee.
    The witnesses will discuss factors leading to increased 
supply, the impact on future natural gas usage that is expected 
as a result of that supply--increased supply. The witnesses 
will also discuss how natural gas resources may be used to 
mitigate climate change and also provide their perspectives on 
pending climate change legislation.
    Some of the key questions that I hope we can find answers 
to are--let me mention five:
    No. 1, what are the latest domestic reserve estimates and 
the economics of delivering natural gas from those newly found 
reserves?
    No. 2, how will this updated supply picture impact the fuel 
mix used for power generation, and how will this affect 
electricity prices?
    No. 3, will an expanded supply reduce the volatility and 
the price spikes that have characterized the natural gas market 
in the past decade?
    No. 4, what are the most appropriate roles for natural gas 
to play in the mitigation of climate change? Would a simple 
price on carbon cause natural gas to be used in those roles or 
should some other policy option be considered?
    No. 5, if natural gas usage increases, how will industries 
using natural gas as a feedstock respond to potential price 
increases?
    We have a distinguished group of witnesses.
    Before I introduce the witnesses, let me call on Senator 
Murkowski for any statement she has.

        STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR 
                          FROM ALASKA

    Senator Murkowski. Thank you, Mr. Chairman.
    Good morning to all the witnesses. I am impressed with the 
very distinguished panel. I have had an opportunity to meet 
with many of you before, but it's nice to have you here today.
    I know that several of you are engineers by training --
petroleum and materials, chemical, and mechanical. I think that 
this technical expertise will help us focus on the facts and 
realities of natural gas in the context of climate policy.
    I have made it very clear that any climate policy that 
decreases the use of natural gas would be a step backward, 
because natural gas is a natural ally of our low-carbon goals.
    Previously described by some as ``too precious to burn,'' 
it's now clear that natural gas can play as valuable a role in 
America's energy future as any other resources out there. The 
Alaska gas line continues to make important progress, and shale 
deposits from the Rockies, all the way to New York, are 
becoming economical to produce.
    While we have a greater supply of natural gas than ever 
before, both the House and Senate climate bills fail to 
acknowledge and embrace its potential. I'm hopeful that today 
we can draw attention to these deficiencies and remedy them in 
any bill that draws enough support to move forward.
    I also want to address concerns that have been raised by 
the coal industry. First, I guess I'd like to point out that 
Alaska's has more coal than any other State, about half of the 
country's total endowment. I want to make sure that coal is not 
sterilized as a valuable energy resource. I think clean coal is 
particularly critical to our future, not least because millions 
of Americans rely on its development for their livelihoods and 
the viability of their regions.
    This hearing is not intended to take anything away from 
coal's status as a large component of our energy supply or its 
viability, going forward. I think the purpose here is to simply 
examine how natural gas can serve as a complement to clean 
coal, to nuclear, to renewables, in an all-of-the-above energy 
policy.
    Now, some would have it that certain domestic resources 
simply get pushed out entirely from our energy--future energy 
mix. I think that is unacceptable. For starters, the world will 
use an estimated 45 percent more energy in 2030 than it does 
today. EIA tells us that U.S. energy consumption won't 
decrease, but rather increase by half a percent per year over 
that period. Senator Inhofe and I, on Friday, released a memo 
from CRS demonstrating that America has more recoverable fossil 
fuel resources than any other nation.
    Given the projected growth in demand and our own abundant 
supplies, I think it's pretty clear that Congress does not need 
to pick between energy resources. Rather, we need to pick all 
of them, and proceed accordingly. It's difficult to imagine an 
energy future that doesn't involve using all of our fossil 
resources in as clean and efficient a manner as possible.
    Climate legislation that fails to promote, or that is 
designed to prevent, the most cost-effective emissions 
reductions will threaten Americans with unaffordable energy 
prices. We have a duty to protect our constituents against that 
risk. We can start by keeping all of our options on the table.
    I'm looking forward to a thoughtful discussion this morning 
about how we strike that balance between getting the greatest 
amount of our emissions reduced for the lowest cost to the 
consumer.
    With that, Mr. Chairman, I thank you for yet another very 
informative hearing on these very important issues.
    The Chairman. Thank you very much.
    Let me introduce our witnesses. We have a very 
distinguished group here. First, Richard Newell, who is the 
administrator with the Energy Information Administration.
    Welcome back to our committee.
    Mr. Lamar McKay, who is the chairman and president of BP 
America.
    Thank you very much, for being here.
    Mr. David Wilks, president of Energy Supply with Xcel 
Energy.
    Thank you, for being here.
    Mr. Edward Stones, the director of Risk--Energy Risk with 
Dow Chemical Company.
    Thank you for being here.
    Mr. Dennis McConaghy, who is senior vice president of 
business development with TransCanada Pipelines, in Calgary; 
and Mr. Jack Fusco, who is the president and chief executive 
officer of Calpine Corporation.
    Thank you all very much, for being here.
    We'll take your full statements and put them in the record 
as if read. If you could take 6 or 7 minutes each and give us 
the main points that you think we need to understand about this 
set of issues, that would be very helpful to us.
    Let's start with you, Mr. Newell, and hear the perspective 
of the Energy Information Administration.

   STATEMENT OF RICHARD NEWELL, PH.D., ADMINISTRATOR, ENERGY 
        INFORMATION ADMINISTRATION, DEPARTMENT OF ENERGY

    Mr. Newell. Thank you, Mr. Chairman and members of the 
committee. I appreciate the opportunity to appear before you 
today to discuss natural gas and its role in mitigating climate 
change.
    The Energy Information Administration is the statistical 
and analytical agency within the Department of Energy. By law, 
our data, analyses, and forecasts are independent of approval 
by any other officer or employee of the U.S. Government, so our 
views should not be construed as representing those of the 
Department of Energy or the administration.
    The main factors to be considered in addressing today's 
topic are the supply of natural gas, the outlook for natural 
gas demand, absent new policies, and the possible impact of new 
policies on natural gas use.
    In terms of domestic supply, EIA focuses on three key 
measures: production, proved reserves, and estimates of 
technically recoverable resources. The major and very positive 
story in all three measures is the growing role of 
unconventional natural gas sources, particularly gas in shale 
formations. Over the past few years, total natural gas 
production has significantly increased through the application 
of new technologies to these unconventional natural gas 
resources. As a result, in 2008, domestic production met 90 
percent of dry gas consumption in the United States, with 
imports from Canada and imports of liquefied natural gas making 
up the balance.
    Despite higher production, proved reserves of natural gas 
have also been increasing. EIA reported a 13-percent increase 
in proved reserves during 2007 and will report a further 3-
percent increase when we release reserves data for 2008 later 
this week. EIA and other experts have also been raising their 
estimates of technically recoverable resources, and EIA expects 
to incorporate a further increase in gas resources in the 2010 
edition of its Annual Energy Outlook, which will be due out at 
the turn of the year.
    Turning to demand, natural gas currently supplies 23 
percent of total U.S. primary energy. Total natural gas use has 
moved within a narrow range over the past 15 years. Use of 
natural gas in residential and commercial buildings has been 
fairly stable, while a significant decline in industrial use of 
natural gas has been roughly offset significant growth in the 
use of natural gas to generate electricity.
    Looking forward, the demand for natural gas in the 
electricity and industrial sectors is a key area of uncertainty 
in the overall use of natural gas. The price of natural gas and 
the rate of growth of the economy in general, and energy--
intensive industries in particular, are critical drivers of 
industrial natural gas demand.
    In the absence of changes in policy, there are two key 
factors that affect the growth of natural gas use for electric 
power generation. One is the rate of growth in electricity 
demand, which EIA projects will average under 1 percent 
annually through 2030. The other is the growth in generation 
from renewable energy sources, spurred by incentives in the 
recent economic stimulus bill and State-level mandates for 
increased use of renewable energy. Given these factors, EIA 
expects total natural gas use to be roughly flat in our current 
reference case scenario.
    Developments in energy and environmental policy can also 
influence the prospects for using natural gas, whether focused 
on greenhouse gas mitigation or other objectives, such as 
diversifying the transportation fuel mix. Actions to reduce 
greenhouse gas emissions would tend to increase the 
attractiveness of electricity generation using natural gas 
relative to conventional coal generation. However, although 
generation using natural gas produces less greenhouse gas 
emissions than generation using conventional coal, it produces 
more emissions than generation using renewable energy or 
nuclear power, which are emissions-free.
    EIA's analysis of House-passed climate legislation, the 
American Clean Energy and Security Act of 2009, considered its 
impacts over the next two decades under different scenarios 
regarding the cost and availability of international offsets 
and low- and no-carbon electricity generation technologies. Our 
results suggest that this legislation would likely result in 
increased use of natural gas for generation over the next 
decade, but the effect over the 2020 to 2030 period and 
thereafter can be either an increase or reduction in natural 
gas use relative to our reference case, depending on the 
assumptions of the cases used.
    Another type of policy proposal that has received recent 
attention would provide tax credits or other incentives to 
encourage the use of natural gas in the transportation sector 
in place of petroleum-based fuels. While natural gas could be 
used in many different types of vehicles, the need for the 
simultaneous introduction of vehicles and fueling 
infrastructure has led many analysts to view centrally-fueled 
fleets as being one of the relatively more suitable market 
segments for deployment of natural gas vehicles. Local air 
pollution concerns and tighter emissions standards for new, 
heavy-duty diesel trucks that are now taking effect also tend 
to increase the relative attractiveness of natural-gas-fueled 
vehicles. However, EIA's reference case projections, which do 
not assume new policy-based incentives, do not show significant 
market penetration of natural-gas-fueled vehicles.
    Mr. Chairman and members of the committee, this concludes 
my testimony. I look forward to answering any questions you 
might have.
    [The prepared statement of Mr. Newell follows:]
  Prepared Statement of Richard Newell, Ph.D., Administrator, Energy 
            Information Administration, Department of Energy
    Mr. Chairman, and members of the Committee, I appreciate the 
opportunity to appear before you today to discuss natural gas and its 
role in mitigating climate change.
    The Energy Information Administration (EIA) is the statistical and 
analytical agency within the Department of Energy. EIA collects, 
analyzes, and disseminates independent and impartial energy information 
to promote sound policymaking, efficient markets, and public 
understanding regarding energy and its interaction with the economy and 
the environment. EIA is the Nation's premier source of energy 
information and, by law, its data, analyses, and forecasts are 
independent of approval by any other officer or employee of the United 
States Government. Therefore, our views should not be construed as 
representing those of the Department or the Administration.
    To briefly summarize, the main factors to be considered in 
addressing today's topic are the supply of natural gas, the outlook for 
natural gas demand absent new policies, and the possible impact of new 
policies on natural gas use and greenhouse gas emissions.
    In terms of domestic supply, EIA focuses on three key measures--
production, proved reserves, and estimates of technically recoverable 
resources. The major, and very positive story, in all three measures is 
the growing role of unconventional natural gas sources, particularly 
gas in shale formations. Over the past few years, total U.S. natural 
gas production has significantly increased (Figure 1)* through the 
application of new technologies to these unconventional natural gas 
resources. Despite higher production, proved reserves of natural gas 
have also been increasing. EIA reported a 13-percent increase in proved 
reserves during 2007 and will report a further increase when we release 
reserves data for 2008 later this week. EIA and other experts have also 
been raising their estimates of technically recoverable resources, and 
EIA expects to incorporate a further increase of natural gas resources 
in the 2010 edition of its Annual Energy Outlook.
---------------------------------------------------------------------------
    * Figures 1-7 have been retained in committee files.
---------------------------------------------------------------------------
    Turning to demand, natural gas currently supplies about 23 percent 
of total U.S. primary energy. Total natural gas use has moved within a 
narrow range over the past 15 years. Use of natural gas in residential 
and commercial buildings has been fairly stable, while a significant 
decline in industrial use of natural gas has roughly offset growth in 
the use of natural gas to generate electricity. Looking forward, the 
demand for natural gas in the industrial and electricity sectors is a 
key area of uncertainty in the overall use of natural gas. The price of 
natural gas, the rate of growth of the economy in general and energy 
intensive industries in particular, and the rate of growth in 
electricity demand are likely to be key drivers of natural gas demand.
    Developments in energy and environmental policy can also influence 
the prospects for using natural gas, whether focused on greenhouse gas 
mitigation or other objectives such as diversifying our transportation 
fuel mix. Action to reduce emissions of greenhouse gases, for example, 
would increase the attractiveness of electricity generation using 
natural gas relative to coal-fired generation. However, although 
generation using natural gas produces less greenhouse emissions than 
generation using coal, it produces more emissions than generation using 
renewable energy or nuclear power, which are emissions-free generation 
sources. EIA's analysis of the House-passed climate legislation, H.R. 
2454, the American Clean Energy and Security Act of 2009 (ACESA), 
considered its impacts over the next two decades under different 
scenarios regarding the cost and availability of international offsets 
and low-and no-carbon electricity generation technologies. Our results 
suggest that this legislation would likely increase the use of natural 
gas for generation over the next decade in all of the scenarios we 
analyzed, but the longer-run effect can be either an increase or 
reduction in natural gas use relative to our Reference Case.
               supply of natural gas in the united states
    Natural gas is both produced within the United States and imported. 
In 2008, domestic production of dry natural gas equaled about 90 
percent of dry gas consumption, with imports from Canada (7 percent of 
consumption) and imports of liquefied natural gas (LNG) (about 3 
percent of consumption) making up the balance. Though I will discuss 
both domestic production and imports, the most important recent 
developments are in domestic production.
    Natural gas production is often classified as either 
``conventional'' or ``unconventional,'' although the definition of the 
boundary between these categories varies across analysts and over time. 
Traditionally, unconventional resources include historically harder-to-
produce supplies embedded in tight sands and shale and in coalbeds. Two 
technological advances have made some unconventional resources easier 
to produce. Horizontal drilling gives producers access to large, 
relatively thin layers of rock without having to drill many traditional 
vertical wells. Horizontal drilling for natural gas and oil in the 
United States even outpaced traditional vertical drilling this year 
(Figure 2). Hydraulic fracturing, or ``fracking,'' shatters rocks that 
are not very permeable, allowing embedded natural gas to flow more 
rapidly into the well bore. Hydraulic fracturing is a common procedure 
in both horizontal and vertical wells in the United States.
    These technological changes have led to large increases in 
available reserves by expanding the types of resource rock that can be 
drilled economically. Most recently, natural-gas-bearing shale that is 
located across the entire United States (Figure 3) has been the focus 
of attention. So far, the Barnett shale in Texas has been the most 
developed, but others, such as Haynesville, may prove more productive 
and the Marcellus in the Northeast is much larger.
    EIA has traditionally taken a relatively optimistic view of the 
unconventional natural gas resource, even at a time earlier this decade 
when many other analysts were suggesting that the lack of natural gas 
resources in North America would lead to a rapid and inexorable 
increase in our reliance on imports of LNG. Recent shale gas 
developments suggest that even our perspective was not optimistic 
enough. In recent years, EIA and other experts, such as the Potential 
Gas Committee (PGC), have raised their estimates of technically 
recoverable resources, and EIA expects to incorporate a further 
increase in the 2010 edition of its Annual Energy Outlook. Most of 
these increases arise from reevaluation of shale-gas plays in the 
Appalachian basin and in the Mid-Continent, Gulf Coast, and Rocky 
Mountain areas. I should note, however, that appraisals of the 
``technically recoverable'' natural gas resource potential of the 
United States do not take into account the costs of finding and 
recovery.
    Later this week, EIA will release its year-end 2008 report U.S. 
Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves. Proved 
natural gas reserves, a small subset of the technically recoverable 
resources, are those volumes that geological and engineering data 
demonstrate with reasonable certainty to be recoverable in future years 
from known reservoirs under existing economic and operating conditions. 
In the report, we will show that proved reserves of natural gas rose 
from 2007 to 2008, not only replacing production of 20.5 trillion cubic 
feet (Tcf), but also growing by almost 3 percent over 2007 (Figure 4). 
The year-end 2008 increase follows an increase of 13 percent the year 
before, reflecting in part stronger price conditions, which was a 
record for the 32 years EIA has collected these data. For both years, 
growth was largely due to continued development of unconventional 
natural gas from shales.
    More recently, some have raised concerns about whether shale can 
continue to deliver relatively low-cost supply to domestic customers. 
Concerns expressed relate to the relative newness of the large-scale 
application of horizontal drilling and hydraulic fracturing 
technologies to shales. Shales in different parts of the country are 
not the same, and differences in techniques and technology are actively 
being developed by the industry. This creates uncertainty in assessing 
the overall resource base. Horizontal wells with fracturing to 
stimulate the flow of natural gas in shale also tend to deliver their 
greatest volumes in the first few years. This raises questions as to 
the ability of the industry to continue to drill productively over the 
long term, which is necessary to sustain higher, or even constant, 
levels of production.
    Delivery of most of a well's volume relatively quickly has 
attractive financial implications as well, providing producers with a 
quicker and more certain return on their investment. In the long term, 
the question will be cost. At this point in the development of new 
technologies, where possible, producers are likely working with the 
easiest, lowest-cost resources they can identify. Continued technology 
improvements will tend to reduce costs, while the exploitation of more 
difficult resources over time will tend to increase them. How these 
costs evolve over time is an important question, though we are seeing 
some immediate effects today as, at prevailing prices, development has 
slowed significantly in the Barnett shale in Texas, although production 
continues to increase rapidly in the Haynesville in Louisiana and the 
Marcellus in the Northeast. The direction of prices is also important 
to future drilling activity, because it is the difference between price 
and cost that determines the profitability of drilling activity. Both 
EIA's short-and long-term projections and the futures price curve for 
natural gas contracts traded on the New York Mercantile Exchange 
support the view that U.S. natural gas prices will rise relative to 
their level in the current economic downturn.
    The other major concern about long-term development of shale gas 
relates to environmental issues. Any new technology is likely to raise 
environmental issues, and drilling, particularly in areas that have not 
seen much in recent years, raises a set of important local 
environmental issues. Drilling requires heavy truck traffic, makes 
noise, and changes the landscape. Fracturing to stimulate the flow of 
natural gas, though it involves mainly highly-pressurized water and 
sand, also involves a relatively small amount of chemical additives. 
Some of these environmental issues have been explored over the past few 
years in Texas. Much of the Barnett shale lies beneath suburban, and 
even urban, Fort Worth. In the case of the Marcellus, the shale lies 
below areas predominantly in Pennsylvania, West Virginia, and New York 
that have not seen large-scale drilling efforts in a century.
    Because of the local nature of the potential environmental effects 
of drilling and hydraulic fracturing, and the authority that resides 
largely in the States for regulating these environmental issues, 
development is likely to be highly dependent on State and local 
development policies. Those policies relate not only to access, but 
also to regulation of certain development activities that may be 
associated with air and water pollution. Formations holding shale gas 
resources have very low permeability and typically lie far below 
sources of ground water. Therefore, water-related concerns have largely 
centered on the amount of water used in the fracturing process and the 
need to handle, recycle, and treat fracking fluids, including used 
fluids that are returned to the surface as part of the process, in a 
manner that addresses the risk of spills that can potentially affect 
water quality. These locally-managed environmental issues make 
assessing the longer-term role of shale natural gas more difficult.
    Depending on overall market conditions, LNG may also continue to 
serve as a source of additional natural gas supply. The United States 
currently has more than 4 Tcf of annual receipt capacity for imported 
LNG. The United States, given its extensive natural gas storage system, 
has in effect become the marginal customer in the international LNG 
trade, attracting uncommitted supplies when spot prices available in 
the United States are higher than international alternatives. In this 
sense, LNG can act as a safety valve in the event that spot prices rise 
due to unanticipated demand growth or supply shortfalls. Under present 
market conditions, where domestic supply has been robust, imports have 
averaged much lower than capacity, totaling a little over 0.3 Tcf last 
year and up about 20 percent year-to-date in 2009.
              demand for natural gas in the united states
    Natural gas has long played an important role in meeting U.S. 
energy needs, providing about 23 percent of the primary energy used in 
the United States, heating more than half of U.S. homes, generating 
more than one-fifth of U.S. electricity, and providing an important 
fuel and feedstock for industry. About one-third of the natural gas 
consumed in 2007 was used for electric power generation, one-third for 
industrial purposes, and the remaining one-third in residential and 
commercial buildings. Only a small portion is used in the 
transportation sector, predominately at pipeline compressor stations, 
although some is used for vehicles.
    The EIA projects and analyzes U.S. energy supply, demand, and 
prices through 2030 using the National Energy Modeling System and 
presenting results in our Annual Energy Outlook. Earlier this year, EIA 
updated its Annual Energy Outlook 2009 (AEO2009) Reference Case to 
include estimates of the implementation of the American Recovery and 
Reinvestment Act (ARRA), which includes significant programs to promote 
both energy efficiency and smart-grid technologies. The updated 
Reference Case shows a continuing slow growth in natural gas use in 
residential and commercial buildings, averaging less than one-third of 
a percent annually through 2030. Our estimates reflect both the 
increase in the amount of residential and commercial space that uses 
natural gas as a primary fuel for space and water heating, which tends 
to increase natural gas use, and projected increases in the efficiency 
of natural-gas-using equipment and better performance of buildings 
subject to tougher codes and standards, which tend to reduce natural 
gas use.
    Projections of industrial natural gas demand are highly sensitive 
to the price of natural gas as well as the level and composition of 
economic activity. As noted previously, natural gas use by industry has 
declined over the past 15 years. In our Reference Case projections, 
industrial-sector natural gas consumption is projected to rebound 
slightly after the recession, and then level off as energy-intensive 
industries continue to grow at a much lower rate than the overall 
economy.
    The electric power sector has been the growth market for natural 
gas over the last decade. In 2009, notwithstanding a projected 4.6-
percent decline in overall electricity demand, generation with natural 
gas is actually expected to grow by 4.1 percent, reflecting a situation 
where generation using efficient natural-gas-fired units is less costly 
than generation from some coal units in parts of the country.
    Looking forward, however, given the projected rise in natural gas 
prices relative to coal prices, displacement of existing coal-fired 
generation does not persist in our Reference Case, where there is no 
implicit or explicit value placed on carbon dioxide emissions emitted 
from the combustion of coal in existing plants. In this setting, the 
growth in electricity demand and the competition of natural gas with 
other electricity sources to serve that growth will determine the 
amount of natural gas used for generation.
    While the recent decline in demand for electricity is largely 
attributable to the current economic downturn, slowing growth in the 
demand for electricity has been a long-term trend for more than 50 
years. After averaging nearly 10 percent per year in the 1950s, the 
annual growth in the demand for electricity slowed to just over 7 
percent in the 1960s, less than 5 percent in 1970s, less than 3 percent 
in the 1980s, less than 2.5 percent in 1990s, and just over 1 percent 
in the first 7 years of the 21st century (Figure 5). The slowing growth 
in electricity demand is projected to continue over next two decades, 
averaging only 0.9 percent per year in our updated recent projections 
through 2030.
    With this outlook for electricity demand growth, natural gas 
generation in our Reference Case is projected to fall over the next few 
years. This occurs because growing renewable generation, stimulated in 
part by the extension of production tax credits and the provision of 
grants and loans in the recent American Recovery and Reinvestment Act, 
together with increased coal generation from new plants already under 
construction, crowd out the increased use of natural gas that might 
have otherwise occurred. Over the longer term, however, natural gas 
generation is projected to grow because few new coal plants beyond 
those currently under construction are projected to be added and the 
production tax credit for eligible renewable sources currently sunsets 
in 2012 or 2013, depending on the technology.
    Of course there are uncertainties. Chief among these is whether new 
electricity-intensive technologies might enter the market to reverse 
this trend. The one most discussed today is plug-in hybrid electric 
vehicles. While we do see plug-in hybrids entering the market over the 
next two decades, we do not expect their penetration to be large enough 
by 2030 to reverse the slowing electricity demand growth trend. A 
simple calculation illustrates the point. One million plug-in hybrid 
electric vehicles with an all-electric range of 40 miles (PHEV-40) 
taking a 14-kilowatthour charge 365 days a year would add about 5 
terawatthours of electricity load on an annual basis. This would 
represent slightly more than one-tenth of 1 percent of projected U.S. 
electricity demand in 2030. Tens of millions of PHEV-40s could, of 
course, make a significant difference to electricity demand, but EIA's 
Reference Case does not envision PHEV penetration on this scale over 
the next two decades given that the technology has yet to be introduced 
commercially, and there are significant challenges in reducing the cost 
and improving the performance of batteries to make this technology 
competitive in the marketplace without continuing subsidies.
  the effect of greenhouse gas mitigation policies on natural gas use
    Just two weeks ago, I had the opportunity to appear before you to 
discuss the recent EIA analysis of the energy and economic impacts of 
ACESA. EIA's analysis of ACESA focuses on those provisions that can be 
readily analyzed using our National Energy Modeling System, including 
the cap-and-trade program for greenhouse gases and its provisions for 
the allocation of allowances, Federal building code updates for both 
residential and commercial buildings, and Federal efficiency standards 
for lighting and other appliances.
    As I noted at the earlier hearing, EIA's analysis shows that the 
estimated impacts of ACESA on energy prices, energy use, and the 
economy are highly sensitive to assumptions about the availability and 
cost of international offsets as well as no- and low-carbon 
technologies for power generation. The six main analysis cases 
considered in EIA's report reflect a variety of different assumptions 
regarding these factors.
    EIA's analysis suggests that the vast majority of reductions in 
energy-related emissions are expected to occur in the electric power 
sector. Across the ACESA main cases, the electricity sector accounts 
for between 80 percent and 88 percent of the total reduction in energy-
related carbon dioxide (CO2) emissions relative to the 
Reference Case in 2030, even though electricity comprises only 41 
percent of such emissions. Emission reductions in the electricity 
sector come primarily from reducing conventional coal-fired generation, 
which in 2007 provided 50 percent of total U.S. generation. A portion 
of the electricity-related CO2 emissions reductions results 
from reduced electricity demand stimulated both by consumer responses 
to higher electricity prices and by incentives in ACESA to stimulate 
greater energy efficiency.
    There are several reasons for the concentration of emissions 
reductions in the electric power sector. First, more than 90 percent of 
coal, the fuel with the highest carbon content, is used in the 
electricity sector. Second, while coal-fired generation is a major 
source of current and projected Reference Case emissions, there are 
several alternative generation sources already demonstrated (e.g., 
natural gas, renewables, and nuclear), and others are being developed 
(e.g., fossil with carbon capture and storage (CCS)). Third, changes in 
electricity generation fuels do not require fundamental changes in 
distribution infrastructure or electricity-using equipment.
    What does this mean for natural gas use in electricity generation? 
In addition to the Reference Case, Figure 6 also shows natural gas 
generation from several cases we prepared in our analysis of ACESA. As 
shown, the impact on the level of natural gas generation depends on 
assumptions about the cost and availability of international offsets 
and low-emitting electricity generating technologies like nuclear, 
fossil with CCS, and biomass.
    In the Basic Case where international offsets are assumed to be 
available and the cost assumptions for low-emitting electricity 
generating technologies are the same as those in the Reference Case, 
natural gas generation rises above the Reference Case through about 
2020, but then falls below it as new renewable and nuclear plants are 
brought on line. In the High Cost Case, where new nuclear and CCS 
plants are assumed to cost 50 percent more than in the Reference Case, 
natural gas generation rises above the Reference Case throughout the 
projections. Finally, in the No International/Limited Case where the 
availability of international offsets and low-emitting electricity 
generating technologies is very limited through 2030, natural gas 
generation is well above the Reference Case level throughout most of 
the projections, exceeding the 2030 Reference Case level by 68 percent.
    One question of interest is why companies don't switch from using 
existing coal plants to increased use of existing natural gas plants to 
reduce their greenhouse gas emissions. The reason is that the dispatch 
decision is quite sensitive to the price of natural gas, and it 
generally takes a fairly significant greenhouse gas allowance price to 
make this switching attractive at projected natural gas prices. Figure 
7 provides an illustrative example of this trade-off with three 
difference assumptions about natural gas prices. As shown, if delivered 
natural gas prices were approximately $5 per million Btu it would make 
sense to dispatch a natural-gas-fired combined-cycle plant before a 
coal plant when the greenhouse gas allowance price reached a little 
over $30 per metric ton of CO2. However, this crossover 
point rises to around $60 per ton of CO2 with $7 natural gas 
prices and around $100 per ton of CO2 with $10 natural gas 
prices. In the Reference Case of our analysis of H.R. 2454, natural gas 
prices to electricity generators are just over $7 per million Btu in 
2020 and just over $8.30 per million Btu in 2030. If natural gas prices 
turn out to be significantly lower than we project, there could be 
considerably greater use of gas than indicated in these scenarios.
                               conclusion
    Given strong technologically-driven U.S. supply development, 
natural gas is likely to play an important role in domestic energy use 
for the foreseeable future, regardless of policy. Clearly, adequacy of 
resources and local environmental implications will be important 
considerations, but if those concerns prove manageable, it should be 
possible for domestic natural gas production to increase well beyond 
its current level, which already reflects significant growth over the 
last several years. While growth in the domestic use of natural gas may 
be constrained by increases in efficiency and relatively slow growth in 
electricity demand, its environmental advantages relative to some other 
energy options suggest that it could be considered for a policy-driven 
role as well.
    Mr. Chairman and members of the Committee, this concludes my 
testimony. I would be happy to answer any questions you may have.

    The Chairman. Thank you very much.
    Mr. McKay.

 STATEMENT OF LAMAR MCKAY, CHAIRMAN AND PRESIDENT, BP AMERICA, 
                       INC., HOUSTON, TX

    Mr. McKay. Chairman Bingaman, Ranking Member Murkowski, 
members of the committee, my name is Lamar McKay, and I am 
chairman and president of BP America.
    I represent the more than 29,000 Americans who work for BP, 
the leading producer of oil and natural gas in the United 
States and the largest investor in U.S. energy development.
    BP is committed to working with the Congress and with a 
broad cross-section of energy producers, energy consumers, and 
others stakeholders to address the challenges of climate change 
in the context of increasing U.S. energy demand.
    We appreciate the opportunity to share our views on energy 
and climate policy, as well the chance to discuss the major 
role natural gas can play in speeding emissions reductions in 
the power sector, delivering the greatest reductions at the 
lowest cost, using technology that is available today.
    BP advocates an all-of-the-above approach, as Senator 
Murkowski mentioned. We believe this approach is the best to 
tackle climate change, enhance U.S. energy security, and meet 
the Nation's growing need for energy. We support policies that 
encourage conservation, energy efficiency, and greater 
production of domestic energy, including alternatives, fossil 
fuels, and nuclear.
    Our views on climate policy flow from the fact that a ton 
of carbon is a ton of carbon, whether that comes out of a 
tailpipe or a smokestack, and the belief that every ton should 
be treated fairly and equally. A climate policy that results in 
disparate treatment of energy producers and consumers will 
result in massive misallocation of capital and insulated 
consumption. That will impede, and make more costly, the carbon 
reductions that we are all working to achieve.
    Now, we support a national climate policy that creates a 
level playing field for all forms of energy that produce carbon 
emissions. In pending legislation, the playing field is not 
level. In spite of its economic and environmental benefits, gas 
is being squeezed out of the power sector by mandates for 
increased use of alternatives and protection of high-carbon 
coal generation. We have long supported transitional incentives 
for alternatives. If we can't achieve a level playing field 
within the power sector, then we would support transitional 
incentives to kick-start the phased retirement of the Nation's 
least efficient and most carbon intense coal-fired plants.
    Now, we very strongly believe that coal is an absolutely 
essential part--essential part--of the Nation's energy future. 
We are working on technology to reduce carbon emissions from 
stationary sources which could be ready for commercial use by 
2020. Now, because of their--some of these coal plants' 
locations and the likelihood of more stringent air quality 
standards, many of the very least efficient, most carbon 
intense coal plants may not be candidates for carbon capture 
and storage. Our analysis shows that the phased replacement of 
about 80 of these bottom-tier plants would deliver 10 percent 
of the cumulative 2010 to 2020 emission reduction targets now 
being considered by the Congress.
    Now, we're not advocating an overnight change. Instead, we 
see a steady, smooth transition involving the retirement of 
perhaps eight to ten coal plants per year. Over the next 
decade, this could create annual incremental gas consumption of 
about one Tcf--one trillion cubic feet. We believe the domestic 
gas industry can very easily meet that demand. In fact, thanks 
to a gas supply picture that has been utterly transformed by 
using technology to unlock vast reserves of shale gas, domestic 
production increased, here in the U.S., 1.5 trillion cubic feet 
just last year. Estimates vary, but the U.S. probably has 
between 50 and 100 years worth of recoverable natural gas.
    Now, some have expressed concern about the volatility of 
natural gas prices. Going forward, we believe natural gas 
prices will be less volatile, thanks to a greatly expanded 
resource base, ranging from shales to Alaska gas, better 
connectivity via significant new pipelines, increased U.S. 
storage volumes, and the capacity of U.S. LNG receiving 
terminals.
    Now, in closing, I want to emphasize again that BP stands 
ready to work with this committee and others to reduce the 
carbon we put into the atmosphere, meet the Nation's growing 
need for energy, and do it at an affordable price for American 
families.
    Natural gas is clean, abundant, affordable, and American. 
We encourage policymakers to provide a level playing field in 
which all sources of carbon are treated fairly. If you do, we 
believe natural gas will deliver the greatest emissions 
reductions at the lowest possible cost using technology 
available today.
    So, I thank you, and I look forward to your questions.
    [The prepared statement of Mr. McKay follows:]
Prepared Statement of Lamar Mckay, Chairman and President, BP America, 
                           Inc., Houston, TX
    Chairman Bingaman, Ranking Member Murkowski, members of the 
committee, my name is Lamar McKay, and I am the Chairman and President 
of BP America.
    I appreciate the opportunity to appear before this panel to present 
BP's views on the role natural gas can play in mitigating climate 
change.
    BP has long been a proponent of comprehensive energy policies that 
promote energy security at an affordable cost through the development 
of both traditional and non-traditional sources of energy, as well as 
conservation and efficiency. We have also been a long-time advocate of 
taking a precautionary approach to CO2 emissions, and are 
committed to reducing the environmental impacts of both energy 
production and consumption.
    Throughout the 20th century, an abundant supply of low-cost energy 
was the driving force behind America's prosperity and development. EIA 
projects that US energy demand will grow by 11 percent from 2007 to 
2030. Satisfying such demand in a sustainable way is one of our 
nation's most significant challenges.
    Accomplishing these objectives in the 21st century will require a 
more diverse energy mix--increased efficiency, nuclear power, renewable 
energy, cleaner coal, oil, and natural gas.
    This will require the right combination of policies and market-
based systems to incentivize the transformation of energy use. Getting 
there will require all energy participants--consumers, governments, 
energy companies and other stakeholders--to work together to build a 
sustainable energy future.
    If we do that, the result will create new jobs, enhance our 
nation's energy security, and mitigate the impacts of climate change.
    At BP, we believe that natural gas, which is in abundant supply, is 
key to making the vision of a lower-carbon energy future a reality.
    As a member of US Climate Action Partnership (CAP), we helped draft 
a blueprint for climate change legislation that recommended, among 
other things, how cap and trade could work--with equitable treatment 
between all sources of carbon as a basis.
    Current legislative proposals do not create a level playing field 
and, as a result, natural gas is in danger of being squeezed. In spite 
of its economic, energy security and environmental benefits, gas is 
caught between support for emerging low carbon technologies on the one 
hand, and relief for coal generation on the other.
    If all sources of carbon are not treated equitably, massive 
misallocation of capital and insulated consumption will occur. Our 
bottom-line is a ton of carbon is a ton of carbon--whether it comes out 
of a tailpipe or a smokestack, it should be treated the same.
                               bp america
    BP has a long history in the US energy market. I represent the 
29,000 US employees of BP America. We are not only the largest oil and 
gas producer in the United States, but also the company that invests in 
the most diverse energy portfolio in the industry. In the last five 
years, we have invested approximately $35 billion in the US to increase 
existing energy sources, extend energy supplies and develop new, low-
carbon technologies.
Oil & Gas
    Offshore and onshore, BP is one of the largest producers of oil and 
gas in the United States. From the Alaskan North Slope to the deep 
waters of the Gulf of Mexico, we are a leader in providing America's 
traditional energy needs. Our recent discovery of the Tiber oil field 
in the Gulf is only the latest in a long list of BP investments in 
America's energy security.
Wind
    We are major investors in wind generation and have amassed a land 
portfolio capable of potentially supporting 20,000 megawatts (MW) of 
wind generation, one of the largest positions in the country. As of 
year-end 2008, we had 1,000 MW of wind generation on-line and expect to 
have an installed capacity of 2,000 MW of wind power by the end of 
2010.
Biofuels
    We are one of the largest blenders and marketers of biofuels in the 
nation. BP has committed more than $1.5 billion to biofuels research, 
development and production in response to increasing energy demand and 
the need to reduce overall greenhouse gas emissions from transport 
fuels. Our cutting-edge research looks to use dedicated energy crops 
that will contain more energy and have less impact on the environment 
than past generations of biofuels. They will also be more compatible 
with existing engines and transport infrastructure, making them less 
costly to deploy at scale.
Carbon Management/Carbon Capture and Storage (CCS)
    BP is involved in three major CCS projects: active operations in 
Algeria; a potential hydrogen energy project in California, and a 
planned project in Abu Dhabi.
Solar
    BP's solar business has been in operation for over 30 years and 
last year had sales of 162 MW globally. This represents an increase of 
29% over 2007 and further growth is expected.
    By investing heavily in the most diverse portfolio of energy 
sources in the industry, BP is helping meet America's energy needs 
while ensuring a more sustainable and secure energy future.
                  transition to a lower-carbon economy
    The transition to a lower-carbon economy will take substantial 
time, investment and technology--spanning decades. While we look to the 
future, we can make choices today based on what we know.
    In reviewing current climate legislative proposals, we have found 
aspects we endorse--such as transitional support for renewables. There 
are other areas, however, that cause us concern.
    First is the way in which mature energy sources (coal, oil, natural 
gas) are treated. Because the utility sector is insulated, the 
transportation/refining sectors foot the vast majority of near-and 
medium-term costs for the entire energy economy. This results in an 
under-allocation of allowances to the refining sector, which puts 
further pressure on an industry already facing significant challenges.
    Our second concern is the lack of a level playing field within the 
utility sector for natural gas--especially over the next decade or so.
    To some extent, this may be an oversight, as America's growth in 
domestic natural gas reserves is a relatively new story. However, we 
have not seen any analysis of legislative proposals which forecast 
natural gas growth to 2020.
    Indeed, our own forecasts indicate the potential for lower demand, 
as natural gas is squeezed over the next decade between growing 
renewable mandates and coal. Our analysis indicates legislative 
insulation for even the oldest and least efficient coal-fired power 
plants.
    Having said that, we are pleased that the Senate climate proposal 
creates a ``place holder'' to discuss natural gas. We welcome the 
opportunity to elaborate on the role natural gas can play in mitigating 
climate change.
                      the potential of natural gas
    Natural gas has played a supporting role in America's energy story. 
However, we believe it is time for its role to change.
    If the necessary technology is applied, within a stable fiscal and 
regulatory framework, natural gas can help fundamentally transform 
America's energy outlook and emissions profile in the decades going 
forward.
    Its advantages are many:

   Natural gas is far and away the cleanest burning fossil fuel 
        in the energy portfolio. It generates less than 50 percent of 
        the CO2 as coal per kilowatt hour and emits 
        significantly less sulfur dioxide, nitrogen oxide, and 
        particulate matter. Unlike coal, natural gas does not emit 
        mercury and generates no waste ash.
   It is also the most versatile fuel, because it can be 
        employed in the transportation sector, for home heating as well 
        as the electricity/industrial sectors.
   Natural gas infrastructure is already in place--with gas 
        pipelines already criss-crossing the country with more being 
        built. There is also significant underutilized gas-fired power 
        generating capacity.
   Natural gas generators are also more easily switched on and 
        off, providing a synergistic compliment to intermittent sources 
        such as solar and wind.
   Finally, natural gas-fired plants can be more easily 
        expanded and permitted than other sources.

    Policies promoting the use of natural gas in power generation hold 
the potential to create new American jobs throughout the natural gas 
value chain (exploration, production, pipelines and gas plants). We 
believe such policies can also help to address concerns around natural 
gas supply and volatility.
                                 supply
    Over the last few years, a revolution has taken place in America's 
natural gas fields. Deposits of shale gas once thought out of reach are 
now accessible, thanks to new uses of proven technologies, such as 
hydraulic fracturing and horizontal drilling.
    These technologies have enabled production in three of BP's key 
fields in Texas to more than double between 2006 and 2008. Successes 
such as these have led to major new discoveries, not only in 
traditional oil and gas states, but also in such non-traditional ones 
as Pennsylvania, Ohio and New York.
    As a result, the US natural gas picture has been transformed. US 
gas production increased last year by 1.5 tcf--the largest increase in 
the world and the largest in US history. And we can do more of this, if 
the right policy framework is put in place to encourage and enable the 
use of natural gas.
    Estimates vary, but the US probably now has between 50 and 100 
years worth of recoverable natural gas which is accessible with 
technology available today.
                            price volatility
    Natural gas prices are driven by a combination of short-term and 
structural factors. Short-term events, such as cold weather and 
hurricanes, will always impact energy markets, and financial tools 
exist to help consumers and producers alike manage such risks. Earlier 
in this decade, structural factors included availability of domestic 
supply and limited LNG import availability.
    That picture has changed dramatically. In addition to the increased 
domestic supplies of natural gas referenced above, there has also been 
significant expansion of LNG import capacity in recent years. These two 
factors, we believe, can help contain structural pressures on natural 
gas prices in the future. Also, stronger base-load demand will 
encourage development of a stronger, more flexible supply base.
    Given this positive new supply picture, the question then becomes: 
What should we do with it?
                options for lowering us carbon emissions
    The US has already taken some significant steps toward lowering 
carbon emissions. In the arena of transportation, which generated about 
2 billion tons of carbon dioxide in 2007, according to the EIA, the 
federal government has mandated more fuel efficient vehicles and 
increasing use of biofuels.
    According to the EPA, electricity generation is the largest single 
source of CO2 emissions, accounting for 41 percent of all 
such emissions. Therefore, this is an area where we should dedicate 
some real focus.
    The numbers are well known. Coal provides around half of America's 
electricity, but contributes over 80 percent of the CO2 
produced via electricity generation.
    Virtually all projections show coal playing an indispensable role 
in the US energy picture for decades to come--and we agree. Coal, as 
well as natural gas plants, can be fitted with carbon capture and 
storage (CCS) technology. This involves capturing CO2 and 
reverse-engineering and building a gas injection field so that we can 
put CO2 back into the ground.
    CCS faces challenges of implementation at scale, substantial costs 
and specific locational issues. It will take time, perhaps a decade or 
more, for the technology to mature.
    Nuclear power is carbon-free and should be part of the solution. 
However, it is also capital intensive and has long lead times.
    Wind and solar are the sources most often mentioned as alternatives 
to existing fuels, and BP is an industry leader in both. Wind can be 
economically competitive with more conventional sources, which is one 
reason it is growing so rapidly--but it still requires subsidies in 
today's environment. Solar is higher cost than wind and requires a 
greater government subsidy, though costs are coming down.
    Both sources, however, face challenges and have limitations of 
intermittence and affordability. The development of smart-grid 
technology might alleviate some of these challenges, but we're not 
there yet.
    So where does this lead us?
          the role of natural gas in mitigating climate change
    We support greater efforts toward energy efficiency and 
transitional incentives to encourage the rapid growth of alternatives.
    We also think it is important to establish an economy-wide carbon 
price, with all hydrocarbon sources treated the same. In that 
framework, increased reserves of natural gas mean we can rely on it 
more fully to support demand growth in electric power generation.
    As we have indicated, current legislative proposals distort that 
framework in favor of coal. Either those distortions should be removed, 
or alternatively, incremental transitional incentives are needed to 
accelerate the retirement of the leastefficient coal-fired generating 
capacity.
    For example, our analysis indicates that if the least efficient 
coal-fired plants are provided with transitional incentives to retire, 
the power sector could deliver a significant amount of near-to-medium 
term emission reductions at low costs. Approximately 80 plants (30 GW 
of generating capacity) fall into the ``least efficient'' category, 
having an average efficiency of 27.1 percent versus 32.7 percent for 
the average plant. In reality, this means that the least efficient 
plants must burn 20 percent more coal to achieve the same amount of 
output.
    Most of these facilities are not located in areas where CCS is an 
apparent option and are not suitable to be retrofitted with CCS. This 
is because of their vintage and emission profiles, factors which will 
also require significant investment to reduce NOX, 
SOX and particulate matter in order to meet new clean air 
requirements.
    The retirement of these 80 facilities over the next decade (8-10 
plants per year) could deliver 10 percent (700 million tons) of the 
Waxman-Markey, Boxer-Kerry targets of 7 billion tons of cumulative 
reductions from 2012-2020. If replaced by gas alone, demand would 
increase by about 1 TCF per year of natural gas by 2020, or roughly 
five percent of the current US market. Given the transformed gas market 
conditions, we believe that such an increase in demand can easily be 
met by existing reserves--recall that US natural gas production grew 
last year by more than this amount.
    We are not suggesting that gas be mandated as a replacement for the 
retired capacity. It could also be replaced by cleaner, more efficient 
energy sources. However, with a level playing field for carbon, we 
believe the market will choose gas, because it offers the lowest-cost 
option to replace retired coal capacity.
    BP believes these important actions will result in a significant 
down payment on carbon emission reductions, with minimal costs to 
generators and consumers while CCS and alternative energy technologies 
mature.
                               conclusion
    In summary, BP is committed to providing the United States with the 
energy it needs to grow in coming decades, and doing so in a 
responsible and sustainable manner.
    We support policies which:

   encourage energy efficiency;
   provide transitional support to renewable technologies; and
   apply a consistent, economy-wide carbon price to all 
        hydrocarbons.

    Failing that we support policies which promote early retirement of 
the least efficient sources of electric power generation as a means of 
achieving and sustaining significant CO2 emission 
reductions. We believe legislation should aim to deliver the greatest 
carbon reductions at the lowest cost, with technology that is available 
today.
    Expanded use of domestic natural gas can help not only the 
environment, but also the economy by providing sufficient supplies to 
meet agricultural and industrial demand.
    BP is eager to join with policy makers, members of the energy 
sector, and other stakeholders in order to develop responsible policies 
that reduce carbon emissions and promote the use of clean, domestic 
sources of energy. Such efforts must not exclude or sideline any 
stakeholder.
    America is at a critical juncture. If we begin to move now, we can 
enable a cleaner energy future for the nation. I don't believe we can 
afford to wait.
    And with that, I would be happy to take your questions.

    The Chairman. Thank you very much.
    Mr. Wilks. Go right ahead.

  STATEMENT OF DAVID WILKS, PRESIDENT, ENERGY SUPPLY BUSINESS 
            UNIT, XCEL ENERGY, INC., MINNEAPOLIS, MN

    Mr. Wilks. Thank you, Chairman Bingaman and members of the 
committee.
    My name is David Wilks, and I am president of the Energy 
Supply Business Unit of Xcel Energy. I am pleased to be here 
today to discuss the potential role of natural gas in reducing 
emissions of greenhouse gases by the utility industry.
    Xcel energy is an investor-owned electricity and natural 
gas company headquartered in Minneapolis, Minnesota. We are one 
of the Nation's largest combined electric and gas companies. We 
serve approximately 3.3 million electric customers and 1.8 
million gas customers. We serve Minneapolis-St. Paul, Denver, 
Amarillo, and other communities in southeast New Mexico, 
Minnesota, Wisconsin, Michigan, North and South Dakota, 
Colorado, and Texas.
    In my capacity as president of Energy Supply, I'm 
responsible for the construction, operation, and maintenance of 
Xcel Energy's power plants, as well as our company's 
environment, energy, trading, fuel, and markets functions. 
There's more detail in attachment A on Xcel Energy.
    Xcel Energy has adopted environmental leadership as a 
cornerstone of its corporate strategy. As a result of our 
environmental leadership strategy, our company is utilizing a 
growing diverse portfolio of clean technologies in its 
operations. In particular, the American Wind Energy Association 
has ranked Xcel Energy as the number-one wind utility provider 
in the Nation. Similarly, the Solar Electric Power Association 
ranked us No. 5 amongst U.S. utilities for the amount of solar 
power we have in our system. Xcel Energy is America's leading 
renewable energy utility, and by 2020 we expect our increase of 
our renewable energy resources to be 25 percent of our energy 
mix.
    As a result of this commitment to environmental leadership, 
our company is one of the first utilities in the Nation with a 
voluntary plan to reduce greenhouse gases and have reduced our 
actual carbon emissions by 8 percent since 2003. Our emission 
reduction strategy relies on the clean energy initiatives that 
I discussed with you above, and the company is also reducing 
its emissions by retiring coal-fired plants and replacing them 
with natural-gas-fired generation.
    We recently completed a voluntary project in Minnesota 
called the Metro Emissions Reduction Project, or MERP. This is 
a $1 billion effort, which includes the conversion of two of 
our older pulverized coal generating units to natural gas. Now, 
through this project we reduced our SO2 and 
NOX emissions by over 95 percent, and we've also 
reduced and accomplished a carbon dioxide reduction of 40 
percent. Now, details regarding the MERP are included in 
Appendix B to my testimony. We're following a similar strategy 
in Colorado.
    Although we believe that, in a carbon-constrained future, 
utilities must rely on a variety of resources, including coal, 
nuclear, and renewable energy, our experience with the MERP 
demonstrates that natural gas conversion is an excellent method 
of reducing emissions. As a rough rule, natural gas combined-
cycle plants emit about one half has much carbon dioxide as 
coal-fired electricity. Natural gas generation is a proven 
technology, has a lower capital cost, and is far easier to 
permit that some of the other technology options, such as 
nuclear energy; unlike renewable energy, a dispatchable and 
controllable resource that's easily integrated into a utility 
system.
    The historic problem with natural gas, of course, has been 
the volatility of the price, and the industry's increasing 
reliance on natural gas for generation of electricity could 
increase customers' exposure to volatile natural gas prices. 
For this reason, we join in welcoming the recent technological 
developments in the production of new natural gas in the United 
States. The development of gas from shale formations has the 
potential to provide a long-term stable supply for the 
generation of electricity. These new technologies will enable 
utilities to make significant short-term emission reductions 
while awaiting the development of innovative clean energy 
technologies necessary to make significant long-term reductions 
in greenhouse gases, and--such as required by the bill of 
Kerry-Boxer, Energy Jobs and American Power Act.
    To take full advantage of the opportunity created by these 
large new natural gas supplies, industry and government 
together should consider the following issues:
    First, abundant natural gas bodes well for renewable energy 
integration.
    Second, it's important to continue policies that promote 
the development of new clean technologies, regardless of what 
happens to natural gas prices. The Nation should continue to 
invest in R&D for the next generation of nuclear, clean coal, 
energy efficiency, and renewables, and should continue to 
promote incentives designed to assure robust markets for these 
technologies.
    In this regard, Xcel Energy is an advocate of the Renewable 
Energy Tax Credit, a tax credit that would encourage utilities 
to integrate intermittent renewable energy on their systems. 
Such a tax credit would reduce the cost of renewable energy and 
promote its wise use, and happens to be--and basically improve 
the natural gas prices.
    Third, Xcel Energy supports the creation of other 
incentives under the Climate Clean Energy Program to promote 
the retirement or replacement of aging coal plants with natural 
gas. For example, we support the creation of a bonus allowance 
pool to provide support for utilities retiring existing coal 
plants and replacing them with natural gas. A similar incentive 
might make sense under national renewable energy standard or a 
clean energy portfolio standard. In any such incentive, 
however, it is important that Congress recognize the efforts of 
utilities, like Xcel Energy, that have already reduced their 
emissions.
    Finally, while we're optimistic, we have to remember that 
there are other options that have to be created for us. We have 
to have all of the--all the choices available, and not just 
one. At Xcel Energy, we're excited by the new supply 
opportunities created by the natural gas market. With a 
balanced use of natural gas and other clean energy sources, we 
believe we can continue our progress toward a clean energy 
future.
    Thanks again for the opportunity to speak with you today.
    [The prepared statement of Mr. Wilks follows:]
 Prepared Statement of David Wilks, President, Energy Supply Business 
                Unit, Xcel Energy, Inc., Minneapolis, MN
    Chairman Bingaman, Members of the Committee, my name is David 
Wilks, and I am President of the Energy Supply business unit at Xcel 
Energy Inc. I am pleased to be here today to discuss the potential role 
of natural gas in reducing emissions of greenhouse gases from the 
utility industry.
    Xcel Energy is an investor-owned electricity and natural gas 
company headquartered in Minneapolis, Minnesota. We are one of the 
nation's largest combined electricity and gas companies. We serve 
approximately 3.3 million electric customers and 1.8 million gas 
customers. We serve the Twin Cities of Minneapolis-St. Paul, Denver, 
Amarillo and numerous other communities in Southeast New Mexico, 
Minnesota, Wisconsin, Michigan, North and South Dakota, Colorado, and 
Texas. In my capacity as President of Energy Supply, I am responsible 
for the construction, operation and maintenance of Xcel Energy's power 
plants, as well as our company's environmental, energy trading, fuel 
and markets functions. More detail regarding Xcel Energy is found in 
Attachment A* to my testimony.
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    * Document has been retained in committee files.
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    Xcel Energy's Environmental Leadership Strategy. Xcel Energy has 
adopted environmental leadership as the cornerstone of our corporate 
strategy. We are building a clean energy future for our customers and 
the communities we serve by investing in advanced technology, 
innovating our business and engaging our customers in energy 
efficiency.
    As a result of our environmental leadership strategy, our company 
is utilizing a growing, diverse portfolio of clean energy technologies 
in its operations. Xcel Energy is America's leading renewable energy 
utility. By 2020 we will increase our use of renewable energy resources 
to 25 percent of our energy mix. We rely on a broad range of 
renewables:

   For the past five years, the American Wind Energy 
        Association has ranked Xcel Energy as the number one utility 
        wind energy provider in the nation. At the end of the year, we 
        will have about 3,235 megawatts of wind energy on our system, 
        and, by 2020, we plan to have 7,000 megawatts.
   The Solar Electric Power Association ranks us No. 5 among 
        U.S. utilities for the amount of solar power on our system. In 
        Colorado, we already purchase over eight megawatts of utility 
        scale solar power and are close to completing a process that 
        will add almost 300 megawatts of additional solar power to our 
        system by 2015. We also have helped our customers install 
        nearly 35 megawatts of on-site solar energy with incentives 
        provided through our Solar*Rewards program.
   We are developing new biomass projects and recently proposed 
        converting an aging coal plant in Wisconsin to one of the 
        largest biomass plants in the Midwest.

    Xcel Energy is also a leader in energy efficiency. Xcel Energy runs 
some of the largest demand-side management and energy efficiency 
programs in the nation. Since 1992 our customers have saved more than 
enough electricity to enable us to avoid building more than eleven 250-
MW power plants. Our goal is to double these savings by 2020.
    In addition, we are investing in a variety of innovative, clean 
technology programs, including developing the nation's first 
SmartGridCityTM in Boulder, Colorado. Also, for many years, 
we have partnered with the National Renewable Energy Lab (``NREL'') to 
research, demonstrate and deploy various clean energy technologies, 
including plug-in-hybrid electric vehicles and cutting-edge renewable 
energy storage. Last week, as a founding member, we helped break ground 
on the Solar Technology Acceleration Center in Aurora, Colorado. 
SolarTAC is a world-class facility for the solar industry and research 
institutions designed to test and demonstrate advanced technologies for 
the emerging solar market.
    Natural Gas and Greenhouse Gas Emission Reductions. As a result of 
this commitment to environmental leadership, our company is one of the 
first utilities in the nation with a voluntary plan to reduce 
greenhouse gases. We have already reduced our carbon dioxide emissions 
by about 8 percent since 2003. Our emission reduction strategy relies 
on the clean energy initiatives I discussed earlier, but the company 
has also reduced its emissions by retiring coal-fired plants and 
replacing them with natural gas fired generation.
    We recently completed a voluntary project in Minnesota called the 
Metro Emissions Reduction Project, or ``MERP.'' This one billion dollar 
effort included the conversion of two of our older pulverized coal 
generating plants to natural-gas combined cycle technology. Through 
this project, we reduced our SO2 and NOx emissions from these 
facilities by over 95%, and we have also accomplished carbon dioxide 
emissions reductions of roughly 40%. Details regarding the MERP are 
included as Appendix B to my testimony. In Colorado, Xcel Energy is 
pursuing a similar strategy: In the next three years, we will retire 
some of our older, less efficient coal plants, and a significant 
portion of their energy will be replaced by efficient natural gas-fired 
electricity.
    Although we believe that, in a carbon constrained future, utilities 
must rely on a variety of resources, including coal, nuclear and 
renewable energy, our experience with the MERP demonstrates that 
natural gas conversion is an excellent method of reducing emissions. As 
a rough rule, natural gas combined cycle plants emit about half as much 
carbon dioxide as coal-fired electricity. Natural gas generation is 
proven technology; unlike carbon capture and sequestration or other 
clean technologies that will become important in the future, utilities 
can rely on natural gas without reservation today. It has lower capital 
cost and is far easier to permit than some of the other technological 
options, such as nuclear energy. And, unlike renewable energy, it is a 
dispatchable, controllable resource easily integrated into a utility 
system.
    The historic problem with natural gas, of course, has been the 
volatility of the price of natural gas fuel. And, the industry's 
increasing reliance on natural gas for generation of electricity could 
increase customers' exposure to volatile natural gas prices.
    For this reason, we join in welcoming recent technological 
developments in the production of new natural gas resources in the 
United States. The development of gas from shale formations has the 
potential to provide a long-term, stable supply of natural gas for the 
generation of electricity. These new technologies will enable utilities 
to make significant short-term emission reductions while awaiting the 
development of the innovative clean energy technologies necessary to 
make the significant long term greenhouse gas reductions that would be 
required by bills like the Kerry-Boxer Clean Energy Jobs and American 
Power Act.
    Considerations for the New Natural Gas Market. In other words, 
natural gas can serve as a bridge fuel as we await the development of 
the next generation of technology. To take full advantage of the 
opportunity created by these large new natural gas supplies, industry 
and government together should keep consider the following issues:

   First, natural gas found in shale formations must be 
        transported from the well to power plants for use as fuel. In 
        other words, the nation will need the right combination of gas 
        pipelines (to serve gas-fired power plants) and electric 
        transmission lines (to transmit the electricity generated to 
        the customer).
   Second, abundant natural gas bodes well for renewable energy 
        integration. Renewable energy resources can vary quite a bit 
        during a given hour, day or season. Unlike coal and nuclear 
        plants, utilities can start and stop gas plants quickly when a 
        wind or solar plant suddenly drops off line or starts back up 
        as wind or sun conditions change. However, the use of gas for 
        renewable energy integration comes at a cost--a cost closely 
        related to the price of natural gas. In particular, utilities 
        often have additional gas fired units kept below normal loading 
        levels to provide back up capability should renewable energy 
        production decline in a particular hour. If the price of 
        natural gas is lower because of the new production technology, 
        the cost of renewable energy integration will be 
        correspondingly lower as well.
   Third, although low-priced natural gas assists in renewable 
        energy integration, ironically it also competes with renewable 
        energy and other clean energy technologies. Essentially, 
        because the nation has a limited supply of clean energy 
        dollars, utilities, customers and policy-makers are more likely 
        to direct those dollars to natural gas-fired generation if 
        natural gas is projected to be cheaper and more abundant in the 
        future. For this reason, it is important to continue policies 
        that promote the development of new, clean technologies 
        regardless of what happens to natural gas prices. The nation 
        should continue to invest in research and development of the 
        next generation of nuclear, clean coal, energy efficiency and 
        renewables. It should also continue to promote incentives 
        designed to assure robust markets for these technologies. In 
        this regard, Xcel Energy is an advocate of a ``renewable 
        integration tax credit,'' a tax credit that would encourage 
        utilities to integrate intermittent renewable energy (wind and 
        solar) on their systems. Such a tax credit would reduce the 
        cost of renewable energy and promote its use regardless of what 
        happens to natural gas prices.
   Fourth, Xcel Energy supports the creation of other 
        incentives under a climate or clean energy program to promote 
        the retirement and replacement of aging coal plants with 
        natural gas. Such incentives could help reduce emissions in the 
        short term, especially emissions from marginal facilities that 
        would otherwise continue to operate. For example, we support 
        the creation of a bonus allowance pool to provide support to 
        utilities retiring existing coal plants and replacing them with 
        natural gas. A similar incentive might make sense under a 
        national renewable energy or clean energy portfolio standard. 
        In any such incentive, however, it is important that the 
        Congress recognize the efforts of utilities like Xcel Energy 
        that have already employed natural gas to reduce their 
        emissions. Xcel Energy and its customers should not be 
        penalized for their foresight in undertaking projects like our 
        Metro Emissions Reduction Project or our early adoption of 
        wind, solar and biomass generation in advance of any climate 
        mandate.
   Finally, while we are optimistic that new gas production 
        technologies may indeed prove to be ``game changers,'' it is 
        important to keep in mind that gas remains a historically 
        volatile commodity. The increased use of natural gas for 
        electric generation could by itself lead to higher natural gas 
        prices than anticipated. We should not put all of our eggs in 
        one basket, even one as promising as natural gas. A continued 
        reliance on a diverse portfolio of resources remains the 
        nation's best electricity and energy policy.

    At Xcel Energy, we are excited by the new supply opportunities 
created in the natural gas market. With a balanced use of natural gas 
and other clean energy resources, we believe we can continue our 
progress toward a clean energy future.
    Thanks again for the opportunity to testify today. I look forward 
to your questions.

    The Chairman. Thank you very much.
    Mr. Stones, go right ahead.

 STATEMENT OF EDWARD STONES, DIRECTOR OF ENERGY RISK, THE DOW 
                        CHEMICAL COMPANY

    Mr. Stones. Thank you, Chairman Bingaman and members of the 
committee. My name is Edward Stones. I'm the director of energy 
risk for Dow Chemical.
    I follow natural gas so closely that my blood pressure goes 
up and down with the price.
    [Laughter.]
    Mr. Stones. So, Dow uses the energy equivalent of more than 
3500 million cubic feet of natural gas every day in our global 
operations. Of this total, about half is in the United States. 
To put this in a dollars-and-cents perspective, in 2008 we 
spent $27 billion on energy, and that's up from 2002, when we 
spent 8 billion.
    The energy Dow uses is primarily naphtha, natural gas and 
natural gas liquids, Both as an energy source for our 
operations and as a feedstock to make products essential to our 
economy and our citizens' quality of life. These products serve 
as building blocks for everything from pharmaceuticals to 
building insulation, electronic materials, fertilizers, and 
much more. In fact, the U.S. chemical industry takes every 
dollar of energy we buy and turns it into $8 of high-value 
products.
    We understand the importance of natural gas as a clean 
fuel, and that it has a role in climate mitigation; however, 
climate policies that legislate an increase in natural gas 
demand can negatively impact certain sectors of our economy as 
prices rise. For example, from 1997 to 2008, U.S. industrial 
gas demand fell 22 percent as average annual prices rose 160 
percent. The economic term for this is ``demand destruction.'' 
But, in human terms, it's ``job destruction.''
    Over the last 12 years, there have been five significant 
natural gas spikes. During this time, these spikes have 
contributed to the loss of nearly 4 million manufacturing jobs, 
135,000 chemical industry jobs, the permanent loss of nearly 
half of the U.S. fertilizer production capacity, and a $1-
billion trade surplus in the chemical industry in 1997, turning 
into a deficit over 2001 to 2007.
    We hope the predictions about increased natural gas supply 
are right. But, we think it's too early to declare natural gas 
a silver bullet or a bridge fuel solution.
    Driving natural gas preferentially into power generation 
could further erode our manufacturing economy and increase the 
volatility of natural gas, especially for those that remain, 
including residential energy users.
    If the predictions of increased supply of natural gas turn 
out to be true, it would be a greater value to our economy as a 
fuel to spur increased manufacturing investment. More 
industrial users of natural gas will also help dampen 
volatility, as we'll have more price-conscious consumers, not 
fewer.
    Let me be clear. Dow supports prompt congressional action 
on climate and energy bills that achieve environmental results 
while maintaining the competitiveness of American 
manufacturing. Congress should adopt policies that ensure the 
diversity of our energy sources while, at the same time, 
reducing demand through robust efficiency efforts. A price on 
carbon, in our opinion, will be a sufficient market incentive 
for natural gas to aid in the transition to a low-carbon 
economy over a reasonable period of time.
    In summary, Congress is debating legislation that would 
make dramatic changes to the Nation's energy markets. We urge 
you to act now and to make policy choices that increase and do 
not limit our energy options. We must be careful to avoid a 
dash to natural gas. Congress created such a dash in the 1990 
Clean Air Act amendments. It then followed with restrictions on 
access that disconnected the supply from demand. We cannot 
afford to replay that scenario.
    Some call natural gas a ``bridge fuel.'' But, if the wrong 
policy causes a ``dash to gas,'' it's going to be ``a bridge 
too far.''
    Thank you, for your time today, and I'd be happy to answer 
any questions you may have.
    [The prepared statement of Mr. Stones follows:]
 Prepared Statement of Edward Stones, Director of Energy Risk, The Dow 
                            Chemical Company
                              introduction
    The Dow Chemical Company appreciates the opportunity to submit 
these written comments to the Committee on Energy and Natural 
Resources.
    Dow was founded in Michigan in 1897 and is one of the world's 
leading manufacturers of chemicals and plastics. We supply more than 
3,300 products to customers in approximately 160 countries, connecting 
chemistry and innovation with the principles of sustainability to help 
provide everything from fresh water, food, and pharmaceuticals to 
insulation, paints, packaging, and personal care products. About 21,000 
of Dow's 46,000 employees are in the US, and Dow helps provide health 
benefits to more than 34,000 retirees in the US.
    Dow is committed to sustainability. We have improved our 
performance on greenhouse gas (GHG) emissions, and we are committed to 
do even better in the future. Our ambitious 2015 sustainability goals 
underscore this commitment.
    Dow is an energy-intensive company. Dow uses energy, primarily 
naphtha, natural gas and natural gas liquids, as feedstock materials to 
make a wide array of products essential to our economy and quality of 
life. We also use energy to drive the chemical reactions necessary to 
turn our feedstocks into useful products, many of which lead to net 
energy savings.
    This testimony describes the current US energy situation and 
recommends specific policies to ensure a sustainable energy policy for 
the United States. Particular attention is focused on natural gas 
prices, which have and continue to affect the US manufacturing sector.
    Dow believes that natural gas will play a critical role in US 
policy to control greenhouse gases. Because US manufacturing jobs are 
dependent on the US natural gas market, policies that impact natural 
gas will have a direct impact on jobs in the US manufacturing sector. 
We recommend that Congress consider policies that utilize natural gas 
in ways that preserve the competitiveness of US manufacturers.
                natural gas in energy and climate policy
    Natural gas is a relatively ``clean'' (in terms of GHG emissions 
per unit of energy) fossil fuel. Current estimates of the domestic 
supply of natural gas are greater than those of just a few years ago. 
Therefore, increased use of natural gas could help the United States 
reduce GHG emissions and reduce its reliance on foreign sources of 
energy. Climate change and energy security are two of the biggest 
challenges facing the United States, so policies that affect natural 
gas markets impact our collective well being.
           natural gas policy is critical to us manufacturers
    Major sectors that use natural gas include the power, industrial, 
residential, commercial, and transportation sectors. Those sectors in 
which demand is most sensitive to natural gas prices are termed price 
elastic. The more elastic the demand, the more quickly a sector will 
change its demand for natural gas after a change in price. Inelastic 
demand occurs when a change in price results in little change in 
demand. Of the sectors previously identified, the industrial sector has 
the most elastic demand for natural gas. From 1997 to 2008, US 
industrial gas demand fell 22% as average annual prices rose 167%. Over 
the same time, demand for power rose 64% (EIA data). Clearly, a change 
in natural gas price will impact industrial sector demand before that 
in other sectors.
    Both price volatility and the ``average'' price over time have an 
impact on the industrial sector and should be addressed by a 
comprehensive energy policy.
             price volatility in the us natural gas market
    Since 1997, there have been five natural gas price spikes, each 
caused by lags between price signals and production response. The lag 
between changes in drilling and changes in production has been 
remarkably consistent, at about six months. This is the time required 
to fund drilling programs, site wells, schedule crews, drill and tie 
new wells into the grid. When the gas market is over supplied, 
producers respond by reducing drilling, leading to a reduction in 
supply.
    In 2009, as in 2002, 2004 and 2006, drilling has declined 
dramatically as price has fallen. After each trough, natural gas demand 
and price rise once the economy turns, signaling the production 
community to increase drilling. During the lag between the pricing 
signals and new production, only one mechanism exists to rebalance 
supply and demand: demand destruction brought about by price spikes. 
Demand destruction is an antiseptic economic term for job destruction.
    These price spikes have significantly contributed to the US 
manufacturing sector losing over 3.7 million jobs, the chemical 
industry losing nearly 120,000 jobs, and the permanent loss of nearly 
half of US fertilizer production capacity. The manufacturing sector, 
which has limited fuel switching ability, has become the shock absorber 
for high natural gas costs.
    Although increased supply from shale gas appears to have changed 
the production profile, we have seen similar scenarios occur after past 
spikes. In 1998, significant new imports from Canada came on line; in 
2002-2003, there were new supplies from the Gulf of Mexico and in 2005, 
new discoveries in the Rockies were brought into play. In each case, 
the initial hopes were too high and production increases were not as 
large as initially expected. Some claim that the lag expected for shale 
gas will be shorter due to the reduced drilling scope of shale type 
wells. However the latest available data show natural gas production 
peaked with the same delay from the start of drilling reductions as in 
other cycles. The inherent lags between changes in drilling and 
production created natural gas spikes over the last ten years, and will 
continue to do so after this and every trough.
    The next table shows the EIA-estimated levelized cost for new power 
plants by fuel type in 2030. This table shows that the levelized cost 
of a new power plant is equal across the four fuel types. However, the 
variable component of cost for natural gas fired generation is much 
greater than for other fuel choices. This means that electricity 
consumers served by natural gas will experience the biggest price 
shocks. Along with manufacturers who rely on natural gas, consumers of 
electricity generated by natural gas are among those who will be most 
negatively affected by price spikes in the natural gas market. 


    We believe that the increased supply of natural gas from shale 
plays will be an important resource for the United States over the next 
decades. However, as has been demonstrated in previous cycles, this new 
production will not end the cyclicality of natural gas markets. Placing 
a price on GHG emissions will also not overcome the most important 
factors affecting volatility of natural gas prices (e.g., weather).
    When it comes to natural gas and climate policy, Congress should 
consider policies that minimize the demand destruction that occurs in 
natural gas price spikes. This means supporting price elastic consumers 
of natural gas and avoiding the disproportionate addition of inelastic 
demand.
            average price level in the us natural gas market
    It is not just price spikes in natural gas that hurt US 
manufacturers. It is also the average level of natural gas prices. Much 
of the US chemical industry was built when natural gas prices were 
below $2/MMBtu. Since 2001, this historic price level has been 
exceeded, maybe forever. We do not expect US natural gas prices to 
return consistently to this low level in the future.
    Because manufacturers that depend on competitive natural gas prices 
must make capital investment decisions that span decades, the US faces 
stiff competition from abroad. In fact, in our 2005 testimony before 
this Committee, Dow stated that of the 120 world scale petrochemical 
plants proposed to be built, only one was planned for the US.
    Should the US enact a price on GHG emissions, the net impact on 
supply and demand balances must be considered in cases of both average 
and extreme demand. The country's energy supply must be resilient 
enough to overcome natural phenomena such as hurricanes, harsh winters, 
and arid summers. It must continue to support economic growth, allowing 
for high-value job creation in the industrial sector. Without this 
resiliency, natural gas price volatility will increase, affecting both 
employment in the industrial sector and all electricity users.
    EIA modeling of the House-passed energy and climate bill indicate 
how to avoid a ``dash to gas'' in the power sector under a cap and 
trade program. If new power plants using nuclear, renewable, and coal 
with associated carbon capture and sequestration (CCS) are not 
developed and deployed in a timeframe consistent with emission 
reduction requirements, covered entities will respond by increasing 
their use of offsets, if available, and by turning to increased use of 
natural gas in lieu of coal-fired generation. Therefore, it is critical 
to advance all low carbon emitting energy sources and ensure the 
availability of offsets under any cap and trade program.
      relationship between the price of carbon and fuel switching
    A price on GHG emissions will increase demand for natural gas 
relative to other fuels that emit more GHGs per unit of energy. Demand 
is also influenced by the relative price of natural gas compared to 
other fuels in the absence of a price on GHG emissions. Both these 
factors--the relative price differential and the price of GHG 
emissions--work together to influence fuel switching. For example, if 
the price of natural gas is only slightly higher than the price of 
coal, then fuel switching from coal to natural gas will occur at a 
relatively low price on carbon. Conversely, if the price of natural gas 
is much higher than the price of coal, then it would take a higher 
price on carbon to impact fuel switching from coal to natural gas.
    In practice, major investment decisions--such as in power 
generation--can impact fuel choices for decades. Therefore, investors 
project the relative price of natural gas and coal and the expected 
carbon price over the entire time period of the investment. Due to the 
much higher capital cost of coal-fired power generation plants, greater 
uncertainty in price outcomes for power or green house gas emissions 
raises the cost of capital for new power projects, and favors natural 
gas generation. A well-considered, comprehensive, and timely energy 
policy will both lower the cost of power for American consumers and 
reduce the impact of implementing policies to address GHG's.
    For policy makers, the lesson to be learned is straightforward: The 
higher the expected carbon price, the greater the degree of fuel 
switching from coal to natural gas in the power sector. Therefore, cost 
containment is key to minimizing fuel switching under any climate 
policy that places a price on carbon. Under a cap and trade system, 
cost containment depends on the reduction schedule over time and on the 
availability of offsets (and international offsets in particular).
                          recommended policies
    When it comes to natural gas and climate policy, Dow favors 
policies that will avoid the demand destruction that occurs in natural 
gas price spikes, along with policies that will allow the US to use all 
of its low-carbon resources. Such policies will maintain industrial 
competitiveness.
    Dow also believes that the US needs a sustainable energy policy. 
Climate change is an important component of a sustainable energy 
policy, but it is not the only part. We have developed a list of 
specific recommendations that, if implemented, would form the basis of 
a sustainable energy policy.
    First, aggressively promote the cleanest, most reliable, and most 
affordable ``fuel''--energy efficiency. Energy efficiency is the 
consensus solution to advance energy security, reduce GHGs, and keep 
energy prices low. It is often underappreciated for its value. Of 
particular importance is improving the energy efficiency of buildings. 
Buildings are responsible for 38% of CO2 emissions, 40% of 
energy use, and 70% of electricity use. A combination of federal 
incentives and local energy efficiency building codes is needed.
    Second, increase and diversify domestic energy supplies, including 
natural gas. Nuclear energy and clean coal with carbon capture and 
sequestration (CCS) should be part of the solution, as should solar, 
wind, biomass, and other renewable energy sources. We believe a price 
on carbon will advantage natural gas, and further incentives would only 
dangerously increase inelastic demand. Therefore, Congress should not 
provide free allowances or other incentive payments for the purpose of 
promoting fuel switching from coal to natural gas in the power sector.
    An estimated 86 billion barrels of oil and 420 trillion cubic feet 
of natural gas are not being tapped. History suggests that the more we 
explore, the more we know, and the more our estimates of resources 
grow. EIA has said that ``the estimate of ultimate recovery increases 
over time for most reservoirs, the vast majority of fields, all 
regions, all countries, and the world.'' And we have the technology 
that allows us to produce both oil and natural gas in an entirely safe 
and environmentally sound manner. Any new fossil energy resources must 
be used as efficiently as possible.
    One way to maximize the transformational value of increased oil and 
gas production is to share the royalty revenue with coastal states and 
use the federal share to help fund research, development and deployment 
in such areas as energy efficiency and renewable energy. Production of 
oil and gas on federal lands has brought billions of dollars of revenue 
into state and federal treasuries. Expanding access could put billions 
of additional dollars into state and federal budgets.
    Third, act boldly on technology policy through long-term tax 
credits, and increased investment in R&D and deployment. These are 
costly but necessary to provide the certainty that the business 
community needs to spur investment. We didn't respond to Sputnik with 
half-measures. We can't afford to respond to our energy challenges with 
halfmeasures, either.
    Fourth, employ market mechanisms to address climate change in the 
most cost-effective way. There is a need for direct action now to slow, 
stop, and then reverse the growth of greenhouse gas levels in the 
atmosphere. We concur with the principles and recommendations of the US 
Climate Action Partnership (USCAP), of which Dow is a proud member. And 
we recognize that concerted action is needed by the rest of the world 
to adequately address this global problem. Particular attention must be 
paid to cost containment and the availability of offsets (and 
international offsets). Also, climate policy should not penalize the 
use of fossil energy as a feedstock material to make products that are 
not intended to be used as a fuel.
    To minimize the downsides of natural gas price volatility, Congress 
should adopt policies to increase the number of elastic users of 
natural gas, and consider policies to increase US supply of natural 
gas. A resilient natural gas market would empower US manufacturers to 
create high value jobs as they did from 1983-1996, during which period 
US industrial gas use grew at an average rate of 2.7%/yr. In the event 
weather increases natural gas demand, price sensitive exports would be 
temporarily reduced, rebalancing the natural gas market with less 
disruption.
    Under this scenario, price spikes won't be as severe, and won't 
cause as much harm when they occur, which is ultimately good for both 
industry and all consumers. Under this scenario we can envision a 
circumstance in which the chemical industry is once again able to 
preferentially invest in the US.
                               conclusion
    Natural gas will play a critical role in US climate policy. US 
manufacturing jobs are closely linked to natural gas price and price 
volatility. The policy choices Congress will make on natural gas are 
therefore critical to US manufacturers. Without industrial gas users, 
any disruption in supply or demand must be met by dramatic price 
changes.
    Energy efficiency should become a national priority. Congress 
should enact legislation to create a sustainable energy supply based on 
all sources of domestic energy, including nuclear energy. Technology 
policy should create powerful incentives for clean energy technologies, 
such as CCS. A price on carbon, coupled with appropriate cost 
containment measures, would be a large and sufficient incentive to 
promote US natural gas demand, which is already growing even in the 
absence of a price on carbon.
    There is no one silver bullet solution to our energy and climate 
problems. All Americans paid a high price for over-reliance on natural 
gas in the last ten years. Our country cannot afford to repeat that 
mistake. This time we must fashion a comprehensive energy policy which 
addresses supply and demand realities, and environmental, security and 
economic goals to ensure energy costs in the US remain globally 
competitive and avoid economically devastating volatility.

    The Chairman. Thank you very much.
    Mr. McConaghy.

   STATEMENT OF DENNIS MCCONAGHY, EXECUTIVE VICE PRESIDENT, 
PIPELINE STRATEGY AND DEVELOPMENT, TRANSCANADA PIPELINES, LTD., 
                        CALGARY, CANADA

    Mr. McConaghy. Thank you, Senator Bingaman. I welcome the 
opportunity this morning to discuss TransCanada's perspective 
on the opportunity of natural gas in climate change 
legislation. It's good to see Senator Murkowski again, and the 
other members of the committee.
    Just to put into context what TransCanada is, in terms of 
the energy infrastructure of the United States, we have more 
than 36,000 miles of pipelines that deliver 20 percent of the 
natural gas consumed daily in North America. We also own 
approximately 370 billion cubic feet of natural gas storage, 
enough to meet the needs of nearly 4 million homes each year. 
We operate almost 11,000 megawatts of nuclear, coal, hydro, and 
wind generation in Canada and the United States, enough 
capacity to power 11 million homes.
    TransCanada is also a leader in the development of the 
Alaska and Mackenzie gas projects, both designed to connect 
Arctic reserves of natural gas into the North American Market.
    TransCanada's message today can be distilled into three 
basic points:
    No.1, North America is blessed with an enormous long-term 
supply of natural gas. The ability to produce natural gas 
supplies efficiently and economically from shale formations has 
become a game-changer in terms of how we think about natural 
gas availability, supply, and how it can integrate into not 
only energy security, also in terms of how consumers can rely 
on that supply, but also, and perhaps just as importantly, 
climate change legislation.
    No. 2, natural gas pipeline industry has constructed, and 
will continue to construct, the necessary infrastructure to 
deliver these supplies and that goes directly to one of the 
concerns related to volatility.
    No. 3, greater use of North America's abundant natural gas 
resource can make a substantial contribution to tangibly 
reducing greenhouse gas emissions in the short and medium term.
    Let me elaborate very briefly on these three points:
    Robust supply. Contrary to the view of a few years ago, no 
one now sees natural gas as a declining resource. DOE and EIA 
estimates would suggest that we have enough natural gas to last 
for the next 100 years. Shale formations in the Lower 48 alone 
are estimated to hold over 650 Tcf of technically recoverable 
gas. On the North Slope of Alaska, there are 35 Tcf of proven 
reserves and another 200 Tcf of estimated recoverable reserves. 
Not only will these supplies--these reserves supply U.S. demand 
for years to come, but they will also dampen gas price 
volatility and lead to an overall general lower level of prices 
than would otherwise have pertained.
    In respect to infrastructure, in 2008 the natural gas 
pipeline industry completed 84 projects, which added nearly 45 
Bcf of capacity to the pipeline grid. That--this industry has 
demonstrated that we have the capability, in terms of financial 
capability, engineering know-how, to deliver this gas as 
customers and producers require them.
    Presently, TransCanada and its partner, ExxonMobil, are 
leading the development of the Alaska gas pipeline project, 
which is probably the biggest single delivery opportunity that 
is available in the United States. I'm pleased to note to the 
committee that we are on schedule to conduct an open season for 
that capacity next year and that will be a significant 
milestone in advancing that project.
    Last, the contribution to mitigating climate change. As has 
been noted by others on this panel already, natural gas emits 
the lowest of amount of carbon dioxide per unit of generated 
electricity of any fossil fuel. We have the ability to 
substantially increase the amount of electricity generated from 
natural gas. As an example, the current annual average capacity 
utilization factor of the installed fleet of natural gas 
combined-cycled generation units is 42 percent. If we could 
increase that utilization factor to up to 55, we would achieve 
a reduction in greenhouse gas emissions of approximately 135 
million metric tons and to put this into perspective, the 
first-year reduction of greenhouse gas emissions, required 
under Waxman-Markey, is 143; so, 135 out of 143. An increase in 
the utilization factor of this magnitude will require an 
additional 5 Bcf per day of natural gas, an increase well 
within the capability of the continental supply available to 
us.
    Greater use of natural gas offers the U.S. a readily 
available economic means of achieving early and genuine 
greenhouse gas emissions. I would only point out that, under 
the current versions of climate change legislation--and this 
has been modeled by the EIA--that the current architecture of 
some of that legislation, as currently proposed, may actually 
constrain the U.S.'s ability to take full advantage of this 
natural gas opportunity and that's one, I think, important 
challenge that we can all make a contribution to finding the 
best means of increasing natural gas utilization, not just for 
energy security and the interests of consumers, but also to 
advance climate change. TransCanada is eager to participate in 
that process, going ahead.
    Thank you very much.
    [The prepared statement of Mr. McConaghy follows:]
   Prepared Statement of Dennis McConaghy, Executive Vice President, 
    Pipeline Strategy and Development, TransCanada Pipelines, Ltd., 
                            Calgary, Canada
    Chairman Bingaman, Ranking Member Murkowski and members of the 
Committee, thank you for the opportunity to testify today.
                              introduction
    I am pleased to be here on behalf of TransCanada Corporation to 
present our views on the role of natural gas in mitigating climate 
change. Accompanying me today is Dr. Bill Langford, Vice President, 
Pipeline Strategy, TransCanada Pipelines, Limited. Bill is 
TransCanada's in-house expert on natural gas supply and demand.
    With approximately $40 billion in assets, TransCanada, through its 
subsidiaries, is a leader in the responsible development and reliable 
operation of North American energy infrastructure including natural gas 
and oil pipelines, power generation and natural gas storage facilities.
    TransCanada delivers 20% of the natural gas consumed each day in 
North America. Our 36,661 mile wholly-owned natural gas pipeline 
network taps into virtually every major natural gas supply basin on the 
continent. Our vast pipeline network is well positioned to connect new 
sources of supply such as shale gas, coalbed methane and offshore 
liquefied natural gas as well as supply from the north.
    TransCanada also is a leading participant in the Alaska Pipeline 
Project and the Mackenzie Gas Project, both designed to connect Arctic 
reserves of natural gas to the North American market.
    TransCanada is also one of the continent's largest providers of 
natural gas storage and related services with approximately 370 billion 
cubic feet of capacity--enough to meet the needs of nearly four million 
homes each year.
    TransCanada is also one of Canada's largest independent power 
producers. TransCanada owns, controls or is developing more than 10,900 
megawatts of power generating capacity in Canada and the United 
States--enough capacity to power 11 million homes. Our diversified 
power portfolio includes natural gas, nuclear, coal, hydro and wind 
generation primarily located in Alberta, Ontario, Quebec and the 
northeastern United States.
    This year, TransCanada is serving as the chair of the Interstate 
Natural Gas Association of America (INGAA), which represents interstate 
and interprovincial natural gas pipeline companies in North America. 
However, this testimony is being presented only on behalf of 
TransCanada and does not necessarily represent the views of INGAA or 
any of its other member companies.
            role of natural gas in mitigating climate change
    TransCanada believes that increased natural gas utilization can 
make a significant contribution to meeting the energy security and 
climate change objectives of the U.S., for the following reasons:

   Natural gas is a largely domestic resource.
   Natural gas is abundant.
   Natural gas is the cleanest burning hydrocarbon.
   Natural gas has substantial infrastructure in place today to 
        move and use the supplies.
   Natural gas can immediately increase its share of baseload 
        power to deliver real emission reductions.
   Natural gas from international sources can be accessed, if 
        necessary, through the nation's well-developed liquid natural 
        gas (LNG) facilities.

    TransCanada believes that effective U.S. climate policy should 
recognize the significant potential of natural gas in meeting 
greenhouse gas (GHG) emission reduction objectives in both the short 
and long term.
    In the short term, meaningful GHG emission reductions can be 
achieved by more fully utilizing already installed natural gas electric 
generation capacity. Because of abundant and readily available supplies 
of natural gas, these emission reductions can be achieved without a 
substantial impact on natural gas prices. In the longer term, 
TransCanada believes that North America's abundant natural gas resource 
endowment can be one of the foundations upon which United States 
climate change policy is built.
                             supply outlook
    Current Department of Energy (DOE) and Energy Information 
Administration (EIA) estimates, based in large part on improved 
drilling technologies, show that the U.S. has enough natural gas to 
last for the next 100 years .
    In 2008, the U.S. and Canada together consumed 26.8 trillion cubic 
feet (Tcf) of natural gas, with the U.S. consuming 23.2 Tcf and Canada 
consuming 3.5 Tcf. Almost all of this gas was domestically produced. 
LNG imports accounted for 1% of total U.S. and Canadian supplies in 
2008.
    On the supply side, a recently released INGAA Foundation Report 
predicted that U.S. natural gas production will increase by 25% (more 
than 5 Tcf) in 2030 compared to 2008 levels. The EIA AEO Reference case 
also shows a significant growth in U.S. gas production from 2008-2030, 
albeit somewhat less than the INGAA Foundation's analysis.
    While conventional natural gas production is expected to decline, 
unconventional\1\ and frontier\2\ natural gas will increase 
significantly. It is important to note that the term ``unconventional'' 
refers to the source of this gas, not its chemical makeup. 
Unconventional natural gas has the same combustion characteristics as 
gas from other sources, and is fully interchangeable with gas from 
other sources. INGAA's analysis forecasts that unconventional and 
frontier natural gas supplies will grow from 8 Tcf in 2008 to between 
16.1 and 22.4 Tcf in 2030. According to the EIA, natural gas production 
from unconventional resources in the U.S. will increase 35%, or 3.2 
Tcf, between 2007-2030.
---------------------------------------------------------------------------
    \1\ Unconventional natural gas is produced from geologic formations 
that may require well stimulation or other technologies to produce. For 
more information, see the report ICF International prepared for the 
INGAA Foundation in 2008 entitled Availability, Economics, and 
Production Potential of North American Unconventional Natural Gas 
Supplies.
    \2\ Frontier supplies include Arctic natural gas production and 
production from remote or new offshore areas, such as the deeper waters 
of the Gulf of Mexico and the offshore moratorium areas off of the East 
and West Coasts and the coasts of Florida.
---------------------------------------------------------------------------
    This major increase in North American natural gas supplies marks a 
paradigm change for natural gas. Only a few years ago, many industry 
observers expected a long-term decline in domestic natural gas supply. 
This fundamental change in outlook has resulted from remarkable success 
in developing new exploration techniques, particularly extraction of 
gas from U.S. shale deposits.
    According to the ``Modern Shale Gas Primer'' issued by the DOE in 
April 2009, the lower 48 states have a wide distribution of highly 
organic shales containing vast resources of natural gas. These shales 
include over 300 Tcf of technically recoverable resources, including 
some of the following major formations:

   The Barnett Shale is located in the Fort Worth Basin of 
        north-central Texas. With over 10,000 wells drilled to date, 
        the Barnett Shale is the most prominent shale gas play in the 
        U.S. Technically Recoverable Resources = 44 Tcf.
   The Fayetteville Shale is situated in the Arkoma Basin of 
        northern Arkansas and eastern Oklahoma. With over 1,000 wells 
        in production to date, the Fayetteville Shale is currently on 
        its way to becoming one of the most active plays in the U.S. 
        Technically Recoverable Resources = 41.6 Tcf.
   The Haynesville Shale (also known as the Haynesville/
        Bossier) is situated in the North Louisiana Salt Basin in 
        northern Louisiana and eastern Texas. In 2007, after several 
        years of drilling and testing, the Haynesville Shale made 
        headlines as a potentially significant gas reserve, although 
        the full extent of the play will only be known after several 
        more years of development are completed. Technically 
        Recoverable Resources = 251 Tcf.
   The Marcellus Shale is the most expansive shale gas play, 
        spanning six states in the northeastern U.S. (NY, OH, PA, WV, 
        KY, and VA). Technically Recoverable Resources = 262 Tcf.
   The Woodford Shale is located in south-central Oklahoma. 
        Technically Recoverable Resources = 11.4 Tcf.
   The Antrim Shale is located in the upper portion of the 
        lower peninsula of Michigan within the Michigan Basin. Aside 
        from the Barnett, the Antrim Shale has been one of the most 
        actively developed shale gas plays with its major expansion 
        taking place in the late 1980s. Technically Recoverable 
        Resources = 20 Tcf.
   The New Albany Shale is located in the Illinois Basin in 
        portions of southeastern Illinois, southwestern Indiana, and 
        northwestern Kentucky. Technically Recoverable Resources = 19.2 
        Tcf.
   Northeast British Columbia shales, although early in their 
        development, exhibit potential reserves comparable to the 
        larger U.S. shale plays.

    The robust development of shale plays in the United States has been 
due to the improvement in, and successful application of, several 
technologies that allow the economic production of natural gas from 
shale formations.
    The successful application of these improved technologies has 
opened up the possibility of accessing an extremely large natural gas 
resource. Furthermore, inevitable continued improvement in technology 
will, in all likelihood, result in a larger and larger proportion of 
existing gas resources--the `gas in place'--being economically 
produced. This will allow for continued growth in North American 
natural gas production even farther into the future.
    In addition to the five key shales in the U.S., shales have also 
been identified and drilled in Canada--the Horn River and Montney plays 
in Western Canada and the Utica in Quebec. These shales, particularly 
the Horn River and Montney plays, have the potential to further support 
U.S. demand growth.
    Although Lower-48 and Canadian shale production will exhibit robust 
growth over the next decade, there will still be a requirement for 
substantial volumes of other, non-shale natural gas. Tight gas, coal-
bed methane and conventional gas will remain prominent in the supply 
mix in the years to come. This will be true even with only modest 
demand growth. More rapid demand growth, perhaps due to the efforts 
aimed at reducing GHG emissions, suggest even larger amounts of non-
shale gas will be in the supply mix.
    Furthermore, the presence of plentiful and ready opportunities for 
natural gas development suggests that gas price volatility will be 
dampened, with any price spikes being smaller and of shorter duration.
    With respect to natural gas prices, the cost of shale gas will not 
`set' the price of natural gas in North America. But the added supplies 
will mean that gas is more plentiful and lower cost than it would have 
been without it.
                        pipeline infrastructure
    Today, there are over 300,000 miles of large-diameter, high 
pressure pipelines in the United States that have the capacity to 
deliver in excess of 70 Bcf per day. These pipelines constitute the 
interstate highway system of our nation's natural gas infrastructure. 
To accommodate the increases in natural gas supply described above, a 
continued expansion of the natural gas pipeline infrastructure is 
needed. To date, the North American natural gas pipeline industry 
successfully has met this challenge. The 84 projects completed in 
2008--the greatest amount of pipeline construction activity in more 
than 10 years--added 44.6 Bcf per day of capacity to the pipeline grid. 
Those 2008 additions cost an estimated $11.4 billion. By comparison, 
pipeline expansion in 2007 was $4.3 billion for 50 projects that added 
14.9 Bcf per day of capacity to the network
    This expansion has (1) allowed market access for incremental gas 
supplies, notably from the Rockies and shale gas production areas; (2) 
moderated regional price differentials and contributed to reducing 
natural gas price volatility; and (3) provided greater supply access to 
domestic natural gas users, notably the power generation sector.
Infrastructure for Alaska Natural Gas
    TransCanada is continuing to invest in infrastructure that will 
accommodate growing domestic natural gas supplies. One prominent 
example is the Alaska Natural Gas Pipeline. Current proven natural gas 
reserves on the North Slope of Alaska are 35 trillion cubic feet. The 
US Geologic Survey has estimated yet to be proven reserves in excess of 
200 Tcf. As currently contemplated, when the Alaska gas pipeline comes 
into service it will add 4.5 Bcf of natural gas per day to the supply 
available to consumers. This capacity can be easily expanded to over 6 
Bcf per day. No other single source of natural gas has the ability to 
increase daily supply by this magnitude.
    For more than 30 years, TransCanada has actively sought to bring 
the enormous proven and unproven reserves of natural gas from the North 
Slope of Alaska to consumers in the lower-48 states, and is leading the 
effort today. In December 2008 TransCanada Alaska Company, LLC, a 
subsidiary of TransCanada Corporation, was awarded a license by the 
State of Alaska pursuant to the Alaska Gasline Inducement Act (AGIA).
    Under its AGIA license, TransCanada will conduct open seasons for 
capacity on the pipeline and prepare and file an application for a 
certificate of public convenience and necessity (CPCN) from the Federal 
Energy Regulatory Commission (FERC). Consistent with the requirements 
of AGIA, TransCanada began the field, engineering, design, commercial 
and regulatory work necessary to conduct an initial open season in 
2010. In June, TransCanada reached an agreement with Exxon Mobil to 
pursue joint development of the pipeline. We are calling that joint 
effort the Alaska Pipeline Project (APP).
    TransCanada is on schedule to make an open season filing with the 
FERC in late January 2010, and, assuming FERC's timely approval, 
conduct a 90 day open season beginning on or about May 1, 2010. This 
will be the first open season ever conducted for an Alaska gas 
pipeline. As with most open seasons for large pipeline projects, the 
bids from potential shippers in the initial open season are likely to 
have conditions that need to be satisfied before the shippers make a 
binding commitment. Nevertheless, TransCanada and the APP will continue 
the substantial work needed to prepare the CPCN application and will 
work with the State of Alaska and the potential shippers to resolve 
those conditions in a satisfactory and timely manner.
    While there are many challenges confronting the Alaska Pipeline 
Project, more progress has been made on the project in the last 15 
months than at any previous time. If all of the involved parties can 
successfully resolve their differences, the APP can deliver North Slope 
natural gas into the North American pipeline grid by late in the next 
decade.
Pipeline and Supplies Match Power Demand
    Today, natural gas fired generation meets about 20% of U.S. 
electricity demand on an annual average basis. The U.S. electric power 
sector has approximately 400 gigawatts (GW) of installed natural gas 
capacity. However, the average capacity utilization factor for natural 
gas combined cycle units was only 42% in 2007. These facilities, which 
are already connected to the electric transmission grid and to natural 
gas supply, constitute a significant inventory of ``ready to be 
dispatched'' natural gas fired generation that can make a significant 
down payment on meeting GHG emission targets.
    For example, if the average utilization factor of these installed 
combined cycle units was increased from the current 42% to 55% with a 
commensurate reduction in coal generation, the resulting net decrease 
in GHG emissions would be on the order of 134 million metric tons. And, 
such an increase in utilization would require roughly an additional 5 
Bcf per day of natural gas--a volume that can be easily accommodated 
from a continental supply perspective considering the contributions 
from shale gas and /or Alaska. With electric generation accounting for 
a third of all greenhouse gas emissions, burning more natural gas for 
electric generation will produce immediate and verifiable GHG emission 
reductions.
    When new generation capacity is required, natural gas has 
significant advantages as a low-carbon generating resource, in that it 
is dispatchable, easily scalable, and can be quickly deployed.
Pipeline Capacity and Expanded Supply Moderate Prices
    There was a period of time where new gas-fired generation and 
drilling projects were outpacing the availability of pipelines. Recent 
major pipeline expansions have significantly improved the access of 
incremental supplies to markets, contributing to reduced price 
volatility and a lower overall price level for natural gas.
    The availability of major new shale supplies in parts of the U.S. 
that are not as prone to weather-related incidents, like hurricanes in 
the Gulf of Mexico, helps reduce price volatility. And, if required, 
the current LNG infrastructure provides the option of accessing 
international supplies which would further assist in moderating price 
volatility.
            natural gas as part of the climate change policy
    Just as natural gas plays a key role in meeting U.S. energy 
demands, it can also play a key part in providing meaningful, 
immediate, and verifiable emission reductions. Natural gas emits the 
lowest amount of carbon dioxide per unit of generated electricity of 
any fossil fuel. Due to its reliability and ease of deployment, natural 
gas generation can also serve as a low-carbon backup resource for 
intermittent renewable energy sources.
    The primary goal of climate change legislation is to reduce 
greenhouse gas emissions. Any GHG regulatory regime ultimately 
established by the Congress should move power generation choices in the 
direction of increased use of lower carbon resources, including natural 
gas, by establishing appropriate price signals and other structural 
provisions. Additionally, natural gas generation can ensure the 
integration of intermittent renewable energy sources into the 
electrical grid.
    An increase in natural gas usage, as the lowest carbon content 
fossil fuel, in a stable investment environment that includes access to 
North America's large natural gas resources, both offshore and onshore, 
can be seen as the appropriate market response to properly designed 
carbon constraint policy.
    However, EPA and EIA modeling of H.R. 2454, the Waxman-Markey 
climate bill, shows a potentially perverse result. For example, in 
EIA's July 2009 analysis of the Waxman-Markey bill, natural gas 
consumption in 2020 drops from a business-as-usual reference case 
projection of 22.1 quadrillion BTU to 21.5 quadrillion BTU in the basic 
Waxman-Markey scenario and drops even more in 2030 from 24.2 
quadrillion BTU in the EIA reference case to 21.1 quadrillion BTU in 
the basic Waxman-Markey scenario. The only scenario where EIA shows an 
increase in the consumption of gas is the so-called ``No International/
Limited Case'' where none of the other low carbon technologies, like 
expanded nuclear or carbon capture and sequestration, are sufficiently 
available in the relevant time frame and use of international offsets 
are constrained.
    Consequently further policy adjustments to proposed climate change 
legislation are justified and necessary. As the Senate deliberates 
climate change and clean energy legislation, it should consider 
additional measures to take advantage of the unique potential of 
natural gas as a low-carbon power resource. Policy choices available to 
promote the use of natural gas would probably requireIn particular, the 
Senate should consider mechanisms that encourage the early retirement 
of less efficient, less clean power sources. A number of ideas, such as 
an auction of 100% of allowances, a climate allowance compliance option 
based on avoided coal/increase natural gas use (so-called ``Bridge Fuel 
Credit''), cash for coal clunkers, and a broader resource-base clean 
energy mandate, have been suggested and should be considered as part of 
the climate debate. But, TransCanada also recognizes the need for some 
transitional support for the customers and shareholders of these less 
efficient, less clean power sources. TransCanada is committed to 
working with policymakers to find the best combination of these policy 
instruments.
Specific Interstate Pipeline Concerns
    With respect to climate change legislative proposals that have a 
direct impact on interstate natural gas pipelines, TransCanada endorses 
recommendations made by INGAA to address two specific concerns--
performance standards for fugitive emissions and the ability to ensure 
recovery of the costs of cap and trade allowances.
    H.R 2454 proposes command-and-control performance standards on 
fugitive methane emissions from natural gas systems, landfills, and 
coal mines. Specifically, the proposed Clean Air Act Section 811 
directs EPA to promulgate performance standards for new and existing 
uncapped sources that individually emit more than 10,000 metric tons of 
CO2e per year and collectively emit at least 20% of uncapped 
emissions. The Kerry-Boxer bill would delay the promulgation of 
performance standards for greenhouse gas emissions until 2020, but 
would still permit EPA to impose such standards after that date.
    These proposed performance standards will impose heavy costs on the 
natural gas industry because of the vast number of small sources of 
fugitive emissions and the technological challenges inherent in 
capturing their emissions. In addition, these proposed standards would 
keep methane sources from qualifying as domestic offset projects--
thereby restricting the supply of domestic offset credits and 
increasing the costs of compliance for all sources within the cap. 
TransCanada recommends that climate change legislation eliminate EPA's 
authority to impose performance standards on uncapped methane sources 
under the Clean Air Act, and instead treat methane sources as offset 
project opportunities. To provide offset project developers with 
greater certainty, the bill should include an explicit list of eligible 
offset project types that includes projects that reduce fugitive 
methane emissions from natural gas systems. In contrast to a command-
and-control regulatory regime, this approach would give fugitive 
methane sources a market-based incentive to begin reducing emissions 
from the first day of the cap-and-trade program. Treating methane 
sources as offset projects would also give our industry the flexibility 
to identify and pursue cost-effective emission reduction opportunities; 
generate revenue to fund the installation of emission capture systems; 
and increase the supply of domestic offset credits to entities within 
the cap, making the entire cap-and-trade program more cost-effective.
                       pass through cost recovery
    Under both the Waxman-Markey and Kerry-Boxer bills, natural gas 
pipelines are treated as industrial emitters and will incur significant 
costs to comply with the cap-and-trade regime and new Greenhouse (GHG) 
Performance Standards. Unlike most other industrial emitters, however, 
natural gas pipelines provide a regulated transportation service and 
therefore have difficulty passing these costs on to customers.
    INGAA strongly urges the Senate to include a provision in its 
climate legislation that permits regulated entities to effectively and 
efficiently recover new costs imposed due to allowance compliance 
obligations as well as new GHG Performance Standards (if they are not 
eliminated as proposed above).
    INGAA believes that the clear, automatic pass through of climate 
legislation-related costs is necessary to ensure timely recovery of 
highly volatile costs, which a traditional filed rate process. Such a 
pass through provision would also place pipelines on equal footing with 
other industrial emitters that have the flexibility to account for new 
costs in their pricing.
                               conclusion
    Natural gas plays an important role to U.S. energy and 
environmental security. Its benefits as a clean, abundant, available, 
and ready source must not be overlooked as part of a climate strategy. 
The new supply paradigm and robust infrastructure, both in terms of 
pipelines and gas-fired power plants, provide a solid foundation for a 
low-carbon energy future.

    The Chairman. Thank you very much.
    Mr. Fusco, why don't you go ahead. You're our cleanup 
witness here.

STATEMENT OF JACK FUSCO, PRESIDENT AND CHIEF EXECUTIVE OFFICER, 
                CALPINE CORPORATION, HOUSTON, TX

    Mr. Fusco. Thank you, Chairman Bingaman, Ranking Member 
Murkowski, and the members of the committee. Thank you for the 
opportunity to testify today on the role of natural gas in 
mitigating climate change.
    I'm Jack Fusco, president/CEO of Calpine Corporation. 
Calpine is the Nation's largest independent power producer, one 
of the largest consumers of natural gas for electric 
generation.
    Because environmental leadership has been a governing 
principle at Calpine for over 25 years, we've been able to 
achieve the lowest greenhouse gas footprint in the industry. 
Our fleet consists of 62 modern, clean, efficient natural-gas-
fired power plants and 15 geothermal plants, located in 16 
States, with the capacity to power over 20 million households. 
Additionally, we are the largest cogenerator in the country. We 
are a significant supplier to America's industry, producing 
steam for refineries, as well as chemical, paper, agricultural, 
and plastic manufacturers. We use approximately 3 percent of 
all the natural gas consumed in the country and almost 10 
percent of that consumed by electric generators. Because we use 
existing modern technology and natural gas for fuel, our 
natural gas plants emit less than 40 percent less carbon 
dioxide than the electric generation industry average, 
virtually zero acid-rain-forming sulfur dioxides, less than 
one-tenth the industry average smog-producing nitrous oxides, 
and no mercury whatsoever.
    I'm here today to tell you that the near- and medium-term 
solution to our climate change challenge is at hand. Natural-
gas-fired electric generation is a compelling solution. First, 
it's far cleaner, with far less impact on our air, our land, 
our water resources, than any other form of fossil fuel 
generation. Second, the proven technology exists; it's far 
cheaper to construct than any other alternatives. Third, it's 
critical for the integration the intermittent renewable 
resources into the electric grid. Fourth, there is enough 
existing underutilized natural gas power plants located in the 
United States today to reduce the annual power sector 
CO2 emissions by up to 20 percent. Then, last, as 
you heard from the others here today, there is an abundant, 
secure, and economical supply of domestic natural gas that 
should last for decades.
    We could, today, simply through the increased use of 
existing modern natural-gas-fired power plants, meaningfully 
reduce the CO2 emissions of the power sector. The 
power would be reliable, available all day and every day, and, 
with the right incentives, American businesses will continue to 
invest its own capital to build more natural-gas-fired plants 
and dramatically greenhouse gas emissions for the long term.
    Calpine, I would modestly submit, is the model for a 
sustainable future. We use a mix of natural-gas-fired and 
renewable generation to achieve the results I just referred to. 
The majority of our gas-fired plants use state-of-the-art 
combined-cycle technology. A significant portion of the plants 
use combined heat and power, or cogeneration technology, to 
produce electricity and steam. Cogeneration opportunity--
operations are significantly more efficient and result in less 
greenhouse gas emissions than having a standalone boiler at an 
industrial site. This is also a very efficient means of serving 
industrial production, and is recognized and encouraged by 
Federal policies.
    We are also a significant contributor to the Nation's 
existing renewable generation capacity, with our 725 megawatts 
of geothermal power located in northern California. This is the 
only currently viable source of baseload renewable electricity, 
and our resource provides California with over 25 percent of 
its current renewable energy production.
    We, at Calpine, continually challenge ourselves to further 
increase our corporate commitment to environmental leadership. 
For example, we have little impact on our Nation's water 
resources by not using once-through cooling at any of our 
plants; instead, we utilize treated municipal wastewater or air 
for cooling purposes.
    Then, finally, we plan to build the Nation's first power 
plant with a voluntary limit on greenhouse gas emissions. The 
plant will emit less than half the carbon dioxide of even the 
most advanced coal-fired generating technologies.
    Calpine has been, and continues to be, supportive of the 
House and Senate efforts to enact climate legislation. There 
are some key issues that I'd like to comment on.
    First, we sell steam and power under long-term contracts, 
many of which may not be--may not allow us to recover our costs 
under a carbon-regulated program. Both the Waxman-Markey and 
the Kerry-Boxer proposals would allocate those free allowances 
to us and others, which is critical to the continued viability 
of those projects. We encourage you to leave those protections 
in place. Otherwise, early actors like Calpine will be unfairly 
punished.
    Then, second, none of the proposals provide incentives to 
utilize existing, highly efficient, combined heat and power 
technology. We encourage you to add such incentives.
    Third, none of the proposals provide incentives to 
encourage the full use of the existing modern natural-gas-fired 
power plants which could immediately reduce the electric 
sector's emissions by over 20 percent.
    Then, fourth, both on the climate change proposal --both 
climate change proposals unduly favor dirtier generation to the 
point that incentives to switch to existing gas generation, or 
build new gas generation, are severely blunted. Under the 
proposed allowance methodologies, carbon prices would have to 
be extremely high for coal-to-gas switching to occur. The 
Kerry-Boxer proposal does include some incentives to replace 
high-emitting fossil fuel generation with a cleaner generation, 
but likely only for owners of high-emitting fossil fuel plants, 
and only if the new gas plants emit at levels not currently 
achievable by the industry.
    In summary, while it's clear that we need a very varied 
energy source to meet the challenges of the future, we can meet 
our national goal of substantially reducing the electric power 
sector's carbon footprint with a policy designed to motivate 
greater use of existing, and to construct new, gas-fired power 
plants. It's also clear the natural gas supply is as secure and 
as abundant as the coal supply.
    Thank you all, and I would be pleased to answer any of your 
questions.
    [The prepared statement of Mr. Fusco follows:]

    Prepared Statement of Jack Fusco, President and Chief Executive 
               Officer, Calpine Corporation, Houston, TX

    Chairman Bingaman, Ranking Member Murkowski and members of the 
Committee, thank you for the opportunity to testify today on the role 
of natural gas in mitigating climate change.
    I am Jack Fusco, President and CEO of Calpine Corporation. Calpine 
is the nation's largest independent power producer with the lowest 
carbon footprint in the industry. In addition to the largest fleet of 
natural gas fired plants we have the largest baseload renewable energy 
resource in the country. We consume approximately 3% of all natural gas 
used in this country and almost 10% of that used to make electricity 
and thermal energy. In short we are uniquely positioned to address the 
role of natural gas in meeting the climate change challenge. Calpine 
has actively supported enactment of climate change legislation for many 
years and we have long put our money where our mouth is when it comes 
to minimizing our carbon footprint. (Please see appendix for more 
detailed background on Calpine.)*
---------------------------------------------------------------------------
    * Appendix has been retained in committee files.
---------------------------------------------------------------------------
    I am here today to tell you that we could, today, simply through 
the increased use of existing natural-gas fired power plants, 
meaningfully reduce the CO2 emissions of the power sector, 
immediately and for the foreseeable future. In other words, a near-and 
medium-term solution to our climate change challenge is at hand. No 
guesswork. No huge spending programs needed. That power would be 
reliable--available all day, every day. And if we embrace this solution 
with the right incentives, American business would continue to invest 
its own capital in existing proven technologies to build even more 
natural gas fired plants to dramatically further reduce emissions for 
the longer term.
    We power American households, businesses and industry with plants 
that, compared with other fossil fuel plants, emit only half of the 
carbon, almost none of the other air pollutants and virtually no 
mercury. We are available now and can quickly build more capacity to 
help America grow tomorrow, responsibly and sustainably. Importantly, 
as you've heard from the other experts today, there is no security of 
fuel supply concern because natural gas supply is as secure as coal 
supply.
        the calpine model is the model for a sustainable future
    I would like to point out a real life example of how private 
business can be a leader in creating a sustainable future and reducing 
GHG emissions through the use of existing and developing technologies 
related to natural gas-fired electric power generation. The best way to 
do that is to tell you about what we have done at Calpine because I 
deeply believe it is the model for the future.
    For better than two decades Calpine has put its money into clean, 
highly efficient natural gas plants and renewable energy production. 
The majority of our gas-fired plants use state-of-the-art combined-
cycle natural gas-fired technology which capture and use the exhaust 
from gas turbines to generate additional energy in a steam turbine.
    A significant portion of our generation uses combined heat and 
power (CHP or cogeneration) technology. At our cogeneration facilities, 
we use natural gas as a fuel to produce not only electricity but also 
thermal (steam) energy. The electricity produced is sold either into 
the wholesale power market or via a long-term contract to an end user 
(typically an electric utility or industrial consumer); the steam is 
sold, via contracts, to our industrial host. CHP operations are 
significantly more efficient and result in less GHG emissions than 
having a stand-alone power plant and a separate stand-alone boiler at 
an industrial site. For this reason there are federal policies and 
programs which actively support CHP. As the largest independent 
cogeneration company we help many of America's chemical, oil refining 
and other industrial facilities operate efficiently and cleanly.
    While a small percentage of our generation mix is renewable, the 
resource we utilize makes it a significant contributor to the renewable 
generation capacity in the country. Calpine generates 725 MW of 
geothermal power at our Geysers facilities in Northern California. The 
geothermal resource is nearly emissions free and is available 24-7-365, 
making it the only currently viable source of baseload renewable 
electricity. Our geothermal operations provide California with its 
largest source of renewable energy.
    Our investments in these technologies have made us a very clean 
generator, and as I said previously, with significantly fewer air 
emissions than the electric sector average. Compared with the 
electricity industry average, Calpine's natural gas plants emit 40% 
less CO2, less than one-tenth of smog producing 
NOX, virtually zero acid rain forming SO2, and 
absolutely no mercury (see figure 1).*
---------------------------------------------------------------------------
    * Figures 1-3 have been retained in committee files.
---------------------------------------------------------------------------
    Our sense of environmental responsibility extends beyond air 
emissions. For example, we invest to reduce or eliminate the impact on 
our nation's water resources. At our geothermal facility, we take 
treated waste water from nearby counties and re-inject it into our 
wells to supplement the steam resources. Further, Calpine has no once 
through cooling power plants. We strive to utilize treated municipal 
waste water for cooling purposes or air cooling. This is the 
sustainable approach.
    We continually challenge ourselves to further increase our 
corporate commitment to environmental leadership and, to that end, we 
recently announced plans to build the nation's first power plant with a 
federal limit on emissions of CO2 and other greenhouse 
gases, even though there currently is no regulation mandating that we 
do so. Our proposed Russell City Energy Center, a 600 MW plant using 
advanced combined-cycle technology, will be the cleanest natural gas-
fired plant in the country. At baseload conditions, the plant is 
designed to operate at an efficiency rate that results in approximately 
800 lbs of CO2 /MWh of power delivered to the grid. This is 
less than half the 1,700 lbs of CO2/MWh emitted by even the 
most advanced coal-fired generating technologies.
                           natural gas is key
    While the technologies we use are an important component of why we 
are so clean and efficient, the major source of our success is our 
chosen fuel--natural gas. Natural gas is considerably cleaner than 
other fossil fuels. Compared to coal, using natural gas as a fuel for 
electricity generation results in nearly 50% less CO2 
emissions, about 80-90% less NOx emissions, negligible SO2 emissions, 
and no mercury emissions. In addition, gas-fired plants produce a 
significantly smaller waste stream, if any, than coal (fly ash) and 
nuclear (spent fuel) plants.
    There are a number of other advantages natural gas-fired generation 
has over other generation sources. Compared to many other generation 
sources, natural gas power plants can be permitted quickly and they 
have a much smaller footprint. In addition, they can be built more 
quickly and cost less to build on a per megawatt of capacity basis (see 
figure 2).
    Natural gas combined-cycle generation is also an ideal choice for 
backing up intermittent renewable electricity sources due to its 
ability to quickly ramp up and down. With the push for vastly expanding 
the nation's renewable generation capacity, much of the new capacity 
that will come on-line to fill this need is likely to be from 
intermittent sources. This could have an impact on the reliability of 
the electricity system. Americans demand and deserve reliable energy--
when they flip on the light switch, the lights must go on. In the near 
term, this will only be achievable if gas-fired plants are there to 
provide that reliability.
    Increased use of natural gas-fired generation can also have an 
immediate impact in reducing carbon emissions. Currently, there is a 
significant amount of existing natural gas-fired generation capacity 
that is not being utilized. The increased utilization of these existing 
facilities in place of older, dirtier power plants would result in near 
term GHG emissions reductions of up to 20% without the need for 
building new generating facilities (See figure 3).
    Calpine continues to believe that natural gas is the right fuel 
choice for electricity generation. With the recent forecasts of 
substantial domestic supplies for the foreseeable future, natural gas 
is the key for providing the clean, efficient, reliable, and affordable 
electricity needed to help meet the nation's climate change goals.
   comments on existing climate change and clean energy legislative 
                               proposals
    Calpine has been very involved in the climate change and clean 
energy policy debate in Congress and applauds the legislative steps 
underway to address the climate change problem and to move the country 
towards the greater utilization of clean, efficient and renewable 
energy resources. We supported H.R. 2454, The American Clean Energy and 
Security Act of 2009, and we are encouraged to see that S. 1733, The 
Clean Energy Jobs and American Power Act, largely follows the same 
framework of H.R. 2454; we also supported components of S. 1462, the 
American Clean Energy Leadership Act of 2009, which passed out this 
committee. I would like to point out an issue of great importance to us 
contained in the climate change bills and some areas of concern in all 
of the bills.
                          long-term contracts
    Calpine sells some of our power and nearly all of our steam under 
long-term contracts. Many of our existing contracts were entered into 
before there was serious consideration of carbon regulations, thus 
these contracts do not include provisions to allow for compliance cost 
recovery. In general, merchant power generators will have an 
opportunity to recover compliance costs via the wholesale price of 
electricity and regulated utilities will have an opportunity to seek 
recovery of their compliance costs via their jurisdictional state or 
local regulatory commission. In our case we remain subject to the terms 
of our sales contracts, and it is unlikely we could successfully change 
these contracts to allow for cost recovery. Should we be unable to 
recover our costs associated with these long-term contracts, we could 
face financial harm and the contracts could be put into jeopardy. It is 
important to note that many of our contracts are associated with our 
CHP facilities.
    Calpine believes it is imperative that climate change legislation 
provide protection for generators with such existing long-term 
contracts for delivery of both electricity and steam. We are very 
pleased that both H.R. 2454 and S. 1733 address this concern by 
providing free allowances to eligible generators with long-term 
electricity and steam contracts. As the legislation moves forward in 
Congress, we implore you to ensure that this provision remains intact.
                             chp incentives
    We know there is established federal policy promoting CHP as an 
important form of energy efficiency. Per such policy, we would expect 
that there would be policies that promote the utilization of both 
existing and new CHP facilities. However, none of the existing 
legislative proposals provide real benefits for existing CHP units. 
There are many underutilized CHP facilities throughout the country that 
could help meet energy efficiency goals. Including credit for these 
facilities for the energy efficiency goals in the various bills would 
ensure that such existing CHP facilities are efficiently and 
effectively used.
                         natural gas incentives
    Real incentives to encourage the greater use of natural gas are 
also largely missing from all of the bills. We have heard arguments 
that just putting a price on carbon will naturally benefit natural gas, 
as this will likely automatically lead to fuel switching from coal to 
natural gas; therefore, there is no need to include incentives for 
natural gas in legislation. However, both H.R. 2454 and S. 1733 provide 
such broad benefits for dirtier sources of generation and for renewable 
energy resources, that the ``natural benefit'' for natural gas will be 
seriously blunted. Under the proposed allowances methodology, carbon 
prices would have to be extremely high for fuel switching to occur.
    S. 1733 includes a provision promoted as encouraging the greater 
use of natural gas. The intent of the provision is to provide 
incentives to displace high GHG emitting electric generating units with 
lower emitting sources, which generally would benefit natural gas fired 
generation. However, the way the section is written could be 
interpreted and implemented in a way that ultimately does not benefit 
natural gas, particularly existing natural gas generation. First the 
funds would only go to new projects. Second, to be eligible for funds, 
the project must reduce emissions below a certain threshold that is 
lower than most natural gas fired plants can likely meet.
    More work and thought needs to be put into providing true 
incentives for natural gas in these legislative proposals.
                               conclusion
    Calpine believes that natural gas is a key resource in helping to 
mitigate the effects of climate change. We remain committed to being an 
important player in working with you to resolve this problem. While it 
is clear that varied energy sources are needed to meet the challenge, 
it is equally clear that the greater use of natural gas with its 
compelling and distinct advantages has been overlooked. I urge you to 
seriously consider natural gas as a solution and to enact policy that 
promotes it.
    Thank you again for this opportunity to testify.

    The Chairman. Thank you. Thank all of you for your 
excellent testimony.
    Let me start with a few questions and then Senator 
Murkowski, and I'm sure all members will have questions.
    Mr. Newell, let me start with you. You know, when we 
started talking seriously, a couple years ago, about climate 
change legislation and putting a price on carbon, I can 
remember discussions where people said one of the effects of 
this would be to encourage more use of natural gas, since it's 
the least carbon-intensive of the various fossil fuels. I 
notice--and you commented on it--your analysis of the Waxman-
Markey legislation, that's passed the House, predicts that 
natural gas usage would not be significantly higher as a result 
of putting a price on carbon, as that legislation proposes to 
do. In fact, in some of the modeling scenarios that you have, I 
guess you have natural gas usage even lower than in the 
reference case.
    Could you just explain how--again, maybe you went over this 
in your comments, but, to the extent you could elaborate on why 
you do not see the enactment of climate change legislation, 
such as the House has passed, increasing the use of natural gas 
in power generation and other sectors of the economy?
    Mr. Newell. Yes. Let me offer a little bit about the 
history. I think that one of the main factors that's changed, 
depending upon how far back you look, is that natural gas 
prices have come up significantly over the last several years, 
whereas, if you turn back the clock to a point when people were 
discussing, for example, the Kyoto Protocol and so on, at that 
point in time gas prices were significantly lower. So, as a 
cost-effective means of reducing greenhouse gas emissions, 
natural-gas-based generation for electricity looked relatively 
more competitive, compared to existing coal, than it does now. 
It's kind of a bit of----
    The Chairman. The new finds of natural gas have not changed 
that perspective, as to what the price of natural gas will be, 
relative to other fuels?
    Mr. Newell. I think they have, but, again, relative to 
historical prices that were down as low as $3, $4 per thousand 
cubic feet for many years. The expectation is, even given the 
new gas shale developments, that over the next several years 
we'll see a gradual increase in the price of natural gas that 
would be necessary to balance supply and demand.
    So, we see that price increasing, over the next several 
years, to the $5 range, and, over time, to $6, $7, potentially 
$8 per thousand cubic feet as you go out a couple of decades.
    If you think about comparing natural-gas-based generation 
versus existing coal, we find that the level of carbon price 
that would be necessary to make natural gas switch out for coal 
in existing plants depends what you assume about the natural 
gas price, again. So, at $5 per Mcf, we estimate, roughly, that 
it would take a $30-per-ton-of-CO2 price to 
encourage switching from a typical existing coal plant--
conventional coal--to natural gas. If the price of natural gas 
is $7 per thousand cubic feet, it would take something like a 
$60-per-ton-of-carbon-dioxide allowance price to encourage 
switching among existing plants.
    So, as one thinks about the results that come out of EIA's 
analysis of the Waxman-Markey bill, the key issue is that--in 
terms of the role that gas plays relative to other 
technologies--in the near term we find that gas tends to 
increase. The reason is that the competiting low-emission 
generation technologies, such as nuclear, renewables, and coal 
with carbon capture and storage, are on a longer-term 
development plan. But, in the longer term, as you get toward 
2020, 2030, zero- to low-carbon technologies, like nuclear 
power, renewable energy, and coal with carbon capture and 
storage, start looking relatively more competitive compared to 
natural gas. So, that's why, over the long run, we actually 
see, in many of our cases, a reduction in natural gas use 
relative to the reference case.
    Is that----
    The Chairman. Yes, that helps. Let me ask one other 
question----
    Mr. Newell. Yes.
    The Chairman [continuing]. Before my time expires, here.
    Mr. McKay, you talk about the importance of--or the idea 
that we might essentially provide incentives to shut down some 
of the least efficient nuclear plants--coal-fired plants--and 
have those replaced with natural gas.
    Could you just elaborate on that proposal, or your 
suggestion there, as to how that could be accomplished? To what 
extent government should be telling companies what to replace 
coal-fired plants with, if we did that? Or, to what extent we 
should incentivize it?
    Mr. McKay. Yes. Let me just expand on that a little bit. 
What we've looked at, and believe, is that some of the most 
inefficient coal plants--the oldest coal plants --are going to 
face increased environmental air standards, here, in the near 
future, and will have to do upgrades--sorry--will have to do 
upgrades of a fairly sizable proportion. So, we took about 80 
plants that we think are in that category, and we said, ``OK, 
those could be potentially upgraded and still working as they 
are. Or, would it be an opportunity to look at, if there's a 
way to retire those plants, what would be the climate benefit, 
in terms of CO2 emitted, if other alternatives were 
used?'' So, you could theoretically go to all wind, you know, 
if it would work. We looked at natural gas. We believe, you 
know, at a very low cost, natural gas could replace that 
capacity with very low effective carbon-mitigated price.
    In other words, if you take a current coal plant, look at a 
new-build gas plant, we think it would add about 1 cent per 
kilowatt-hour to that coal plant. If you take that 1 cent per 
kilowatt-hour for those 80 coal plants, over the period of 2012 
to 2020 that would be about a $5-billion dollar increment. OK? 
But, that's from current coal to brand new natural gas 
generation.
    One of my colleagues here today has said there's a lot of 
excess capacity, so it would be lower cost if we use excess 
natural gas generating capacity. OK? So, this is about new 
build. If you did that, you would mitigate about 100 to 125 
million tons a year, per year, as I indicated in my remarks, as 
you phase eight or ten of these out a year. So, over the period 
of 2012 to 2020, that would be about 700 million tons, we 
believe, of CO2 mitigated, if you switched these to 
natural gas. The cost of that mitigation, if you take my $5 
billion and that amount of CO2, is about $13 a ton.
    So, we think it's an efficient way to at least look at it 
as an option, if these coal plants need a lot of work, to start 
with. That's where we're coming from.
    The Chairman. Thank you very much.
    Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    Thank all of you for your testimony this morning.
    I think, without exception, the comments have been that we 
have an available, secure supply of natural gas that can last 
for 100 or 150 years, but a considerable source. Mr. Stones, I 
appreciate the concerns that you have raised.
    But, I want to ask you, Mr. McConaghy, you've actually used 
the term ``game-changer,'' that the shale that we're finding, 
whether it's the Marcellus or the Barnett or wherever in the 
country, that this is a game-changer for us, in terms of 
identifying a vast resource, and the availability.
    Can you explain to me and the other members of the 
committee a little bit more about Alaska's gas resources and 
its relevance as a long-term source of supply, given what we're 
seeing in the Lower 48 and the prospects that we're seeing with 
the gas shale? Does Alaska still play in the North America 
market for the long term?
    Mr. McConaghy. Thank you, Senator.
    The short answer is, we very much do believe that Alaska, 
as a supply component to the North American fuel mix, is 
absolutely part of that future. One of the reasons that we have 
that view is that the price level that's going to have to 
pertain, over the back end of this decade, in order to ensure 
that the level of gas consumption that the United States will 
require for, not just carbon reasons, but for all the other 
applications that natural gas is used for, is going to be a 
price level --and our own view would be that that price level 
is likely somewhere in the range of $6 to $8--would tell us 
that the cost structure that it's going to take to bring Alaska 
into the market can still make that a totally economic 
contribution to the supply mix. So, we very much are of the 
view that Alaska is a component of this, notwithstanding the 
significant, quote, ``game-changing'' advent of the shale gas 
resource, so that it's very much a case that we need both of 
these resources coming into the U.S. supply mix. Of course, in 
the case of Alaska, it is going to take us probably most of the 
rest of the next decade to realize that. But, we certainly do 
not ascribe to a view of crowding out. We don't take that view 
with respect to Mackenzie, either.
    Thank you.
    Senator Murkowski. Mr. McKay, do you care to comment?
    Mr. McKay. I think I generally agree with that. I mean, 
it's a world-scale resource. It's a long way from market, and 
it needs to compete into the U.S. market, but we--but I would 
agree, generally, with his comments, yes.
    Senator Murkowski. Good.
    Let me ask a followup because you mentioned the price. You 
anticipate that natural gas prices are going to be holding 
somewhere between $6 to $8. That certainly helps TransCanada, 
as you look to build this out. It certainly helps BP and the 
other producers that are involved. You need that higher price 
for the natural gas. Given that right now the consumers are 
experiencing and enjoying a lower price, what does this do? How 
much of a pinch is this to the consumer? It helps to build out 
the project, but ultimately, what is the impact to the average 
household?
    Mr. McConaghy, you can comment, or anyone else.
    Mr. Stones, you can go ahead.
    Mr. Stones. I mean, one of the things that we've seen over 
the last several years is, you know, we had a spike in 2001, in 
2003, in 1997, in 2005, and 2008. We believe spikes will 
continue. We are enjoying low prices now. As a result, gas 
production is actually falling, per EIA data, in this country, 
at present. There will be a time lag between the resumption of 
it, and that's likely to lead to a spike.
    These higher prices are going to continue, and they're 
going to be volatile, going forward. That's why we've ended up 
losing so many jobs in manufacturing. I disagree, respectfully, 
with Mr. McKay, that there's a need to drive demand to gas. 
Right now, over the last, say, 6 to 12 months, the United 
States has actually moved, by most accounts, 2 to 3 Bcf of 
electricity--2 to 3 Bcf of gas consumption's worth of 
electricity consumption from coal plants to gas plants, without 
any need for an incentive. We believe that there is enough 
incentive in the market, just left alone, to drive the 
replacement of these coal power plants, as was testified to by 
the members of the panel. They've already replaced them. Why do 
we need an additional incentive?
    Senator Murkowski. Mr. Chairman, my time is expired, but 
hopefully we'll have time for a second round.
    The Chairman. Senator Menendez.
    Senator Menendez. Thank you, Mr. Chairman.
    Mr. Newell, I'm concerned both about climate change, as 
well as our complete reliance on oil for virtually all of our 
transportation needs. When the economy fully rebounds, there 
are few, I think, who do not believe we'll see, again, a spike 
in oil prices. That's why, along with my colleague, Senator 
Hatch and the majority leader, Senator Reid, and Senator 
Murkowski, we introduced the Nat Gas Act, which is a bill that 
extends and increases important tax incentives to jump-start 
the national--natural gas vehicle industry and allow us to 
diversify our transportation fuel mix and also reduce carbon 
emissions.
    Now, the Energy Information Administration seems to have 
some quite conservative estimates for oil price rises, and it 
did not predict the incredible volatility in oil prices we've 
experienced in recent years. So, my question is, Has the EIA 
done any work to explain this volatility or to examine how 
expanding the use of other fuels for transportation, such as 
natural gas or electricity, might help U.S. consumers from such 
volatility?
    Mr. Newell. Yes, Senator, we have. In September, we 
launched what we're calling the Energy and Financial Markets 
Initiative, the purpose of which is to increase EIA's 
information base and our analytic capacity for understanding 
and explaining the wide variety of factors that influence oil 
and other energy prices. There are a number of different 
elements to the initiative, some of which are reflected in 
previous legislation that has actually passed out of this 
committee, so we're taking action on a number of those things 
already. It includes increasing information collection on 
various things, also increased cooperation with other Federal 
agencies that are, you know, involved in the issue of analyzing 
energy and financial markets. We're also undertaking analysis 
of various types.
    One of the things that we have started doing in our short-
term forecast, which is our Short-Term Energy Outlook, is that 
as of October, we now include uncertainty bands around our 
price forecasts, to better show that there is wide range of 
uncertainty on where oil prices and natural gas prices could 
go. If you look at that, based on the analysis we've done, 
there's a significant range around which oil and natural gas 
prices could be within the next couple of years.
    Within our long-term projections, we have a central case 
for an oil price. We also have a high and a low price case. The 
high price case goes as high as $200 per barrel of crude oil.
    So, we are trying to better articulate the broad range of 
possible future prices for oil and natural gas in our work. 
Also----
    Senator Menendez. Have you looked at expanding the use of, 
for example, natural gas or electricity for transportation 
costs as something----
    Mr. Newell. We have not specifically analyzed that, and we 
haven't been asked to.
    Senator Menendez. OK. Let me ask you one other question. 
Many of my colleagues continue to promote the view that if we 
drill for more oil on the Outer Continental Shelf, we will soon 
drill our way into energy independence and low oil prices. The 
fact of the matter, the United States has 2 to 3 percent of the 
world's oil reserves. According to the EIA's report, even if we 
opened up all of our shores to drilling, quoting from your 
agency's report, quote, ``the impact on average wellhead prices 
is expected to be insignificant.'' That's the end of the quote. 
Has there been any recent developments that would make you 
change that conclusion in your report? Is there any reason to 
believe that any change that would open up everything to U.S. 
oil production would have a different impact on wellhead 
prices, as the agency has previously said, that it would be 
insignificant?
    Mr. Newell. No.
    Senator Menendez. No? That's a succinct answer. Rarely 
achieved here.
    [Laughter.]
    Senator Menendez. Let me ask one last question.
    Mr. McKay, with reference to that Nat Gas Act that I was 
referring to, transitioning our vehicles to natural gas would, 
of course, offer the dual accomplishment of mitigating 
emissions and reducing dependency on foreign oil.
    What do you believe that companies like your own are 
willing to be, in terms of a partner, in bringing more natural 
gas vehicles to market, if the incentives are there?
    Mr. McKay. Let me just first say that I do think there will 
be increased penetration of natural gas vehicles, because--for 
all the reasons you said, and primarily around centrally fueled 
fleet and commercial vehicles.
    We actually, as Amoco--and I'm a former Amoco employee, 
before we merged with BP--we did this, and tried this, in the 
1990s, and it works. We didn't have the customers at the time. 
The infrastructure is the issue. So, we will be continuing to 
watch this to see if it's an opportunity. But, there's 
experience with it. This has gone on for decades, and still 
going on in places we put it in, like Egypt, believe it or not. 
So, yes. We'll be watching this very----
    Senator Menendez. My time is up, but we'd appreciate 
hearing from you as to what it would take to have companies 
like your own be fully engaged, if we could incentivize it to 
do so.
    Thank you, Mr. Chairman.
    The Chairman. Senator Brownback.
    Senator Brownback. Thank you, Mr. Chairman. I appreciate 
that.
    I appreciate the panel. It's been excellent information on 
a good topic.
    Mr. Newell, I want to provide you with a little 
information, just on a local level. You were talking about some 
of the cost of the pending legislation on cap-and-trade. A 
couple of my utilities in my State have done some projections. 
Kansas City, Kansas, Board of Public Utilities says the first-
year cost to their ratepayers would drive electric rates up 25 
percent if the cap-and-trade legislation that's passed the 
House were to pass. Kansas City Power and Light is projecting a 
4-percent increase--now, that's on their high-end projections--
by 2012. So, to just to give you some real-world perspective. 
I'm sure you're familiar with how sensitive people are about 
electric rates going up. So, I hope you also track the 
projections on those--and I presume that you are--about what 
would happen--if you put these requirements in place, what 
happens to real people that are struggling in the economy 
presently, and driving up these sort of costs.
    Mr. McKay, I want to ask you, if I could--Mr. Stones seems 
to have a legitimate question about--it's going up now, on 
natural gas demand through the electric power sector. I'm happy 
to see that. I toured, recently, in a new gas-fired power-
generating unit in my State. Small footprint. Good unit. Seems 
to really go in well. Why the additional incentives for 
something that's growing presently?
    Mr. McKay. Let me first acknowledge Mr. Stones' viewpoint, 
because one of their largest costs is feedstock cost, to do 
what they do.
    Senator Brownback. Right.
    Mr. McKay. Natural gas is their feedstock. So, I totally 
understand the concern, and they're one of our customers.
    However, natural gas is used for a lot of different things, 
not just the chemical industry. It's used for power. It's used 
for other industrial demand, natural gas vehicles, et cetera.
    One fundamental thing that has changed recently, that I 
think we shouldn't underestimate, is the structural change in 
the gas resource base, and that has changed tremendously. Even 
over the last 3 years, that's gone up, by our estimates and, I 
think, EIA's estimates, 40 percent in the last 3 years. So, the 
resource base has enlarged and the pipeline infrastructure has 
enlarged. So, we're connecting a bigger resource base to the 
markets in a better way. I think this--things like this will 
help the volatility and help Mr. Stones.
    I do also think that when you look at the power sector, as 
we're here today, natural gas does have the biggest role to 
play in the cheapest reduction of carbon dioxide emissions. I 
think what we're really balancing, then, is the usage of--I 
don't think we should reserve natural gas usage for one sector, 
and it has to play across the sectors. What we're trying to do 
is balance the right thing.
    Let me just make one clarifying comment. What I said, to 
start with, is, we believe in a level playing field. We don't 
believe the playing field is level in the proposed legislation. 
If it's not level, then we would say, ``Could we look at this 
as a way of a smooth transition?'' That's our logic.
    Senator Brownback. That's a good thought.
    I just--Mr. Chairman, I think these are interesting ideas, 
particularly Mr. McKay's, about, maybe that--the bottom-end 
coal-fired power plants and providing some support for 
transitioning. But, I don't want to create the situation that 
hurts the manufacturing sector, which we're desperately trying 
to bring back and to stimulate. This is my own pet peeve, or 
pet project, maybe, for my State, in Kansas, but if we could do 
things that combined the renewables, particularly wind, with 
natural gas as a way to maybe help in assisting those bottom-
end coal-fired power plants--that may be too complicated by 
half, but might be fairly simple and----
    We've got to do it in a cost-effective way. We can't drive 
utility rates up. Can't do that, because they just--people 
won't stand for that. We don't need to do it that way. I think, 
if we're wise enough, we could keep from doing that. So, I hope 
we can be balanced on this, without hurting people, and, at the 
same time, reduce our CO2 emissions.
    Thanks, Mr. Chairman.
    The Chairman. Thank you very much.
    Senator Stabenow.
    Senator Stabenow. Thank you very much, Mr. Chairman, for an 
excellent hearing.
    I first want to welcome Mr. Stones, from my native Michigan 
company, and also----
    Mr. Stones. Glad to be here.
    Senator Stabenow [continuing]. Mr. Wilks, for being a part 
of the Michigan economy, as well. So, it's great to see 
Michigan represented.
    I guess I would go back to what Senator Brownback just 
asked, in terms--and what Mr. Stones asked--and that relates 
to, Why do we need additional incentives? If you look at 
natural gas and the incentives that come with it automatically, 
in terms of the environment, terms of what's happening now, the 
current cost incentives in moving--Mr. McKay, as you said--
moving your plants, and so on--I think a basic question for us 
is, Is there enough incentive in the market place right now to 
be able to make things happen? That would be one question.
    Then, second, it is of, obviously, great concern to me that 
we balance our natural gas policies. Clearly, natural gas is 
part of a low-carbon future for us. Critical. Important. We 
have large amounts of natural gas--very important for us--that 
that is a part of the mix, as I think we need to make sure 
everything is a part of the mix. But, we also have to balance 
that with our manufacturing policies. I'm deeply concerned, in 
the short run. Mr. Newell, you were talking about nuclear and 
CCS and other things becoming more viable by 2030. What happens 
in the meantime? I don't want to be losing jobs offshore until 
2030 in manufacturing until those things happen. So, the key 
question really relates to cost, right now, and what this does 
for manufacturing, and, in fact, is there a necessity for 
additional incentives in an area of energy that already has, I 
think, a great deal of appeal and incentives to it.
    Mr. Newell, I would ask you a question. You had indicated, 
in your testimony, that recent appraisals of technically 
recoverable natural gas does not take into account the costs of 
finding and recovery of supplies in previously unknown sources, 
such as shale. So, I wonder if you might talk a little about 
the cost of shale production. At what price do the supplies 
start to become viable?
    Mr. Newell. Yes. I think that that part of the testimony 
was drawing the distinction between technically recoverable 
resources and proven reserves. The reserve concept takes into 
account the cost of drilling and extracting those reserves, as 
well as the price that one could get in the market, whereas 
resources is more about the physical resource base. So, we've 
seen significant expansion of the physical resource base, most 
of it associated with shale technology development.
    In terms of the price levels for natural gas that would be 
necessary to continue expansion of shale production, there's a 
range. It depends on which shale play you're talking about, how 
mature it is. There's a range of estimates, some as low as $3 
per thousand cubic feet for shale to be profitable. With other 
shale plays you need $7 per thousand cubic feet to make those 
profitable. So, there's a range.
    In terms of looking forward, the price levels that we think 
are necessary to balance supply and demand are going to be 
moving up from the $5 to $6 to $7 range. But, you know, some 
plays will be relatively more profitable under those scenarios, 
and others will be just on the edge.
    Senator Stabenow. OK. Thank you.
    So, given that, I'm wondering, Mr. Stones, at what prices 
does your business model start to change when we look at this 
whole picture?
    Mr. Stones. Let me say a couple of things. You know, one of 
the things we've talked a lot about is average price. You know, 
what we've seen over the last 5 years or more is that 80 
percent of the time the price is lower than the average price. 
The issue is the other 20 percent of the time. How do we get 
through to the other side? These are the spikes. These are 
the--what actually causes us to shut down. So, when you have a 
5 to 8--what--3 to 8, or whatever the number was, $6 to $8 
dollar range, it can often be, for short periods of time, 
maybe, but out of that, for a period of time long enough to 
cause real significant job destruction and job losses.
    The second thing, you know, I would talk about, that's 
important for us to think about, is, as we build more power 
demand and more natural gas vehicle demand, these are inelastic 
resources. These are people who will pay any price to get their 
fuel. We will not be cold, we will not be dark, we will drive 
our car to work. What manufacturing provides is a buffer and a 
way to minimize those spikes.
    So, we're very excited. We hope that there is this new 
resource. But, it seems to us a very large risk to take, to pin 
everything on this and assume that the gas will follow.
    Mr. McConaghy. Senator, if I could make one--just one 
comment?
    Senator Stabenow. Yes.
    Mr. McConaghy. Yes. Just in--respectfully, on the issue of 
volatility, which has been raised this morning, I would just 
emphasize there are, I think, two significant structural 
differences, and one is the fact that the shale gas resource is 
a different kind of gas resource. It is a resource that is 
more--almost akin to a manufacturing process of its own, 
because it's got less geological risk, its process is to just 
get the amount of necessary drilling done, to get it done. 
That's a significant difference than what was done previously, 
when geology was a much bigger issue, as to how you can ramp 
up.
    Second, the pipeline infrastructure today, and most notably 
some of the infrastructure that's been created to bring Rockies 
gas to the midcontinent, the laterals that have been connected, 
some of the existing shales, whether it's Barnett, 
Fayetteville, et cetera--the infrastructure that will help 
reduce volatility is significantly better now than it has been 
before.
    So, I'd respectfully make the point that the concern about 
volatility has changed and that, I would just register, is 
something that there can be, you know, honest debate about how 
extreme that is. But, I do think there have been, 
fundamentally, structural improvements that reduce that 
concern. I would just register that.
    Senator Stabenow. I appreciate that. I guess the question--
I know my time is up, Mr. Chairman--is, As we look at this new 
technology, are we at a point yet where it's cost effective 
even though there's great opportunities through that? I think 
that's probably something we'll have to further talk about.
    So, thank you, Mr. Chairman.
    The Chairman. Thank you.
    Senator Sessions.
    Senator Sessions. Thank you.
    To follow up on Senator Stabenow's question, Mr. McConaghy, 
perhaps, I've heard that one company is--drilled 4,000 wells in 
shale and not had a dry hole yet. Is that correct? Is----
    Mr. McConaghy. I could----
    Senator Sessions [continuing]. Are those numbers realistic? 
Are----
    Mr. McConaghy. I could believe that. I can't, obviously, 
attest to what you've just referred to. But, it is a 
fundamentally different kind of production process than what 
was formerly known as conventional wildcat drilling.
    Senator Sessions. The amounts of it indicate pretty 
clearly, Mr. Newell, that we have 100 years-plus of supplies of 
this shale oil, would you not agree--I mean, shale gas--or 
natural gas in America, maybe is better way, including the 
shale gas, discoveries that have added to the supply.
    Mr. Newell. Exactly how many years, you know, depends--
there is the resource base, and then you divide by something 
like current production, but certainly well above 50 years. I 
think there's a pretty broad consensus, whether it's 80 or 100 
or a bit above 100. I think there's more there. The Gas 
Committee roughly doubled their estimate of the resource base, 
over the last 4 years.
    Senator Sessions. Did they do it in terms of how many years 
of supply exist? Do you recall what those numbers were?
    Mr. Newell. It basically went from roughly 50 years to 
roughly 100, yes.
    Senator Sessions. That's proven reserves, right?
    Mr. Newell. No, this is resources.
    Senator Sessions. Resources?
    Mr. Newell. Yes.
    Senator Sessions. Now, with regard to the emissions, it's 
about--natural gas would get the same energy BTU production at 
about 40 percent less CO2. Is that correct?
    Mr. Newell. Yes, that's correct.
    Senator Sessions. It seems to me that this is a dramatic 
development. The increase in supply of natural gas is just 
stunning, and a great development. It's cleaner. If it can be 
connected to the pipelines, it's very transportable.
    I would think that one of the things we would like to see--
and suspect it will happen naturally, but perhaps we could 
accelerate it--would be to utilize more natural gas for 
transportation in our fleets, which--mean buses here in 
Washington, DC, use natural gas, and other cities --and into 
larger vehicles. That's the--essentially what Mr. Boone Pickens 
has proposed, and I think, essentially, with the new 
discoveries, that makes sense to me, because--several things. 
It will pay for itself, will it not? Would anybody like to 
comment on that, in terms of at least vehicles?
    Mr. Fusco.
    Mr. Fusco. Not so much on vehicles, Senator. But, if I 
could, just to clarify, you know, a conventional coal plant, 
which is what the U.S. has, has an efficiency of around 30 
percent. That's the thermal efficiency. So, for the same BTU, 
in one of my modern gas plants you're going to get over 50-
percent efficiency. You're actually get more megawatt hours, as 
well as lower emissions, than----
    Senator Sessions. So, compared to coal, it's even better. 
Right.
    Mr. Fusco. Then, last, you know, on incentives, right? The 
reason we need incentives is--my company had the benefit of 
seeing coal-to-gas switching in our southern and southeastern 
fleet this past year. It's only when gas prices get around the 
low $3 in MMBTU, so extremely low, that incentivizes the coal 
guys to shut their units down. OK? With the current forecast of 
$6 to $8, it's going to be more of the same. There will be no 
switching. You will not get the--any environmental benefits. We 
need environmental regulations in this country.
    Senator Sessions. We can make anything happen, Mr. Fusco, 
with enough subsidies. So, it's the question of how to do it. 
I'd like to not burden the American consumer any more than we 
possibly can.
    With regard to current prices of natural gas, I have been 
informed that, even though a natural gas vehicle, like a bus or 
a truck, that travels many miles--Mr. McKay, I guess BP might 
know this--that it would pay for itself at current prices, the 
extra cost, if you used natural gas and had the infrastructure 
to utilize natural gas, as opposed to diesel fuel.
    Mr. McKay. Yes. I think, at current natural gas prices, 
that would be true. We do believe there will be increased 
penetration or more natural gas vehicles. We do agree with 
that.
    Senator Sessions. It would seem to me, as a matter of 
national policy, we should favor natural gas, because, in many 
ways, it's cleaner to produce, and secondly, it's almost all 
American. So, it eliminates the balance-of-trade deficits that 
we have when we import 60 percent of gasoline and diesel fuel. 
So, we import all of this, send American wealth abroad, when we 
could produce 40 percent less CO2 and create a cost-
effective substitute for at least fleets, I would think, if not 
every individual automobile. If we could figure a way to expand 
that, then we've not burdened the economy and we've reduced our 
balance-of-trade deficit and we've reduced, significantly, 
CO2 emissions. Am I off base on that?
    Mr. McKay. No.
    Senator Sessions. I see most of you agree with that?
    I would just say, Mr. Newell, we've got to watch the 
objections over the production. I mean you drill--my 
understanding is, most of the shale gas is about 2 miles deep, 
and your water level is 600 feet or less, where water exists. 
So, it's unlikely that anything injected to help get the gas 
out would impact our water supply, it seems to me. So, I really 
think that can be a problem that's--would cause some concern. 
You mentioned it, I think, in your written testimony. I hope we 
can work on it and make sure that we're not causing any 
pollution. But, I don't think, what we've seen so far, we're 
seeing a pollutant effect from natural gas production.
    The Chairman. Senator Shaheen.
    Senator Shaheen. Thank you, Mr. Chairman.
    Thank you all for your testimony.
    I would actually like to follow up a little bit on the 
Senator's question about the pollution and water, because there 
has been concern expressed about potential results of the new 
fracturing technology and what that might mean, in terms of 
polluting water supplies. So, I'd like to hear your thoughts 
about that, whether you've seen that to be a concern.
    Senator Casey has introduced a bill, called the Fracturing 
Responsibility and Awareness of Chemicals Act, which would 
repeal the safe drinking water exemption, which was--is 
provided to hydraulic fracturing, and require a public 
disclosure of chemicals used in the process. So, I guess I'd 
like to also hear, those of you who are producers and users of 
natural gas, whether you think that's legislation that you 
could support.
    Mr. McKay. Let me just address your original point, first. 
On FRAC, fracking is not a new technology. It's 50 years old, 
and there's been over 1 million fracks done in the U.S. So, 
that technology is not new. What's new in shale is that--you--
we drill horizontal wells, maybe 5,000 feet, and do multiple 
fracks on those--on that lateral. That's the new part.
    So, the fracking has been around--I mean, I worked on it 
when I first started. The fracking technology is --and the 
protection for groundwater--is very robust and very solid. Of 
those million frack jobs, there's very few that--I don't know 
of any that have had any surface water issues. So, I don't----
    Senator Shaheen. I was thinking more of groundwater----
    Mr. McKay. That's what I----
    Senator Shaheen [continuing]. That would affect wells.
    Mr. McKay. Sorry. That's what I mean by surface water--near 
surface water, groundwater. I didn't mean really on the 
surface. That's a----
    Senator Shaheen. OK.
    Mr. McKay [continuing]. Industry term. So, groundwater--
there haven't been groundwater issues.
    We have physics working on our side. When you frack 
underground at 10,000 feet or 5,000 feet, the horizontal 
stresses are what are relieved, and it propagates horizontally, 
it doesn't propagate up.
    It's a solid technology. I do understand your fluids point 
about--the disclosure of what's in fluids, I think, was in your 
second point.
    Senator Shaheen. Right. That's part of this proposed 
legislation.
    Mr. McKay. We believe that fracking needs to be regulated 
at the State and local level. We believe that State and local 
regulation can include disclosure of what's in those fluids. We 
would support that. We have been working very hard to make sure 
the footprint of fracking, or any issues around fracking, is 
minimized and would be--Colorado's got a good plan that they've 
put in place and I think is a model that States could look at. 
So, State and local--because everything is different--geology, 
water, everything--at a local level. The technology is robust.
    Senator Shaheen. So, you wouldn't support a repeal of the 
exemption to the Safe Water----
    Mr. McKay. I would not.
    Senator Shaheen [continuing]. Drinking Act?
    Mr. McKay. I would not.
    Senator Shaheen. Is there anybody here who would support 
that legislation?
    [No response.]
    Senator Shaheen. Mr. Fusco--I want to change the subject a 
little bit at this point--you testified about Calpine's use of 
combined heat and power and----
    Mr. Fusco. Yes.
    Senator Shaheen [continuing]. The additional efficiencies 
that are created as the result of that. I know that a number of 
us on this committee believe that that's an important way to 
use power and improve the efficiency of our energy sources. So, 
as you think about what we might do to encourage that use of 
combined heat and power, are there incentives that you could 
suggest, or other ways that you would urge us, to better 
support combined heat and power?
    Mr. Fusco. Yes. Thank you, Senator.
    I think, you know, currently there aren't any incentives 
for existing combined heat and power plants, in either of the 
bills. So, I think the first thing would be to try to 
incentivize those of us who have it to expand those facilities. 
Most of these gentlemen at the table are either a customer or a 
supplier, or both, in most instances. So, I believe in combined 
heat and power, mostly because when we talk about the 
efficiency of a combined heat and power plant, it exceeds 50 
percent. It's in the mid-55-percent range, compared to the 
conventional plants that are 30 percent. But, I do think 
there--you know, and we're happy to work with you all to figure 
out the right mechanisms that need to be put in place for that.
    Senator Shaheen. Thank you.
    I'm almost out of time, so I'll try and ask this question 
very quickly.
    Mr. Newell, I understood you to say that, despite 
incentives in the current legislation, that we wouldn't see our 
natural gas use increase in the future. Am I correct?
    Mr. Newell. It depends on the scenario. In our reference 
case, which is absent the climate policy that's been discussed, 
we see a drop in natural gas consumption over the next several 
years, because new renewable energy for electricity and some 
coal installations are coming in. But, over the longer term, 
natural gas use comes up a bit and is roughly flat over the 
next 20 years, in our reference case. Once you layer on top of 
that a bill like the Waxman-Markey bill passed out of the 
House, depending upon the availability of other options for 
reducing greenhouse gas emissions--such as the availability of 
international offsets, and the cost and availability of nuclear 
power, and coal with carbon capture and storage, which are 
close to emission-free, or emission-free--if those are not 
available, natural gas could actually increase substantially, 
we find. If those are available, which is what our Basic Case 
and some of our other cases assume, natural gas does not 
compete with those technologies as a cost-effective greenhouse 
gas compliance option, given the other incentives that are in 
the system. There's also --and I think this gets back to one of 
the questions Senator Bingaman asked earlier--State renewable 
portfolio standards which are moving renewables into the mix. 
In the Waxman-Markey bill, we also have bonus allowances for 
carbon capture and storage, which are also part of what's 
driving that technology. So, it's not just the carbon price, 
per se. There are other policies and incentives that are in 
place. Is that----
    Senator Shaheen. Thank you. My time is up.
    Thank you, Mr. Chairman.
    The Chairman. Senator Cantwell.
    Senator Cantwell. Thank you, Mr. Chairman. Thank you for 
holding this important hearing.
    Gentlemen, thank you for being here and to talk about this 
larger issue of future energy supply.
    I'm somebody who, even though we have a hydro system that 
is about 71 percent of our electricity grid, certainly want to 
see the U.S. electricity grid diversify and to have more 
natural gas. I mean, if we're at 23 percent today, I'm hoping 
that we can grow that significantly in the future. We have many 
farmers in our State that the supply of natural gas does really 
affect the price of product that we have. People think of 
Washington State as, you know, software and airplanes, but 
agriculture is still the number-one employer. So, diversifying 
is really important.
    Mr. McKay, you talked about a level playing field and how 
important that was, not to pick winners and losers and to have 
the market continue to do that. I wondered if you could comment 
a little bit more on how you think the House bill treats that--
I get a sense that you think it distorts the market--and what 
you think would happen as a result of that.
    Mr. McKay. So, in the--if we use Waxman-Markey as a --as 
something as a--to talk about, there's two fundamental, we 
think, nonlevel playing fields. First is, the transportation 
sector is sort of a paying sector, and the utility sector--
roughly, roughly--a nonpaying sector, in terms of the price of 
carbon, because free allowances are given. That's the first 
dislocation.
    The second one within the utility sector is that we think 
alternatives are effectively mandated or encouraged, which--you 
know, we support transitional incentives, reasonable ones. 
Coal, we believe, is insulated. The consumers of coal are 
insulated, for sure. Some of the generation of coal is 
insulated through credits, allowances, funding for CCS with 
coal, not with natural gas, these type of things. Therefore, we 
think the price of carbon will not be--not flow easily to make 
changes in investment decisions about whether you should use 
coal or natural gas.
    Senator Cantwell. Basically, you're saying they're going to 
help pump up the price of--or support a lower price of coal and 
cause a----
    Mr. McKay. I think it's insulation, primarily. So, what 
we're saying is, if you could strip all the insulation back and 
get to a really pure playing field, we're fine with that. 
Absolutely fine. If you can't strip the insulation back, how do 
we smooth the transition in the period of time when we're 
trying to get to lower carbon future?
    I just want to say one thing about the demand or 
production. Industrial demand has dropped tremendously. The 
projections that we see, going forward, we don't even get back 
to last year's production until 2020, or later. So, this idea 
about, you know, natural gas production ramping up is not--
every projection I've seen, after this drop, we barely get back 
to the level we were at last year. So, there's plenty of supply 
to do that, is all I'm saying.
    Senator Cantwell. So, definitely not a level playing field, 
as far as natural gas is concerned.
    Then, on the sequestration issue, the same dilemma? The 
House-incented----
    Mr. McKay. Yes.
    Senator Cantwell [continuing]. Carbon sequestration, but 
not any natural gas sequestration? Is that your read of it?
    Mr. McKay. Yes, I think natural gas is a great clean 
utility player that's being not let on the field.
    Senator Cantwell. That what?
    Mr. McKay. Not being let on the field fully.
    Senator Cantwell. OK.
    Mr. McConaghy. Senator, if I could just also add one 
comment to your question, I would--I understand that the bill 
that you have sponsored, in terms of a different approach than 
Waxman-Markey, to how one would design a cap-and-trade bill--I 
would--by my review of it, it comes the closest to establishing 
a level playing field, because it really starts with a full 
auction and that would clearly be responsive to the notion of 
a--setting a carbon price that would be without the distortion 
between the different alternatives and that should be, 
probably, all things being equal, advantageous to natural gas. 
So, I do make that observation.
    But, given that we are reacting to what is currently in 
play, I endorse the comments that have just been made, quite 
eloquently, that, in fact, you have an insulation of coal, 
through the allocation of free allowances, you have the 
increasing phenomenon of renewable portfolio requirements 
growing, squeezing out the most benign, from a carbon 
perspective, of the hydrocarbons. Ultimately, the point of this 
exercise is to do something about carbon, despite the fact 
there are other collateral considerations, which others have 
talked about. So, I just wanted to make that acknowledgment 
of--you know, a different kind of carbon bill design could also 
level the playing field.
    Senator Cantwell. Thank you. No, I definitely agree. I 
think a level playing field and predictability is critical for 
moving forward.
    So, I know I'm out of time, Mr. Chairman. I'll try to stay 
for a second round.
    The Chairman. All right. Thank you.
    Senator Landrieu.
    Senator Landrieu. Thank you, Mr. Chairman.
    I think this hearing has been exceptional and one of the 
best, and I really appreciate you putting panel together.
    I want to associate myself with the remarks of Senators 
Sessions and Senator Cantwell as we move forward. But, I did 
want to comment--Senator Menendez, our colleague, has slipped 
out of the room, but I did want to comment on one of his 
points. Since I am, proudly, one of the leaders of more 
domestic oil and gas production in the Nation, I want to point 
out a couple of things and then get to two questions.
    One, I've never heard anyone in the U.S. Senate say that 
they thought we could drill our way to national security. What 
I have said, and what I've heard others say, is, there's 
generally a lot more oil and gas, domestically, than we 
acknowledge. We fail, sometimes, to realize the dynamic and 
exciting changes in the industry that are providing more 
supply. I want, one more time --I've done this three times, but 
I'm going to do it again, for the record--this is what we 
thought was in the Gulf of Mexico, in 1987: 5 billion barrels 
of oil. Is this only oil, Tom?
    Voice: That's right.
    Senator Landrieu. Now, it's gone up, in 2006, to 30 
billion. Meanwhile, we have been using and producing all of the 
oil between 5 billion and 30 billion barrels. We still have 30 
billion. So, the fact of the matter is, if you look for it, you 
might find it.
    No. 2--or you usually find it--and number two, we can 
extract it with a much smaller environmental footprint than 
ever before. I'm going to submit again, for the record, that 
the natural seepage of oil into the ocean is much greater than 
oil from spilled production.
    No. 2, for gas--and I want to get this straight on the 
record. Drilling-related spills are less than 1 percent of 
spills in the ocean. Tankering of oil is a 4-percent. Run-offs 
from boats and jet skis is 20 percent. Natural seepage is 73 
percent.
    So, yes. I am an unabashed advocate for more domestic 
drilling of oil and gas, not because I think it solves any 
problem, but because I think the American people have a right 
to benefit from resources that they own. I think Americans are 
tired and feel like it is really embarrassing and downright 
shameful to ask OPEC to produce more, when we won't, ourselves. 
So, I'm going to continue to be a fierce advocate for more 
onshore and offshore natural drilling--I mean, production.
    This is the gas resources, which is a good picture to show 
what these gentlemen have said, Mr. Chairman, that the gas 
resources--it really has been a game-changer, in terms of 
outlying projections. The great news is, is because we 
deregulated the natural gas pipelines, we've built 11,000 miles 
of pipelines pretty efficiently throughout this country, which 
is contrary to what we've been able to manage in electricity 
lines, which we're having a big fight over, now, and we can not 
only find gas in more places, but move it more quickly. So, 
there is not only a greater supply, a very clean supply, but it 
is almost in every corner of the country, which is not true of 
hydro. It's located--or it's not true of coal, or it--well, 
maybe coal is a different exception--not true of oil, maybe; 
not true of hydro; not true of other parts. But, natural gas 
has some really wonderful qualities.
    So, my question is, I think, Mr. McKay, to you. Your 
comment about the distortions in Waxman-Markey are, I think, 
particularly telling. We don't have to go over that; it's 
fairly obvious. But, when you talked about the utilities being 
relatively insulated, or the electricity sector being 
insulated, what about the transportation sector and refineries? 
Could you talk a bit about that and see, maybe, is there an 
alternative that you might suggest, in the transportation 
sector?
    Mr. McKay. So, in the transportation sector, that sector is 
about--let's just say 40 percent of the emissions--
CO2 emissions in the country, and needs to--for 
products and their own emissions--and needs to buy the 
allowances, under Waxman-Markey, out of a--basically, a 15-
percent government auction pool. So, it worries us, about how 
the transportation sector is going to cope with that.
    Refineries within the transportation sector are very trade-
exposed industries. Those refineries all around the country are 
exposed, in the sense they've got to scramble for their 
emission credits, under Waxman-Markey, and imported products 
don't, from refineries overseas. So, it's a trade-exposed 
industry that was left out of the trade-exposed industries in 
Waxman-Markey, is the fundamental point.
    Senator Landrieu. I know my time is expired, but it's a 
real problem, Mr. Chairman, in the current framework of Waxman-
Markey, because if we aren't careful, what little refining 
capacity we have left in this country, we will potentially 
eliminate if we don't do this correctly. Then, instead of 
importing unrefined products in and being reliant, as we are on 
unrefined products, we're now going to become reliant on 
refined products, which is worse, in some ways. So, I just 
really caution us. I know the chairman is sensitive to this.
    My final point is, I do believe that natural gas, while we 
cannot be over-reliant on any one source of energy, and we want 
to be--have a multiple of clean-burning fuels, or clean-burning 
sources, I do believe that it is something that we potentially 
have overlooked. I hope, as we move forward, we can be more 
sensitive to it.
    I'm pleased to be leading in that effort with Senator 
Chambliss on the new Natural Gas Caucus.
    Thank you.
    The Chairman. Thank you.
    Senator Murkowski, you had some additional questions.
    Senator Murkowski. Thank you, Mr. Chairman.
    I'll direct this to you, Mr. Fusco and Mr. Wilks. You both 
have spoken within Calpine and within Xcel, regarding business 
judgment decisions that have moved you from coal to natural 
gas. As Congress considers the various policies that are at 
play here, I'm very concerned about how we have this tendency 
to pick winners and losers within the industry. We have 
discussed level playing fields. As we discuss the policies that 
business really needs to provide for a level of certainty, and 
I assume you're making some business judgment decisions, based 
on the environmental considerations and the price 
considerations, but you never really know what we may do next. 
The next favored child within the energy sector may be algae, 
and you're out. What do you need from Congress to give you that 
level of certainty to make these long-term investments in your 
businesses?
    Mr. Wilks, you can go first, and then we'll ask Mr. Fusco.
    Mr. Wilks. Thank you, Senator Murkowski.
    I'll just say that we do State-level resource planning in 
all of our States. All those States have different rules that 
apply in resource planning. From my standpoint, you know, the 
clarity on what we want to do, and the country needs to do, on 
carbon reduction, and how that's to be allocated--is 
allocated--that kind of clarity is what's going to support 
long-term investment in the infrastructure from power 
generation perspective.
    Senator Murkowski. So, let me just clarify. Do you want to 
see that specific 20-percent reduction by 2020? Is it 
definitely part of a cap-and-trade proposal? Does that give you 
business certainty?
    Mr. Wilks. That's--what you described to me is a very good 
example of the clarity that we need. So, I think having that 
clarity will allow you to do, then, the long-term resource 
planning. Most of our assets are 30-year lived. So, when you 
make that kind of investment, you have to have certainty that 
the profile, the game plan, the economics that you're planning 
on, in fact, do unfold themselves for the future. So, that kind 
of certainty is very important.
    Senator Murkowski. Mr. Fusco.
    Mr. Fusco. Yes. I would just add to the ``level the playing 
field,'' because I think that's extremely important, when you 
think through this legislation, as well as--I would also say, 
don't harm the good actors. We have been a leader. We never had 
coal generation at Calpine. We've stuck with natural gas and 
geothermal. We've been a good actor. We've designed plants that 
are ahead of their time, as far as environmental emissions, 
rules, regulations, and laws. We went from being excited about 
the potential of the bill, to being defensive, just trying to 
protect our current business. That's just not the way it should 
be here in America. I think the clarity would be helpful.
    Then, last, when we look at the investment decision, what 
could be potentially harmful is, the people with the dirtier 
generation could potentially get favored to build the new units 
of the future. My investors, my shareholders, my board, expects 
growth. If that's not crafted right, you're going to favor 
those folks, or you're going to force me to have to buy old, 
dirty coal units so I can trade the credits in and build new 
units. Neither of those are the right answer.
    Senator Murkowski. Let me ask the rest of you----
    Mr. Stones. Could I make a comment----
    Senator Murkowski. Mr. Stones? Yes.
    Mr. Stones [continuing]. As well, too? I mean, we support--
--let's be clear--we support congressional action on a climate 
bill, and we--promptly--that supports a diversified portfolio, 
because what we need to be sure of is that we don't end up with 
another ``dash to gas.'' So, our fear is that if it's not a 
comprehensive bill that keeps manufacturing competitive, that 
we don't know what the playing field is, just like these guys 
don't.
    Senator Murkowski. So, when you say ``comprehensive,'' I'm 
assuming you would include nuclear----
    Mr. Stones. Absolutely.
    Senator Murkowski [continuing]. As a robust component and 
all of the others?
    Mr. Stones. Right. We need to make sure that the options 
for energy generation in America grow and become more flexible, 
not less flexible. That helps the consumers, because one of the 
concerns I have is, if flexibility in the natural gas market 
goes down, all of a sudden, when it gets cold, everybody has to 
buy at the same time and nobody can afford not to. So, gas 
prices will go higher and lower, and you'll get much more 
volatility. So, we need--you know, we agree, there's a 
potential to take a real step forward, here. But you need a 
balanced approach that covers supply, demand, energy policy, 
security, climate, manufacturing. All of those things need to 
be considered.
    Senator Murkowski. Thank you.
    The Chairman. Senator Cantwell, did you have additional 
questions?
    Senator Cantwell. Yes. Thank you, Mr. Chairman.
    I wanted to ask Dr. Newell--obviously, we were talking 
earlier about level playing fields. Let's assume a level 
playing field exists and that, because of that level playing 
field, renewables have the easier way to the marketplace by 
having a more accurate price on carbon. Is your assessment 
that--is EIA's analysis that there would be a likely use of 
natural gas as a backup to renewable power? So, the fact that 
renewables will be out there in the marketplace in a bigger 
way, that they have to--you know, there's this symbiotic 
relationship between natural gas and renewables for reasons of, 
obviously, consistency, and so, this will help pull more 
natural gas in the market? Is that what your analysis shows?
    Mr. Newell. Depending upon the circumstances, there can be 
a symbiotic relationship, with natural gas backing up 
intermittents, like renewable power. On a net basis, though, in 
most of our climate analysis cases, except when various options 
are very limited, we see the net generation from natural gas 
going down after 2020. So, there's a certain amount of natural 
gas that's symbiotic, but, overall, after some initial period 
of increase, it's going down somewhat, except if nuclear power, 
international offsets, and other technological options that 
compete with gas are off the table, then natural gas expands 
significantly. But, it's not primarily due to the renewable, 
natural gas complementarity; it's due to other factors.
    Senator Cantwell. Mr. McKay, did you want to comment on 
that?
    Mr. McKay. No. I think it's right. If alternatives come in 
at the speed we all would like and think they possibly could, 
then I think natural gas does get squeezed in that piece. If 
there's insulation, as I've said--and I know you don't want to 
go here--but, insulation, that I've said before, in the coal 
sector, then natural gas is getting squeezed in the middle. I 
just want to say that I think the supply side of this is 
fundamentally changed and can handle and lower volatility than 
it's been in the past.
    Mr. McConaghy. Senator, if I could----
    Senator Cantwell. Yes.
    Mr. McConaghy [continuing]. Just add this comment, because 
I think there are some practical considerations. Even if we 
hypothesize a level playing field that provides a transparent 
carbon price that's applicable to all the hydrocarbons, there 
are real constraints in how much incremental nuclear we could 
ever install, from today for the next--within the next 15 to 20 
years, realistically.
    Second, the cost of doing CCS is still, in some of our 
judgment, going to be much more expensive than is anticipated. 
As an actual, practical option, it's going to take longer to be 
available as a practical consideration.
    So, when you look at the medium and short term--and by 
that, I'll say within the next 5 to 20 years--if we do have, 
quote, ``a level playing field,'' I do believe that is going to 
require a greater utilization of gas, if the objective is to 
actually reduce carbon emissions and that's just going to be 
the case.
    It is also the case that, regardless of what is done on 
carbon, natural gas prices are going to have to rise, simply 
because of the amount of loss of initial production from the 
conventional source, not withstanding the very welcomed 
addition of shale gas.
    So, I'd just underscore, there are some practical 
constraints that--when we look at these other technologies. 
That's even accounting for a significant contribution from 
renewables. So, I do think it points, in the context of a level 
playing field, for a greater reliance on natural gas, if the 
objective is to achieve carbon goals.
    Senator Cantwell. I think the symbiotic relationship 
exists. We've already had to get very smart, in the Northwest, 
about hydro and wind and the balance with natural gas, because 
that, along with efficiency and Smart Grid technology--this is 
about how you make all those resources work together. I just 
think we need to work harder and--on this focus in research--of 
how to make all these resources work together. I think there's 
a sweet spot, here, as it relates to driving down cost and 
utilization, getting the best out of each of these energy 
sources, and putting that mix onto the grid. But, it's clear 
that natural gas is going to be a part of that.
    Mr. Fusco. Senator, if I may, you know, we have seen, in a 
massive increase in the utilization of our quick-starts and 
ramping capabilities at Calpine, for our customers here--Mr. 
Wilks would be a prime example of that at Xcel, in Colorado. I, 
a few weeks back, was in Colorado at our power plant called 
Rocky Mountain. The plant was sitting at a 20-percent loading. 
Immediately the pedal goes to the metal. These are very 
sophisticated pieces of equipment. Ramps up. Hits 80 percent 
output. We call the Xcel dispatcher, our customer, and say, 
``What happened?'' He said, ``The wind stopped blowing in 
Wyoming.'' That's the value we've added. We just negotiated 
five contracts with Pacific Gas and Electric because of that, 
because of the location of our plants and the ability to ramp 
quickly, start quickly, and manage that wind and solar 
intermittent loads.
    Senator Cantwell. Thank you.
    Mr. Fusco. It's been extremely valuable for us.
    Senator Cantwell. Thank you. You made my point for me. 
Thank you very much.
    Mr. Stones. From our perspective, that's exactly right. Gas 
is going to grow dramatically. It did in--after the 1990 Clean 
Air Act. We don't know--you know, we've heard this story about, 
``There's lots of gas,'' before. You know, it was the Gulf of 
Mexico, it was Canada, it was the Rockies, and now it's shale 
gas. We are very hopeful that it's there. But, what we would 
urge is caution, moving forward, to ensure that we have a broad 
portfolio of ideas and ways to do it, like both of you said.
    Senator Cantwell. Thank you.
    Thank you, Mr. Chairman.
    The Chairman. Thank you.
    Senator Sessions, did you have additional questions?
    Senator Sessions. Just briefly.
    Substituting natural gas for coal has environmental 
CO2 benefits, but it's considerably more expensive. 
Coal is essentially an American-produced, domestic-produced 
fuel, so we don't gain on our balance of trade. But, 
substituting natural gas for--in vehicles that utilize gasoline 
and diesel fuel, 60 percent of which is imported, also reduces 
the environmental impact substantially and helps us 
economically, and, as a matter of price, is no more expensive 
that diesel and gasoline.
    So, I guess, Mr. McKay, I'll ask you, Are there things that 
we can do, at reasonable cost to the American citizenry, that 
will help us utilize more natural gas in vehicles--in 
particular, fleets and long-distance trucking? Anyone else who 
would like to comment on that, I'd like to hear.
    Mr. McKay. I think the scale of the resource base opens 
up--effectively opens up confidence in what price is going to--
--the resource base expansion allows confidence, I think, in 
people to feel that natural gas prices are not going to get too 
far out of line. Therefore, we do believe natural gas vehicles 
are going to accelerate and it--there is infrastructure in 
place that can allow that. So, I don't think it needs a big 
infrastructure project, I just think that confidence needs to 
grow. We're seeing that growing. It already is.
    Boone Pickens has recommended certain things. Those are big 
infrastructure things. That's an option that can be looked at. 
But, we think it's mostly about centrally fueled commercial 
fleets and that can grow naturally, I think.
    Senator Sessions. You mean like fleets that operate within 
a given city?
    Mr. McKay. Buses. Yes. Buses, heavy haulers, those kind of 
things, that centrally fuel and use a depot.
    Senator Sessions. What about long-distance trucking?
    Mr. McKay. Potentially. Potentially. But that's where you--
    Senator Sessions. You'd have to have interstate supplies 
and--
    Mr. McKay. That's where you've got to have infrastructure 
and filling stations and things like that. Which is possible, 
but that's another step of a process.
    Senator Sessions. But, not exceedingly expensive, to 
achieve that.
    Mr. McKay. I don't personally know the cost, but it 
probably wouldn't be exceedingly expensive, no.
    Senator Sessions. Thank you, Mr. Chairman.
    The Chairman. Thank you.
    Senator Landrieu.
    Senator Landrieu. Yes, just two questions.
    I think this has been gone over, but just to be clear, Mr. 
Newell. Our objective is to clean the environment and to do it 
in a very cost-effective manner. Would you believe that natural 
gas meets those two goals? Could you comment about that?
    Mr. Newell. Yes, I think it does. Under the wide variety of 
different scenarios we've looked at, based on greenhouse gas 
legislation, natural gas continues to be a competitive part of 
the energy portfolio, looking forward as far as we can see.
    Senator Landrieu. OK.
    Let me ask Dow Chemical--and, of course, I'm in an 
interesting position, Mr. Chairman, as you know, because my 
State is a--one of the number of top producers of natural gas, 
but we also consume a great deal. Dow is in Louisiana----
    Mr. Stones. We are.
    Senator Landrieu [continuing]. In a big way. So, I'm 
extremely sensitive to this price issue, as well.
    But, let me ask you--describe, just very briefly, how you 
use natural gas in your process and what Dow Chemical or other 
companies in your situation have done to diversify your own 
sources, so you're not over reliant, regardless of the price, 
of one source for your production.
    Mr. Stones. Right. So, we use natural gas as a feedstock. 
We make power from it, and from that we create--you know, get 
the chlorine chain and plastics. The production of natural gas 
is how ethane comes out of the ground, and that becomes 
plastics--and all the other things we make. So, it's a big 
feedstock for us.
    We've taken a number of different approaches. One of the 
things we haven't spoken much about in this room, but we've 
spend a lot of time on efficiency. We've saved 1400 trillion 
BTUs, since 1994, on efficiency. So, certainly when we consider 
climate change--and, you know, supporting energy efficiency is 
one of the things that we would, you know, think is 
appropriate.
    We've also established an alternative feedstock group. So, 
for example, at present, we're looking at different ways to 
make plastics and chemicals from algae, coal, petroleum coke, 
sugarcane. We're trying to bring what we do best, which is 
bring technology to the party, as well. We've also looked at 
gasification in various stages.
    So, we have a kind of an efficiency and also a--diversify 
the types of things we move. We have built a broad portfolio. 
As you know, our crackers in Louisiana can use multiple fuels, 
depending on what's most economic.
    Senator Landrieu. But, Mr. Chairman, I don't want to 
underestimate the importance of our manufacturing base either 
being incentivized--not that they aren't already--but, for us 
to be mindful that--I guess, as Senator Cantwell said, the 
sweet spot is a wide variety of choices of clean fuels, with 
competition in the marketplace, so that it will eliminate, by 
the--if we can price carbon appropriately--eliminate these 
price spikes, create lots of jobs, more predictability in the 
market. We all have a responsibility to move in that direction.
    So, I just wanted to say that I understand the ``dash to 
gas.'' We've lived through--the people of Louisiana and Texas, 
and, to some degree Mississippi and Alabama, along the Gulf 
Coast,--these wild spikes in energy prices that--you know, when 
the price goes too high, we get criticized by everyone else; 
when it goes too low, we go bankrupt. So, you know, the people 
in the Gulf Coast, you know, have not had a very good comfort 
over the last 20, 25 years. We'd like to find a better place 
for all of us, both producers and our users.
    So, I think that's important for manufacturers, like 
yourself, to be looking aggressively for other sources, so that 
if gas is in--more in demand to be the bridge to the future, 
that you can perhaps use sugarcane, which we have a lot of----
    Voice: Understand.
    Senator Landrieu [continuing]. As you know.
    So, thank you, Mr. Chairman, you've been very generous.
    The Chairman. Thank you.
    I thank all the witnesses. It's been a useful hearing, 
useful testimony. Thank you very much.
    That will conclude our hearing.
    [Whereupon, at 12 p.m., the hearing was adjourned.]
                               APPENDIXES

                              ----------                              


                               Appendix I

                   Responses to Additional Questions

                              ----------                              

       Responses of Jack Fusco to Questions From Senator Bingaman
    Question 1. I continue to hear concerns that placing a price on 
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The 
implication is that fuel-switching will result in sharp increases in 
electricity prices. Could you please give us a sense of at what carbon 
price using natural gas to generate electricity becomes comparable in 
cost to coal generation? What is the likelihood of a large-scale 
transition to natural gas, and what timeframe could that potentially 
occur on?
    Answer. Under the current House and Senate climate change 
legislative proposals, the allowance allocation structure is such that 
large-scale switching to natural gas will not take place, particularly 
in the near to mid-term timeframe, based on EPA's CO2 price 
forecast. Providing allowances to coal-fired generators based on an 
updating emissions basis for a long time period dampens the incentive 
to switch to cleaner burning resources. Under this structure, our 
analysis shows that it will take a carbon price of well over $100 to 
motivate switching from coal to natural gas.
    Using current projected gas and coal prices, sub-bituminous coal 
becomes comparable to gas at a carbon price of $30 per metric ton and 
bituminous coal becomes comparable to gas at a carbon price of $25 per 
metric ton. This number would increase if a coal facility receives 
allowance allocations that are linked to output.
    The EPA forecast 2015 CO2 allowance prices of $13 in its 
June analysis of H.R. 2454. Thus, the EPA's analysis does not suggest 
that a ``dash to gas'' would occur (at least initially). Electricity 
price increases would be driven by CO2 costs, not by 
switching to gas. Switching to gas would actually be electricity price 
neutral if CO2 prices reach $25.
    Question 2. Reducing the volatility in the price of natural gas is 
an important goal if we are to lean more heavily on this resource. For 
producers, independent generators, and utilities to enter into long-
term contracts for gas supply would seem to be one way to reduce 
pricing volatility. Could you describe your willingness to enter into 
such long-term contracts, and what obstacles may stand in the way of 
them?
    Answer. Calpine is willing to enter into long-term contracts for 
gas supply. One of the main obstacles standing in the way of long-term 
contracts is the regulatory uncertainty for carbon emissions.
    Question 3. Is it your opinion that the advanced CCS bonus 
allocations in the Kerry/Boxer bill are enough to jumpstart broad 
deployment of CCS? I've noticed that only a maximum of 15% of the 
advance allocations can be given to projects that do not employ coal. 
Do you think that this will potentially restrict other industrial 
CO2 emitters from being able to deploy CCS at their 
facility? Are the CCS allocations enough, in your opinion, to 
incentivize the gas industry to try and deploy this technology? If not, 
how would you improve the CCS bonus allowance to open up the field to 
all industrial stationary source emitters?
    Answer. As currently structured, the advanced CCS bonus allocations 
are only available for coal-fired generation and qualifying industrial 
operations. Additionally, you point out that only a small percentage of 
the bonus allowances are available for industrial operations. The 
structure of this provision is unfair to natural gas-fired generation. 
Preferences should not be given to coal over natural gas or any other 
resources. While much cleaner than coal-fired generation (roughly 50% 
less CO2), natural gas generation does have carbon emissions 
and should benefit from CCS technologies. The provision should be 
available equally to coal fired generation, natural gas fired 
generation and other industrial operations.
    Question 4. You mentioned that you use treated municipal wastewater 
at your natural gas fired power plants in the cooling towers. What are 
the economic differences between treated waste water and using the 
water available through the municipal water supply?
    Answer. In general, water from municipal supplies requires less 
treatment to be suitable for use in our plants than wastewater sources. 
Thus, while cost savings can be obtained by using municipal wastewater, 
any savings are site specific. In addition to being economically 
viable, the use of recycled wastewater also has a positive 
environmental impact--the wastewater is not released into the local 
waterways, local freshwater resources are preserved for other 
beneficial uses, and there are no fisheries impacts from the use of 
recycled wastewater. Our proposed Russell City Energy Center will use 
100% reclaimed water from the City of Hayward's Water Pollution Control 
Facility which will prevent four million gallons per day of treated 
water effluent from being discharged into San Francisco Bay.
    Question 5. All of the natural gas discussed at the hearing will 
come from both conventional and unconventional extraction methods. A 
major stake of the gas future sits in extracting natural gas from tight 
gas sands/shales.
    There has been some discussion here in Congress that the Safe 
Drinking Water Act exemption for hydraulic fracturing should be 
reconsidered. Do you think a repeal of this exemption would 
dramatically affect the future of natural gas extraction of these 
unconventional gas sources?
    Answer. Calpine is in the wholesale electricity generation 
business, not the natural gas production business, so we are not in a 
position to give an informed opinion on this question.
    Question 6. What is the marginal cost of Combined Cycle Gas Turbine 
(CCGT) electricity vs. that generated with pulverized coal? At what 
price for gas is it lower for CCGT?
    How do these numbers compare for old, relatively inefficient coal 
plants vs. new gas plants?
    Answer. Assuming a $5.00 per MMBtu gas price, a typical CCGT with a 
heat rate of 7.0 and a variable operations and maintenance expense 
(``VOM'') of $1.05/MWh can generate electricity at approximately $37/
MWh. Assuming a sub-bituminous coal (e.g. Powder River Basin coal) 
price of $1.81 per MMBtu and a bituminous coal (e.g. Appalachian coal) 
price of 2.71 per MMBtu, a modern sub-bituminous coal plant with a heat 
rate of 10.2 and VOM of $2.00/MWh can be used to generate electricity 
at approximately $21/MWh and a modern bituminous coal plant with a heat 
rate of 9.1 and VOM of $2.75 can be used to generate electricity at 
$28/MWh. A CCGT would be more competitive with an older, less efficient 
coal plant.
    Question 7. How much does conversion from coal to CCGT cost per 
megawatt?
    Answer. The Energy Information Association (the ``EIA'') does not 
provide any guidance on the costs associated with converting a coal-
fired plant to a CCGT; and it is difficult to approximate a generic 
cost for switching from coal-fired to gas-fired due to numerous site-
specific issues, including, but not limited to, variances in the 
amounts and types of equipment that can be salvaged, obtaining 
transportation of gas to the coal plants, and costs associated with 
cleaning up the coal plant.
    We understand, however, that Xcel Energy recently converted its 
Riverside plant in Minnesota from coal-fired to gas-fired for 
approximately $536 per kilowatt. For reference, the EIA has calculated 
that a typical CCGT costs approximately $1000 per kilowatt.
    In terms of converting the generation stack from coal-fired to gas-
fired, which we have the existing capacity to do, and assuming a $6.00 
per MMBtu gas price, gas-fired plants will begin to displace coal on 
the generation stack when carbon allowance prices reach $25/ton, and 
gas-fired plants will be more economical than almost all coal plants 
when carbon allowance prices reach $40/ton.
    Question 8. What is the primary obstacle to CHP?
    Answer. One of the primary obstacles to CHP is the lack of partners 
to contract with for the full power generated from the facilities. 
Without a PPA for the surplus electricity it is difficult to get 
financing for large-scale CHP projects. In addition, many industrial 
facilities already have on-site boilers to produce steam and although 
CHP would emit far less CO2, contracting with a new CHP 
facility could be more expensive than using an existing boiler. Thus, 
incentives are needed to encourage the industrial facilities to make 
the switch.
      Responses of Jack Fusco to Questions From Senator Murkowski
    Question 1. You may know that Senator Menendez and I are both on a 
bill to promote the development of natural gas vehicles. NGV advocates, 
myself included, have pointed out that natural gas as a transportation 
fuel reduces carbon emissions, offsets petroleum imports, and provides 
an economic boost here at home by using natural gas in place of 
imported petroleum. Given the recent findings concerning the increased 
availability of natural gas supplies in North America and here in the 
U.S. should we be doing more to advance the use of natural gas as a 
transportation fuel?
    Answer. Because Calpine is in the wholesale electricity generation 
business, not the transportation business, we do not have an informed 
opinion on this issue.
    Question 2. Currently there are serious regulatory obstacles 
positioning in front of domestic energy development. Particularly, 
surface coal mining rules are under serious assault and offshore oil 
and gas development is facing increasing scrutiny from at least three 
different federal agencies. Can the panel speak to how we ever get to a 
point of more natural gas power plants or, for that matter, clean coal 
if, despite policies encouraging the advancement of these new and 
exciting power sources, we simply can't access and produce the basic 
resource?
    Answer. We refer to the testimony of the production experts who 
expressed the view that the resource is plentiful and production is far 
less difficult than current drilling methods.
    Question 3. What would be your opinion about a Low Carbon 
Electricity Standard that would allow electric utilities to use a 
variety of alternatives to reduce greenhouse gas emissions, including 
renewables, natural gas, nuclear and hydroelectric?
    Answer. Calpine would support a Low Carbon Electricity Standard 
that includes a variety of low and zero GHG emitting resources. As we 
move towards a low carbon future, the federal government should be 
encouraging the use of all low and zero emitting resources--we can meet 
our energy needs by focusing only on renewable resources. Including 
natural gas in a Low Carbon Electricity Standard is an excellent means 
to encourage the greater use of this resource.
    Question 4. To the extent that deliverability of natural gas to 
markets has been an issue in the past, should recent improvements in 
pipeline infrastructure, as well as prospects for additional projects 
coming online, serve as any comfort to those with concerns about spikes 
in natural gas prices?
    Answer. Yes, the discovery of vast reserves of shale gas as well as 
improved infrastructure for bringing gas to the market should dampen 
the volatility in natural gas prices.
    Question 5. Please give me a sense of the relative challenges in 
choosing fuel investments from the perspective of a regulated versus a 
non-regulated utility--I understand Xcel is the regulated utility.
    Answer. At Calpine we base our investment decisions on customer 
electric requirements and the contractual payments needed to provide an 
adequate return on investment. We expect to continue to focus our 
attention on developing power plants fueled by natural gas and 
geothermal energy given our view of environmental responsibility as 
well as our knowledge regarding their operation and maintenance. As 
noted in my testimony, natural gas fired generation is significantly 
cleaner than coal fired generation, In addition, compared to many other 
generation sources, natural gas power plants can be permitted and built 
more quickly and they have a much smaller footprint. Our expectation is 
bolstered by the likelihood that gas-fired capacity will continue to be 
the most cost effective form of new, reliable capacity for our 
customers.
    Question 6. I was interested in Mr. Wilks' testimony about 
SmartGrid City in Boulder, Colorado, as well as the solar work that 
Xcel is doing in Colorado. Can you talk about why natural gas is so 
important as a backup, or baseload generator, for intermittent solar or 
wind power?
    Answer. The increasing utilization of intermittent electricity 
generation resources could have a tremendous impact on the reliability 
of the electricity grid. As I noted in my written testimony, Americans 
demand and deserve reliable energy; they expect the lights to go on 
when they flip the light switch. In the near term, this will only be 
achievable if gas-fired plants are there to provide that reliability. 
Natural gas power plants are versatile and are designed such that they 
can be started quickly and placed into service instantly to meet demand 
when the wind stops blowing or the sun stops shining.
       Responses of Jack Fusco to Questions From Senator Sessions
    Question 1. If the transportation sector moves towards natural gas, 
how will this affect the price of natural gas, the United States' crude 
oil imports, greenhouse gas emissions, other energy sectors that 
currently use this energy source?
    Answer. No comment.
    Question 2. What incentives or regulatory changes are necessary to 
effectively enhance the use of natural gas over coal, diesel, or 
gasoline? And the cost associated with the switch?
    Answer. One of the greatest incentives to enhance the use of 
natural gas is to put a price on carbon. Tighter regulations on other 
pollutants (e.g. NOX, SO2, mercury, coal ash, 
etc.) will also have an impact. Other regulatory changes that could be 
implemented to enhance natural gas usage are generation performance 
standards and low carbon energy standards. All of these incentives and 
regulatory changes will only be effective, however, if the playing 
field remains level in terms of incentives and allowance allocation 
structures for all fossil fuels.
    We do not know what the exact costs associated with the switch 
would be, however, switching to gas would actually be electricity price 
neutral if CO2 prices reach $25.
       Responses of Jack Fusco to Questions From Senator Cantwell
    Question 1a. I think it is very important that we ensure that 
climate policy doesn't introduce unnecessary volatility into markets 
for oil and natural gas. We've seen gas prices fluctuate sharply over 
the past two years, from $5.90 up to $10.82 and then back down to 
around $3.40 where we are now. I think we all agree that this sort of 
uncertainty isn't good for energy producers or consumers.
    What do modeling results and forecasts tell us about what would 
actually happen in the real world with regard to fuel mix, energy costs 
and investment under this kind of price volatility?
    Answer. We believe that natural gas price volatility referenced in 
your question was driven in large part by concern of the long-term 
availability of domestic natural gas resources. The recent discovery of 
vast reserves of shale gas and the improved gas infrastructure should 
mute the volatility in natural gas prices.
    Question 1b. Could a well-designed price collar mitigate this sort 
of volatility?
    Answer. A well-designed price collar in a carbon cap-and-trade 
regulatory program could mitigate price volatility.
    Question 2a. In thinking about alternative approaches to climate 
change policy, one important consideration is the point of regulation, 
especially with regard to an emissions cap. Both the House and Senate 
bills propose downstream caps by regulating thousands of emitting 
entities.
    But an upstream cap for natural gas seems like it could achieve the 
same broad coverage much more simply, by regulating less than a 
thousand entities. What is the most efficient point of regulation to 
achieve broad coverage of fossil carbon for natural gas?
    Answer. Calpine believes that an upstream cap on natural gas is the 
most efficient point of regulation. By regulating upstream, the cost of 
reducing emissions from natural gas combustion is borne by all users of 
this resource and the compliance costs are internalized within the 
price of natural gas. Upstream regulation also simplifies allowance 
allocation distribution as fewer entities are regulated under such a 
program. Further, because the number of regulated entities will be much 
smaller than regulating at the point of combustion, the cost of 
overseeing compliance will be far less.
    Question 2b. Are there any problems with mixing upstream caps for 
some fossil fuels and downstream caps for others? Does an upstream cap 
on all fossil fuels help to promote a consistent, economy-wide carbon 
price signal necessary to transition to a low-carbon economy?
    Answer. While Calpine believes that an upstream cap on all fossil 
fuels is the best and most efficient point for regulation, we do not 
think there would be problems with mixing upstream and downstream caps 
for different fossil fuels. Because natural gas is used in many diverse 
ways (electricity generation, direct home use, industrial processes, 
etc), regulating upstream ensures that emissions from all uses are 
captured and the compliance costs are lower and spread broadly. Oil is 
similar to natural gas with the added factor that it is difficult to 
regulate at the tailpipe for all mobile sources, so capping upstream 
definitely makes the most sense for oil. Coal, however, is primarily 
used for electricity generation so regulating downstream is just as 
practical as regulating upstream. Coal-fired power plants are already 
under regulation for a variety of air emissions and thus have 
experience with complying with emissions reduction programs.
    Question 3. With the recent advances in drilling technology in the 
gas industry, domestic gas reserves shot up by more than 35 percent 
this year, which of course is terrific news for the gas industry and 
potentially for our efforts to address climate change by reducing 
greenhouse gas emissions.
    But I'm wondering about the broader environmental implications of 
the use of technologies such as hydraulic fracturing to produce 
unconventional shale gas resources. What are the implications of shale 
gas production for ground water and drinking water quality? How do 
these environmental risks compare to those of other energy sources?
    Also, from an economic perspective, at what price is shale gas 
production viable for the industry? Would the price certainty of a 
carbon price floor be necessary for shale gas to be economic? How do 
the two prices--the natural gas price and the carbon price--interrelate 
and affect shale gas production?
    Answer. Calpine is in the wholesale electricity generation 
business, not the natural gas production business, so we are not in a 
position to give an informed opinion on this question.
    Question 4. Since natural gas has the lowest carbon content among 
fossil fuels, I would expect that a carbon price would not lead to a 
decline in the natural gas industry. But over the longer term, as the 
economy decarbonizes, there will be pressure on gas-fired utilities, as 
with coal-fired ones, to adopt carbon capture and sequestration 
technologies.
    What is your assessment of the feasibility of commercial scale 
carbon capture and sequestration with natural gas?
    Are the economics of CCS likely to be comparable for gas and coal 
consumers?
    Could reimbursements in the form of allowances in excess of the cap 
for the amount of carbon captured and sequestered make CCS economic? 
And would this framework treat both coal and natural gas fairly?
    Answer. Calpine has not investigated the use of carbon capture and 
sequestration (``CCS'') for natural gas generation. However, we are of 
the opinion that CCS for combined-cycle natural gas plants is feasible, 
in fact potentially more feasible and less expensive than for coal 
plants. It will likely be easier to reform natural gas on the front end 
into hydrogen (primarily for newer projects). On the back end, the 
lower flows and cleaner overall condition of exhaust gas will make it 
easier to remove carbon so the per megawatt cost will be less. Most 
coal applications will need entirely new facilities. If the playing 
field is level, natural gas CCS will be competitive with coal CSS.
    As noted, Calpine has not given much consideration to CCS for 
natural gas generation so we have not thought through needed incentives 
or allowances. However, it is important that CCS incentives and 
allowances for coal and natural gas be fair and equal.
        Response of Jack Fusco to Question From Senator Lincoln
    1. As you know, several recent studies have projected that our 
natural gas supply is much larger than previous estimates. For example, 
the Potential Gas Committee estimates that the U.S. now has a 35% 
increase in supply estimates from just two years ago, which is enough 
they say to supply the U.S. market for a century. The Energy 
Information Agency (EIA) has also predicted a 99-year natural gas 
supply. I am proud that the Fayetteville Shale in Arkansas is already 
producing over one billion cubic feet of natural gas per day, while 
only in its fifth year of development. What role do you believe the 
improvement in drilling technologies such as horizontal drilling and 
hydraulic fracturing played in the estimated increase in natural gas 
supply?
    Answer. Calpine is in the electricity generation business, not the 
natural gas production business, so we do not have an informed opinion 
this question.
         Response of Jack Fusco to Question From Senator Udall
    Question 1. It was mentioned that some coal utilities are already 
switching over to gas without incentive in place, could you elaborate 
on this dynamic? Does low gas price and region play any role in some of 
these changes?
    Answer. Low gas prices and increasingly stringent environmental 
rules have contributed to fuel switching. Last Spring, for instance, 
our Southeast plants produced 60% more MWh than during the same period 
of 2008. This demonstrates that fuel switching (and corresponding 
emissions reductions) is feasible, even in the absence of 
CO2 regulations. Although gas prices have been lower than we 
expect going forward, the introduction of CO2 regulations 
would contribute to fuel switching even at higher gas prices if 
structured properly. However, the allowance allocation structure in the 
current House and Senate climate change legislative proposals dampens 
the incentive to switch to cleaner burning resources, particularly in 
the near to mid-term timeframe. Our analysis shows that by providing 
allowances to coal-fired generators based on an updating emissions 
basis for a long time period, it will take a carbon price of well over 
$100 to motivate switching from coal to natural gas.
                                 ______
                                 
    Responses of Dennis McConaghy to Questions From Senator Bingaman
    Question 1a. I continue to hear concerns that placing a price on 
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The 
implication is that fuel-switching will result in sharp increases in 
electricity prices. Could you please give us a sense of at what carbon 
price using natural gas to generate electricity becomes comparable in 
cost to coal generation? What is the likelihood of a large-scale 
transition to natural gas, and what timeframe could that potentially 
occur on?
    Could you please give us a sense of at what carbon price using 
natural gas to generate electricity becomes comparable in cost to coal 
generation?
    Answer. TransCanada has examined a wide range of gas prices and 
coal plant efficiencies to arrive at the following general conclusions.
    For existing combined cycle and coal plants, with no consideration 
of the fixed costs of such plant, gas-fired generation will be lower or 
comparable in cost to coal generation when natural gas prices are in 
the $6--$8/mmBtu range and carbon prices are in the $20--$40/ton of 
CO2 equivalent range. At the low end of the CO2 
price range, gas-fired generation becomes higher cost than the more 
efficient coal plants.
    For new combined cycle and coal plants, with the full cycle costs 
of the investment factored in, gas-fired generation still is lower or 
comparable in cost to coal generation when natural gas prices are in 
the $6--$8/mmBtu range and carbon prices in the $20--$40/ton of 
CO2 equivalent range, In the low end of the range of 
CO2 prices, gas-fired generation becomes higher cost than 
coal when gas prices go beyond $8/mmBtu.
    Question 1b. What is the likelihood of a large-scale transition to 
natural gas, and what timeframe could that potentially occur on?
    Answer. The gas combined cycle fleet in most US markets is the 
swing electricity producer and currently operates at approximately 42% 
utilization of installed capacity. All other factors being equal, 
carbon prices in the $20--$40/ton of CO2 equivalent range 
and gas prices in the $6-$8/mmBtu range would result in more of this 
capacity being used. For example, if the average utilization factor of 
these installed combined cycle units was increased from the current 42% 
to 55% with a commensurate reduction in coal generation, demand for 
natural gas would increase by an additional 5 Bcf per day--a volume 
that can be easily accommodated from a continental supply perspective 
while maintaining gas prices in the $6--$8/mmBtu range.
    The likelihood of this transition and the timeframe in which it 
could occur largely depends upon what the Congress enacts by way of 
climate change and energy legislation. If that legislation establishes 
a transparent price on carbon that is applied equally to all emitters, 
then the transition is likely to occur in relative short order. On the 
other hand, if the legislation insulates coal-fired electric generation 
from the true costs of controlling greenhouse gas (GHG) emissions the 
transition will be much slower and may not occur at all.
    Question 2a. One area of concern about depending on our natural gas 
resources is that gas has been prone to strong price spikes over the 
past decade. The most recent one was just in 2008, with prices soaring 
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned 
that the expanded reserves and greater ability to receive LNG shipments 
could mitigate future price spikes. Please comment on the factors that 
resulted in the 2008 price spike and other recent spikes. Is the supply 
situation now such that we will be insulated from such volatility in 
the future? Are there policy options we could pursue to reduce price 
volatility?
    Please comment on the factors that resulted in the 2008 price spike 
and other recent spikes.
    Answer. The Federal Energy Regulatory Commission (FERC) has 
prepared one of the most detailed analyses of that price spike in its 
2008 State of the Markets Report, released in August 2009. See http://
www.ferc.gov/market-oversight/st-mkt-ovr/2008-som-final.pdf. In 
general, FERC concluded that, while physical fundamentals of gas supply 
and demand can explain why natural gas prices rose during the first 
half of 2008, none of the physical fundamentals alone were extreme 
enough to explain the high level that natural gas prices reached.
    From a study of this FERC report, TransCanada would make the 
following observations.

   Changes in the physical fundamentals of the market--supply 
        and demand--are the main drivers of volatility, however, 
        commodity market activity can, at times, increase the amplitude 
        of price movements. .
   Increased levels of buying interest, easy access to capital, 
        strongly rising commodity prices in general and trend trading 
        by financial players all helped push prices higher during the 
        first six months of 2008.
   During the last six months of 2008, reduced levels of buying 
        interest, lowered liquidity, generally falling commodity prices 
        and selling pressures all were financial factors that drove 
        prices down.
   In the first half of 2008 market perceptions were very 
        bullish and the market tended to ignore the emerging signs of 
        unconventional gas supply growth, whereas in the second half, 
        perceptions became very bearish and the market completely 
        disregarded the serious impact of the two hurricanes on gas 
        supply.
   With respect to the physical fundamentals in the first half 
        of 2008, a mildly bullish stance was perhaps justified because 
        of gas storage levels below recent years due to cold weather 
        and moderate gas demand growth.
   A more bearish stance due to the impact of the spreading 
        recession on gas demand and the clear evidence of a building 
        over-supply of domestic gas was certainly appropriate for the 
        second half of the year.

    Question 2b. Is the supply situation now such that we will be 
insulated from such volatility in the future?
    Answer. TransCanada believes that the robust supplies of natural 
gas from shale formations and the Arctic combined with expanded 
pipeline, storage, and LNG regasification infrastructure will moderate 
price volatility in the future.
    Price volatility caused by the physical fundamentals of the market 
can be of two types. There is price volatility driven by temporary 
imbalances in continental supply and demand. This type of volatility 
affects the general level of gas prices across the continent and is 
reflected in higher prices at Henry Hub. A second type of volatility is 
regional, as opposed to continental. For example, prices in areas of 
the U.S. Northeast may spike for periods when storage facilities and/or 
transportation facilities are operating at full capacity and are unable 
to keep up with demand.
    Increased transportation infrastructure out of the Rockies and out 
of the key shale plays (supply-connecting pipelines) help ameliorate 
continental price volatility by ensuring greater access to more gas 
supply.
    Increased transportation infrastructure connecting supply pipelines 
to markets (market-connecting pipelines), on the other hand, help 
reduce regional market price volatility by ensuring that supply reaches 
the ultimate consumer.
    The natural gas pipeline industry is increasing substantially the 
transportation infrastructure needed to help reduce volatility. In 2007 
through the first 9 months of 2009 5808 miles of pipelines and 39.2 
Bcf/day of capacity were added to the nation's pipeline grid.
    In addition, substantial increases in gas storage over the past 
three years should reduce seasonal volatility in prices. Total U.S. gas 
storage capacity has increased by 187 Bcf or 55 per cent over this 
period.
    It is equally true that the newly important shale gas resource and 
the increased investment in pipelines and storage will not eliminate 
price volatility. As with other commodities, natural gas will continue 
to exhibit price volatility characteristic of well-functioning markets 
reflecting supply and demand fundamentals. Natural gas prices will 
continue to respond to seasonal changes in demand, hurricane-related 
disruptions in supply, unanticipated changes in the demand for natural 
gas fired electricity as well as overall demand due to general economic 
conditions, and, to reactions of speculative commodity traders to these 
events.
    TransCanada believes, however, that the size and nature of the 
shale resource together with the development of vast Alaskan and 
Canadian reserves over the next decade will assure sufficient supplies 
to assist in maintaining supply-demand balance for decades to come. 
These additional supplies together with sizeable new investments in 
pipelines and storage will continue to moderate price volatility in 
natural gas markets in the years to come.
    Although substantial increases in gas demand over the next decade 
will mean somewhat higher prices (compared to a scenario without 
durable demand increases), TransCanada believes that the natural gas 
industry's continued development of conventional resources together 
with distant Alaskan and other Arctic supplies will, together with the 
``game-changing'' shale gas resource, mean that prices remain at 
reasonable levels and volatility will be moderated.
    Question 3. Is it your opinion that the advanced CCS bonus 
allocations in the Kerry/Boxer bill are enough to jumpstart broad 
deployment of CCS? I've noticed that only a maximum of 15% of the 
advance allocations can be given to projects that do not employ coal. 
Do you think that this will potentially restrict other industrial 
CO2 emitters from being able to deploy CCS at their 
facility? Are the CCS allocations enough, in your opinion, to 
incentivize the gas industry to try and deploy this technology? If not, 
how would you improve the CCS bonus allowance to open up the field to 
all industrial stationary source emitters?
    Answer. As a general proposition, TransCanada questions the 
efficacy of using free allowance allocations to provide incentives for 
CCS research and development. We recognize the considerable capital 
expense required for CCS research and development, but we believe that 
a mechanism that establishes a transparent price for carbon combined 
with direct subsidies for CCS research and development will be more 
effective and economically efficient. Such an approach will allow all 
emitters of GHG to determine the best means to control GHG emissions 
through CCS technologies and / or fuel-switching and will not mask or 
skew the true price of carbon.
    If, however, the Congress decides to pursue a program of free 
allowances to promote CCS technology, TransCanada recommends that the 
current proposals should be modified to create a level playing field 
for all fossil fueled facilities that emit GHG.
    The Kerry-Boxer and Waxman-Markey bills reserve 85% of the CCS 
bonus allowances for coal-fired power plants. This bias in favor of 
clearly will discourage other industrial CO2 emitters from 
attempting to deploy CCS at their facilities.
    In certain situations, facilities other than coal-fired power 
plants present more cost-effective and energy-efficient opportunities 
to capture and sequester CO2 than coal-fired power plants. 
The exhaust streams from natural gas processors and hydrogen producers, 
for example, have a higher concentration of carbon dioxide than most 
coal-fired power plants--meaning that it is less expensive and less 
energy-intensive on a per unit of CO2 to capture 
CO2 from these facilities than from a coal-fired power 
plant. From an environmental perspective, a ton of sequestered 
CO2 is just as beneficial whether it is emitted from a coal-
fired facility or from a facility utilizing natural gas for an 
industrial process.
    If the CCS bonus allowance program is artificially restricted to 
coal-fired facilities, it could end up needlessly spending more 
resources to achieve fewer emission reductions than it would absent the 
restriction.
    Question 4. All of the natural gas we're discussing here today will 
come from both conventional and unconventional extraction methods. A 
major stake of the gas future sits in extracting natural gas from tight 
gas sands/shales. There has been some discussion here in Congress that 
the Safe Drinking Water Act exemption for hydraulic fracturing should 
be reconsidered. Do you think a repeal of this exemption would 
dramatically affect the future of natural gas extraction of these 
unconventional gas sources?
    Answer. TransCanada transports natural gas through its pipelines 
and consumes natural gas in its electric generation facilities. We are 
not involved in the production of natural gas. As such, TransCanada has 
had no experience with the regulation of hydraulic fracturing and will 
defer to views of BP and other natural gas producers on this issue.
    TransCanada does believe, however, that the environmental impacts 
of natural gas extraction from tight sands and shale formations can be 
managed effectively and efficiently without unduly limiting the 
production potential of these sources. To ensure this is the case, the 
regulatory process for managing environmental risks must be guided 
fundamentally by scientific and technical considerations and must yield 
expeditious and predictable results.
   Responses of Dennis McConaghy to Questions From Senator Murkowski
    Question 1. You may know that Senator Menendez and I are both on a 
bill to promote the development of natural gas vehicles. NGV advocates, 
myself included, have pointed out that natural gas as a transportation 
fuel reduces carbon emissions, offsets petroleum imports, and provides 
an economic boost here at home by using natural gas in place of 
imported petroleum. Given the recent findings concerning the increased 
availability of natural gas supplies in North America and here in the 
U.S. should we be doing more to advance the use of natural gas as a 
transportation fuel?
    Answer. TransCanada believes that North American natural gas 
reserves are sufficient to support an increase in demand created by a 
policies designed to advance the use of natural gas both in the 
transportation sector and, more importantly, in the power sector.
    Particularly in the short and medium term, TransCanada believes 
that emission reductions can be most effectively achieved by moving 
from high emission power resources, like coal, to lower emission 
resources, like natural gas, nuclear, and renewables. One approach that 
TransCanada supports to achieve these reductions is a Low Carbon 
Electricity Standard, described in Murkowski Question #3.
    With respect to natural gas as a transportation fuel, TransCanada 
supports appropriately designed federal policies designed to increase 
the use of natural gas as a transportation fuel because such fuel 
switching will result in less dependence on crude oil from overseas and 
reduced GHG emissions. However, TransCanada strongly recommends that 
such policies be limited to the government, commercial and industrial 
fleets components of the in the transportation sector. The necessity 
for specialized fuel storage and handling equipment in natural gas 
vehicles and refueling stations, makes conversion of large numbers of 
private automobiles unlikely and prohibitively expensive. By 
comparison, incentives and/or mandates targeted at fleet operators are 
likely to result in the greatest level of vehicle conversions from 
petroleum based fuels to natural gas.
    Question 2. Currently there are serious regulatory obstacles 
positioning in front of domestic energy development. Particularly, 
surface coal mining rules are under serious assault and offshore oil 
and gas development is facing increasing scrutiny from at least three 
different federal agencies. Can the panel speak to how we ever get to a 
point of more natural gas power plants or, for that matter, clean coal 
if, despite policies encouraging the advancement of these new and 
exciting power sources, we simply can't access and produce the basic 
resource?
    Answer. TransCanada believes the goals of energy / climate change 
legislation should be to reduce the overall level of greenhouse gas 
emissions and lessen dependence on fossil fuels imported from overseas 
in a manner that is environmentally and economically sound. To 
accomplish these goals, it is necessary that the U.S. embrace energy / 
climate change policies that allow maximum use of all domestic North 
American energy resources as well as encourage greater conservation and 
efficiency.
    Development and production of energy resources, whether renewable 
or fossil fueled, should not be limited arbitrarily. The U.S. energy 
industry consistently has demonstrated that it possesses the technology 
and experience to effectively and efficiently manage the environmental 
risks posed by energy production. The starting point for any debate 
over access to and development of a particular area or resource should 
be whether the risks posed by such access and development can be 
appropriately managed and mitigated. If it is determined that they can, 
access and development should be permitted. TransCanada is confident 
that if the process for making access and development decisions is 
based on sound scientific and technical analysis and designed to yield 
expeditious and predictable results, such a process will lead to a 
fundamentally well-balanced energy / climate change policy.
    Question 3. What would be your opinion about a Low Carbon 
Electricity Standard that would allow electric utilities to use a 
variety of alternatives to reduce greenhouse gas emissions, including 
renewables, natural gas, nuclear and hydroelectric?
    Answer. TransCanada believes that if Congress is to pursue a clean 
energy mandate either as a stand-alone policy or as a complement to a 
cap-and-trade framework, a Low Carbon Electricity Standard (LCES) is a 
better policy approach than a standard devoted solely to renewable 
energy sources. A broad mandate, like an LCES, provides certainty that 
there will be a credible and significant substitution of clean 
resources in place of higher emission sources.
    Unlike current Renewable Electricity Standard (RES) proposals, 
which focus only on achieving a specified percentage of renewable 
electricity each year, the LCES would provide an opportunity for a 
meaningful down payment on GHG emission reductions by relying on a full 
menu of clean energy options, including energy efficiency; renewable 
energy; new and incremental nuclear; new and incremental 
hydroelectricity; coal with CCS; and high-efficiency natural gas 
generation. Any credible climate strategy must include an explicit role 
for natural gas. Natural gas is the cleanest domestic fossil fuel. The 
carbon content of natural gas is almost 50% less than coal, and it can 
be used at substantially greater thermal efficiencies. Natural gas 
produces less SOX, NOX, mercury, and particulate 
matter than coal. Recent major additions to natural gas reserves mean 
that domestic gas will be abundant, affordable, and available for 
electric generation.
    If Congress cannot reach a consensus on a cap-and-trade climate 
change bill, adoption of the LCES would provide a path to increased 
energy and environmental security through power resource 
diversification. With its broader base of eligible resources, the LCES 
would yield more GHG emission reductions and within a shorter time 
horizon than an RES due to the difficulties of renewable energy sources 
to reach meaningful scale in any near or intermediate term. The LCES 
would also provide retail suppliers greater compliance flexibility than 
and RES, which in turn would help keep power prices lower in comparison 
to an RES. While an RES may point us in the right direction, the LCES 
would actually achieve tangible progress in our efforts to address 
climate change while also advancing development of renewable energy.
    In the context of a cap-and-trade bill that allocates a significant 
percentage of free allowances, an LCES would provide all the benefits 
described above plus act as a meaningful balance to free -allowance 
incentives to continue to burn higher emission resources like coal. 
Free allowances not only minimize the incentive to reduce emissions, 
but they also distort the price of carbon. In the early years of a cap-
and-trade program with a large distribution of free allocations, it is 
likely that allowance prices may not be high enough to encourage 
deployment of low-carbon generation. Without the additional policy 
determinations embodied in the LCES, it is unlikely the electric power 
sector will have the economic motivation to make the investments in low 
carbon technology necessary to address in any significant way actual 
reductions in carbon emissions; an RES alone would only partially 
address this risk.
    If the primary goal of energy and climate legislation is to 
increase security and reduce GHG emissions, then adoption of a low 
carbon standard will make a real down payment on a clean energy future 
by weighting technologies by their carbon content. Limiting that down 
payment to a subset of only a few renewable clean power choices, such 
as with an RES, would be short changing and unnecessarily delaying our 
clean energy future.
    Question 4. To the extent that deliverability of natural gas to 
markets has been an issue in the past, should recent improvements in 
pipeline infrastructure, as well as prospects for additional projects 
coming online, serve as any comfort to those with concerns about spikes 
in natural gas prices?
    Answer. The past and projected expansion of natural gas pipelines 
certainly plays an important role in reducing price volatility by 
improving the deliverability of additional supplies into major 
consuming markets. Indeed, the multi-billion dollar expansion of the 
Nation's pipeline infrastructure underscores the confidence of the 
natural gas markets in the ``game changer'' character of the shale 
reserves as well as the prolific Rocky Mountain reserves. Even with 
expanded pipelines, however, not all volatility can be eliminated.
    Price volatility caused by the physical fundamentals of the market 
can be of two types. There is price volatility driven by temporary 
imbalances in continental supply and demand. This type of volatility 
affects the general level of gas prices across the continent and is 
reflected in higher prices at Henry Hub. A second type of volatility is 
regional, as opposed to continental. For example, prices in areas of 
the U.S. Northeast may spike for periods when storage facilities and/or 
transportation facilities are operating at full capacity and are unable 
to keep up with demand.
    Increased transportation infrastructure out of the Rockies and out 
of the key shale plays (supply-connecting pipelines) help ameliorate 
continental price volatility by ensuring greater access to more gas 
supply.
    Increased transportation infrastructure connecting supply pipelines 
to markets (market-connecting pipelines), on the other hand, help 
reduce regional market price volatility by ensuring that supply reaches 
the ultimate consumer.
    The natural gas pipeline industry is increasing substantially the 
transportation infrastructure needed to help reduce volatility. In 2007 
through the first 9 months of 2009 5808 miles of pipelines and 39.2 
Bcf/day of capacity were added o the nation's pipeline grid.
    In addition, substantial increases in gas storage over the past 
three years should reduce seasonal volatility in prices. Total U.S. gas 
storage capacity has increased by 187 Bcf or 55 per cent over this 
period.
    Although new gas supplies and expanded infrastructure will moderate 
price volatility, TransCanada believes that it is equally true that 
they will not eliminate price volatility. As with other commodities, 
natural gas will continue to exhibit price volatility characteristic of 
well-functioning markets reflecting supply and demand fundamentals. 
Natural gas prices will continue to respond to seasonal changes in 
demand, hurricane-related disruptions in supply, unanticipated changes 
in the demand for natural gas fired electricity as well as overall 
demand due to general economic conditions, and, to reactions of 
speculative commodity traders to these events.
    TransCanada believes, however, that the size and nature of the 
shale resource together with the development of vast Alaskan and 
Canadian reserves over the next decade will assure sufficient supplies 
to assist in maintaining supply-demand balance for decades to come. 
These additional supplies together with sizeable new investments in 
pipelines and storage will continue to moderate price volatility in 
natural gas markets in the years to come.
    Although substantial increases in gas demand over the next decade 
will mean somewhat higher prices (compared to a scenario without 
durable demand increases), TransCanada believes that the natural gas 
industries continued development of conventional resources together 
with distant Alaskan and other Arctic supplies will, together with the 
``game-changing'' shale gas resource will mean that prices will remain 
moderate and that volatility will also exhibit characteristics of 
moderation.
    Responses of Dennis McConaghy to Questions From Senator Sessions
    Question 1. If the transportation sector moves towards natural gas, 
how will this affect the price of natural gas, the United States' crude 
oil imports, greenhouse gas emissions, other energy sectors that 
currently use this energy source?
    Answer. TransCanada believes that North American natural gas 
reserves are sufficient to support an increase in demand created by a 
policies designed to advance the use of natural gas both in the 
transportation sector and, more importantly, in the power sector.
    Particularly in the short and medium term, TransCanada believes 
that emission reductions can be most effectively achieved by moving 
from high emission power resources, like coal, to lower emission 
resources, like natural gas, nuclear, and renewables. One approach that 
TransCanada supports to achieve these reductions is a Low Carbon 
Electricity Standard, described in Murkowski Question #3.
    With respect to natural gas as a transportation fuel, TransCanada 
supports appropriately designed federal policies designed to increase 
the use of natural gas as a transportation fuel. Greater use of natural 
gas as a transportation fuel will also reduce the United States' 
dependence on crude oil imports and the level of emissions of 
greenhouse gases from the transportation sector. The degree to which 
these reductions occur will depend upon the level of vehicle 
conversions that occur.
    TransCanada strongly recommends that policies promoting the use of 
natural gas for vehicle use be limited to government, commercial and 
industrial fleets components of the in the transportation sector. The 
necessity for specialized fuel storage and handling equipment in 
natural gas vehicles and refueling stations, makes conversion of large 
numbers of private automobiles unlikely and prohibitively expensive. By 
comparison, incentives and/or mandates targeted at fleet operators are 
likely to result in the greatest level of vehicle conversions from 
petroleum based fuels to natural gas.
    With respect to increased gas demand for fleet vehicle use, 
TransCanada believes that such an increase in natural gas demand is not 
sufficient to have a material impact on gas prices. Although any 
increase in gas demand, other things equal, will increase price, the 
volumes in this instance will be small to modest and slow to build as 
infrastructure is added and vehicles replaced. Consequently, the 
increase in price related to more use of natural gas by fleets should 
be insignificant.
    As noted above, in the absence of an increase in supply of natural 
gas, any policy that increases demand will result in an increase in the 
price of natural gas. However, TransCanada believes that the 
significantly improved methods of economically and efficiently 
producing natural gas from shale formations, complemented by the likely 
introduction of Arctic reserves, have fundamentally changed the 
continental natural gas supply outlook. These robust supplies will 
support and respond to a substantial increase in natural gas demand 
that is driven by policies designed to advance the use of natural gas 
as a transportation fuel without greatly affecting the price of natural 
gas. As we testified at the hearing, TransCanada believes that a 
natural gas price in the $6--$8/mmBTU range is likely to achieve 
equilibrium between ensuring development and production of natural gas 
supplies and increasing demand.
    Question 2. What incentives or regulatory changes are necessary to 
effectively enhance the use of natural gas over coal, diesel, or 
gasoline? And the cost associated with the switch?
    Answer. TransCanada has not conducted any direct study or analysis 
of regulatory barriers to increasing use of natural gas in the 
transportation sector and therefore is not in a position to offer any 
recommendations in that regard. Similarly, TransCanada has not invested 
any resources in exploring potential incentives to enhance the use of 
natural gas in the transportation sector.
    Responses of Dennis McConaghy to Questions From Senator Cantwell
    Question 1. I think it is very important that we ensure that 
climate policy doesn't introduce unnecessary volatility into markets 
for oil and natural gas. We've seen gas prices fluctuate sharply over 
the past two years, from $5.90 up to $10.82 and then back down to 
around $3.40 where we are now. I think we all agree that this sort of 
uncertainty isn't good for energy producers or consumers.
    What do modeling results and forecasts tell us about what would 
actually happen in the real world with regard to fuel mix, energy costs 
and investment under this kind of price volatility?
    Could a well-designed price collar mitigate this sort of 
volatility?
    Answer. TransCanada acknowledges that extreme volatility in energy 
prices can cause hardship for businesses and households. However, all 
commodity markets--no matter how well-regulated--are susceptible to 
some degree of volatility, and the natural gas market is no exception. 
Rather than engage in a futile attempt to stamp out volatility in 
energy markets, sound energy policy should seek to ensure that prices 
reflect genuine forces of supply and demand and well-functioning 
competitive markets. Without taking any position here on pending 
legislation, TransCanada notes that both the Senate and the House of 
Representatives have been actively pursuing legislation--in addition to 
the market manipulation provisions you spearheaded in the Energy Policy 
Act of 2005--to prevent misconduct in the commodity derivatives 
markets. If properly designed, such legislation should provide 
additional transparency in a well-functioning market in energy 
commodities, including natural gas.
    In addition, as discussed elsewhere in these responses, recent 
developments in natural gas supply and transportation infrastructure 
should avert a recurrence of the rapid increase in natural gas prices 
observed from 2005-2008. Indeed, the key to moderating volatility is 
maintaining reasonable balance between supply and demand. The 
referenced price run-up was caused in part, not by a lack of supply, 
but by a lack of pipeline capacity to satisfy growing demand for 
natural gas during this period. Since 2007, the natural gas supply and 
delivery situation has changed dramatically.
    The unprecedented expansion of the U.S. gas pipeline network in 
2008, and the simultaneous expansion of U.S. gas reserves, should 
moderate price volatility in the gas markets with supply being 
delivered to consuming markets and should reduce the chance of a 
similar supply constraint in the foreseeable future. Of course, the 
recent dramatic decline in prices in 2008 and 2009 is due in part to 
increased supply hitting the market at the same time demand has been 
weakened by the general economic situation.
    TransCanada submits that most observers believe that the natural 
gas markets are well-functioning and that periods of price volatility 
have been of relative short duration and a function of supply-and-
demand situations that generally correct quickly either with resolution 
of supply interruption, break in a cold snap or greater supply 
responding to greater demand as reflected in price increases.
    TransCanada interprets the question regarding the efficacy of a 
price collar as applying to a price collar on carbon prices; we assume 
that it is not a reference to price collars on natural gas. TransCanada 
believes that any attempt to regulate the price of natural gas, whether 
through a price collar or otherwise, would lead to extreme disruptions 
in the market.
    TransCanada does believe that price predictability in carbon 
pricing is warranted and deserves closer scrutiny by the Congress. If 
the cost of purchasing CO2 emission allowances in a cap-and-
trade program is reflected in the unit price of energy delivered to 
consumers, then volatility in the CO2 allowance market has 
the potential to add to overall volatility in energy markets generally. 
A ``price collar'' mechanism that places a firm ceiling and a firm 
floor on allowance will help mitigate or avoid this additional 
volatility in energy prices, by reducing volatility in the component of 
energy prices that is attributable to emission allowances. TransCanada 
strongly supports efforts to provide type of stability and 
predictability to any carbon price.
    In TransCanada's opinion, which is shared by a number of economists 
and industry participants, a carbon tax that sets a specific price for 
carbon would be the most efficient method to address GHG emissions. If 
the paramount goal is to set a clear price on carbon to induce 
behaviors that reduce GHG emissions, then a carbon tax would arguably 
be the clearest path to achieving that goal. A properly set and 
maintained carbon tax would incent GHG reductions, provide businesses 
certainty, and would not create the degree of administrative difficulty 
that can be anticipated under a that a cap-and-trade / offsets program 
regime.
    Question 2. In thinking about alternative approaches to climate 
change policy, one important consideration is the point of regulation, 
especially with regard to an emissions cap. Both the House and Senate 
bills propose downstream caps by regulating thousands of emitting 
entities.
    But an upstream cap for natural gas seems like it could achieve the 
same broad coverage much more simply, by regulating less than a 
thousand entities. What is the most efficient point of regulation to 
achieve broad coverage of fossil carbon for natural gas?
    Are there any problems with mixing upstream caps for some fossil 
fuels and downstream caps for others? Does an upstream cap on all 
fossil fuels help to promote a consistent, economy-wide carbon price 
signal necessary to transition to a low-carbon economy?
    Answer. The optimal point of regulation in a cap-and-trade program 
is one that (a) covers an adequate proportion of greenhouse gas 
emissions, (b) affects a manageable number of carbon-regulated 
entities, and (c) transmits an appropriate price signal to consumers of 
carbon-intensive fuels and products. There is no reason to believe that 
the best point of regulation will be the same for all fossil fuels, 
given that each fuel has a different supply chain and market structure. 
Indeed, both the Waxman-Markey and Kerry-Boxer climate change bills 
recognize the need for a nuanced point of regulation by specifying an 
``upstream'' point of regulation for some fossil fuels (such as 
petroleum-based liquid fuels) and a ``downstream'' point of regulation 
for others (large users of coal and natural gas).
    In the case of natural gas, TransCanada believes that a 
``downstream'' point of regulation (at the point of emission) is 
generally most appropriate. Making upstream producers of natural gas 
accountable for GHG emissions from gas combustion would introduce 
several significant problems. First, there are several hundred thousand 
facilities that produce natural gas in the United States, making an 
allowance requirement difficult to administer at the point of natural 
gas production. Second, natural gas has substantial uses (as a chemical 
feedstock, for example) that do not result in GHG emissions--meaning 
that an ``upstream'' point of regulation would require a supplemental 
mechanism for thousands of natural gas users to claim a rebate for non-
emissive uses of natural gas. Pipelines are an inappropriate point of 
regulation for the same reasons, but also because the complexity of 
pipeline networks makes it difficult to define a pipeline point of 
regulation that would avoid double-counting (or under-counting) natural 
gas emissions.
    By contrast, a ``downstream'' point of regulation for natural gas 
would still affect a limited number of large entities (such as power 
plants and large industrial users of natural gas), while ensuring that 
non-emissive uses of natural gas do not fall under the cap. For the 
numerous residential and commercial consumers of natural gas, the most 
efficient point of regulation is probably at the local distribution 
company (LDC). This is more or less the approach taken in the Kerry-
Boxer and Waxman-Markey bill, and--according to a recent study by the 
Pew Center on Global Climate Change\1\--would cover 95% of 
CO2 emissions from natural gas while affecting a reasonable 
number of facilities.
---------------------------------------------------------------------------
    \1\ Joel Bluestein, Coverage of Natural Gas Emissions and Flows 
Under a Greenhouse Gas Cap-and-Trade Program (Pew Center on Global 
Climate Change, December 2008) http://www.pewclimate.org/docUploads/
NaturalGasPointofRegulation09.pdf.
---------------------------------------------------------------------------
    In the case of natural gas markets, however, regulation of large 
emitters of combusted natural gas does present some significant issues 
for regulated entities to recover allowance costs and to avoid 
duplicative, diverse state programs. Thus, while a purely upstream 
point of regulation for natural gas may avoid some of the recovery 
issues for downstream regulated entities, TransCanada believes these 
transition issues can be address with a clear statutory provision 
directing regulators to all for tracking of carbon allowance compliance 
costs as well as a strong pre-emption provision which preempts not only 
individual state efforts to further regulate carbon emissions but also 
preempts the EPA from any further regulation of carbon emissions under 
the Clean Air Act or any other federal statute or regulation.
    Question 3. With the recent advances in drilling technology in the 
gas industry, domestic gas reserves shot up by more than 35 percent 
this year, which of course is terrific news for the gas industry and 
potentially for our efforts to address climate change by reducing 
greenhouse gas emissions.
    But I'm wondering about the broader environmental implications of 
the use of technologies such as hydraulic fracturing to produce 
unconventional shale gas resources. What are the implications of shale 
gas production for ground water and drinking water quality? How do 
these environmental risks compare to those of other energy sources?
    Also, from an economic perspective, at what price is shale gas 
production viable for the industry? Would the price certainty of a 
carbon price floor be necessary for shale gas to be economic? How do 
the two prices--the natural gas price and the carbon price--interrelate 
and affect shale gas production?
    Answer. TransCanada transports natural gas through its pipelines 
and consumes natural gas in its electric generation facilities. We are 
not involved in the production of natural gas. As such, TransCanada has 
had no experience with the regulation of hydraulic fracturing and will 
defer to views of BP and other natural gas producers on this issue.
    TransCanada does believe, however, that the environmental impacts 
of natural gas extraction from tight sands and shale formations can be 
managed effectively and efficiently without unduly limiting the 
production potential of these sources. To ensure this is the case, the 
regulatory process for managing environmental risks must be guided 
fundamentally by scientific and technical considerations and must yield 
expeditious and predictable results.
    There are many different shale plays in the US and across the 
continent. These plays differ in their production economics. Even 
within individual plays there are substantial differences in the cost 
of production depending on exact location. Furthermore, some shale 
formations (e.g. the Marcellus) are closer to market and, consequently, 
receive higher net back prices than other, more remote shales.
    TransCanada believes that at a gas price of $6 to $8/mmBtu range 
shale gas will make a large and growing contribution to US and 
continental supply over the next decade and beyond. We also believe 
that this price range generally can be maintained in the absence of 
very high carbon prices.
    It is not clear that a carbon price, by itself, will improve the 
economics of shale gas or natural gas in general. Indeed, TransCanada's 
assessment is that the Waxman / Markey bill does not increase the 
demand for gas and therefore does not improve the economics of gas. 
This is because, under the bill, alternatives to natural gas either 
receive substantial incentives or are insulated from true carbon 
prices, or both, leaving little or no scope for increases in natural 
gas demand.
    The interplay between carbon prices and natural gas prices is both 
direct and indirect. First, the carbon price as it applies to natural 
gas increases the gas price to the consumer but not for the producer. 
Second, there can be an indirect affect. Institution of any system that 
results in carbon prices of $30 per ton or more, if applied to all 
fossil fuels completely and equally, have the potential to cause 
switching of natural gas for coal. The extent of switching will depend 
primarily on the price of natural gas and the magnitude of the carbon 
price.
    Question 4. Since natural gas has the lowest carbon content among 
fossil fuels, I would expect that a carbon price would not lead to a 
decline in the natural gas industry. But over the longer term, as the 
economy decarbonizes, there will be pressure on gas-fired utilities, as 
with coal-fired ones, to adopt carbon capture and sequestration 
technologies.
    What is your assessment of the feasibility of commercial scale 
carbon capture and sequestration with natural gas?
    Are the economics of CCS likely to be comparable for gas and coal 
consumers?
    Could reimbursements in the form of allowances in excess of the cap 
for the amount of carbon captured and sequestered make CCS economic? 
And would this framework treat both coal and natural gas fairly?
    Answer. TransCanada has been actively involved in the study and 
development of CCS projects for the past 5 to 6 years. Our involvement 
has included front end development on both pre-combustion capture and 
post combustion capture plants fuelled with varied grades of petcoke 
and coal. TransCanada has also been involved in a number of industry 
and government committees and initiatives which focused on CCS 
technologies, costs and policy.
    TransCanada's experience in developing pre-combustion capture of 
CO2 through proven gasification technology indicates that in 
order to recover costs on the CO2 capture portion of a 
facility in today's markets, carbon prices in the range of $90 to $150 
per ton would be required. The range of cost is related to the 
technology employed, whether the facility produced a single product 
(e.g. electricity or hydrogen--$150 pre ton) or multiple products (i.e. 
polygeneration--$90 per ton) and the market price for natural gas. The 
current natural gas price forecasts of $6-8/mmBtu push the carbon price 
very high as natural gas pricing has an inverse effect on the price of 
carbon. The reason for this is that the outputs from gasification (e.g. 
electricity, hydrogen, synthetic natural gas) are currently produced 
using natural gas as the primary feedstock and output from a 
gasification process would be required to compete with the prevailing 
market price of natural gas.
    TransCanada's experience in developing post-combustion capture of 
CO2 is gained through our exposure to the capture of 20% 
CO2 from an existing sub-critical coal plant in Alberta. Our 
work indicated that carbon prices in the range of $150-$200 per ton 
would be required in order to recover costs on post combustion 
CO2 capture facilities. The higher carbon price over 
gasification based technologies is required due to the lower pressure 
and less concentrated CO2 stream leaving a post combustion 
plant. This requires larger equipment and more compression horsepower 
over a gasification facility. Our carbon costs also account for 
parasitic electrical and steam load loss from the base plant.
    There has been some discussion regarding utilizing captured 
CO2 for application in enhanced oil recovery (EOR) 
operations. The total cost of carbon required does not change in this 
application but the economic value attached to CO2 for EOR 
application can offset a portion of the total carbon price required.
    The following table demonstrates some key comparative carbon cost 
findings TransCanada has made as part of our CCS experience. This shows 
that the lowest cost of emissions reduction results from the 
utilization of natural gas itself without carbon capture. Natural gas 
based power production will result in an emission reduction of 
approximately 60% compared to a coal plant utilizing sub-critical coal 
with no capture.

 
------------------------------------------------------------------------
                                                            Capture Cost
              Plant                  Carbon       Natural       ($/ton
                                    reduction    Gas Price    captured)
------------------------------------------------------------------------
SubCritical Coal (Baseline)       baseline      $6-8        N/A
------------------------------------------------------------------------
Add on 20% Post Combustion        20%           $6-8        $150-$200
 Capture
------------------------------------------------------------------------
New Natural Gas Combined Cycle    60%           $6-8        $0
------------------------------------------------------------------------
Polygeneration/IGCC with 90%      90%           $6-8        $90-$150
 Capture
------------------------------------------------------------------------

    With respect to the question regarding the use of allowances for 
CCS, TransCanada questions the efficacy of using free allowance 
allocations to provide incentives for CCS research and development. We 
recognize the considerable capital expense required for CCS research 
and development, but we believe that a mechanism that establishes a 
transparent price for carbon combined with direct subsidies for CCS 
research and development will be more effective and economically 
efficient. Such an approach will allow all emitters of GHG to determine 
the best means to control GHG emissions through CCS technologies and / 
or fuel-switching and will not mask or skew the true price of carbon.
    If, however, the Congress decides to pursue a program of free 
allowances to promote CCS technology, TransCanada recommends that the 
current proposals should be modified to create a level playing field 
for all fossil fueled facilities that emit GHG.
    The Kerry-Boxer and Waxman-Markey bills reserve 85% of the CCS 
bonus allowances for coal-fired power plants. This bias in favor of 
clearly will discourage other industrial CO2 emitters from 
attempting to deploy CCS at their facilities.
    In certain situations, facilities other than coal-fired power 
plants present more cost-effective and energy-efficient opportunities 
to capture and sequester CO2 than coal-fired power plants. 
The exhaust streams from natural gas processors and hydrogen producers, 
for example, have a higher concentration of carbon dioxide than most 
coal-fired power plants - meaning that it is less expensive and less 
energy-intensive on a per unit of CO2 to capture 
CO2 from these facilities than from a coal-fired power 
plant. From an environmental perspective, a ton of sequestered 
CO2 is just as beneficial whether it is emitted from a coal-
fired facility or from a facility utilizing natural gas for an 
industrial process.
    If the CCS bonus allowance program is artificially restricted to 
coal-fired facilities, it could end up needlessly spending more 
resources to achieve fewer emission reductions than it would absent the 
restriction.
        Response of Dennis McConaghy to Question From Mark Udall
    Question 1. You mentioned that the new gas shale resources would 
provide a more stable resource than traditional natural gas resources, 
thereby reducing the volatility in gas prices. Specifically you 
mentioned that gas shale is a different kind of resource and that 
geology is less of an issue. Could you please elaborate more on this?
    Answer. TransCanada does believe that the natural gas industry will 
be able to develop sufficient natural gas supplies to support increased 
use of natural gas in the electricity sector as well as the 
transportation sector. This supply will come from continued 
technological developments which will support production of both 
conventional and unconventional supplies.
    Shale production, in particular, is a ``game changer'' in terms of 
natural gas supplies. Because producers generally know where shale 
reserves are located they are not confronted with the same ``finding'' 
risk that exists in the case of conventional natural gas reserves. 
Rather, the limitations on shale gas supply are ``production'' risks. 
In this regard, production of shale gas is similar to a ``manufacturing 
process''. A vertical well is drilled into a shale formation and then 
the formation is drilled horizontally. This technique permits multiple 
perforations along a horizontal axis as opposed to conventional 
vertical perforations through gas bearing formations. With horizontal 
drilling and horizontal completions, the odds of increasing production 
are dramatically higher.
    With non conventional gas, specifically shale gas, vast amounts of 
resource have been identified. If prices spike, increased drilling can 
occur immediately (i.e. additional ``manufacturing'' assembly lines can 
be added) and result in timely increases in gas supply. With horizontal 
drilling, the exploration process at the front end is not required.
      Responses of David Wilks to Questions From Senator Bingaman
    Question 1. I continue to hear concerns that placing a price on 
carbon through climate legislation will result in significant fuel 
switching, or what has been referred to as a ``dash to gas''. The 
implication is that fuel-switching will result in sharp increases in 
electricity prices. Could you please give us a sense of at what carbon 
price using natural gas to generate electricity becomes comparable in 
cost to coal generation? What is the likelihood of a large-scale 
transition to natural gas, and what timeframe could that potentially 
occur on?
    Answer. With the imposition of a CO2 allowance price, 
the costs to operate all fossil resources will increase, but to varying 
extent depending on each fuel's carbon intensity (emissions per MWh). 
Efficient combined cycle natural gas has approximately half or less of 
the emissions per MWh of typical pulverized coal-fired power 
generation. Thus, although the cost of gas generation will increase 
with the cost of CO2, the CO2 cost impact on coal 
generation will be approximately twice as much.
    The CO2 allowance price at which using natural gas to 
generate electricity becomes comparable in cost to coal generation is 
intuitively the price at which all costs--capital, O&M, fuel, and 
carbon costs--sum to the same $/MWh for coal and gas. Natural gas tends 
to have lower capital, higher fuel, and approximately half the carbon 
costs of coal. In theory, at a high enough CO2 price, gas 
could push coal out of the dispatch order even though gas also must 
hold allowances. The exact carbon price at which this substitution 
could occur is hard to predict, and will depend on a variety of 
factors, including (1) the projected cost of natural gas; (2) the 
projected cost of coal; and (3) the efficiency and operating costs of 
existing coal facilities and any replacement natural gas facilities.
    For specific carbon values at which the cost to generate 
electricity with natural gas is equivalent to coal fired generation, 
the time frame needs to be considered. In the near-term, coal to 
natural gas switching would occur through the re-dispatching of the 
existing generation fleet and would occur economically (when it is less 
expensive to generate electricity from natural gas rather than coal) 
with a CO2 cost of roughly $45/ton depending on specific 
plant characteristics and assuming, among other things, $7.00/MMBtu 
natural gas.
    In the intermediate term, when new construction is required to meet 
electricity generation needs, capital costs and utilization of the 
plant must be considered in the natural gas vs. coal assessment. In a 
scenario where natural gas generation displaces coal generation, the 
utilization of each plant type would change from current levels and by 
extension the cost per unit of electricity would change as the fixed 
costs are spread over greater (gas) or fewer (coal) units of 
electricity. The amount of potential displacement would vary depending 
on capital costs, fuel costs and the details of the system in which the 
plant operates. Using current utilization rates the break-even 
CO2 cost for new natural gas generation vs. new coal 
generation is roughly $25/ton assuming, among other things, $7.00/MMBtu 
gas.
    In both examples, the CO2 ``break-even'' cost is 
sensitive to natural gas prices where a $1 increase in natural gas 
prices would add roughly $10--$12/ton to the CO2 ``break-
even'' cost.
    As I testified, the retirement of at least some coal plants and 
increased reliance on natural gas for electricity generation is an 
inevitable result of a cap and trade program. The likelihood and timing 
of a large-scale transition to natural gas for baseload power 
generation, however, depends on many factors other than the price of 
CO2 allowances. Recent advancements in unlocking shale gas 
will increase economically recoverable supplies and could reduce gas 
price volatility; however, at the moment, there are a number of 
regulatory uncertainties as well as uncertainty about what gas price is 
needed to incentivize shale gas exploration and production. Expanded 
use of natural gas for power generation, vehicles, intermittent 
renewable energy balancing, and other demands will put upward pressure 
on prices. Under CO2 regulation it seems likely that there 
will be increased reliance on natural gas for power generation in the 
early years of the program, particularly if carbon offsets are in short 
supply,\1\ but beyond 2020 natural gas generation could again decrease 
as carbon capture and storage (CCS) technologies for coal become 
commercial and with possible investments in new nuclear generating 
capacity. Also, achieving CO2 emission reductions of around 
80% by 2050 will not be possible even by replacing all coal generation 
with gas. Thus, increased natural gas power generation appears to be a 
``bridge'' strategy that would begin immediately and continue through 
2020 or 2025, and the magnitude of this change will probably depend on 
the availability and timing of carbon offsets, CCS and other low-and 
zero-carbon generation technologies. At the same time, as our own 
experience with the Minnesota Emission Reduction Program demonstrates, 
state policies can promote earlier retirement of coal and replacement 
with natural gas in some circumstances independent of any federal 
climate change strategy.
---------------------------------------------------------------------------
    \1\ As suggested in the USDOE Energy Information Administration's 
analysis of the energy market and economic impacts of H.R. 2454, the 
American Clean Energy and Security Act of 2009. See http://
www.eia.doe.gov/oiaf/servicerpt/hr2454/index.html. Only in EIA's 
scenarios in which offsets and technology are constrained did the 
electric sector use significantly more gas and less coal than in the 
reference case by 2030.
---------------------------------------------------------------------------
    Question 2. One area of concern about depending on natural gas 
resources is that gas has been prone to strong price spikes over the 
past decade. The most recent one was just in 2008, with prices soaring 
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned 
that the expanded reserves and greater ability to receive LNG shipments 
could mitigate future price spikes. Please comment on the factors that 
resulted in the 2008 price spike and other recent spikes. Is the supply 
situation now such that we will be insulated from such volatility in 
the future? Are there policy options we could pursue to reduce price 
volatility?
    Answer. There have been three significant price spikes in the past 
decade. The first one occurred in December 2000 when NYMEX prices 
spiked to just under $10.00 per million British thermal units (mmBtu). 
This price spike was a result of an extremely cold start to the winter 
heating season and below average storage levels. The second price spike 
occurred in the fall of 2005 when the combination of hurricanes Katrina 
and Rita disrupted a significant amount of production in the Gulf of 
Mexico and NYMEX prices spiked as to just over $14.00 per mmBtu. The 
third spike occurred in June and July of 2008 when prices spiked to 
over $13.00 per mmBtu. However this one was unique as there was no 
obvious underlying disruption in the natural gas market that would 
account for the price spike.
    The expanded reserves associated with shale gas and the ability of 
the nation to receive larger quantities of LNG should insulate the 
market from extended periods of extreme volatility, but they cannot 
eliminate the possibility of price spikes altogether due to the lag 
times associated with drilling activity in order to access the expanded 
reserves and the global market forces that drive the pricing of LNG.
    Below are four policies that could reduce natural gas price 
volatility:

   First, Congress should encourage practices by state 
        regulators and large players in the natural gas market that 
        result in a more stable, predictable price. In addition to 
        ensuring that companies that trade in natural gas markets do 
        not engage in abusive trading practices, Congress should 
        encourage utilities to use, and state regulators to allow, 
        prudent and appropriate hedging strategies.
   Second, as I testified, climate policy will inevitably rely 
        in part on repowering of existing coal plants to natural gas. A 
        volatile carbon dioxide allowance price could exacerbate the 
        volatility of natural gas prices. In designing climate policy, 
        Congress should use price collars and other mechanisms to 
        control the volatility of the price of a carbon dioxide 
        allowance. Such mechanisms will assist in controlling the 
        volatility of natural gas prices.
   Third, adopting a policy that would encourage the 
        development of additional storage facilities or the expansion 
        of existing facilities would have the potential to limit future 
        price volatility. The development of additional storage 
        capacity would provide a supply buffer to help offset periodic 
        disruptions of supply or periods of increased demand and in 
        addition it could act as balancing mechanism for the physical 
        market during periods of excess production.
   Finally, the best way to avoid volatility of natural gas 
        prices is to assure a stable supply and reduce the barriers to 
        development of new natural gas resources. Even with expanded 
        supply options, sudden changes in demand for natural gas could 
        result in a significant short-term increase in natural gas 
        prices unless natural gas supply can rise to meet that demand. 
        Congress should avoid creating unnecessary permitting barriers 
        to the development of both conventional and shale gas, as well 
        as pipelines and other supporting infrastructure.

    Question 3. Reducing the volatility of the price of natural gas is 
an important goal if we are to lean more heavily on this resource. For 
producers, independent generators, and utilities to enter into long-
term contracts for gas supply would seem to be one way to reduce 
pricing volatility. Could you describe your willingness to enter into 
such long-term contracts, and what obstacles may stand in the way of 
them?
    Answer. Long-term commitments for gas supply at a fixed price could 
alleviate concerns related to fuel price changes over the long term for 
a generating unit or group of units. Fixed price contracts eliminate 
the opportunity for upside market price movement for the seller and the 
benefit of lower market prices for the utility. State regulated 
utilities must be prudent in fuel purchase decisions and utilities 
would need the support of regulators to commit to long-term contracts 
that could be priced above the spot market in the future. Long-term 
contracts would need to address security issues related to financial 
performance through collateral or margin posting as well as the 
commitment of both parties to perform operationally. If satisfactory 
contractual and regulatory arrangements could be implemented, Xcel 
Energy would be interested in long term fixed price contracts for 
natural gas.
    Question 4. Is it your opinion that the advanced CCS bonus 
allocations in the Kerry/Boxer bill are enough to jumpstart broad 
deployment of CCS? I've noticed that only a maximum of 15% of the 
advance allocations can be given to projects that do not employ coal. 
Do you think that this will potentially restrict other industrial 
CO2 emitters from being able to deploy CCS at their 
facility? Are the CCS allocations enough, in your opinion, to 
incentivize the gas industry to try and deploy this technology? If not, 
how would you improve the CCS bonus allowance to open up the field to 
all industrial stationary source emitters?
    Answer. In our opinion:

   The advanced bonus allocations under the Kerry/Boxer bill 
        are enough to jumpstart the deployment of CCS, and such a 
        provision is an important feature of any policy to address 
        major emission sources of CO2. However, the key 
        phrase of the question is ``broad deployment.'' Kerry/Boxer's 
        incentives and advanced allocation will increase certainty, buy 
        down the cost of CCS, and help make fossil-fueled facilities 
        with CCS more competitive, but only within the limits set in 
        the bill regarding percentage of allowances provided, economic 
        value of the bonus to an individual project, and overall 
        capacity threshold. The larger issues are (1) whether the 
        support provided to CCS is sufficient considering the cost of 
        sequestration and regulatory requirements yet to be 
        established, and (2) whether the support is sufficient to 
        create the impetus for CCS technological advances that will, in 
        time, make CCS economically viable beyond the scope of the 
        bonus program. These issues remain to be determined and will 
        require continuing evaluation and possible adjustment to the 
        program in the future.
   Coal is the major source of CO2 emissions and 
        directing 85% of the advance allocations toward coal appears 
        sensible. Moreover, the experience gained and technology 
        improvements achieved applying CCS to coal will also be of 
        significant value in enabling CCS in the gas industry and other 
        industrial stationary source emitters.

    Question 5. All of the natural gas we're discussing here today will 
come from both conventional and unconventional extraction methods. A 
major stake of the gas future sits in extracting natural gas from tight 
gas sands/shales. There has been some discussion here in Congress that 
the Safe Drinking Water Act exemption for hydraulic fracturing should 
be reconsidered. Do you think a repeal of this exemption would 
dramatically affect the future of natural gas extraction of these 
unconventional gas sources?
    Answer. Xcel Energy is not involved in the natural gas extraction 
industry. We have no direct experience with the hydraulic fracturing 
and production of natural gas from conventional or unconventional 
resources. We have no experience to allow us to comment on the impact a 
repeal of the Safe Water Drinking Act hydraulic fracturing exemption 
may have on the natural gas extraction industry. As a significant 
participant in the purchasing of natural gas, however, we are concerned 
that any change to the regulations governing the development of 
unconventional gas may create significant and sustained challenges to 
the production of natural gas from shale formations. These in turn may 
have an impact on the volatility of the market price for natural gas. 
Consequently, we encourage Congress to consider whether the 
environmental benefits of additional regulation of hydraulic fracturing 
would outweigh the lost environmental and potential economic 
opportunity associated with expanded gas production.
    Question 6. What is the marginal cost of Combined Cycle Gas Turbine 
(CCGT) electricity vs. that generated with pulverized coal? At what 
price for gas is it lower for CCGT? How do these numbers compare for 
old, relatively inefficient coal plants vs. new gas plants?
    Answer. The term marginal cost is typically used to describe the 
cost to operate an electric generating plant which includes the cost of 
fuel and certain operations and maintenance (O&M) costs. The CCGT 
plants operating on Xcel Energy's systems today would typically 
generate electricity in the neighborhood of $50/MWh to $55/MWh (burning 
$7.00/MMBtu natural gas). In comparison, Xcel Energy's pulverized coal 
plants typically generate electricity in the range of $12/MWh to $20/
MWh depending on coal type. In both the CCGT and pulverized coal values 
above, approximately 90% of these costs are associated with the fuel 
and the remaining 10% are related to O&M. Note that these costs do not 
include the capital cost required to construct the plants nor do they 
include any cost for CO2.
    When the capital costs to construct new generating plants are 
factored into the pricing (creating an ``all-in'' cost), the CCGT costs 
are in the $80-$85/MWh range (at 50% capacity factor) with pulverized 
coal falling in the range of $55/MWh to $65/MWh (at 90% capacity 
factor). These pricing estimates assume the capital cost of a new CCGT 
to be in the range of $800-$1000/kW of nameplate generating capacity 
and a new pulverized coal unit (without carbon capture) to be in the 
range of $2400-$3000/kW of nameplate generating capacity.
    These $/MWh ``all-in'' cost estimates are heavily dependent on how 
often the unit is utilized. The basic cost characteristics of thermal 
generation resource technologies are illustrated in the following 
table.

 
------------------------------------------------------------------------
                                   Gas Turbine
              Costs                   (GT)         CCGT         Coal
------------------------------------------------------------------------
Capital Costs                     Low           Mid         High
------------------------------------------------------------------------
Operating Costs                   High          Mid         Low
------------------------------------------------------------------------
Intended Use                      Peaking       Intermedia  Baseload
                                                 te
------------------------------------------------------------------------
Hours of Use                      Low           Medium      High
------------------------------------------------------------------------

    The figure* below provides an illustration of how the general cost 
characteristics of GT, gas CCGT, and coal generators might compare with 
one another based on how they are utilized (i.e., peaking, 
intermediate, or baseload) on the system. The figure shows that the 
``all-in'' cost of electric energy per MWh depends highly on the number 
of hours a unit is operated, (i.e., the unit's capacity factor). The 
``all-in'' cost curves decline as the fixed costs (capital and fixed 
O&M) are distributed over more hours of operation.
---------------------------------------------------------------------------
    * Graph has been retained in committee files.
---------------------------------------------------------------------------
    Assuming the mid-point of $60/MWh for the ``all-in'' cost from a 
new pulverized coal plant described above, a new CCGT with capital 
costs of $900/kW and operating at a 50% capacity factor would have an 
``all-in'' cost of $60/MWh at a gas price of approximately $4.00/MMBtu.
    While older coal plants may be relatively inefficient compared to 
newer coal plants, the capital cost to construct the older coal plants 
was often significantly lower than the $2400-$3000/kW cost range 
estimated for construction of a new coal plant today. These older coal 
plants can have ``all-in'' costs for electricity in the $40/MWh to $50/
MWh range since the lower capital costs more than offset the lower 
efficiencies. The gas cost needed to make a new CCGT plant have a $45/
MWh all-in cost is approximately $1.80/MMBtu.
    Question 7. How much does conversion from coal to CCGT cost per 
megawatt?
    Answer. Although general information regarding the cost of 
conversion of a coal plant is discussed above, the actual cost is very 
case specific. The cost depends on several factors including how much 
of the existing coal plant facilities can be utilized by the CCGT 
plant. For example, it is often possible for the CCGT facility to reuse 
the coal plant's steam turbine. While the reuse of certain components 
results in a savings of capital dollars to the CCGT facility, there can 
be additional design and construction costs that erode a portion of 
these capital savings. Furthermore, a CCGT plant that uses an existing 
steam turbine is often less efficient than a CCGT that utilizes a steam 
turbine that has been specifically engineered and designed to be used 
in a combined cycle application. The loss in efficiency results in 
higher operating costs which can also erode a portion of the capital 
savings. The end result can be a converted CCGT plant that has 
essentially the same ``all in'' cost as a new CCGT facility that does 
not utilize components from an existing coal plant.
    Question 8. What is the primary obstacle to CHP?
    Answer. CHP technology has some very good applications, but for 
Xcel Energy there are some recognized obstacles including a process 
need (for the heat) and a power need that must be at the same location. 
The economics of the project decline as the distance between the 
process and power needs increase. It is also a technology better suited 
for an industrial site, not a residential or commercial site thus 
further limiting suitable locations. Most of our industrial customers 
have already taken advantage of CHP in the form of cogeneration. Hence 
the likelihood that CHP could be a big contributor to carbon reduction 
is remote.
      Responses of David Wilks to Questions From Senator Murkowski
    Question 1. You may know that Senator Mendendez and I are both on a 
bill to promote the development of natural gas vehicles. NGV advocates, 
myself included, have pointed out that natural gas as a transportation 
fuel reduces carbon emissions, offsets petroleum imports and provides 
an economic boost here at home by using natural gas in place of 
imported petroleum. Given the recent findings concerning the increased 
availability of natural gas supplies in North America and here in the 
U.S. should we be doing more to advance the use of natural gas as a 
transportation fuel?
    Answer. The technology exists to reduce the use of petroleum in the 
transportation sector through either natural gas vehicles or electric 
vehicles among other developing technologies. Both technologies require 
significant investment in infrastructure to be successful. There are 
very good uses for both of these types of transportation fuel 
technology. For the automobile sector electrified transportation is a 
technology solution that has the additional benefit of providing an 
off-peak load for electric utilities and the ability to support off-
peak renewable energy generation and storage. We are supporting the 
development of transportation electrification through our commitment to 
the Edison Electric Institute industry-wide pledge to the full scale 
deployment and commercialization of an electrified transportation 
sector as illustrated in the industry pledge attached as Exhibit 1.
    Question 2. Currently there are serious regulatory obstacles 
positioning in front of domestic energy development. Particularly, 
surface coal mining rules are under serious assault and offshore oil 
and gas development is facing increasing scrutiny from at least three 
different federal agencies. Can the panel speak to how we ever get to a 
point of more natural gas power plants or, for that matter, clean coal 
if, despite policies encouraging the advancement of these new and 
exciting power sources, we simply can't access and produce the basic 
resource?
    Answer. To make the transition to a low-carbon, clean energy 
future, the utility industry must rely on a diverse portfolio of clean 
energy resources, including natural gas, clean coal, nuclear, renewable 
energy and energy efficiency. At Xcel Energy, we have already begun to 
reduce our emissions and have plans in place to achieve a 15% reduction 
in CO2 across the system by 2020, relying on almost all of 
these clean resources. Our strategy today shows how the industry will 
likely respond to the challenge of federal climate legislation 
tomorrow. However, the success of that strategy depends on unfettered 
access to capital, steel and other construction materials, and, of 
course, coal, natural gas, and uranium fuels.
    Question 3. What is your opinion about a Low Carbon Electricity 
Standard that would allow utilities to use a variety of alternatives to 
reduce greenhouse gas emissions, including renewables, natural gas, 
nuclear and hydroelectric?
    Answer. Xcel Energy has long been an advocate of such a standard. 
Several years ago, in an effort to break the logjam on climate and 
energy policy, Xcel Energy became a proponent of a Clean Energy 
Portfolio Standard, or CEPS. Under CEPS, utilities would have been 
required to derive a portion of the electricity provided to their 
customers from clean energy resources, which would have included 
renewables, new nuclear, clean coal and energy efficiency. EIA analyzed 
the policy and found it to be a very cost-effective method of promoting 
new technologies and reducing emissions. Although we designed CEPS 
prior to the recent shale gas discoveries, the policy can easily be 
modified to accommodate natural gas repowering as a clean energy 
alternative. More information regarding CEPS is attached as Exhibit 2.
    Question 4. To the extent that deliverability of natural gas to 
markets has been an issue in the past, should recent improvements in 
pipeline infrastructure, as well as prospects for additional projects 
coming online, serve as any comfort to those with concerns about spikes 
in natural gas prices?
    Answer. The pipeline improvements that have recently been completed 
or are in the process of being permitted and constructed have or will 
alleviate a number of regional pricing anomalies including many of the 
spikes seen over the last 3-5 years. The improvements that are complete 
have resulted in a number of regional markets that are functioning and 
falling more inline with national pricing trends. Geographic changes to 
the natural gas producing areas, like the new shale basins 
(Pennsylvania shale vs. Wyoming traditional production), as well as the 
geographic changes to the market demand for gas caused by power 
generators moving from coal or other fuels to natural gas could result 
in regional pricing differentials becoming greater than they are now. 
These regional production and demand shifts may again cause gas 
pipeline constraints that could result in regional price spikes.
    The continued development and use of natural gas storage in and 
around the market demand areas has the potential to reduce the short 
duration impacts of increased natural gas demand by allowing for the 
efficient use of the pipeline infrastructure. Natural gas storage can 
help the natural gas generator avoid short duration price spikes by 
having storage gas available rather than going to the market during 
periods of high gas demand and the corresponding price increases. 
Natural gas storage does not have a significant impact on long term 
price trends as storage must eventually be refilled after it has been 
consumed.
    Question 5. Please give me a sense of the relative challenges in 
choosing fuel investments from the perspective of a regulated versus 
non-regulated utility-I understand Xcel is the regulated utility.
    Answer. In selecting fuel investments, a non-regulated entity must 
choose the project only after considering the needs and desires of its 
stakeholders (e.g. shareholders, customers and policy makers). The 
decision is made based on a number of factors, including the impact of 
the investment on the environment, its consistency with state policy, 
its feasibility and risk, additional transmission and other supporting 
infrastructure associated with the investment, its community acceptance 
and, of course, its cost.
    A regulated utility in selecting fuel investments has to work 
within the rules of its federal, state or local regulatory construct 
and in some cases receive regulatory approval of the need for such fuel 
investment. These rules may require the utility to follow a certain 
bidding process, allow interested third parties to intervene and/or 
mandate a preference for certain types of projects (i.e. renewables), 
in addition to meeting the needs of its stakeholders.
    Question 6. I was interested in Mr. Wilks' testimony about 
SmartGrid City in Boulder, Colorado, as well as the solar work that 
Xcel is doing in Colorado. Can you talk about why natural gas is so 
important as a backup, or baseload generator, for intermittent solar or 
wind power?
    Answer. We are very proud of SmartGridCity and believe that it will 
allow us to test a variety of new ways to run a utility. We believe 
that the Smart Grid will be an important tool to help us integrate 
renewable energy onto our system.
    As your question implies, natural gas is important as a backup to 
intermittent solar or wind power because of the unpredictable nature of 
those generation resources. Renewable energy ``integration'' refers to 
those ancillary activities necessary to absorb increasing penetration 
of intermittent renewable generation while maintaining overall electric 
system stability and reliability. To support this integration Xcel 
Energy relies heavily on natural gas fired power plants, which can be 
brought online with fairly short notice. However, integrating the 
renewable resources into our system with the help of the back up 
natural gas resources inevitably imposes additional costs on our 
customers. These costs are variable, but studies of utilities across 
the country conclude that these costs can exceed $5.00/MWh for 
utilities like Xcel Energy with high levels of renewable energy 
penetration.
    To help reduce the burden of these costs on our customers, Xcel 
Energy is encouraging the adoption of new federal renewable tax 
incentive policies. These policies should recognize that integrating a 
substantial amount of renewable generation-in particular wind and 
solar-on the grid imposes significant burdens on the utilities that 
transmit and distribute electricity from such resources to customers. 
To account for these burdens and encourage utilities to make necessary 
system upgrades and ongoing integration expenditures, including those 
in SmartGrid technology, Congress should enact a ``Renewable 
Integration Credit'' (RIC). The RIC would provide utilities with a tax 
credit based on the kilowatt hours of ``intermittent renewable 
electricity'' generated on the system. Unlike the production tax 
credit, the RIC would be directed toward defraying the integration 
costs incurred by the utility system. More detail regarding the RIC is 
attached as Exhibit 3.
      Responses of David Wilks to Questions From Senator Sessions
    Question 1. If the transportation sector moves towards natural gas, 
how will this affect the price of natural gas, the United States' crude 
oil imports, greenhouse gas emissions, other energy sectors that 
currently use this energy source.
    Answer. Fleets vehicles which consume a consistent daily amount of 
fuel will be the early users of natural gas as transportation fuel. 
These vehicles return to their terminal every evening and can utilize 
the large central natural gas fueling facility. The use of natural gas 
as a motor fuel by the general public is expected come later as there 
would be a need for a significant change in the fueling infrastructure 
and the increase in the availability of factory built natural gas 
vehicles.
    Each MMBTU of natural gas used by vehicles will displace 
approximately 8 gallons of gasoline and reduce carbon emissions by 20-
30%. The use of natural gas by the transportation sector will increase 
natural gas consumption which may place upward pressure on natural gas 
pricing similar to any increase in consumption.
    Question 2. What incentives or regulatory changes are necessary to 
effectively enhance the use of natural gas over coal, diesel, or 
gasoline? And the cost associated with the switch?
    Answer. At the present time there are no major restrictions on the 
use of natural gas as a fuel in any economic sector, in contrast to the 
1970s when such restrictions were in place. Economic considerations 
tend to dominate decisions about the use of natural gas, along with the 
fuel's physical availability (tied to the deployment of delivery 
infrastructure). Natural gas has some inherent advantages in terms of 
its handling and combustion characteristics, so if cost is close to 
even natural gas is often a preferred choice. Policies to incent fuel 
switching in the electric utility sector include:

   credit for early action if a switch is made prior to a new 
        GHG regulatory program;
   allowance trading for other air emissions, as natural gas 
        has lower or no emissions of SO2, NOX or 
        mercury or particulates, but such reductions may not be valued 
        in a `command and control' regulatory system;
   enhanced regulatory support for regulated utilities in terms 
        of accelerated rate recovery, higher allowed return on invested 
        capital, etc.;
   robust support for storage and delivery infrastructure 
        including positive tax treatment for investment, streamlined 
        siting and permitting processes, and a consistent safety and 
        inspection regime; and
   properly regulated commodity markets in order to ensure 
        price discovery, product innovation, and access to risk 
        management mechanisms such as hedging.
      Responses of David Wilks to Questions From Senator Cantwell
    Question 1. I think it is very important that we ensure that 
climate policy doesn't introduce unnecessary volatility into markets 
for oil and natural gas. We've seen gas prices fluctuate sharply over 
the past two years from $5.90 up to $10.82 and then back down to around 
$3.40 where we are now. I think we all agree that this sort of 
uncertainty isn't good for energy producers or consumers.

   What do modeling results and forecasts tell us about what 
        would actually happen in the real world with regard to fuel 
        mix, energy costs and investment under this kind of price 
        volatility?
   Could a well designed price collar mitigate this sort of 
        volatility?

    Answer. With regard to natural gas price volatility, we agree that 
recent years have seen significant ups and downs. In that context there 
has nonetheless been strong investment in new natural gas power plants. 
Thus, even without CO2 regulation and with natural gas 
prices remaining volatile, we expect trends would be similar to recent 
years: utilities will continue to invest in gas generation to meet peak 
demand and increasingly as a resource to balance higher levels of 
intermittent renewable power. The national energy mix would likely 
transition incrementally toward renewables with natural gas, and 
incrementally away from coal, but this transition would be gradual.
    With volatile gas prices and CO2 regulation, one recent 
analysis--EIA's analysis of the American Clean Energy and Security Act 
of 2009--suggests that natural gas power generation and natural gas's 
share of the national energy mix would increase; however, differences 
from the reference case are only significant if offsets and low-carbon 
technologies are constrained. In this scenario investment in new 
natural gas generation could increase significantly during a transition 
period in which utilities use gas as a ``bridge'' strategy until 
offsets, CCS or new nuclear become available. Otherwise, EIA describes 
a future in which emissions are in decline, even without changes in the 
fuel mix, due to energy efficiency and a slow economic recovery, and in 
which many of the reductions needed for compliance come from offsets 
rather than internal abatement.
    Xcel Energy believes a well-designed carbon dioxide allowance price 
collar could mitigate CO2 allowance price volatility. A 
price collar would establish a ceiling and floor on the prices 
regulated entities pay for allowances, with the ceiling designed to 
avoid economic harm and the floor designed to ensure an adequate price 
to incentivize carbon reductions and energy efficiency. A price collar 
would provide some cost certainty for regulated entities, reduce price 
volatility and market manipulation. A carbon dioxide price collar would 
by extension help reduce the potential volatility of natural gas prices 
under a cap and trade program.
    Question 2. In thinking about alternative approaches to climate 
change policy, one important consideration is the point of regulation, 
especially with regard to an emissions cap. Both the House and Senate 
bills propose downstream caps by regulating thousands of emitting 
entities.

   But an upstream cap for natural gas seems like it could 
        achieve the same broad coverage much more simply, by regulating 
        less than a thousand entities. What is the most efficient point 
        of regulation to achieve broad coverage of fossil carbon for 
        natural gas?
   Are there any problems with mixing upstream caps for some 
        fossil fuels and downstream caps for others? Does an upstream 
        cap on all fossil fuels help to promote consistent, economy 
        wide carbon price signal necessary to transition to a low-
        carbon economy?

    Answer. Natural gas does pose special issues in terms of point of 
regulation for GHG emissions. Natural gas is a uniquely pervasive fuel, 
ranging across economic sectors from electric utilities, to heavy 
industry, to large commercial and small residential end users. In 
general, given this usage profile, an upstream point of GHG regulation 
for natural gas seems preferable and easier to administer. However, it 
would also be possible to regulate large stationary sources at the 
point of use, while regulating the remainder of natural gas upstream. 
GHG and regulatory accounting systems can be used to facilitate either 
approach.
    Nearly all proposals for a GHG cap and trade system have used a so-
called `hybrid upstream-downstream' approach to the point of regulation 
issue. While sectoral definitions and entity size criteria vary, these 
hybrid approaches all make the common assumption that any problems that 
may arise from combining upstream and downstream approaches will be 
more manageable than the problems that could result from imposing an 
inappropriate point of regulation on some major portion of the economy. 
In practice, we simply don't know much about the real tradeoffs 
underlying this policy decision. Both upstream and downstream 
approaches serve to limit GHGs and thus create price signals; it does 
not appear to be necessary for all fossil fuels to be regulated in the 
same manner for this price (scarcity) signaling to have an economic 
effect.
    Question 3. With the recent advances in drilling technology in the 
gas industry, domestic gas reserves shot up by more than 35 percent 
this year, which of course is terrific news for the gas industry and 
potentially for our efforts to address climate change by reducing 
greenhouse gas emissions.

   But I'm wondering about the broader environmental 
        implications of the use of technologies such as hydraulic 
        fracturing to produce unconventional shale gas resources. What 
        are the implications of shale gas production on ground water 
        and drinking water quality? How do these environmental risks 
        compare to those of other energy sources?
   Also, from an economic perspective, at what price is shale 
        gas production viable for the industry? Would the price 
        certainty of a carbon price floor be necessary for shale gas to 
        be economic? How do the two prices-the natural gas price and 
        the carbon price-interrelate and affect shale gas production?

    Answer. Reliable and environmentally beneficial energy production 
is in the public interest. Whatever the implications are for ground 
water associated with hydraulic fracturing, they need to be balanced 
with whatever environmental risks are associated with other energy 
sources. As indicated above, we support policies that allow for the 
responsible development of clean energy options such as unconventional 
natural gas.
    Since Xcel Energy is not a producer we do not have the necessary 
insight into determining at what price shale gas production is viable. 
The interrelation of natural gas and carbon prices can affect shale gas 
only to the extent that carbon prices positively or negatively impact 
the underlying price of natural gas, which in turn impacts the economic 
viability of shale gas production.
    Question 4. Since natural gas has the lowest carbon among fossil 
fuels, I would expect that a carbon price would not lead to a decline 
in the natural gas industry. But over the longer term, as the economy 
decarbonizes, there will be pressure on gas-fired utilities, as with 
coal-fired ones, to adopt carbon capture and sequestration 
technologies.

   What is your assessment of the feasibility of commercial 
        scale carbon capture and sequestration with natural gas?
   Are the economics of CCS likely to be comparable for gas and 
        coal consumers?
   Could reimbursements in the form of allowances in excess of 
        the cap for the amount of carbon captured and sequestered make 
        CCS economic? And would this framework treat both coal and 
        natural gas fairly?

    Answer. We believe that with current CCS technology, CCS with 
natural gas is technically feasible but significantly less economical 
than with coal, primarily because of the lower concentration of 
CO2 in the exhaust gas from a natural gas facility. In terms 
of cost-effectiveness with respect to both investments and the impact 
of CCS allowance incentives, we therefore feel CCS should be supported 
on behalf of coal consumers, at least in the short and mid-term. The 
experience gained and technological advance achieved in applying CCS to 
coal will also be of significant value to gas consumers going in the 
future.
        Response of David Wilks to Question From Senator Lincoln
    Question 1. As you know, several recent studies have projected that 
our natural gas supply is much larger than previous estimates. For 
example, the Potential Gas Committee esimtates that the U.S. now has a 
35% increase in supply estimates from just two years ago, which is 
enough they say to supply the U.S. market for a century. The Energy 
Information Agency (EIA) has also predicted a 99-year natural gas 
supply. I am proud that the Fayetteville Shale in Arkansas is already 
producing over one billion cubic feet of natural gas per day, while 
only in its fifth year of development. What role do you believe the 
improvement in drilling technologies such as horizontal drilling and 
hydraulic fracturing played in the estimated increase in natural gas 
supply?
    Answer. Improved drilling technology has played a very significant 
role in the increase in natural gas supply. According to America's 
Natural Gas Alliance, advances in geoscience, drilling and well 
completion technology as well as 3-D seismic technology now allow 
production companies to ``see'' the resource and to tap underground 
reservoirs with less surface disturbance. The development of the 
Fayetteville Shale (and the benefits it provides to Arkansas and the 
people of the United States) and other unconventional formations is 
made possible by this new technology.
      Response of David Wilks to Question From Senator Mark Udall
    Question 1. It was mentioned that some coal utilities are already 
switching over to gas without incentive in place, could you elaborate 
on this dynamic? Does low gas price and region play any role in some of 
these changes?
    Answer. In our experience, state legislatures may create programs 
that offer cost recovery and other incentives to encourage utilities to 
reduce emissions in part by retiring older coal plants and replacing 
them with natural gas generation. Senator Udall himself cosponsored 
legislation creating such a program in Colorado when he was a state 
legislator in 1998. These programs are designed to achieve different, 
state specific goals, including improving air quality, promoting 
economic development, or helping to achieve the state's own greenhouse 
gas reduction goals. As indicated in my testimony, at Xcel Energy, we 
have undertaken retirement and gas replacement programs in Minnesota 
(the MERP) and are in the process of implementing a similar plan in 
Colorado.
    In our experience, however, these programs do not give utilities 
unlimited discretion to undertake such projects. Instead, they require 
the state public utilities commission to oversee the projects and 
approve them only if they have reasonable cost and customer benefits. 
In evaluating these projects, state commissions must evaluate the 
potential cost of the project, including the potential cost of fuel. 
Thus, lower projected gas prices will make these projects less costly 
and thus more likely to be approved by the state commissions. In other 
words, lower gas prices encourage states and utilities to undertake gas 
replacement projects.
 Exhibit 1.--News Release From Edison Electric Institute, October 21, 
                                  2009
     industry-wide plug-in electric vehicle market readiness pledge
    DETROIT--EEI member companies are committed to making electric 
transportation a success. At the center of these efforts is the 
industry-wide pledge to plug-in electric vehicle market readiness. The 
pledge represents a culmination of efforts by EEI member companies to 
survey the current state of electric transportation initiatives among 
utilities, evaluate how those initiatives fit in with the overall goal 
of advancing transportation electrification and determine what more is 
needed. There are five areas of focus:

          1. Infrastructure: Utilities pledge to proactively work with 
        their state regulatory and legislative bodies to assess and 
        address any potential system impacts from fueling large numbers 
        of plug-in vehicles from the electrical grid. Further, 
        utilities will work collaboratively with state and local 
        officials, public/private entities, automakers, and other 
        stakeholders to help develop a comprehensive local charging 
        infrastructure deployment plan.
          2. Customer Support: Utilities pledge to assure that a robust 
        customer service process is in place that can scale up to 
        support large numbers of plug-in vehicle customer service 
        requests ranging from charging infrastructure installations to 
        utility-specific rate options and incentive plans. Utilities 
        will work with stakeholders to facilitate a streamlined 
        charging installation process.
          3. Customer and Stakeholder Education: Utilities pledge to 
        collaborate with state and local officials, public/private 
        entities and automakers to help implement a broad nationwide 
        education program highlighting the benefits of electric 
        transportation (energy security, reduction in greenhouse gases 
        and air pollutants); the benefits of electricity as an 
        alternative fuel; the creation of public-access charging 
        infrastructure; steps cities and individual customers need to 
        take to get plug-in ready; and the importance and benefits of 
        off-peak charging.
          4. Vehicle and Infrastructure Incentives: Utilities pledge to 
        work with federal, state and local stakeholders to help develop 
        purchase and ownership incentives (monetary/non-monetary) 
        supporting both vehicles and infrastructure deployment. 
        Incentives could include purchase incentives, tax rebates, off-
        peak charging rates, preferential and/or free parking, and 
        grants for charging infrastructure installation, all designed 
        to encourage a significant penetration of electric 
        transportation solutions.
          5. Utility Fleets: Utilities pledge to develop new 
        sustainable fleet acquisition and operations plans, helping 
        drive development and significant deployment of electric 
        transportation solutions in light-, medium-and heavy-duty 
        utility applications. These efforts could include development 
        of industry-wide vehicle specifications by weight class; 
        industry-wide fuel economy requirements; fleet user education 
        programs; and industry-wide best practices, all designed to 
        help achieve a significant increase in fleet fuel efficiency 
        and a commensurate decrease in GHG and other emissions.
          Exhibit 2.--National Clean Energy Portfolio Standard
      a climate change and energy policy for the utility industry
    Climate change is of significant interest and concern to our 
customers, the states we serve and our nation. How our country deals 
with this issue is critical to achieving real environmental improvement 
while keeping electricity affordable for all consumers.
    We propose a clean energy approach through a Clean Energy Portfolio 
Standard (CEPS). A CEPS is an increasing requirement for a utility's 
energy sales to come from non-CO2-emitting generation. 
Utilities would meet a 25 percent CEPS requirement in 2025 by choosing 
from a portfolio of eligible technologies. The policy sets later 
technology targets to achieve 1990-level CO2 emissions.
CEPS
   Reduces utility CO2 emissions at low cost.
   Encourages clean technology and transforms the utility 
        industry.
   Promotes national energy security.
   Reduces natural gas consumption.
   Manages cost through flexibility and resource diversity.
   Rewards early action.
   Protects economic growth and national competitiveness.
CEPS Specifics
   10% by 2015; 17% by 2020; 25% by 2025 of energy sales.
   Post-2025, the CEPS targets are adjusted to achieve 2005 
        emissions levels by 2030, 1996 levels by 2035, and 1990 levels 
        (2 billion tons per year) by 2040.
   Compliance occurs through tradable Clean Energy Credits 
        (CECs).

    --Credit for renewable energy or ``low emission'' generating 
            facilities
    --Acquisition of CECs from national trading market
    --Purchase of ``safety valve'' CECs from Department of Energy (2.5 
            cents/kilowatt-hour (kwh), indexed for inflation)

   Early credit beginning in 2010 for renewable resources
   Three-year borrowing forward allowed
   Cost recovery for:

    --Clean energy generation or CECs
    --Ancillary costs (firming, shaping, backup) for intermittent 
            resources
    --Transmission and distribution

   State opt-out provision for excessive cost

 
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
CEPS eligible technologies and values:
         Renewable energy = 1 CEC/kwh
         Advanced fossil w/ carbon capture = 1 CEC/carbon-free
       kwh
         New nuclear = 1 CEC/kwh
         Energy efficiency/conservation investments = CECs
       awarded at safety valve price
         Carbon offsets--carbon sequestration, plant efficiency
       improvements, other offsets = 1000 CECs per ton of CO2, with
       limit at 10% of compliance
------------------------------------------------------------------------

    Exhibit 3.--Utility Renewable Energy Integration Cost Recovery 
 Mechanisms--Based upon Xcel Energy's Three Operating Companies: PSCo, 
                              NSP and SPS
    Renewable energy ``integration'' refers to those ancillary 
activities necessary to absorb increasing penetration levels of 
intermittent renewable generation while maintaining overall electric 
system stability and reliability. Integration does not include project 
costs incurred by developers of intermittent renewable energy (capital, 
O&M, etc.), but rather the additional costs of incremental electric 
production and incremental gas supply to account for the renewable 
energy on a utility system. These costs are borne by utilities through 
four primary activities: load following, unit commitment, generating 
facilities for balancing, and increased operations and maintenance 
costs for existing plants.
    These costs are variable, but studies of utilities across the 
country conclude that these costs exceed $5.00/MWh on average. Only the 
highest levels of intermittent generation requiring over 20% of retail 
sales coming from solar or wind generation would be eligible for $5.00/
MWh credit. At least 4% renewable generation would need to be achieved 
to earn $1.00/MWh credit.

          1. Load Following--this activity includes adjusting 
        generation to follow the changes in total customer demand 
        versus the variability in wind output as well as regulation of 
        the output of generation units to maintain system frequency.

          Cost Recovery: Resulting increased fuel costs are passed 
        through directly to customers through periodic fuel cost 
        adjustments. Additional load following costs resulting from 
        less than optimal system operations and higher power production 
        costs are also incurred by the customer through increased 
        electric rates.

          2. Unit Commitment--the process of determining which 
        generators should be operated each day to meet the daily demand 
        of the system including maintaining adequate reserve capacity.

          Cost Recovery: The cost of forecasting and planning for the 
        daily expected wind generation is incurred by utility customers 
        through adjustments to their electric cost of service. More 
        accurate wind forecasting will be critical to successfully 
        integrate higher levels of wind and this will increase the unit 
        commitment costs.

          3. Investments--Utilities may need new quick-start natural 
        gas generating facilities, and supporting natural gas 
        infrastructure, storage and fuel, in order to balance the 
        intermittency of renewable generation.

          Cost Recovery: Investments in generation are recovered 
        through rate increases if approved by state utility 
        commissions. If additional generation is acquired through 
        purchased power, those costs are passed through to customers 
        through periodic electric cost adjustments and base rate 
        increases.

          4. O&M--Increased O&M costs for existing coal and gas plants, 
        due to more frequent changes in operating rates to balance 
        renewable generation.

          Cost Recovery: The increased costs of O&M are borne by the 
        customer once included in approved rate increases. Increased 
        electric costs that result from purchasing electricity when 
        company owned units are out of service for maintenance are also 
        passed through to the customer. This cost can increase 
        substantially when power must be purchased to fulfill our 
        reserve requirements in addition to meeting load.
                      renewable energy tax credits
    Utility commissions set utility rates based so that the utility 
recovers the cost of operating its system plus a reasonable rate of 
return. These costs include the cost of taxes imposed on the utility; 
utility rates are set to assure that the utility can recover its tax 
liability. As a general rule, if the utility receives a tax benefit, 
such as a tax credit related to renewable energy, the value of those 
tax credits are passed through to customers.
    For example, when Xcel Energy constructed the Grand Meadow Wind 
Farm in Minnesota, it reduced its charge to customers by the value of 
the wind production tax credit (see attached, page 12). The Renewable 
Integration Credit would be subject to similar regulatory treatment.
                                 ______
                                 
      Responses of Lamar McKay to Questions From Senator Bingaman
    Question 1. I continue to hear concerns that placing a price on 
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The 
implication is that fuel-switching will result in sharp increases in 
electricity prices. Could you please give us a sense of at what carbon 
price using natural gas to generate electricity becomes comparable in 
cost to coal generation? What is the likelihood of a large-scale 
transition to natural gas, and what timeframe could that potentially 
occur on?
    Answer. The price at which natural gas competes with coal in 
electricity generation is dependent on the relative price of coal and 
gas and the relative efficiencies of the respective coal-and natural 
gas-fired power plants under consideration. For electricity dispatch 
from the existing coal generation fleet, based on a coal price of 
$40ton and using the thermal efficiency of representative US coal-and 
natural gas-fired (combined-cycle gas turbine) power plants, new 
natural gas plant capacity would be competitive with coal at prices 
around $4/Mmbtu. With a CO2 price of $20/ton, natural gas 
prices of around $6/Mmbtu would be competitive (holding all other 
factors constant).
    Any large-scale change in the nation's energy use would take 
decades to play out, given the long lead times needed to invest in new 
equipment to both produce and consume energy. Based on this, coal will 
continue to play the dominant role in US electricity generation for 
decades to come. The proposals I discussed in my testimony were more 
modest but quicker to have an impact: the incremental natural gas 
demand that could potentially deliver 10% of the carbon savings 
required by proposed legislation by 2020 are about 1 Tcf per year--less 
than the increase seen in 2008 US natural gas production alone. And 
this could be done partially by using existing natural gas-fired power 
generating capacity.
    The switching from coal-fired generation to gas provides a material 
option in the short/medium term which has the added benefit of 
contributing carbon emissions reductions while CCS technologies on both 
coal and gas are fully demonstrated. However, whether the option is 
actually realized will ultimately depend on the relationship between 
coal, gas and carbon prices, which may be different from those 
illustrated.
    Question 2. One area of concern about depending on our natural gas 
resources is that gas has been prone to strong price spikes over the 
past decade. The most recent one was just in 2008, with prices soaring 
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned 
that the expanded reserves and greater ability to receive LNG shipments 
could mitigate future price spikes. Please comment on the factors that 
resulted in the 2008 price spike and other recent spikes. Is the supply 
situation now such that we will be insulated from such volatility in 
the future? Are there policy options we could pursue to reduce price 
volatility?
    Answer. Prices for all forms of fossil fuels increased in the first 
half of 2008. Central Appalachian coal spot prices, for example, rose 
from about $58/short ton at the beginning of 2008 to $140/ton by August 
and now stand near $55/ton. (Source: US DOE/EIA) Even as natural gas 
prices in the US rose in the first half of last year, they remained 
well below oil prices (when compared on a comparable basis).
    To a large extent, these increases were due to a period of strong 
economic growth--not just in the US, but around the world--that pushed 
prices for energy and many other commodities to record levels by the 
middle of 2008. And the recession that has followed has led to lower 
prices for all forms of fossil fuels as well as many other commodities. 
So the primary driver of natural gas--and other fossil energy--price 
increases up to mid-2008 was a strong economy. In the face of strong 
demand, investment lags and government policies that constrained the 
ability of producers to respond to higher prices hindered the supply 
response, resulting in higher prices (through the middle of last year).
    As noted in my testimony, US natural gas supply has undergone a 
quiet revolution in recent years. Technological innovation has allowed 
resources previously deemed to be ``unconventional'' to play a larger 
role, with the result being that US-proved reserves of natural gas over 
the past decade have increased by 45% at a time when proved reserves of 
oil have increased by just 7%. So we now have the domestic resource 
base to grow supply substantially if demand increases--and if 
investment is permitted to occur.
    In addition, natural gas demand in the US has a much more 
pronounced seasonality to it--which has historically been a key driver 
of greater natural gas price volatility. For example, looking at the 
range of demand from month-to-month in 2008, oil consumption varied by 
18%, coal by 25%, and natural gas by a massive 87%. This is a key 
reason why unusually cold weather--or other unexpected disruptions such 
as hurricanes--can have an out-sized impact on natural gas prices. If 
natural gas consumption increased for power generation (since power 
demand tends to peak in the summer for air conditioning, rather than in 
winter), it would tend to reduce the seasonality in domestic natural 
gas demand and could therefore help to reduce seasonal price 
volatility. It would have a smoothing effect.
    Any market is uncertain--and we can never insulate ourselves 
completely from unexpected events that cause price volatility--but we 
at BP believe that government does have tools to help limit price 
volatility and to help market participants manage their exposure to 
unexpected changes in price. First, an expanded diversity of supply 
options has the potential to improve energy security and reduce price 
volatility; thus, measures to permit industry access to potential 
domestic gas resources, while developing those resources in an 
environmentally sound manner, would help. Similarly, as Energy 
Information Administration (EIA) Administrator Newell has noted, access 
to international LNG can help to limit price spikes by allowing US gas 
consumers access to global suppliers. At the same time, we should 
encourage US power producers to maintain a diverse set of power-
generating facilities, to allow a greater degree of competition between 
energy sources. Finally, regulators should allow both producers and 
consumers (including utilities) to manage short-term price risk by 
hedging in (appropriately regulated) forward markets.
    Question 3. Reducing the volatility in the price of natural gas is 
an important goal if we are to lean more heavily on this resource. For 
producers, independent generators, and utilities to enter into long-
term contracts for gas supply would seem to be one way to reduce 
pricing volatility. Could you describe your willingness to enter into 
such long-term contracts, and what obstacles may stand in the way of 
them?
    Answer. This question has long involved a chicken and egg 
discussion. The incorporation of long-term supply contracts in a fuel 
portfolio can indeed help to mitigate overall volatility, but wholesale 
market participants are often reluctant to engage in them because of 
the perceived volatility.
    Because natural gas demand is weather-sensitive in both winter and 
summer, with limited opportunity for on-site storage, it has been, and 
will likely remain, susceptible to some degree of price volatility. BP 
and other suppliers do offer hedging and risk-management services, 
however, to help ensure competitive fuel price certainty. While these 
options may not eliminate volatility, they can serve to insulate 
customers from their exposure to it. Innovative gas recovery techniques 
have significantly expanded the U.S. resource base and hopefully will 
serve to mitigate these concerns going forward. Nonetheless, the longer 
the term, the greater the market risk, and potentially the need for 
additional policy incentives to secure additional market receptivity.
    For instance, utility companies often find it prudent to rely more 
on market-indexed commodity pricing for their customers, since 
regulatory pass-through of these costs might not otherwise be assured. 
Another barrier tends to be the increased credit requirements and 
rating thresholds associated with longer-term transactions.
    Another factor contributing to shorter-term transactions is the 
reliance on fuel for limited peaking needs and power dispatch. Peaking 
units tend to buy their fuel and transportation capacity on an ``as-
needed'' basis only via interruptible transportation. Longer-term deals 
often result in the perceived sunk cost of un-used transportation 
capacity.
    Question 4. Is it your opinion that the advanced CCS bonus 
allocations in the Kerry/Boxer bill are enough to jumpstart broad 
deployment of CCS? I've noticed that only a maximum of 15% of the 
advance allocations can be given to projects that do not employ coal. 
Do you think that this will potentially restrict other industrial 
CO2 emitters from being able to deploy CCS at their 
facility? Are the CCS allocations enough, in your opinion, to 
incentivize the gas industry to try and deploy this technology? If not, 
how would you improve the CCS bonus allowance to open up the field to 
all industrial stationary source emitters?
    Answer. The Kerry/Boxer bill should provide enough financial 
incentives to help initiate and illustrate the potential of large-scale 
deployment of CCS. Under the bill, Section 780, ``Commercial Deployment 
of Carbon Capture and Permanent Sequestration Technologies,'' will 
provide an average of 90 million allowances (1 allowance = 1 metric ton 
of carbon dioxide equivalent emissions) from 2014 through 2017 for CCS 
incentives. Between 2018-2022 this will increase to an average of 240 
million allowances. These allowances are in addition to the $1 billion 
per annum provided by Section 125, ``Carbon Capture and Sequestration 
Demonstration and Deployment.'' Assuming $20/ton carbon allowance 
price, this should be sufficient funding for approximately 30 coal-
fired projects with CCS and 5-7 gas-fired projects, assuming that 15% 
of the allowances are provided for gas-fired technologies. This should 
be enough to prove the CCS concept and spur further efforts to deepen 
its application in the power sector.
    The 15% limitation for the allowance pool under Section 780 will 
limit the application to natural gas-fired power generation. Ideally, 
all power sources would compete for funding based on the lowest cost of 
abatement balanced against the overall cost to electricity consumers. 
On a carbon abatement cost basis, coal-fired CCS has the potential to 
lower emissions at lower incremental costs compared to gas-fired CCS 
($55/ton vs. $110/ton for coal and gas CCS, respectively) primarily 
because of much smaller inherent CO2 emissions by natural 
gas to begin with. However, from an overall cost per kilowatt hour, 
gas-fired CCS will cost less to the consumer ($95/MWh for coal vs. $81/
MWh for gas assuming $2/mmbtu for coal and $6/mmbtu for gas). While the 
current level of allowances could be sufficient for the gas industry, 
5-7 projects, an equal playing field in gas generation will ensure that 
both coal and gas compete in both abatement costs and overall cost to 
consumers.
    We are encouraged that Section 182, ``Advanced Natural Gas 
Technologies'' has been included in the bill. It provides funding for 
natural gas end-use technologies, and including funding for CCS 
technology for natural gas-fired power generation.
    Question 5. All of the natural gas we're discussing here today will 
come from both conventional and unconventional extraction methods. A 
major stake of the gas future sits in extracting natural gas from tight 
gas sands/shales.
    There has been some discussion here in Congress that the Safe 
Drinking Water Act exemption for hydraulic fracturing should be 
reconsidered. Do you think a repeal of this exemption would 
dramatically affect the future of natural gas extraction of these 
unconventional gas sources?
    Answer. Repealing the current exemption of hydraulic fracturing 
from being defined as underground injection under the Safe Drinking 
Water Act (SDWA) would have a dramatic negative effect on natural gas 
development in the US. The repeal would result in the permitting 
requirements of the SDWA being applied to hydraulic fracturing 
operations which would result in significant delays (up to a year) and 
preclude the highly efficient drilling/stimulation operations and 
practices necessary to access and produce unconventional resources, 
such as shale and tight sand gas, in a cost efficient manner. The 
increased costs coupled with permitting delay will raise the cost of 
developing these resources and make much of the unconventional gas 
resource uneconomic at a natural gas price the economy can afford. All 
of this will occur in an environment where the country should be using 
more natural gas to reduce greenhouse gas and other air pollutant 
emissions.
    A more appropriate approach would be for the States, who currently 
effectively oversee and manage hydraulic fracturing operations, to 
adopt other State and industry best practices into their programs. 
These might include:

          a. Well construction standards to ensure aquifer protection--
        including:

   Setting the well bore surface casing below the lowest 
        drinking water aquifer and cementing it back to surface.
   Pressure testing the casing/well head to confirm that there 
        are is no annular communication or leaks.
   Running cement bond logs to confirm that the cement is 
        bonded to the well steel casing and re-cementing any voids.

          b. Testing of drinking water wells within a \1/4\ mile radius 
        of the proposed well before drilling and again after completion 
        (hydraulic fracturing).
          c. Using lined pits and steel tanks on the surface to prevent 
        hydraulic fracturing fluids at the surface from contaminating 
        soils or groundwater.

    Question 6a. What safeguards do you currently undertake in your 
upstream gas recovery to protect ground and surface water resources 
during and after utilization of hydraulic fracturing? Do you have any 
modifications or improvements that you are planning to implement in 
this area?
    Answer. BP employs a variety of methods and practices in our 
overall operations, and during hydraulic fracturing, to protect soils, 
groundwater, and the environment. These include:

   Conducting various tests to verify well integrity.
   Where appropriate, conducting routine annular pressure 
        testing to identify any pressure build-up and verify casing and 
        well-head integrity.
   Routinely running and evaluating cement bond logs (test 
        results from the drilling process) to confirm that the cement 
        in the well is properly adhered to the well casing and that the 
        annulus is properly filled.
   Groundwater monitoring
   Protecting wellbores, pipelines and tanks to prevent 
        corrosion of equipment where appropriate.
   Using infrared camera and other optical gas imaging 
        technology to scan pipelines and identify small leaks before 
        they could become big leaks.
   Providing adequate containment for tanks and equipment
   Quickly responding to and cleaning up any spills or leaks 
        which do occur along with determining and fixing the causes.
   Using tanks for produced water handling.
   Using ``closed loop'' drilling fluid systems where 
        appropriate
   Properly constructing and lining reserve pits used for 
        handling of drilling cuttings and fluids where these are used.
   Injection disposal, in UIC permitted Class 2 wells, of 
        produced water rather than surface discharge.
   Properly handling, treating and disposing of wastes 
        generated during the development and operation of our fields 
        and facilities.

    Question 6b. In the last few years, BP has focused their company 
image on being good environmental citizens. As such, have you begun to 
apply this to your subsurface operations? More specifically, what (if 
any) technological advancements have you invested in or started to use 
in your operations, to address the issues of managing or reusing 
flowback water and the use of non-potable water for hydraulic 
fracturing fluid?
    Answer. Reducing and re-use of both flow-back (hydraulic 
fracturing) and produced fluids (water) is a priority for BP. Examples 
of activities underway:

   Reducing the amount of fresh water used during drilling and 
        hydraulic fracturing by using produced water in lieu of fresh 
        water where possible.
   Recycling/re-use of drilling and fracturing fluids.
   Active field testing of on-site water/fluid treatment 
        technologies to allow beneficial reuse of water.
   Piloting advanced technologies to reduce water usage.

    Question 6c. Additionally, several groups have been discussing the 
use of ``green frac'ing fluids''. This would imply that the frac'ing 
fluids currently being used in the industry are perhaps unsafe to the 
environment and public health. It has come to my attention that it is 
required that employees at a site are entitled to know what chemicals 
are being used in the process of fracturing, but the public is not 
entitled to the same information (more specifically, material safety 
data sheets). What are you doing to address these concerns, are you 
making your chemical data available for public inquiry? Or are you 
considering a switch to ``green frac'ing fluids''? I would hope that 
with the growing concerns around fresh water availability that the 
industry, more broadly, would routinely make this information available 
to the public (at a minimum) and start to look for other ``greener'' 
fluids for the gas extraction process.
    Answer. BP strongly supports measures to ensure that agencies and 
medical professionals have timely access to chemical products 
information to facilitate responses to and potential environmental 
incidents and medical emergencies, subject to appropriate safeguards 
for proprietary information consistent with federal laws. Operators 
presently comply with a range of federal chemical recordkeeping and 
reporting requirements, including the OSHA Hazard Communication 
Standard, and requirements under SARA Title III, and CERCLA. These 
regulations require operators to maintain plans and processes for the 
safe handling, storage and transportation of chemical products in order 
to protect employees, the general public and environmental resources. 
These regulations also contain reporting and disclosure requirements 
(including maintaining MSDS sheets for chemicals) to make chemical 
information available in a timely manner to employees, contractors and 
emergency responders.
    Regarding green fracturing fluids, BP will continue to encourage 
our hydraulic fracturing contractors to reduce the toxicity and volume 
of the chemicals used. We believe progress has been made in the past 
with this objective and will continue as we work with our contractors.
      Responses of Lamar McKay to Questions From Senator Murkowski
    Question 1. You may know that Senator Menendez and I are both on a 
bill to promote the development of natural gas vehicles. NGV advocates, 
myself included, have pointed out that natural gas as a transportation 
fuel reduces carbon emissions, offsets petroleum imports, and provides 
an economic boost here at home by using natural gas in place of 
imported petroleum. Given the recent findings concerning the increased 
availability of natural gas supplies in North America and here in the 
U.S. should we be doing more to advance the use of natural gas as a 
transportation fuel?
    Answer. BP expects compressed natural gas application in light-duty 
vehicle service will grow but be limited due to a number of factors. 
Specifically, the incremental cost of the vehicle relative to 
conventional cars and hybrids; NGV driving range being only 50-60% of a 
gasoline vehicle, reduced storage capacity in the vehicle (trunk space) 
due to use of compressed natural gas tanks, the lack of wide spread 
natural gas retail distribution infrastructure and the incremental cost 
of fuelling infrastructure to provide natural gas at the high pressures 
required for refueling.
    For these reasons, natural gas is more suitable for short range 
fleets, such as buses and delivery vehicles, which can re-fuel at a 
dedicated natural gas compression and storage facility at a central 
fleet depot. Short range urban fleets, such as buses and commercial 
delivery vans, can overcome many of the passenger NGV disadvantages due 
to this larger scale that enables efficient cost spreading and 
amortization.
    A large compressor and storage system at a depot will benefit from 
economies of scale resulting in per ``gallon'' CNG costs that are 50-
60% less expensive than those expected from residential/home units. 
Because of high vehicle miles traveled, CNG fueled fleets will realize 
fuel cost savings versus those expected from gasoline or diesel fuel 
use. However, a significant number of miles (approx. 300,000) must be 
traveled in order to recoup the infrastructure associated with NGVs.
    On an equivalent tail pipe emission basis, NGVs emit 65-70% of the 
CO2 as a conventional vehicle. However, NGVs also emit fewer 
tail pipe criteria pollutants such as CO (carbon monoxide), 
particulates and NOX.
    Question 2. Currently there are serious regulatory obstacles 
positioning in front of domestic energy development. Particularly, 
surface coal mining rules are under serious assault and offshore oil 
and gas development is facing increasing scrutiny from at least three 
different federal agencies. Can the panel speak to how we ever get to a 
point of more natural gas power plants or, for that matter, clean coal 
if, despite policies encouraging the advancement of these new and 
exciting power sources, we simply can't access and produce the basic 
resource?
    Answer. Access to domestic energy resources is fundamental to 
meeting society's energy demands while enhancing the domestic economy, 
jobs, and energy security. Congress is uniquely positioned to take a 
leadership position to ensure access to domestic resources remains 
achievable while ensuring that the appropriate and needed environmental 
safeguards are in place. While we cannot comment on the challenges that 
the coal mining industry faces, we do have ideas for actions Congress 
should take to enhance the ability of American business to access 
domestic oil and gas resources in a responsible and cost effective 
manner:

   Maintain exclusion of hydraulic fracturing stimulation from 
        the Safe Drinking Water Act permitting: The ability to 
        artificially stimulate the non traditional fuel reservoirs, 
        which are the bulk of new domestic oil and gas resource 
        potential, through fracture stimulation is critical to 
        production of oil and gas from these resources.
   Open areas excluded from leasing, such as the OCS waters, 
        for additional leasing and potential development.
   Perform regional analysis of rural and high country ozone: 
        Regional analyses of rural and high country ozone, particularly 
        in the Western US, by the EPA will inform sound policy 
        regarding the lowering of the current National Ambient Air 
        Quality standard for ozone.
   Air quality evaluation of offshore development: A 
        comprehensive air quality analysis by the EPA, with the 
        participation of relevant stakeholders, of the potential for 
        offshore development to impact onshore air quality and public 
        health prior to imposing CAA permit and control programs to 
        offshore development.
   Cost ceiling for CO2 reductions: A cost ceiling 
        per metric ton of CO2 equivalent reduction could be 
        used in the economic reasonableness analysis under the Clean 
        Air Act; Prevention of Significant Deterioration (PSD); Best 
        Available Control Technology (BACT) requirements.
   Reform the implementation of the National Environmental 
        Policy Act: Steps can be taken to bring the implementation of 
        the National Environmental Policy Act back to its original 
        purpose of informing decision making and to streamline the 
        analysis process.

    Question 3. What would be your opinion about a Low Carbon 
Electricity Standard that would allow electric utilities to use a 
variety of alternatives to reduce greenhouse gas emissions, including 
renewables, natural gas, nuclear and hydroelectric?
    Answer. BP believes pricing carbon is fundamental and has a 
preference for an economy-wide cap and trade system that, if equitably 
designed, would expose all energy sectors to a uniform carbon price. 
This approach, we believe, will deliver the most certain environmental 
outcome, at the least cost to the economy. Depending on how they are 
structured, standards, mandates and obligations are likely to imply a 
higher carbon price in sectors where they are used than in the rest of 
the economy, and a higher carbon price for some fossil fuels within 
those sectors. BP does support transitional standards for emerging low-
carbon technologies, like renewables, that have significant potential 
for future cost reduction and carbon savings, but are not yet 
commercial-scale. Such standards, and the implied higher carbon price, 
can be justified in these cases to provide transitional support for 
innovation and deployment but not permanent support for carbon 
reduction per se. Carbon reduction should be achieved through an 
economy-wide carbon price.
    Question 4. To the extent that deliverability of natural gas to 
markets has been an issue in the past, should recent improvements in 
pipeline infrastructure, as well as prospects for additional projects 
coming online, serve as any comfort to those with concerns about spikes 
in natural gas prices?
    Answer. All facets of the natural gas industry have been actively 
engaged in mitigating customer price risks. In addition to the producer 
supply activities mentioned previously, there have been significant 
pipeline and storage capacity additions in response to the resource 
additions and infrastructure constraints witnessed in recent years--and 
these investments are continuing at all levels. Natural gas inventories 
will hit a new record high before the withdrawal season begins a few 
days from now. According to the EIA, this level was made possible by 
recent capacity additions that have brought the total available 
inventories for the heating season to almost 4 Tcf.
    Completion of the eastern leg of the new Rockies Express pipeline 
in time for this winter will further extend access to less-expensive 
resources in the intermountain West that were previously out of reach 
for many. The pending Ruby pipeline will extend those benefits further 
west into northern California--and these are just two examples of the 
significant investments that are being made by the pipeline industry to 
ensure consistent and reliable service to new and existing markets.
    From a policy perspective, continuing to provide access to the most 
economic resources will be a key factor, as will regulatory willingness 
to consider and accept the initial or periodic premiums associated with 
any expansion of longer-term supply deals.
    Question 5. In your written and oral testimony, you appear to have 
a level of confidence about the U.S. resource base. Can the U.S. 
continue to be about 90% independent for its natural gas purposes?
    Answer. We are confident that the US has the resource base to 
support much higher production for decades to come. As discussed in an 
earlier answer, US proved reserves of natural gas have increased by 45% 
over the past decade--to 238 Tcf--largely due to technological advances 
that have allowed the industry to develop ``unconventional'' resources 
cost-effectively. Based on these same innovations, the Potential Gas 
Committee earlier this year revised its estimate of the US potential 
gas resource--resources in addition to the proved reserves mentioned 
earlier--up by 39%, to 1,836 Tcf.
    International natural gas markets also have been rapidly 
developing. While we support robust efforts to increase domestic 
production, it also stands to reason that US consumers could benefit by 
tapping into abundant global resources of natural gas.
    Question 6. Why do you believe natural gas can play such an 
important role in mitigating climate change when it is, in reality, 
still a fossil fuel?
    Answer. Natural gas can be a key component in mitigating GHG 
emissions. Natural gas is the cleanest burning fossil fuel in the 
energy portfolio; delivering 50% less CO2 than coal per 
kilowatt hour when used for electrical generation. Increasing the use 
of natural gas in power generation provides an affordable, efficient, 
and immediate step towards reducing CO2 emissions from the 
power generating sector today. Additionally, natural gas powered 
generation lowers emissions of NOX by 85%+; virtually 
eliminates emissions of SOX, and particulate matter; and 
eliminates mercury emissions and ash waste. These attributes make 
natural gas a key component of the US energy mix that can help mitigate 
climate change, especially within the power sector, in the most 
efficient and cost-effective way.
    Question 7. We have heard a great deal about how unless the United 
States passes one of the current cap and trade bills under 
consideration, China and other nations are going to outpace us in 
renewable energy development. But China certainly doesn't have any 
carbon laws on the books. My question is, do we truly require more 
mandates to drive us to a lower carbon economy?
    Answer. Without the appropriate policy mechanisms in place, there 
is little expectation that the economy will see significant efforts to 
reduce carbon emissions in China or the US. China does not have 
comprehensive climate legislation, but, driven by security and economic 
as well as climate objectives, China has undertaken a number of 
domestic carbon reduction initiatives, including setting renewable 
energy and energy intensity reduction targets, and is building 
institutional capacity for lower carbon technologies.
    Existing mandates here in the US, at both state and federal levels, 
focus mainly on renewable fuels and power, and vehicle efficiency. 
Renewable standards will help new low-carbon technologies become 
commercial and compete without support in the future but will make only 
a small contribution to carbon reduction today. Vehicle efficiency 
standards are very important by reducing carbon at a relatively low 
cost. However, the best and least-cost way to kick-start a move to a 
lower carbon economy is to put a price on carbon--potentially through a 
well-designed, equitable economy-wide cap and trade system, 
supplemented by efficiency mandates across a range of demand-side 
activities that do not fit within a cap and trade market.
      Responses of Lamar McKay to Questions From Senator Cantwell
    Question 1a. I think it is very important that we ensure that 
climate policy doesn't introduce unnecessary volatility into markets 
for oil and natural gas. We've seen gas prices fluctuate sharply over 
the past two years, from $5.90 up to $10.82 and then back down to 
around $3.40 where we are now. I think we all agree that this sort of 
uncertainty isn't good for energy producers or consumers.
    What do modeling results and forecasts tell us about what would 
actually happen in the real world with regard to fuel mix, energy costs 
and investment under this kind of price volatility?
    Answer. While greater price volatility--that is, greater 
uncertainty--can impact the investment decisions of both producers and 
consumers, it's important to note that investments, and therefore, 
ultimately the fuel mix tend to be based on long-term expectations--and 
long-term price expectations are considerably less volatile than spot 
prices. The equipment employed to produce and consume energy tends to 
be long-lived, and to have long lead-times.
    Accordingly, long-term relative price expectations are what really 
matters. For example, when BP considers investments, we are more 
concerned with the price of natural gas relative to other, competing 
energy sources. Both producers and consumers can limit their exposure 
to short-term price volatility through well-regulated futures markets.
    All fossil fuels and many other commodities have seen volatile spot 
prices in recent years, due in large part to an unusually strong global 
economy. Central Appalachian coal spot prices, for example, rose from 
about $58/short ton at the beginning of 2008, to $140/ton by August and 
now stand near $55/ton. (Source: US DOE/EIA)
    Question 1b. Could a well-designed price collar mitigate this sort 
of volatility?
    Answer. In principle, BP would prefer to allow markets to operate 
with minimal constraints to promote efficiency. In practice, especially 
during the early phase of operation of carbon allowance markets, when 
uncertainty is greater, measures can be used to reduce price risk of 
various kinds. However, such measures should be designed to work with 
the market, rather than against it, and can be seen as addressing three 
related, but different issues: allowance price level; volatility; and 
transparency.
    Price level.--High carbon prices can provide a powerful incentive 
for low-carbon investment, innovation and energy conservation. But if 
there is a concern about carbon prices above a certain level, or the 
effects of carbon prices on demand and price for conventional fuels, 
there are several market-compatible means of addressing the concern. 
For example, the concern can be addressed by making multiple 
alternative compliance units such as offsets available or by 
introducing extra compliance units into the market if the allowance 
price reaches a certain level. If extra units are borrowed from the 
future or compensated by purchasing international offsets (as in the 
strategic reserve) the cap does not need to be compromised. Less 
desirable, because it introduces uncertainty and compromises the 
environmental goal, the target can actually be lowered (cap raised) if 
the price goes too high. Or a buy-out price can be used, which sets a 
firm price cap and raises revenues for government, but this inhibits 
the market and also risks compromising the cap.
    In all cases in which some kind of price cap or buy-out price is 
employed, it is preferable for it to be set quite high, as a kind of 
safety valve, or it will effectively become a tax that has high 
transaction costs, and will reduce the incentive for low carbon 
investment and innovation and energy conservation.
    To guard against allowance prices falling too low, and removing the 
incentive for obligated parties to invest in carbon reduction 
activities, a floor price can also be established.
    Allowance price controls or allocation mechanisms may also be used 
to address the competitive disadvantage that occurs when domestic 
industries are competing with the same industries in countries without 
a carbon price.
    Price volatility.--Price volatility can be addressed by different 
market instruments, including banking of allowances and limited 
borrowing of allowances from future years, provided the long-term 
targets are not eroded. Further mitigation of price volatility is 
possible by linking emission trading schemes together.
    Price transparency can be achieved in several ways, ranging from 
the regular publication of allowance auction prices to a daily price 
index for allowances traded via an exchange.
    Problems of price level, volatility and transparency can all be 
reduced by good, fundamental cap and trade system design. This should 
include:

   Eventually, the widest feasible coverage across the economy
   A cap that starts high and declines slowly, to provide time 
        to adjust
   The creation of a deep and liquid market for allowances, 
        with multiple participants regularly engaged in trading. Note 
        that the free distribution of allowances to entities that are 
        not covered in the cap and trade system accomplish this goal.
   An accurate assessment of emissions from all sectors 
        included in the program to determine the baseline and 
        understand the market scope.
   An accurate assessment of the availability and cost of 
        emission reduction opportunities to reduce the risk of 
        unacceptable/surprise sustained high prices
   Allocation/compliance periods that are set to allow adequate 
        investment lead time for emission reductions to come online.

    Question 2a. In thinking about alternative approaches to climate 
change policy, one important consideration is the point of regulation, 
especially with regard to an emissions cap. Both the House and Senate 
bills propose downstream caps by regulating thousands of emitting 
entities.
    But an upstream cap for natural gas seems like it could achieve the 
same broad coverage much more simply, by regulating less than a 
thousand entities. What is the most efficient point of regulation to 
achieve broad coverage of fossil carbon for natural gas?
    Answer. The optimal point of regulation is the physical point of 
emission (i.e. where the combustion of the fossil fuel occurs), because 
information and opportunities to reduce emissions are greatest, and 
supply chain distortions smallest. Also, combining the economic signal 
with active participation in the trading scheme will provide the 
greatest catalyst for action.
    However, practicalities and transaction costs currently limit the 
number of entities that can be directly regulated. If these policy 
considerations lead to a shift in the point of regulation, it should 
still be kept as close as possible to the physical point of emission, 
subject to reducing the number of regulated entities to a manageable 
level while still preserving a liquid market with multiple 
participants. Selection of a point of regulation should also limit the 
potential for double counting or missing fuel borne emissions and not 
disrupt the supply chain.
    Using the example of emissions from the use of oil products (such 
as gasoline and diesel), this balance point is logically the fuel 
supplier, providing that liability for the emissions is not attached to 
the supplier, and the costs of the regulation continue to be borne by 
the true emitter. Key considerations in this regard will be to ensure 
that, for example, imported and domestically produced or refined fuels 
are treated in exactly equivalent ways and that an adequate supply of 
allowances will be available in the market for the supplier to meet the 
requirement at a well defined price. Moving the point of regulation any 
further upstream than is necessary is likely to magnify distortions in 
the supply chain, distort economic signals to the emitter, reduce 
incentives and opportunities for carbon abatement, and reduce the 
number of participants in the market.
    For these reasons, BP supports striking a practical balance between 
downstream and upstream regulation and would not support a move to 
upstream regulation only.
    Question 2b. Are there any problems with mixing upstream caps for 
some fossil fuels and downstream caps for others? Does an upstream cap 
on all fossil fuels help to promote a consistent, economy-wide carbon 
price signal necessary to transition to a low-carbon economy?
    Answer. The principles described in the previous answer apply 
economy-wide, so moving the point of regulation further upstream from 
the physical point of emission than is necessary for any sector is 
likely to diminish the effectiveness of the overall system. To the 
extent that commodity fuel prices and competition, both domestic and 
international, inhibit a clear carbon price signal to the decision 
making consumer, and upstream cap does not provide incentives for lower 
carbon decisions.
    For these reasons, we see no problem with hybrid downstream and 
upstream regulation, with the balance struck on pragmatic grounds.
    Question 3a. With the recent advances in drilling technology in the 
gas industry, domestic gas reserves shot up by more than 35 percent 
this year, which of course is terrific news for the gas industry and 
potentially for our efforts to address climate change by reducing 
greenhouse gas emissions.
    But I'm wondering about the broader environmental implications of 
the use of technologies such as hydraulic fracturing to produce 
unconventional shale gas resources. What are the implications of shale 
gas production for ground water and drinking water quality? How do 
these environmental risks compare to those of other energy sources?
    Answer. Hydraulic fracturing has been done for decades on 
approximately one million wells in the US with, to my knowledge, no 
case documented where contamination of groundwater was conclusively 
linked to hydraulic fracturing operations. In the very few known 
complaints of groundwater contamination made by individuals, it appears 
that the contamination occurred due to loss of well integrity from 
corroded well pipes, spills of chemicals and products at the surface, 
or leaking surface facilities (pits, tanks, piping and hoses)--
unrelated to hydraulic fracturing.
    Question 3b. Also, from an economic perspective, at what price is 
shale gas production viable for the industry? Would the price certainty 
of a carbon price floor be necessary for shale gas to be economic? How 
do the two prices--the natural gas price and the carbon price--
interrelate and affect shale gas production?
    Answer. There are a variety of industry, academic and government 
estimates for the breakeven price for shale gas production depending 
upon the particular basin (Barnett, Fayetteville, Woodford, Marcellus, 
etc.). However, most of these ranges are in the $4/mmbtu to $7/mmbtu 
range, with the average between $4 and $5/mmbtu. However, this is based 
on today's technology and today's pipeline transport and storage 
infrastructure. As both technology and infrastructure continue to 
improve, these breakeven costs could drop over time--similar to the 
decrease in development and production costs of coal-bed methane and 
tight sand gas over the last decade.
    Given the current view of shale development economics, a carbon 
price will not be required to make this exciting new source of natural 
gas available.
    Natural gas and carbon price are interrelated to the extent that a 
carbon price makes natural gas more attractive for power generation vs. 
coal. It is difficult to place any firm numerical relationships to 
carbon and gas price and the details of specific policies will affect 
the overall relationship between the two prices.
    Question 4a. Since natural gas has the lowest carbon content among 
fossil fuels, I would expect that a carbon price would not lead to a 
decline in the natural gas industry. But over the longer term, as the 
economy decarbonizes, there will be pressure on gas-fired utilities, as 
with coal-fired ones, to adopt carbon capture and sequestration 
technologies.
    What is your assessment of the feasibility of commercial scale 
carbon capture and sequestration with natural gas?
    Answer. With sustained technology development efforts, commercial 
scale carbon capture and sequestration for both coal and natural gas 
could be available for wide-scale deployment after 2020. It is more 
expensive, on a dollar per metric ton basis, to capture and sequester 
carbon from natural gas-fired power than from coal-fired power 
(primarily due to lower inherent CO2 concentration). 
However, on a total cost of electricity basis, natural gas CCS should 
be less expensive than coal with CCS. Both of these factors will play 
in to the timing of commercial scale deployment of both coal and gas-
fired CCS.
    Question 4b. Are the economics of CCS likely to be comparable for 
gas and coal consumers?
    Answer. It is more expensive, on a dollar per metric ton of 
CO2 captured basis, to capture carbon from natural gas-fired 
power than from coal-fired power. However, depending upon coal and gas 
prices, gas-fired CCS should be less expensive on a total cost of 
electricity basis. The following table shows the comparison of total 
electricity costs for gas with CCS and coal with CCS for a variety of 
gas prices:

 
------------------------------------------------------------------------
            $ per MWh                  Natural Gas Prices ($/mmbtu)
------------------------------------------------------------------------
                                     $4        $6        $8        $10
------------------------------------------------------------------------
Coal w/ CCS ($2/mmbtu cost)       95        95        95        95
------------------------------------------------------------------------
Gas w/ CCS                        67        81        96        110
------------------------------------------------------------------------

    Question 4c. Could reimbursements in the form of allowances in 
excess of the cap for the amount of carbon captured and sequestered 
make CCS economic? And would this framework treat both coal and natural 
gas fairly?
    Answer. Both the Waxman-Markey and Kerry-Boxer bills allow for a 
significant amount of domestic and international offsets. Providing 
credit from this offset pool to CCS projects on the basis of carbon 
captured and permanently sequestered could help make CCS economic, 
without increasing the cap for the entire economy. Allowing all CCS 
projects to compete for these offset credits will provide a level-
playing field for CCS incentives.
     Responses of Lamar McKay to Questions From Senator Mark Udall
    Question 1. You mentioned that the new gas shale resources would 
provide a more stable resource than traditional natural gas resources, 
thereby reducing the volatility in gas prices. Specifically you 
mentioned that gas shale is a different kind of resource and that 
geology is less of an issue. Could you please elaborate more on this?
    Answer. First, gas shale is known as a ``resource play'' in 
contrast to an ``exploration play.'' A resource play carries low 
geological risk of not finding natural gas. The limiting factor is 
economics. The application of hydraulic fracturing and horizontal 
drilling has made shale gas economically viable and now allows the US 
to tap the enormous potential of the shale basins.
    The production volumes from a shale gas well can be higher than a 
``good'' conventional well allowing a quicker response to demand. 
Evidence of this is the ability of the industry to produce record 
volumes of gas with fewer rigs. Historically, rig count served as a 
good indicator of expected gas volumes but the gas shales have changed 
this dynamic and a new index is being developed taking into account 
where rigs are drilling.
    Finally, many of the basins for shale gas are located near large 
gas markets or in areas with existing pipeline infrastructure--giving 
shale gas resources an ability to respond quickly.
    Question 2. It was mentioned that some coal utilities are already 
switching over to gas without incentive in place, could you elaborate 
on this dynamic? Does low gas price and region play any role in some of 
these changes?
    Answer. Through July of this year, net US electricity generation 
has fallen by 5.4% compared with the same period last year. (Source: US 
DOE/EIA) Electricity generated by coal has fallen by 13.1%, while 
electricity generated by natural gas has grown by 1.7%. This has been 
primarily due to lower natural gas prices relative to coal prices: 
Through July, average coal prices paid by US power generators rose by 
13% compared with the same period last year, while natural gas prices 
paid by US power generators fell by 52%. (In fact, US natural gas 
consumption has fallen in other sectors of the economy this year due to 
the recession, but has increased slightly in power generation.)
    As you note, it is important to recognize that both natural gas and 
coal prices vary widely by region. In the case of natural gas, 
transportation costs are the key driver of regional price 
differentials; in the case of coal, both transportation costs and coal 
quality vary significantly by region.
    A final factor to consider when assessing the competition between 
natural gas and coal in power generation is the efficiency of the 
respective power plants, which also varies widely.
    Question 3. Do you believe that a transparent, market price for 
carbon will help reduce volatility in the natural gas market?
    Answer. A robust, economy wide carbon price could help to reduce 
the volatility of natural gas prices by increasing and stabilizing gas 
demand for power, the more important drivers of lower volatility will 
be the game-changing gas reserves picture, significant amount of LNG 
re-gas capacity (approximately 20% of current US gas demand in next few 
years will be available) and gas pipeline and storage projects due to 
come on line in the next few years.
    A robust, economy-wide price for carbon should naturally advantage 
natural gas over coal-fired power generation. In this scenario, natural 
gas could play a greater role in providing electricity, allowing for 
different contract structures that could bring volatility in line with 
that of coal.
        Response of Lamar McKay to Question From Senator Lincoln
    Question 1. As you know, several recent studies have projected that 
our natural gas supply is much larger than previous estimates. For 
example, the Potential Gas Committee estimates that the U.S. now has a 
35% increase in supply estimates from just two years ago, which is 
enough they say to supply the U.S. market for a century. The Energy 
Information Agency (EIA) has also predicted a 99-year natural gas 
supply. I am proud that the Fayetteville Shale in Arkansas is already 
producing over one billion cubic feet of natural gas per day, while 
only in its fifth year of development. What role do you believe the 
improvement in drilling technologies such as horizontal drilling and 
hydraulic fracturing played in the estimated increase in natural gas 
supply?
    Answer. The use of horizontal drilling and hydraulic fracturing 
technologies enables the commercial production of natural gas from 
shale reservoirs. These improvements in drilling and completion 
technologies have had a substantial effect on the amount of recoverable 
natural gas in the US. Shale gas alone is responsible for approximately 
40% of the increase in US natural gas reserves. Hydraulic fracture 
stimulation of the other non-conventional gas resources (tight sands 
and coal beds) is also necessary to enable commercial natural gas 
production. Collectively, these non-conventional resource plays 
represent most of the potential future domestic gas supply for the US. 
This supply is only accessible utilizing techniques such as horizontal 
drilling and hydraulic fracturing.
      Responses of Lamar McKay to Questions From Senator Sessions
    Question 1. If the transportation sector moves towards natural gas, 
how will this affect the price of natural gas, the United States' crude 
oil imports, greenhouse gas emissions, other energy sectors that 
currently use this energy source?
    Answer. BP believes that the US has the domestic resource base to 
support much higher levels of domestic production over the next several 
decades. How that incremental supply will be used within the US economy 
is best sorted by the domestic market, which has proved efficient in 
directing gas supply to end-uses that have the highest value-added.
    To date, transportation has not been a large consumer of natural 
gas. In 2008, about one-tenth of one percent of US natural gas 
consumption was for vehicle transportation. To reduce US oil imports by 
1 million b/d (net imports were 11.1 Mb/d in 2008) would require just 
over 5 bcf/d of natural gas--or nearly 2 Tcf per year--just under 10% 
of 2008 consumption.
    By converting one half of America's commercial and municipal fleets 
(e.g. delivery services, municipal utility services, buses and 
corporate fleets) to CNG, the US could reduce oil imports by 500,000 b/
d. This would require an additional 2.5 bcf/day, or 1 Tcf/year, or 5% 
of current gas production. It would reduce US emissions by 0.5%, or 30 
Mt/year.
    Question 2. What incentives or regulatory changes are necessary to 
effectively enhance the use of natural gas over coal, diesel, or 
gasoline? And the cost associated with the switch?
    Answer. BP believes that with a level playing field and uniform 
carbon price for all fossil fuels, natural gas will be able to compete 
effectively in the power sector. In lieu of a level playing field, BP 
believes that targeted incentives to retire the least efficient coal-
fired generation are needed. With a level playing field for carbon, we 
believe the market will choose gas to replace the retired capacity 
because it offers the lowest-cost option. However, to incentivize the 
conversion to natural gas via the bonus of award of carbon allowances 
would cost approximately $5bn-$10bn over three years, assuming a $20/
ton carbon price. This conversion has the potential to reduce emissions 
by 700 million tons between 2012 and 2020, or $15/ton.
    In the transport sector, tax incentives for the conversion of 
vehicle fleets (buses, long-haul trucks) could support conversion to 
natural gas over gasoline. Targeted investments in infrastructure for 
natural gas transport may also be required to support the switch.
                                 ______
                                 
     Responses of Edward Stones to Questions From Senator Bingaman
    Question 1. I continue to hear concerns that placing a price on 
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The 
implication is that fuel-switching will result in sharp increases in 
electricity prices. Could you please give us a sense of at what carbon 
price using natural gas to generate electricity becomes comparable in 
cost to coal generation? What is the likelihood of a large-scale 
transition to natural gas, and what time frame could that potentially 
occur on?
    Answer. The price of carbon at which using natural gas to generate 
electricity becomes comparable in cost to that from coal generation 
depends on three factors:

          1) The price of natural gas
          2) The price of coal
          3) Capital costs required to maintain or build new coal power 
        plants relative to natural gas fired generation.

    Although many projections assume increases in natural gas prices, 
few project changes in coal prices. This is despite the fact that the 
most likely coal power plants to be displaced by new gas fired 
generation facilities use Appalachian coal, which has traded between 
$42/ST and $142/ST over the last eighteen months. We believe that coal 
fired power generation has been displaced by gas generation for most of 
the period since August, 2008. Said another way, during this period, 
the cost of carbon at which using natural gas to generate electricity 
was comparable or better than that from coal was zero.
    The cost of generating electricity from coal is driven to a large 
extent by the capital costs required to build and maintain highly 
capital intensive coal fired power generation plants. Dow believes the 
carbon cost which will force construction of gas fired generation 
plants in place of coal fired power plants is between $10/MT of 
CO2 and $25/MT of CO2 over the period 2015-2020. 
Testimony by Xcel Energy suggested the cost of carbon at which gas 
fired generation displaces coal is zero today, at least for the 
marginal plants, as they have shut down three coal facilities 
(producing more than a Gigawatt of electricity) and replaced them with 
natural gas fired generation. Similarly, Calpine states: ``Compared to 
many other generation sources, natural gas power plants can be 
permitted quickly and they have a much smaller footprint. In addition, 
they can be built more quickly and cost less to build on a per megawatt 
of capacity basis.''
    Given widely proclaimed attractive economics for natural gas fired 
power generation, high capital costs and uncertain costs for carbon 
mitigation from coal fired generation, we believe there is a high 
likelihood for a continued large scale transition to natural gas in the 
power generation sector. If 80 coal fired power plants were shut down 
(as advocated by other witnesses), approximately 1.8 Trillion Cubic 
Feet (TCF)/yr of additional gas demand would be created. This is but 
one third of the increase in gas for power consumption expected over 
the period 2008-2020, however. Natural gas burned for electric 
generation grew from 4.3 TCF in 1996 to 6.8 TCF in 2008 (a change of 
2.5 TCF/yr), a cumulative growth rate of 4.84)/01yr. Over the same 
period, power generation from coal increased from 1,795,000 GWH in 1996 
to 1,994,000 GWH in 2008, which would require the equivalent of almost 
1.4 TCF/yr more gas for power generation to displace. Factoring all 
three likely causes for increased gas demand for power generation (i.e. 
5.8 TCF/yr), increases in gas use for power could exceed 28% of the 
current natural gas supply by 2020. 


    Question 2a. One area of concern about depending on our natural gas 
resources is that gas has been prone to strong price spikes over the 
past decade. The most recent one was just in 2008, with prices soaring 
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned 
that the expanded reserves and greater ability to receive LNG shipments 
could mitigate future price spikes.
    Please comment on the factors that resulted in the 2008 price spike 
and other recent spikes.
    Answer. Since 1997, there have been five natural gas price spikes, 
each caused by lags between price signals and production response. The 
lag between changes in drilling and changes in production has been 
remarkably consistent, at about six months. This is the time required 
to fund drilling programs, site wells, schedule crews, drill and tie 
new wells into the grid. When the gas market is over supplied, 
producers respond by reducing drilling, leading to a reduction in 
supply. The reduction in supply eventually leads to a price spike as 
demand increases.
    Question 2b. Is the supply situation now such that we will be 
insulated from such volatility in the future?
    Answer. No. In 2009, as in 2002, 2004 and 2006, drilling has 
declined dramatically as price has fallen. After each trough, natural 
gas demand and price rise once the economy turns, signaling the 
production community to increase drilling. During the lag between the 
pricing signals and new production, only one mechanism exists to 
rebalance supply and demand: demand destruction brought about by price 
spikes.
    Some claim that the lags between price signals and drilling 
response expected for shale gas will be shorter due to the reduced 
drilling scope of shale type wells. However the latest available data 
show natural gas production peaked with the same delay from the start 
of drilling reductions as in other cycles. Clearly, the new shale gas 
production was unable to mitigate the 2008 spike, which occurred less 
than 18 months ago. LNG may mitigate very high gas price spikes, but 
only if US gas prices are higher than elsewhere in the world. During 
the 2008 spike, LNG prices in Asia and Europe were $1-2/mmbtu higher 
than in the US. As a result, LNG imports in 2008 (during the spike) 
were less than 50% of those in 2007 (when gas prices were more normal). 
The inherent lags between changes in drilling and production created 
natural gas spikes over the last ten years, and will continue to do so 
after this and every trough.
    Finally, weather shocks (be they hurricane damage, very cold 
winters, or very warm summers) will continue, and will continue to 
stress test our energy markets. Growth in supply is important, but the 
best chance for reductions in volatility lie in building a flexible 
demand sector (see below).
    Question 2c. Are there policy options we could pursue to reduce 
price volatility?
    Answer. When it comes to natural gas and climate policy, Dow favors 
policies that will avoid the demand destruction that occurs in natural 
gas price spikes, along with policies that will allow the US to use all 
of its low-carbon resources. Such policies will maintain industrial 
competitiveness.
    Dow also believes that the US needs a sustainable energy policy. 
Climate change is an important component of a sustainable energy 
policy, but it is not the only part. We have developed a list of 
specific recommendations that, if implemented, would form the basis of 
a sustainable energy policy.
    First, aggressively promote the cleanest, most reliable, and most 
affordable ``fuel''--energy efficiency. Energy efficiency is the 
consensus solution to advance energy security, reduce GHGs, and keep 
energy prices low. It is often underappreciated for its value. Of 
particular importance is improving the energy efficiency of buildings. 
Buildings are responsible for 38% of CO2 emissions, 40% of 
energy use, and 70% of electricity use. A combination of federal 
incentives and local energy efficiency building codes is needed.
    Second, increase and diversify domestic energy supplies, including 
natural gas. Nuclear energy and clean coal with carbon capture and 
sequestration (CCS) should be part of the solution, as should solar, 
wind, biomass, and other renewable energy sources. We believe a price 
on carbon will advantage natural gas, and further incentives would only 
dangerously increase inelastic demand. Therefore, Congress should not 
provide free allowances or other incentive payments for the purpose of 
promoting fuel switching from coal to natural gas in the power sector.
    An estimated 86 billion barrels of oil and 420 trillion cubic feet 
of natural gas are not being tapped. History suggests that the more we 
explore, the more we know, and the more our estimates of resources 
grow. EIA has said that ``the estimate of ultimate recovery increases 
over time for most reservoirs, the vast majority of fields, all 
regions, all countries, and the world.'' And we have the technology 
that allows us to produce both oil and natural gas in an entirely safe 
and environmentally sound manner. Any new fossil energy resources must 
be used as efficiently as possible.
    One way to maximize the transformational value of increased oil and 
gas production is to share the royalty revenue with coastal states and 
use the federal share to help fund research, development and deployment 
in such areas as energy efficiency and renewable energy. Production of 
oil and gas on federal lands has brought billions of dollars of revenue 
into state and federal treasuries. Expanding access could put billions 
of additional dollars into state and federal budgets.
    Third, act boldly on technology policy through long-term tax 
credits, and increased investment in R&D and deployment. These are 
costly but necessary to provide the certainty that the business 
community needs to spur investment. We didn't respond to Sputnik with 
half-measures. We can't afford to respond to our energy challenges with 
half-measures, either.
    Fourth, employ market mechanisms to address climate change in the 
most cost-effective way. There is a need for direct action now to slow, 
stop, and then reverse the growth of greenhouse gas levels in the 
atmosphere. We concur with the principles and recommendations of the US 
Climate Action Partnership (USCAP), of which Dow is a proud member. And 
we recognize that concerted action is needed by the rest of the world 
to adequately address this global problem. Particular attention must be 
paid to cost containment and the availability of offsets (both domestic 
and international). Also, climate policy should not penalize the use of 
fossil energy as feedstock materials to make products that are not 
intended to be used as a fuel.
    To minimize the downsides of natural gas price volatility, Congress 
should adopt policies to increase the number of elastic users of 
natural gas, and consider policies to increase US supply of natural 
gas. A resilient natural gas market would empower US manufacturers to 
create high value jobs as they did from 1983-1996, during which period 
US industrial gas use grew at an average rate of 2.7%/yr.
    Finally, the country must advance all low carbon emitting energy 
sources and ensure the availability of offsets under any cap and trade 
program. EIA modeling of the House-passed energy and climate bill 
indicate how to avoid a ``dash to gas'' in the power sector under a cap 
and trade program. New power plants using nuclear, renewable, and coal 
with associated carbon capture and sequestration (CCS) must be 
developed and deployed in a timeframe consistent with emission 
reduction requirements. Otherwise, covered entities will respond by 
increasing their use of offsets, if available and by turning to 
increased use of natural gas in lieu of coal-fired generation.
    Question 3. Is it your opinion that the advanced CCS bonus 
allocations in the Kerry/Boxer bill are enough to jumpstart broad 
deployment of CCS? I've noticed that only a maximum of 15% of the 
advance allocations can be given to projects that do not employ coal. 
Do you think that this will potentially restrict other industrial 
CO2 emitters from being able to deploy CCS at their 
facility? Are the CCS allocations enough, in your opinion, to 
incentivize the gas industry to try and deploy this technology? If not, 
how would you improve the CCS bonus allowance to open up the field to 
all industrial stationary source emitters?
    Answer. Dow supports the recommendations of the US Climate Action 
Partnership (USCAP) with respect to advancing CCS, which are listed in 
the USCAP Blueprint for Action (www.us-cap.org). Although many of these 
recommendations focus on CCS at coal-fired power plants, other 
recommendations cover CCS at industrial facilities. USCAP has not, 
however, developed a recommendation regarding the allocation of CCS 
bonus allowances between coal-fired power producers and other 
stationary sources.
    Question 4. You mentioned that you utilize natural gas as a 
chemical feedstock Will the shift towards a more gas intensive energy 
economy impact the availability of the resource for yours and others 
chemical industries? If there is a large impact to your business 
structure, is there another viable feedstock alternative for your 
chemical business?
    Answer. There are currently no other viable feedstock materials 
commercially available at the scale that our company and industry 
requires. Dow is exploring alternative feedstocks via both biochemical 
and thermochemical (gasification) routes. For example, Dow plans to 
operate a world scale polyethylene plant in Brazil using ethylene 
feedstock derived from sugar cane ethanol. In exploring possibilities 
for this feedstock in the US we found that the domestic sugar cane crop 
and more limited growing season can not support such a plant. Dow 
testified before this committee in 2007 that coal gasification could 
produce feedstocks at sufficient scale to substitute for natural gas 
liquids. However, the capital cost of such technology is prohibitive. A 
$19 Billion US chemical industry trade surplus in 1997 became a deficit 
from 2001-2007 as resources became economically unavailable for 
industry. Over this period, nearly 135,000 jobs were lost in our 
industry. If the economy becomes more gas intensive without a carefully 
considered plan to foster a resilient supply and demand balance, spikes 
will continue, our business structure will require relocation to other 
areas, and US manufacturing will continue to deteriorate. The key to 
continued manufacturing competitiveness is a well executed, 
comprehensive energy policy which addresses supply and demand, energy 
security, and environmental objectives.
    Question 5. All of the natural gas we're discussing here today will 
come from both conventional and unconventional extraction methods. A 
major stake of the gas future sits in extracting natural gas from tight 
gas sands/shales.
    There has been some discussion here in Congress that the Safe 
Drinking Water Act exemption for hydraulic fracturing should be 
reconsidered. Do you think a repeal of this exemption would 
dramatically affect the future of natural gas extraction of these 
unconventional gas sources?
    Answer. We support the environmentally sound production of domestic 
supplies of natural gas. However, history has shown that Congress has a 
proclivity for legislating policies that increase natural gas demand 
while at the same time constraining access to adequate supply. We are 
not convinced that all of the natural gas that has been identified as 
recoverable can overcome local resistance and other obstacles to full 
production of this valuable resource. This is a major reason why we 
believe that proposals to legislate incentives for increased natural 
gas demand are misguided. The key to continued manufacturing 
competitiveness is a well executed, comprehensive energy policy which 
addresses supply and demand, energy security, and environmental 
objectives.
     Responses of Edward Stones to Questions From Senator Murkowski
    Question 1. You may know that Senator Mendendez and I are both on a 
bill to promote the development of natural gas vehicles. NGV advocates, 
myself included, have pointed out that natural gas as a transportation 
fuel reduces carbon emissions, offsets petroleum imports, and provides 
an economic boost here at home by using natural gas in place of 
imported petroleum. Given the recent findings concerning the increased 
availability of natural gas supplies in North America and here in the 
U.S. should we be doing more to advance the use of natural gas as a 
transportation fuel?
    Answer. History has shown that consumption of transportation fuels 
is largely unresponsive to price inputs. As a result, the consumption 
of natural gas for vehicles will be largely unaffected when prices 
spike--potentially exacerbating shortage conditions. The key to 
continued manufacturing competitiveness is a well executed, 
comprehensive energy policy which addresses supply and demand, energy 
security, and environmental objectives.
    Dow believes there are other more prudent approaches to reduce our 
dependence on foreign sources of transportation fuel while reducing GHG 
emissions. For example, a combination of more efficient use of gasoline 
engines (higher fuel economy), and electrification of the vehicle fleet 
would be a better plan. If we built a smart electric grid which could 
optimize charging plug-in electric vehicles when power was available 
from base-load power (i.e. new clean coal or nuclear) or could take 
advantage of the wind/solar power if available, then plug-in vehicles 
could greatly reduce the reliance on oil while simultaneously reducing 
the volatility of power prices. Dow is applying its long history in 
electrochemistry in support of the development of an advanced 
automotive battery manufacturing infrastructure in the U.S. Dow and its 
Dow Kokam joint venture are beneficiaries of federal and state 
incentives to help develop this new industry. We would in effect, build 
an interruptible source of energy which could store solar/wind power in 
a usable form while not creating a huge need for additional peaking 
power. The key is the development of the advanced battery systems, a 
smart grid and the increased base-load power from coal and nuclear. In 
this scenario, we should also increase home energy efficiency, and by 
so doing would free up base-load power for plug-in hybrids.
    Question 2. Currently there are serious regulatory obstacles 
positioning in front of domestic energy development. Particularly, 
surface coal mining rules are under serious assault and offshore oil 
and gas development is facing increasing scrutiny from at least three 
different federal agencies. Can the panel speak to how we ever get to a 
point of more natural gas power plants or for that matter, clean coal 
if, despite policies encouraging the advancement of these new and 
exciting power sources, we simply can't access and produce the basic 
resource?
    Answer. It is important to note that the share of new electricity 
generation capacity from natural gas is growing. It is also true that 
CCS technologies are being developed and moving toward 
commercialization. A policy that imposes a price on carbon would hasten 
these trends.
    History has shown that Congress has a proclivity for legislating 
policies that increase natural gas demand whil at the same time 
constraining access to adequate supply. We are not convinced that all 
of the natural gas that has been identified as recoverable can overcome 
local resistance and other obstacles to full production of this 
valuable resource. This a major reason why we believe that proposals to 
legislate incentives for increased natural gas demand are misguided.
    Nonetheless, Dow believes it is important for the US to enhance its 
energy security by increasing the diversity and supply of all domestic 
energy sources. With respect to oil and gas exploration in the Outer 
Continental Shelf, Dow believes Congress can impact the domestic energy 
supply through these actions:

   Congress should not re-impose the moratoria on offshore 
        drilling, but create a statutory construct under which drilling 
        can go forward in a safe and effective manner.
   Any offshore energy access policy should be flexible enough 
        to assure that coastal views are protected and that access is 
        provided in areas expected to offer the greatest prospect for 
        productive oil and gas wells. It makes no sense to establish a 
        50-mile ban that closes off a huge natural gas held 35 miles 
        from shore.
   States should share in the revenue from offshore energy 
        production. Given the current fiscal strain on state budgets, 
        offshore oil and gas revenue sharing can be of enormous benefit 
        to state economies if used prudently.
   The granting of states the right to opt-in to offshore 
        drilling should be explored. This must be balanced against the 
        national energy security imperative and the fact that the 
        energy off our shores is federal land and the resource belongs 
        to all of the American people
   The federal share of royalty and bonus bid revenues should 
        be dedicated to promoting energy efficiency, renewable energy 
        and other low-carbon technology development.

    Question 3. What would be your opinion about a Low Carbon 
Electricity Standard that would allow electric utilities to use a 
variety of alternatives to reduce greenhouse gas emissions, including 
renewables, natural gas, nuclear and hydroelectric?
    Answer. If Congress imposes a federal portfolio standard on 
electricity utilities, then the standard should emphasize energy 
efficiency, which is the quickest, cheapest and often the easiest way 
to improve the U.S. energy situation. Therefore, any low-carbon 
electricity standard should allow energy efficiency to meet a 
significant share of the target/goal, and that the energy efficiency 
share should be beyond business as usual''.
    Questions 4 and 5a. To the extent that deliverability of natural 
gas to markets has been an issue in the past, should recent 
improvements in pipeline infrastructure, as well as prospects for 
additional projects coming online, serve as any comfort to those with 
concerns about spikes in natural gas prices? I am sensitive to the 
concept of our domestic industries losing global competitive advantage 
under a climate bill so I want to get a sense of how your realities 
play with the facts we're hearing about supply.
    Answer. In general, infrastructure limitations are not the source 
of spikes which affect the manufacturing industry. In the short term, 
improved pipeline infrastructure within the lower 48 states may help 
mitigate price disparities caused by regional shortages for gas, 
especially in Northeast consuming markets. They will do little to 
offset the cyclical nature of the gas market, however, which is 
fundamentally inherent. Since 1997, there have been five natural gas 
price spikes across all US markets, each caused by lags between price 
signals and production response. The lag between changes in drilling 
and changes in production has been remarkably consistent, at about six 
months. This is the time required to fund drilling programs, site 
wells, schedule crews, drill and tie new wells into the grid. When the 
gas market is over supplied, producers respond by reducing drilling, 
leading to a reduction in supply. The reduction in supply eventually 
leads to a price spike as demand increases.
    In the longer term, projects such as the Alaska Pipeline would 
provide a more robust energy supply to the United States, and as such, 
would help reduce concerns about natural gas spikes. Dow would support 
tangible action to bring this project on line.
    Question 5b. Do you have reason to disagree with any of the 
increased natural gas supply figures cited by the witnesses today?
    Answer. We believe that all sources of supply for the North 
American market are important, and that trends in the more traditional 
sources of natural gas, which constitute 83% of 2008 consumption, bear 
increased scrutiny.
    While we acknowledge that production of shale gas looks encouraging 
today, other plays have looked highly encouraging only to disappoint 
later. In 2008, EIA data show that gas produced from shale supplies 
less than 10% of total consumption. We share the concerns expressed in 
Dr. Newell's testimony:
    More recently, some have raised concerns about whether shale can 
continue to deliver relatively low-cost supply to domestic customers. 
Concerns expressed relate to the relative newness of the large-scale 
application of horizontal drilling and hydraulic fracturing 
technologies to shales. Shales in different parts of the country are 
not the same, and differences in techniques and technology are actively 
being developed by the industry. This creates uncertainty in assessing 
the overall resource base. Horizontal wells with fracturing to 
stimulate the flow of natural gas in shale also tend to deliver their 
greatest volumes in the first few years. This raises questions as to 
the ability of the industry to continue to drill productively over the 
long term, which is necessary to sustain higher, or even constant, 
levels of production.
    Long term, the natural gas supply for the United States will depend 
on domestic conventional and unconventional production, and imports. 
Although production from unconventional sources such as shales has been 
increasing, gas recoveries from some conventional sources have been 
declining dramatically. Marketed production from the Gulf of Mexico has 
been declining since 2001, and now is close to half the level in those 
years.
    Similarly, natural gas imports from Canada have declined 
dramatically, and YTD (through August) 2009 imports are down 15% from 
those in the same period in 2007. Imports are likely to decline further 
in 2010 and beyond as drilling in Canada has fallen dramatically and 
consumption for oil sands converters increases. Similarly, over the 
same period, LNG imports are down 50%.
    While we agree recent developments in shale gas are encouraging, we 
believe caution is warranted for the overall supply picture.
    Question 6. You have cited in your testimony serious concerns with 
the increased use of natural gas for power generation. Does that 
concern extend to increased use of natural gas as a backup source to 
renewable fuels? Does it extend to increased use of natural gas as a 
vehicle fuel?
    Answer. If electric power generation by renewable fuels with 
natural gas as a back up reduces the overall demand for natural gas, we 
are supportive of its use there.
    Dow is concerned about the implementation of plans to use natural 
gas as a vehicle fuel. Poorly executed plans might greatly increase 
demand for natural gas and could, in the absence of increased supply, 
drive up prices for manufacturers. As discussed in the testimony, price 
spikes due to sudden increases in demand due to weather events already 
occur. The use of natural gas as a vehicle fuel would likely further 
amplify natural gas volatility during weather events like cold winters, 
hot summers or supply disruptions unless concerted effort were made to 
increase the flexibility of demand from other applications (such as the 
implementation of smart grid technologies or the development of 
industrial demand based on competitive and stable natural gas pricing). 
A comprehensive policy approach must consider all sources of demand in 
the context of both normal and extreme situations to ensure the market 
is resilient to both supply and demand shocks.
    It is possible that successful development of advanced energy 
storage technology could provide a superior long term alternative to 
natural gas as a backup source for renewables. Dow envisions its work 
on advanced automotive batteries to include applications for stationary 
energy storage.
    Question 7. I understand that under the Kerry/Boxer bill, owners of 
natural gas liquids, or NGLs like propane and butane extracted from 
natural gas, are required to buy allowances as though 100% of those 
NGLs are actually combusted. In practice, however, I'm told about 50% 
of those liquids are used by petrochemical companies in the manufacture 
of things like plastics where they aren't burned, so no emissions ever 
occur. I also understand that petrochemical companies would get 
compensated in the form of free allowances for liquids used in these 
processes where there is no combustion. Is my understanding accurate?
    Answer. The Kerry Boxer bill defines a covered entity to be any 
stationary source that produces a natural gas liquid (ethane, propane, 
butane, isobutene, and natural gasoline), the combustion of which would 
emit 25,000 tons or more of carbon dioxide equivalent. These NGLs can 
and are used as a feedstock material by the chemical industry, and many 
of these NGLs are also used to produce transportation fuel. We do not 
know the percentages, but it varies by NGL. (For example, ethane is 
used almost entirely as a feedstock material for chemical companies). 
The Kerry Boxer bill provides compensatory allowances for the non-
emissive use of NGLs as a feedstock, if allowances or offset credits 
were retired for the GHGs that would have been emitted from their 
combustion.
    Question 8. If Congress were to enact legislation that somehow 
promoted natural gas use, and natural gas was available at a consistent 
$6-8 dollar per MMBtu range, how would that impact your 
competitiveness?
    Answer. US petrochemical competitiveness depends on a multitude of 
factors, such as the relative cost of energy (including crude oil, 
coal, etc.), the relative cost of new facility construction, the 
strength of the economy in each global area, and the extent to which 
local industry is protected by local government policies. In general, 
we believe that if crude were in the $75-$100 range, and natural gas 
were available at a consistent $6-$8 dollar per MMBtu range, US 
petrochemical facilities could be globally competitive. We believe the 
best way to achieve consistent natural gas pricing is to adopt a 
comprehensive policy approach which considers all sources of demand in 
the context of both normal and extreme situations to ensure the market 
is resilient to both supply and demand shocks. This presumes there are 
enough price-sensitive (demand-elastic) natural gas users to assure 
minimal volatility. We cannot effectively plan major long term 
petrochemical investments in the U.S. if the historical pattern of 
natural gas price spikes persists.
     Responses of Edward Stones to Questions From Senator Sessions
    Question 1. If the transportation sector moves towards natural gas, 
how will this affect the price of natural gas, the United States' crude 
oil imports, greenhouse gas emissions, other energy sectors that 
currently use this energy source.
    Answer. History has shown that consumption of transportation fuels 
is largely unresponsive to price inputs. As a result, the consumption 
of natural gas for vehicles will be largely unaffected when prices 
spike--potentially exacerbating shortage conditions.
    As part of the a comprehensive plan, Dow believes there are other 
more prudent approaches to reduce our dependence on foreign sources of 
transportation fuel while reducing GHG emissions. For example, a 
combination of more efficient use of gasoline engines (higher fuel 
economy), and electrification of the vehicle fleet would be a better 
plan. If we built a smart electric grid which could optimize charging 
plug-in electric vehicles when power was available from base-load power 
(i.e. new clean coal or nuclear) or could take advantage of the wind/
solar power if available, then plug-in vehicles could greatly reduce 
the reliance on oil while simultaneously reducing the volatility of 
power prices. Dow is applying its long history in electrochemistry in 
support of the development of an advanced automotive batter 
manufacturing infrastructure in the U.S. Dow and its Dow Kokam joint 
venture are beneficiaries of federal and state incentives to help 
develop this new industry. We would in effect, build an interruptible 
source of energy which could store solar/wind power in a usable form 
while not creating a huge need for additional peaking power. The key is 
the development of the advanced battery systems, a smart grid and the 
increased base-load power from coal and nuclear. In this scenario, we 
should also increase home energy efficiency, and by so doing would free 
up base-load power for plug-in hybrids.
    Question 2. What incentives or regulatory changes are necessary to 
effectively enhance the use of natural gas over coal, diesel, or 
gasoline? And the cost associated with the switch?
    Answer. We believe that current market incentives already support 
the transition of demand historically supplied by coal and diesel to 
natural gas, as evidenced by the shut down of coal fired generation 
plants described in the testimony of Xcel Energy. A price on carbon 
will also accelerate fuel switching to natural gas. As a result, we 
believe no further incentives are necessary.
    The cost of too rapid a transition to the use of natural gas in 
power generation and transportation (a ``dash to gas'') would 
dramatically increased prices and volatility for natural gas and demand 
destruction in the industrial sector, as was seen in the period 1997-
2007, when nearly 4 million US manufacturing jobs were lost.
     Responses of Edward Stones to Questions From Senator Cantwell
    Question 1. I think it is very important that we ensure that 
climate policy doesn't introduce unnecessary volatility into markets 
for oil and natural gas. We've seen gas prices fluctuate sharply over 
the past two years, from $5.90 up to $10.82 and then back down to 
around $3.40 where we are now. I think we all agree that this sort of 
uncertainty isn't good for energy producers or consumers.
    What do modeling results and forecasts tell us about what would 
actually happen in the real world with regard to fuel mix, energy costs 
and investment under this kind of price volatility?
    Could a well-designed price collar mitigate this sort of 
volatility?
    Answer. Pricing volatility increases the uncertainty of investment 
returns, and therefore, the cost of borrowing money and the required 
returns for energy projects. As a result, total investment decreases, 
fewer projects are built, and average costs for energy increase as 
demand continues to grow.
    The volatility cycle is made worse because projects with lower 
capital costs (i.e. natural gas fired power generation) but higher 
variable costs are favored over those with higher capital costs (coal 
and/or nuclear based generation) and lower variable costs. Over time, 
only gas fired generation is built, worsening the impact of weather 
events on the power market, further increasing the volatility in both 
natural gas and power markets. Consumers pay the price through more 
volatile and higher cost power and natural gas.
    Price collars can help reduce volatility, but they introduce 
significant additional costs to energy consumers which would be reduced 
if volatility were more muted, and are available to only the largest 
users. Since natural gas is a market in which daily prices are below 
the mean 80% of the time, the strike price of purchased calls (which 
protect consumers) are further from the underlying price than the 
strike price of sold puts (which potentially obligate consumers to pay 
higher than market prices). For example, on November 9th 2009, one can 
purchase a $7/mmbtu call for 2010 and sell a $4.50/mmbtu put to fund 
it. The underlying price for this period is $5.46/mmbtu, so the call is 
about $1.50/mmbtu from the expected price, whereas the put is less than 
one dollar lower. The costs to consumers are even higher if one 
considers the shape of the forward curve, which is higher over time 
(i.e. in contango). Natural gas for delivery on the morning of November 
10th cost $3.78/mmbtu at Henry Hub. So, a consumer would incur the 
obligation to purchase gas at a price $0.75/mmbtu higher than current 
cost to protect against prices rising to almost double current costs 
($7/mmbtu). Executing hedges in financial markets requires a trained 
staff to manage volatile energy market positions, significant 
accounting expertise to comply with complicated Financial Accounting 
Standard Board (FASB) requirements, and large amounts of capital to 
cover margin requirements.
    Large consumers can, and do, incur these costs to reduce volatility 
to levels at which they are able to stay in business. Smaller 
industrial, commercial and residential consumers are unable to 
participate in the financial energy markets. The best solution is to 
obviate the need for these ``Band Aid'' management tools by 
establishing a comprehensive energy policy which addresses both supply 
and demand for energy in both the short and long term, and has a 
sufficient number of price-sensitive consumers. If both energy supply 
and demand become resilient to shocks, volatility will be reduced. 
Financial instruments will become more affordable for those who need 
them and unnecessary for most.
    Question 2a. In thinking about alternative approaches to climate 
change policy, one important consideration is the point of regulation, 
especially with regard to an emissions cap. Both the House and Senate 
bills propose downstream caps by regulating thousands of emitting 
entities
    But an upstream cap for natural gas seems like it could achieve the 
same broad coverage much more simply, by regulating less than a 
thousand entities. What is the most efficient point of regulation to 
achieve broad coverage of fossil carbon for natural gas?
    Answer. Policymakers should consider several factors when 
determining the point of regulation for a program to control GHG 
emissions, including coverage, administrative complexity, equity, and 
efficiency. Dow supports the recommendations of the US Climate Action 
Partnership (USCAP) regarding the point of regulation for an economy-
wide cap and trade program: on transportation fuel providers, on Local 
Distribution Companies (LDCs) for natural gas, and on large stationary 
sources.
    Question 2b. Are there any problems with mixing upstream caps for 
some fossil fuels and downstream caps for others? Does an upstream cap 
on all fossil fuels help to promote a consistent, economy-wide carbon 
price signal necessary to transition to a low-carbon economy?
    Answer. Dow supports the USCAP recommendation of a hybrid (i.e., 
combination of upstream and downstream) point of regulation for fossil 
energy, as described previously. However, an ``upstream'' point of 
regulation runs the risk of covering fossil energy that is used in non-
emissive ways, such as a feedstock for chemical production. Dow 
believes there should not be a price signal for fossil energy used as a 
feedstock material, where the carbon is embedded in a manufactured 
product not intended for use as a fuel. Any such price signal could be 
avoided by either (1) an exemption from coverage or (2) the awarding of 
compensatory allowances.
    Question 3a. With the recent advances in drilling technology in the 
gas industry, domestic gas reserves shot up by more than 35 percent 
this year, which of course is terrific news for the gas industry and 
potentially for our efforts to address climate change by reducing 
greenhouse gas emissions.
    But I'm wondering about the broader environmental implications of 
the use of technologies such as hydraulic fracturing to produce 
unconventional shale gas resources. What are the implications of shale 
gas production for ground water and drinking water quality? How do 
these environmental risks compare to those of other energy sources?
    Answer. We support the environmentally sound production of domestic 
supplies of natural gas. We defer to others with more expertise on the 
environmental impacts of hydraulic fracturing to answers these 
questions.''
    Question 3b. Also, from an economic perspective, at what price is 
shale gas production viable for the industry? Would the price certainty 
of a carbon price floor be necessary for shale gas to be economic? How 
do the two prices--the natural gas price and the carbon price--
interrelate and affect shale gas production?
    Answer. We believe the current natural gas market dynamics suggest 
that many shale gas resources are economic at the current (or slightly 
higher) pricing levels. We are concerned that proposed policies will 
require higher cost increments be produced, and expect volatility to 
continue. In either case, we do not believe that a carbon price floor 
is necessary for shale gas resources to be economic.
    Question 4a. Since natural gas has the lowest carbon content among 
fossil fuels, I would expect that a carbon price would not lead to a 
decline in the natural gas industry. But over the longer term, as the 
economy decarbonizes, there will be pressure on gas-fired utilities, as 
with coal-fired ones, to adopt carbon capture and sequestration 
technologies.
    What is your assessment of the feasibility of commercial scale 
carbon capture and sequestration with natural gas?
    Answer. It is as feasible as commercial scale carbon capture and 
sequestration for coal. Capture will be more difficult due to the lower 
concentration of CO2 (3-4% vs. 11-12% for coal fired plants) 
in the effluent from natural gas power plant turbines. However, capture 
for natural gas will not have to deal with some of the impurities (fly 
ash, Hg, sulfur, etc.) associated with pulverized coal. Once capture is 
accomplished downstream unit operations will be similar for natural 
gas.
    Question 4b. Are the economics of CCS likely to be comparable for 
gas and coal consumers?
    Answer. Yes they are comparable. See H. de Conninck, Cost and 
Economics of CO2 Capture & Storage, ECN & Princeton, Near 
Zero Emissions Coal workshop, Beijing 2006.
    Question 4c. Could reimbursements in the form of allowances in 
excess of the cap for the amount of carbon captured and sequestered 
make CCS economic? And would this framework treat both coal and natural 
gas fairly?
    Answer. Dow supports the USCAP recommendations for deployment of 
CCS. These recommendations call for a wide variety of policies. It is 
unclear what is meant by ``allowances in excess of the cap''. If it 
means ``offset'', then Dow believes it will not be sufficient to drive 
rapid, cost-effective deployment of CCS as there are other barriers to 
CCS (see USCAP recommendations) that must also be addressed.
    Question 5a. With an upstream cap on fossil carbon, industries that 
use fossil fuels as feedstocks will see an increase in input prices. 
Does it make sense to reimburse these industries for the fossil carbon 
that they embed into their products and prevent from emission into the 
atmosphere?
    Answer. YES.
    Question 5b. Do these reimbursements in the form of allowances in 
excess of the cap make sense?
    Answer. Yes it makes sense in that the net effect (of covering 
feedstock fossil energy and providing compensatory allowances) should 
be the same as not covering feedstock fossil energy and not providing 
compensatory allowances.
       Response of Edward Stones to Question From Senator Lincoln
    Question 1. Mr. Stones, in your testimony you state that natural 
gas price spikes have contributed to manufacturing job losses, 
including a significant reduction in jobs related to the U.S. 
fertilizer production capacity. How do you believe that the fertilizer 
industry, and other industries that use natural gas as a feedstock, 
will respond to potential price increases in natural gas?
    Answer. Raising the price of energy for energy-intensive, trade-
exposed manufacturers will hurt their ability to compete against 
manufacturers in countries that do not have policies to control GHG 
emissions. History has shown that when faced with high and volatile 
domestic process, these industries shut down and/or move to countries 
with lower energy and feedstock costs. Dow is an example, wherein high 
US natural gas prices in this decade have resulted in our decision to 
preferentially invest in projects in Brazil, China, Kuwait, Saudi 
Arabia and Libya. However, if the projections of abundant U.S. natural 
gas are accurate and the gas is not forced into inelastic uses such as 
power generation and transportation, we can envision the U.S. once 
again as a preferred location for world scale petrochemical 
manufacturing investment.
    Dow believes that any climate policy that puts a price on carbon 
will need to prevent carbon leakage by energy-intensive, trade-exposed 
(EITE) manufacturers. We support a set aside of sufficient allowances 
for EITE manufacturers until there is a globally level playing field. 
Ultimately, the solution is to garner an international effort by all 
major-emitting countries to reduce GHG emissions.
     Responses of Richard Newell to Questions From Senator Bingaman
    Question 1. I continue to hear concerns that placing a price on 
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The 
implication is that fuel-switching will result in sharp increases in 
electricity prices. Could you please give us a sense of at what carbon 
price using natural gas to generate electricity becomes comparable in 
cost to coal generation? What is the likelihood of a large-scale 
transition to natural gas, and what timeframe could that potentially 
occur on?
    Answer. In our analysis of H.R. 2454, we found that in most cases 
the major compliance options were the use of international offsets and 
increased investment in low-emitting electricity generating 
technologies such as nuclear, fossil with carbon capture and storage 
(CCS) and biomass. However, we did see a large increase in projected 
natural gas use in cases where these offsets and low-emitting 
electricity generation are either unavailable or very costly.
    The attractiveness of natural gas versus coal as a fuel for 
electricity generation depends heavily on the level of future natural 
gas prices and the price of greenhouse gas emission allowances. If 
natural gas prices were approximately $5 per million Btu it would make 
sense to dispatch an existing natural gas combined cycle plant before 
an existing coal plant when the greenhouse gas allowance price reached 
a little over $30 per metric ton of CO2. However, this 
crossover point rises to around $60 with $7 natural gas prices and to 
around $100 with $10 natural gas prices. In the Reference Case in our 
analysis of H.R. 2454, natural gas prices to electricity generators are 
just over $7 per million Btu in 2020 and just over $8.30 per million 
Btu in 2030 (2007 dollars).
    Under market and policy conditions that favor displacement of 
generation from existing coal-fired plants to gas-fired generation, a 
transition could occur quite rapidly, given the potential to increase 
the supply of natural gas from unconventional resources, including 
shale resources. Existing natural gas combined-cycle power plants can 
be operated at higher utilizations rates. Experience in the first seven 
years of this decade, when nearly 142 GW of new natural gas combined 
cycle capacity was added in the United States, also suggests an ability 
to quickly add significant amounts of new gas-fired capacity.
    Question 2. One area of concern about depending on our natural gas 
resources is that gas has been prone to strong price spikes over the 
past decade. The most recent one was just in 2008, with prices soaring 
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned 
that the expanded reserves and greater ability to receive LNG shipments 
could mitigate future price spikes. Please comment on the factors that 
resulted in the 2008 price spike and other recent spikes. Is the supply 
situation now such that we will be insulated from such volatility in 
the future? Are there policy options we could pursue to reduce price 
volatility?
    Answer. The Henry Hub natural gas spot price peaked at a monthly 
average of $12.69 per million Btu in June 2008, an increase of over $5 
from the average of $7.35 in June 2007. Over the last 10 years similar 
price spikes occurred in October 2005 because of hurricanes Rita and 
Katrina, and in December 2000 and February 2003 because of very cold 
weather combined with lower-than-normal natural gas inventories.
    Physical fundamentals that contributed to higher natural gas prices 
during the first half of 2008 included relative inventories, high 
consumption, and uncertainty about future supply growth. End-of-winter 
(March 31) natural gas working inventory in 2008 was 2.1 percent below 
the 5-year (2003-07) average for that time, 22 percent below the end-
of-March level in 2007, and the lowest winter-exit level recorded since 
2004. Weekly natural gas inventories remained below their corresponding 
5-year average levels until natural gas consumption began to fall in 
August 2008. A large increase in natural gas consumption in the 
electric power sector, which was 18 percent above the 5-year average 
during the first half of 2008, was driven in part by the surge in coal 
spot prices, which more than doubled between January and July 2008. 
While the supply response to lower inventories and higher consumption 
over this period is clear in retrospect, there was tremendous 
uncertainty about the supply potential at the time-particularly for 
domestic production. Although EIA expected domestic natural gas 
production to increase in 2008, the extent of the growth in supply was 
initially underestimated.
    As noted in the Federal Regulatory Commission (FERC) 2008 State of 
the Markets report, a review of natural gas markets in 2008 is not 
complete without an analysis of financial market developments. 
According to FERC, the two key financial fundamental drivers of natural 
gas prices during the first half of 2008 were the large influx of 
passive investments into commodities and technical trading strategies 
based on trading around the prevailing market momentum. As EIA has 
noted in response to earlier inquiries from Congress, the rapid 
increase in natural gas prices during the first half of 2008 paralleled 
movements in the prices for a wide range of commodities including crude 
oil, corn, and metals. EIA's Energy and Financial Markets Initiative, 
launched in September 2009, builds upon EIA's traditional coverage of 
physical fundamentals, such as energy consumption, production, 
inventories, spare production capacity, and geopolitical risks, to also 
assess other influences such as speculation, hedging, investment and 
exchange rates, as we seek to fully understand energy price movements.
    The natural gas supply situation today is noticeably different from 
that of early 2008. Natural gas inventories at the start of the 2009-
2010 winter season were at record levels. Improved technology and 
increased efficiency have enhanced the supply capabilities and lowered 
the marginal costs for production from shale, tight gas, and coal-bed 
methane formations located in States such as Texas, Louisiana, 
Oklahoma, Pennsylvania, and Wyoming. Furthermore, while U.S. liquefied 
natural gas (LNG) import capacity utilization was below 10 percent in 
2008, LNG imports represent an additional option for increased natural 
gas supplies to the United States, particularly as new LNG supply 
projects are brought into service around the world. While periods of 
significant price volatility cannot be ruled out due to uncertainties 
associated with weather and economic growth, sustained periods of high 
prices should be mitigated by the enhanced capability to develop 
domestic supply. Price volatility would tend to be lowered by 
increasing the responsiveness of supply and demand to prices changes, 
and by dampening forces that may amplify price changes.
    Question 3. Is it your opinion that the advanced CCS bonus 
allocations in the Kerry/Boxer bill are enough to jumpstart broad 
deployment of CCS? I've noticed that only a maximum of 15% of the 
advance allocations can be given to projects that do not employ coal. 
Do you think that this will potentially restrict other industrial 
CO2 emitters from being able to deploy CCS at their 
facility? Are the CCS allocations enough, in your opinion, to 
incentivize the gas industry to try and deploy this technology? If not, 
how would you improve the CCS bonus allowance to open up the field to 
all industrial stationary source emitters?
    Answer. We have not analyzed the CCS provisions of the Kerry/Boxer 
bill and how these may accelerate or expand carbon capture at 
industrial facilities and power plants.
    A broad deployment of CCS at certain industrial facilities is 
included in the AEO 2009 reference case to supply CO2 for 
enhanced oil recovery (EOR) operations to produce crude oil. This 
activity occurs under current laws and regulations without the 
enactment of the proposed legislation, and is motivated by the current 
state of the technology and the projected level of crude oil prices. 
The cost of carbon capture is dependent on the particular industrial 
process being employed, distance from suitable EOR opportunities, 
quantity of CO2 produced, capability and willingness to 
invest in an existing or planned industrial facility and other factors. 
We are aware that a few such projects are already in operation or are 
being considered by industry, but it remain unclear as to how bonus 
allocations might incentivize additional projects.
    In our analysis of H.R. 2454, the American Clean Energy and 
Security Act of 2009, we did find that the CCS provisions could lead to 
significant investment in that technology by 2030. Approximately 69,000 
megawatts of new coal plants with CCS were projected to be built by 
2030 in our Basic Case. However, the cost and pace of development of 
commercial-scale CCS projects are very uncertain. As a result, 
alternative cases which assumed higher costs and/or limited 
availability of the technology through 2030 were also prepared. The 
total additions of coal plants with CCS through 2030 varied from 2,000 
megawatts to 69,000 megawatts in the main cases in our report. While 
some new natural gas plants with CCS were also added in our analysis of 
H.R. 2454, the additions were generally much smaller than those for 
coal-based plants. In our modeling and analysis of that legislation, we 
did not explicitly represent the CCS credit to industrial sources, but 
did find that its provisions also lead to an increase in CO2 
from industrial sources for enhanced oil recovery.
    Question 4a. ICF: ANGA Climate Policy Analysis: Has EIA had an 
opportunity to review the ICF International analysis of the policies 
proposed by ANGA ( America's Natural Gas Alliance--large independents) 
Can you provide comments for the hearing record?
    Question 4b. LNG Terminals/ Gas prices: Eight terminals (7 import 
and 1 export) are already operating on the East Coast, Gulf Coast, 
Puerto Rico and Alaska (export). Also a terminal in Mexico serving 
California markets. There are about 40 LNG terminals that are either 
before FERC or being discussed by the LNG industry for North America. 
What is EIA's estimate of how many LNG terminals will be in operation 
by 2030. If domestic gas prices spike in the future, under what 
conditions can LNG imports act as a safety valve to moderate prices?
    Answer. 4a. EIA has seen a summary presentation of the ANGA 
analysis, which does not provide sufficient detail to comment, 
particularly regarding their ANGA Gas Supply Case. EIA would need more 
information and would have to conduct its own analyses of the proposed 
policy scenarios to provide a basis for commentary on the 
reasonableness of the results.
    Answer. 4b. The LNG capacity existing and under construction is 
more than adequate to handle EIA's projected LNG import levels through 
2030. Our projections suggest that LNG terminal capacity will not be 
fully utilized as a ``baseload'' source of natural gas supply. Rather, 
imports of LNG are expected to vary with conditions in the global LNG 
market. So far, LNG import increases have not coincided with U.S. gas 
price increases, but rather with events elsewhere in the world. There 
may be future circumstances, however, where relatively high United 
States gas prices induce additional LNG volumes.
    Question 5. All of the natural gas we're discussing here today will 
come from both conventional and unconventional extraction methods. A 
major stake of the gas future sits in extracting natural gas from tight 
gas sands/shales.
    There has been some discussion here in Congress that the Safe 
Drinking Water Act exemption for hydraulic fracturing should be 
reconsidered. Do you think a repeal of this exemption would 
dramatically affect the future of natural gas extraction of these 
unconventional gas sources?
    Answer. Virtually all natural gas production from unconventional 
resources, and a significant amount of production from conventional 
resources, relies on the application of hydraulic fracturing 
techniques. The impact of a repeal of the Safe Water Drinking Act 
(SWDA) exemption for hydraulic fracturing would depend largely on the 
specific provisions of that repeal and any subsequent regulatory action 
that might be taken.
    Question 6. To your knowledge, are there any reliable ``life-cycle 
analyses'' of greenhouse gas emissions from current and anticipated 
future natural gas development in the United States? By ``life-cycle 
analyses'' I mean GHG emissions from all sources that accompany the 
exploration, development (ex., diesel exhaust from compressor 
stations), and production (ex., fugitive methane emissions from 
production activities) of natural gas resources, as well as the 
combustion of nature gas in boilers and other uses.
    Answer. In 2002, a study entitled ``Life-Cycle Assessment of 
Electricity Generation Systems and Applications for Climate Change 
Policy Analysis,'' was prepared by Paul J. Meier at the University of 
Wisconsin. This study takes into consideration the factors you mention 
above. Based on that study, when only combustion is taken into account, 
natural gas generation has 50 percent of the GHG emissions of coal. 
When the full life cycle is taken into consideration, natural gas 
generation has 60 percent of the emissions of coal. However, while EIA 
has not reviewed this study in detail, it appears that the results do 
not fully account for the thermal efficiency advantage (lower heat 
rate) of natural gas combined cycle generators relative to existing 
coal plants.
    Question 7. A recent published analysis of the life-cycle 
greenhouse gas emissions of the natural gas industry indicates that, 
``The natural gas supply chain is the second largest source of 
greenhouse gas emissions in the U.S., generating around 132 million 
tons of CO2 equivalents annually.'' (EPA ``Inventory of US 
Greenhouse Gas Emissions and Sinks: 1990-2002,'' Office of Global 
Warming, 2004, quoted in Jaramillo, et al., ``Comparative Life Cycle 
Emissions of Coal, Domestic Natural Gas, LNG, and SNG for Electricity 
Generation,'' 2007) Has EIA performed any similar analyses of life-
cycle GHG emissions from the development and use of natural gas as 
compared to coal? If so, please share such analyses with the Committee.
    Answer. EIA has not conducted a formal life-cycle analysis of 
greenhouse gas emissions from natural gas. However, the latest EIA and 
EPA data do not appear to support the quote cited in your question. For 
example, according to EIA's 2007 greenhouse gas (GHG) emissions 
inventory, total U.S. greenhouse gas emissions in 2007 were 7,282.4 
million metric tons of carbon dioxide equivalent (MMTCO2e). 
Total carbon dioxide emissions from combustion of fossil fuels were 
5,990.9 MMT in 2007, with oil, coal and natural gas accounting for 
2,579.9 MMT, 2,162.4 MMT, 1,237.0 MMT, respectively. According to EPA, 
emissions from the natural gas supply chain encompassing production 
processing, transportation, and distribution but excluding end-use 
consumption were 133,4 MMTCO2e in 2007. The natural gas 
supply chain excluding combustion is clearly a much smaller GHG 
emissions source than combustion of any of the three fossil fuels. By 
way of comparison, EPA reports that non-combustion emissions from coal 
mining were 57.6 MMTCO2e in 2007, all of which consisted of 
methane. That estimate does not include emissions from the 
transportation of coal. In 2007, coal was roughly 40 percent of total 
freight rail ton-miles in the United States. Using this share to 
allocate a portion of total freight rail fuel use to coal, coal 
transport by rail is estimated to account for an additional 17.5 MMT of 
carbon dioxide emissions, for a total of at east 75.1 MMT.
    Responses of Richard Newell to Questions From Senator Murkowski
    Question 1. You may know that Senator Menendez and I are both on a 
bill to promote the development of natural gas vehicles. NGV advocates, 
myself included, have pointed out that natural gas as a transportation 
fuel reduces carbon emissions, offsets petroleum imports, and provides 
an economic boost here at home by using natural gas in place of 
imported petroleum. Given the recent findings concerning the increased 
availability of natural gas supplies in North America and here in the 
U.S. should we be doing more to advance the use of natural gas as a 
transportation fuel?
    Answer. The EIA does not advocate policy. However, our prior 
analysis has shown that market forces alone would not be sufficient to 
increase natural gas use in the transportation sector. For light-duty 
vehicles, impediments to increased market penetration include a lack of 
natural gas vehicle (NGV) offerings by vehicle manufacturers, less 
driving range, less cargo capacity, higher vehicle costs, and an actual 
and perceived lack of refueling infrastructure. While natural gas use 
has increased significantly in transit buses, success in other heavy 
truck applications has been limited due to the reasons stated above. 
Incentives that reduce the net cost of NGVs or NGV refueling 
infrastructure to potential purchasers would tend to increase the rate 
of NGV penetration.
    Question 2. Currently there are serious regulatory obstacles 
positioning in front of domestic energy development. Particularly, 
surface coal mining rules are under serious assault and offshore oil 
and gas development is facing increasing scrutiny from at least three 
different federal agencies. Can the panel speak to how we ever get to a 
point of more natural gas power plants or., for that matter, clean coal 
if, despite policies encouraging the advancement of these new and 
exciting power sources, we simply can't access and produce the basic 
resource?
    Answer. While EIA takes no position on the appropriate regulatory 
treatment for approving the development of natural gas and coal 
resources, in EIA's projections both of these fuels play an important 
role in energy markets in the Nation for many years. In 2008, coal 
accounted for 49 percent and natural gas accounted for 21 percent of 
total electricity generation. Despite growth in the use of other fuels, 
coal and natural gas accounted for 84 percent of the increase in 
electricity generation between 1990 and 2008. Analysis of specific 
proposed limitations would be required to assess their possible 
impacts.
    Question 3. What would be your opinion about a Low Carbon 
Electricity Standard that would allow electric utilities to use a 
variety of alternatives to reduce greenhouse gas emissions, including 
renewables, natural gas, nuclear and hydroelectric?
    Answer. Without a specific proposal it is difficult to speculate on 
possible impact. A low-carbon electricity standard, like a greenhouse 
gas cap-and-trade program or carbon tax, would provide an incentive to 
electricity producers to increase their use of low-to zero-emitting 
technologies. However, an output-based low-carbon electricity standard 
might not provide as large an incentive to electricity consumers to 
invest in energy efficiency because it would generally lead to a 
smaller increase in electricity prices than would a comparable 
greenhouse gas cap-and-trade program or carbon tax.
    Question 4. To the extent that deliverability of natural gas to 
markets has been an issue in the past, should recent improvements in 
pipeline infrastructure, as well as prospects for additional projects 
coming online, serve as any comfort to those with concerns about spikes 
in natural gas prices?
    Answer. Natural gas price spikes occur for a number of reasons, one 
of which involves limitations imposed by pipeline infrastructure. 
Pipeline-induced price spikes are generally the result of insufficient 
capacity into a region experiencing particularly cold temperatures. 
Pipeline constraints tend to raise prices at the receiving end and 
lower them at the supply source to enable markets to balance.
    EIA estimates that natural gas pipeline capacity additions totaled 
approximately 45 billion cubic feet per day (Bcf/d) in 2008, roughly 
triple the amount of capacity added in 2007 and the greatest amount of 
pipeline construction activity in more than 10 years. While EIA expects 
another sizeable increase in pipeline capacity in 2009, it likely will 
be smaller than the increase recorded in 2008. Recent natural gas 
pipeline expansion has created enhanced connectivity between regions 
that have historically been net sellers, producing more than they 
consume, with those that have been net buyers of natural gas. For 
example, the Rockies Express (REX) pipeline, which provides 1.8 Bcf/d 
of transport service between Wyoming and Ohio, now offers a crucial 
outlet for previously constrained production in Wyoming, Colorado and 
Utah. As pipeline infrastructure has expanded and bottlenecks have been 
removed, regional price differentials (known as ``basis spreads'') have 
narrowed and in some eases prices have been reduced.
    However, despite the robust increase in pipeline capacity in recent 
years, temporary periods may persist when demand exceeds available 
supply in some regions due to local limitations in the pipeline 
network. This is particularly relevant for the Northeast, where peak 
winter heating demand can reach 30 Bcfld on extremely cold days 
(Northeast natural gas consumption averaged 10.9 Bcf/d during the 
summer of 2008). While pipeline infrastructure is extensive in the 
Northeast, and capacity additions continue, the regional network 
remains vulnerable to constraints that result in high prices when 
demand temporarily surges during the coldest periods in winter.
     Responses of Richard Newell to Questions From Senator Sessions
    Question 1. If the transportation sector moves towards natural gas, 
how will this affect the price of natural gas, the United States' crude 
oil imports, greenhouse gas emissions, other energy sectors that 
currently use this energy source?
    Answer. Any increase in natural gas demand would be expected to 
increase natural gas prices. Since increased natural gas use in 
transportation would likely displace petroleum, which currently 
provides 96 percent of all energy used for transportation in the United 
States, imports of petroleum would be apt to decrease. Since natural 
gas has a lower carbon content per unit of energy than oil, the direct 
effect would be to reduce greenhouse gas emissions in the 
transportation sector.
    Recent experience suggests that the electric power sector would be 
the most responsive to changes to natural gas prices, potentially 
inducing an increased use of coal, nuclear, as well as renewable 
sources. As such, the potential impact on greenhouse gas emissions in 
the electric power sector is hard to assess without a clearer 
definition of market and/or policy changes.
    Question 2. What incentives or regulatory changes are necessary to 
effectively enhance the use of natural gas over coal, diesel, or 
gasoline? And the cost associated with the switch?
    Answer. Key impediments to significant increases in natural gas use 
in the transportation sector are the lack of refueling infrastructure, 
the higher cost of natural gas vehicles (NGVs), limited vehicle 
offerings by manufacturers, reduced driving range, and reduced cargo 
capacity. Incentives that reduce the net cost of NGVs or NGV refueling 
infrastructure to potential purchasers would tend to increase the rate 
of penetration of natural gas into the transportation sector.
    EIA's previous analyses have shown that placing an implicit or 
explicit value on carbon dioxide emissions tends to dissuade the use of 
coal in the electric sector. However, such policies do not necessarily 
increase the amount of generation fueled by natural gas in the long 
term given the combination of a projected reduction in total 
electricity consumption and the possibility of increased supply from 
non-fossil generation sources such as nuclear and renewables. Energy 
and Natural Resources.
    Question 3. Could you please explain in further detail why the 
increase in natural gas and oil production off the Outer Continental 
Shelf would have no impact on the price of these commodities?
    Answer. The increase in natural gas and oil production would likely 
have a small impact on the price of these commodities. The fact that 
the production change for both crude oil and natural gas is modest and 
gradually introduced to the market over a 20-year period limits the 
price impact. For crude oil, the main factor is that the market is 
global and one for which the projected increase of 0.54 million barrels 
per day in production by 2030 from OCS areas that were under moratoria 
until late 2008 represents a 0.5 percent increase in projected global 
world oil supply. According to EIA analysis included in the Annual 
Energy Outlook 2009 (AE02009) this amount of additional supply would 
result in about a $1.33 decline in the world oil price, from $131.76 
per barrel to $130.43 per barrel (in 2007 dollars). Crude oil producers 
could also react to this level of increase by delaying the production 
of other fields that are similar in size around the world, which would 
lessen the price impact.
    For natural gas, the 0.6 trillion cubic feet increase in OCS 
production expected by 2030 in EIA's AE02009 analysis represents a 2.6 
percent increase in projected domestic gas production, resulting in a 
decline in that year's projected price of $0.21 per thousand cubic feet 
(Mcf), from $8.61 per Mcf to $8.40 per Mcf (in 2007 dollars).
     Responses of Richard Newell to Questions From Senator Cantwell
    Question 1. I think it is very important that we ensure that 
climate policy doesn't introduce unnecessary volatility into markets 
for oil and natural gas. We've seen gas prices fluctuate sharply over 
the past two years, from $5.90 up to $10.82 and then back down to 
around $3.40 where we are now. I think we all agree that this sort of 
uncertainty isn't good for energy producers or consumers.

   What do modeling results and forecasts tell us about what 
        would actually happen in the real world with regard to fuel 
        mix, energy costs and investment under this kind of price 
        volatility?
   Could a well-designed price collar mitigate this sort of 
        volatility?

    Answer. Price volatility has the effect of inducing uncertainty in 
producer and end-user investments in long-lived capital assets. In 
EIA's analysis of H.R. 2454, it is assumed that allowance prices will 
rise smoothly at the rate of return that investors would require. Our 
analysis does not address the volatility in allowance prices that might 
occur in the actual market. A well designed price collar could dampen 
the volatility in prices that might otherwise occur.
    Question 2. In thinking about alternative approaches to climate 
change policy, one important consideration is the point of regulation, 
especially with regard to an emissions cap. Both the House and Senate 
bills propose downstream caps by regulating thousands of emitting 
entities.

   But an upstream cap for natural gas seems like it could 
        achieve the same broad coverage much more simply, by regulating 
        less than a thousand entities. What is the most efficient point 
        of regulation to achieve broad coverage of fossil carbon for 
        natural gas?
   Are there any problems with mixing upstream caps for some 
        fossil fuels and downstream caps for others? Does an upstream 
        cap on all fossil fuels help to promote a consistent, economy-
        wide carbon price signal necessary to transition to a low-
        carbon economy?

    Answer. An important characteristic of any cap-and-trade system is 
how comprehensively it covers all sources of emissions. The point of 
regulation decision is generally made to ensure comprehensive coverage 
while also minimizing the number of reporting entities and the burden 
placed on them. For natural gas this can be difficult because natural 
gas can take so many paths between production wells and the end-users. 
Any single point of regulation--i.e., wellhead, re-gasification plants, 
processing plants, pipelines, or local distribution companies--would 
not be comprehensive because some portion of the natural gas consumed 
does not pass through each point. As a result, comprehensive coverage 
of natural-gas-related greenhouse gas emissions may require a mix of 
regulatory points.
    Question 3. With the recent advances in drilling technology in the 
gas industry, domestic gas reserves shot up by more than 35 percent 
this year, which of course is terrific news for the gas industry and 
potentially for our efforts to address climate change by reducing 
greenhouse gas emissions.

   But I'm wondering about the broader environmental 
        implications of the use of technologies such as hydraulic 
        fracturing to produce unconventional shale gas resources. What 
        are the implications of shale gas production for ground water 
        and drinking water quality? How do these environmental risks 
        compare to those of other energy sources?
   Also, from an economic perspective, at what price is shale 
        gas production viable for the industry? Would the price 
        certainty of a carbon price floor be necessary for shale gas to 
        be economic? How do the two prices--the natural gas price and 
        the carbon price--interrelate and affect shale gas production?

    Answer. In June of 2009, the Potential Gas Committee (PGC) 
estimated that, as of the end of 2008, the total natural gas resource 
base of the United States was 2,074 trillion cubic feet (Tcf)--35 
percent more than the PGC had estimated as recently as 2006. EIA has 
reported that end-of-year proved reserves of natural gas not only 
covered production, but increased 13 percent in 2007 and a further 3 
percent in 2008, largely as a result of the recognition of shale gas 
resources. Proved reserves are a relatively small subset of the 
ultimately recoverable resource base. They are those volumes of natural 
gas that geological and engineering data demonstrate with reasonable 
certainty to be recoverable in future years from known reservoirs under 
existing economic and operating conditions. Technically recoverable 
resources are less certain, can be uneconomic, and include estimates of 
undiscovered volumes.
    Extraction and use of any energy source involves local 
environmental concerns. For natural gas from shale, these concerns have 
centered primarily on water.
    Observers have raised several water issues related to hydraulic 
fracturing:

   fracturing fluids might enter ground water and fresh water 
        aquifers from a well bore during the hydraulic fracturing 
        operation itself;
   waste water might enter ground water because of improper 
        treatment and release of fluids that return up the well bore 
        after the treatment; and
   the volume of water drawn for the treatment might stress an 
        area's resources, or the returned waste water overwhelm local 
        water treatment capabilities.

    Leakage directly from the fractured shale into groundwater is 
unlikely. The major shale gas plays range in depth from 5,000 feet to 
13,000 feet. Most fresh water aquifers lie at much shallower depths--
typically, less than 1,000 feet. It is unlikely that hydraulic 
fracturing of shale would force fracturing fluids through thousands of 
feet of rock up into a fresh water aquifer.
    Leakage is possible if a well's integrity were compromised through 
a variety of mechanisms, including casing leaks, tubing leaks, 
insufficient cementing, or surface casing set too shallow, in which 
case fluids could circulate up the outside of the casing and into an 
aquifer (or other groundwater formations). Operators can minimize these 
risks through inspection and testing of the well and downhole equipment 
before high-pressure pumping of the fracturing treatment begins. Under 
current law, State and local authorities manage the likelihood of such 
incidents through regulation and enforcement of well construction, 
including the casing and cementing program.
    After operators finish a fracturing job on a well, some of the 
injected fluid flows back to the surface. This returned fluid, though 
mainly water and sand, includes small amounts of added chemicals 
(typically less than 1 percent of the total volume) and can include 
contaminants leached from the shale formation. Operators can address 
wastewater problems in several ways: by treating and recycling produced 
fracturing fluids for use in other fracturing treatments, by injecting 
this wastewater into deep underground disposal wells, or by 
sufficiently treating the wastewater making it suitable for release 
back into the natural environment. Where central treatment or disposal 
facilities do not have the capacity to deal with large volumes, 
operators can and do use mobile treatment and recycling systems. 
Nonetheless, surface spills are possible through careless handling of 
materials and equipment, poorly trained personnel, and poorly 
maintained equipment. Operators generally have an incentive to avoid 
such spills, which can be costly.
    With regard to the second part of the question, development of 
natural gas from shales through horizontal drilling and hydraulic 
fracturing is still a relatively new technological development, and 
each shale play in the United States has different individual 
characteristics. Few shale plays (other than the Barnett in Texas) have 
seen substantial development, so the price at which shale development 
will be economically viable in a given shale play is extremely 
difficult to assess with any degree of confidence.
    That said, prevailing prices in 2009, which dropped at the Henry 
Hub in Louisiana below $5 per million British thermal units (MMBtu) 
early in the year and averaged only about $4, did have significant 
effects on drilling although they did not impact shale plays to the 
same degree. Our most recent review of the available literature 
regarding breakeven costs for major U.S. natural gas shale plays shows 
a range from the relatively lower-cost Haynesville play (about $3 to a 
little over $4 per MMBtu) to the relatively high-cost Woodford shale (a 
little over $4 to about $7 per MMBtu). The well-developed Barnett play, 
and the Fayetteville play, range from about $4 to about $5 per MMBtu 
and the Marcellus play in the Northeast is at a little below $4 per 
MMbtu. These estimates, collated from Deutsche Bank, Ross Smith Energy 
Group, Bentek Energy Consulting, and Range Resources do not necessarily 
reflect the same assumptions about ultimately recoverable reserves, up-
front capital cost, or return on investment. Furthermore, financial 
factors such as hedging could allow producers to lock in a rate of 
return and maintain production activities even if prices fall.
    From a technology-application perspective, as a play develops, 
costs tend to decline and well performance tends to increase as 
companies figure out what works and what doesn't in that particular 
play. This would suggest a lower economically viable price. On the 
other hand, the initial wells reported in the literature will tend to 
be drilled on the best prospects or in the best areas, and so the gas 
price required for economic viability could ultimately be higher for 
the average well in the play. There often is a significant economic 
difference between the core and non-core areas of any natural gas play.
    Shale gas price and carbon prices are likely to be interrelated to 
the extent that natural gas can be used in combined-cycle power plants, 
which benefit from improved efficiency and reduced CO2 
emissions when compared to coal-fired power plants. Significant carbon 
prices are likely to discourage the use of coal for electric power 
generation. The availability of domestic shale gas resources, combined 
with significant carbon prices, could encourage the use of natural gas 
as a substitute for coal, especially if renewables, nuclear power, 
carbon capture and sequestration, and offsets are either too costly or 
otherwise unavailable for use to comply with a cap and trade program.
    Question 4. Since natural gas has the lowest carbon content among 
fossil fuels, I would expect that a carbon price would not lead to a 
decline in the natural gas industry. But over the longer term, as the 
economy decarbonizes, there will be pressure on gas-fired utilities, as 
with coal-fired ones, to adopt carbon capture and sequestration 
technologies.

   What is your assessment of the feasibility of commercial 
        scale carbon capture and sequestration with natural gas?
   Are the economics of CCS likely to be comparable for gas and 
        coal consumers?
   Could reimbursements in the form of allowances in excess of 
        the cap for the amount of carbon captured and sequestered make 
        CCS economic? And would this framework treat both coal and 
        natural gas fairly?

    Answer. In our analysis of H.R. 2454, we found that in most cases 
the major compliance options were the use of international offsets and 
increased investment in low-or zero-emitting electricity generating 
technologies like nuclear, fossil with carbon capture and storage 
(CCS), and biomass. However, if these options were less available than 
expected we did see a large increase in natural gas use. The reason 
that we did not project a large increase in natural gas use in most 
analysis cases is that it generally takes a fairly significant 
greenhouse gas allowance price to make that attractive, and other 
options can become economical at a lower allowance price. The 
attractiveness of natural gas versus coal depends heavily on what 
happens to future natural gas prices. We find that if natural gas 
prices were approximately $5 per million Btu it would make sense to 
dispatch a natural gas combined-cycle plant before a coal plant when 
the greenhouse gas allowance price reached a little over $30 per metric 
ton of CO2. However, this crossover point rises to around 
$60 with $7 natural gas prices and to around $100 with $10 natural gas 
prices. In the Reference Case in our analysis of H.R. 2454, natural gas 
prices to electricity generators are just over $7.00 per million Btu in 
2020 and just over $8.30 per million Btu in 2030 (2007 dollars).
    While we have not analyzed the CCS provisions of the Kerry/Boxer 
bill, in our analysis of the H.R. 2454 we did find that the CCS 
provisions could lead to significant investment in the technology by 
2030. Approximately 69,000 megawatts of new coal plants with CCS were 
projected to be built by 2030 in our Basic Case. However, the cost and 
pace of development of commercial scale CCS projects are very 
uncertain. As a result, alternative cases which assumed higher costs 
and/or limited availability of the technology through 2030 were also 
prepared. The total additions of coal plants with CCS through 2030 
varied from 2,000 megawatts to 69,000 megawatts in the main cases in 
our report. While some new natural gas plants with CCS were also added 
in our analysis of H.R. 2454, the additions were generally much smaller 
than those for coal-based plants because of the higher price of natural 
gas relative to coal.
    Question 5. I was intrigued that a price on carbon did not 
necessarily result in fuel switching from coal to natural gas. When the 
carbon price is high due to limited availability of offsets for 
example, however, EIA projects substantial fuel switching.

   Are there factors, other than international offset 
        availability, that can lead to similar fuel switching?
   If the cap were to decline at a substantially slower rate 
        than the House-passed bill initially, would such a policy 
        provide sufficient lead time to avoid or mitigate such a risk 
        of rapid fuel switching and premature retirement of existing 
        power plants in the near term?

    Answer. As noted in the previous answer, the attractiveness of 
natural gas versus coal depends heavily on future natural gas prices. 
We find that if natural gas prices were approximately $5 per million 
Btu it would make sense to dispatch a natural gas combined-cycle plant 
before a coal plant when the greenhouse gas allowance price reached a 
little over $30 per metric ton of CO2. However, this 
crossover point rises to around $60 with $7 natural gas prices and to 
around $100 with $10 natural gas prices. In the Reference Case in our 
analysis of H.R. 2454, natural gas prices to electricity generators are 
just over $7.00 per million Btu in 2020 and just over $8.30 per million 
Btu in 2030 (2007 dollars).
    Since fossil fuels account for virtually all of the greenhouse gas 
emissions in the electric power sector, the emissions reductions in the 
House bill cannot be achieved without substantial switching to low-or 
zero-carbon options such as nuclear and renewables. Taking account of 
differences in the carbon content of coal and natural gas and the 
greater efficiency of modern gas-fired generators, the emission rate 
for natural gas is about 40 percent of the corresponding rate for coal 
so the potential emissions reductions due to switching from coal to 
natural gas are not sufficient to meet the specified long term caps. 
Furthermore, the carbon prices add considerably to the cost of all 
fossil-fired generation so that these plants are less economic compared 
to nuclear and renewables. However, a slower emissions cap trajectory 
would decrease the required emissions reductions in the near term and 
likely necessitate fewer retirements of existing plants and less 
switching out of fossil fuels during that initial period. The higher 
caps during that period would also decrease the corresponding carbon 
prices and lessen the impact on the generation costs for fossil-fuel 
capacity. EIA, however, has not evaluated any scenarios that assumed 
differing levels of greenhouse gas caps than those specified in the 
legislation.
      Response of Richard Newell to Question From Senator Lincoln
    Question 1. According to your testimony, the EIA estimated that 
about 1/3rd of the natural gas consumed in 2007 was used for electric 
power generation, 1/3rd for industrial purposes and the remaining 1/3rd 
in residential and commercial buildings. However, only a small portion 
is used in the transportation sector, predominantly at compressor 
stations, although some is used for vehicles. How do you view the use 
of natural gas in our transportation sector changing or increasing in 
the future, particularly with heavy duty or fleet vehicles?
    Answer. The AE02009 projects modest growth in natural gas use in 
highway vehicles, increasing from 0.02 quadrillion Btu in 2007 to 0.08 
quadrillion Btu in 2030. The majority of this growth occurs in heavy-
duty vehicles, but incremental vehicles costs, lack of retail refueling 
infrastructure, and costs associated with installation of on-site 
natural gas refueling impede significant gains in market share. Without 
significant increases in natural gas refueling infrastructure and 
reductions in incremental vehicle costs, market penetration will likely 
be limited to fleet applications where the economic benefits of natural 
gas can be captured by owners, or to fleet applications legislatively 
required to use alternative fuels like natural gas.
     Response of Richard Newell to Question From Senator Mark Udall
    Question 1. It was mentioned that some coal utilities are already 
switching over to gas without incentive in place, could you elaborate 
on this dynamic? Does low gas price and region play any role in some of 
these changes?
    Answer. The key factor in recent fuel switching from coal to 
natural gas has been the dramatic fall in natural gas prices that has 
occurred during the economic downturn as industrial demand for natural 
gas has fallen. For a brief time in recent months, average spot natural 
gas prices actually fell below $3 per thousand cubic feet. At these 
prices, modern natural gas combined-cycle plants can operate at a lower 
cost than many coal plants. However, since natural gas prices to 
electricity generators are projected to exceed $5 per million Btu in 
2010 and reach just over $7 per million Btu in 2020 and just over $8.30 
per million Btu in 2030 (2007 dollars) in our latest Reference Case, we 
expect that it will soon become cheaper to dispatch coal plants ahead 
of combined-cycle plants fueled with natural gas when both types of 
units are available for use.
                              Appendix II

              Additional Material Submitted for the Record

                              ----------                              

     Statement of the Interstate Natural Gas Association of America
    Mr. Chairman and Members of the Committee: The Interstate Natural 
Gas Association of America (INGAA) asks that this written testimony be 
included in the record of the hearing held on October 28th, 2009. The 
members of INGAA appreciate the Committee conducting a hearing on 
natural gas and its role in reducing greenhouse gas emissions. As the 
Senate develops climate change policy, we ask that the Committee keep 
in mind that natural gas is available now, and will be available in the 
coming decades, in sufficient quantity to play a major role in reducing 
greenhouse gas emissions in the Unites States.
    Mr. Chairman, INGAA represents the interstate and interprovincial 
natural gas pipeline companies in North America. Our members operate 
approximately 220,000 miles of large-diameter, natural gas transmission 
pipeline in the U.S. alone. This infrastructure continues to grow, 
especially in response to recent development of supplies of 
unconventional natural gas. According to the Energy Information 
Administration (EIA), almost 4,000 miles of new natural gas 
transmission pipeline was completed in 2008--a level of construction 
that EIA has called ``exceptional.'' Much has been said about the 
dramatic increase in natural gas supply in recent years. It is also 
worth noting that natural gas infrastructure, especially new gas 
transmission pipeline capacity, has increased dramatically as well.
    Given the prospects for continued growth in unconventional natural 
gas supply (principally, shale gas), INGAA believes that billions of 
dollars in additional investment in pipeline, storage and other 
midstream infrastructure will be required through 2030. The INGAA 
Foundation recently released a study, Natural Gas Pipeline and Storage 
Infrastructure Projections Through 2030, which uses multiple market 
scenarios to estimate the range of infrastructure investment that will 
be needed in coming decades. The key findings of this report include:

   A range of between $133 and $210 billion will need to be 
        invested in midstream natural gas infrastructure over the next 
        20 years (between $6 and $10 billion annually), primarily to 
        attach increased domestic natural gas production from 
        unconventional shale basins and tight sands to the existing 
        pipeline network.
   The U.S. and Canada will need to construct between 
        approximately 29,000 and 62,000 miles of additional natural gas 
        transmission pipelines, and between 370 and 600 billion cubic 
        feet (Bcf) of additional storage capacity.
   In the Base Case projection, annual natural gas consumption 
        in the U.S. and Canada is projected to grow from about 26.8 
        trillion cubic feet (Tcf) in 2008 to 31.8 Tcf by 2030, which 
        equates to total market growth of 18 percent, or an annual 
        growth rate of 0.8 percent. The two alternative cases, High Gas 
        Growth and Low Electric Load Growth, bracket reasonable ranges 
        of future natural gas consumption.
   About three-fourths of the market growth will occur in the 
        power sector. The growth rate of natural gas consumption in the 
        electric generation sector is the predominant determinate of 
        the growth rate of the entire natural gas market. Electric load 
        growth, the timing and development of renewable generation 
        technologies, the deployment of clean coal with carbon capture 
        and storage, and the expansion of nuclear generation are areas 
        of uncertainty.
   Interregional transmission pipeline capacity between major 
        areas in the U.S. and Canada currently is approximately 130 Bcf 
        per day. By 2030, the need for interregional natural gas 
        transport is likely to increase by between 21 and 37 Bcf per 
        day, which will drive the development of additional pipeline 
        and storage capacity. Interregional natural gas transport 
        capacity will be needed even without a growing North American 
        natural gas market due to shifts in the location of natural gas 
        production. The need for laterals to access new production and 
        deliver natural gas to new customers, such as new gas-fired 
        power plants, also will drive investment.

    The record of natural gas supply AND infrastructure development in 
recent years provide a strong foundation for policymakers to move 
beyond to old assumptions about natural gas. Today, natural gas is 
domestically abundant, reliable and cost effective. The pipeline 
industry continues to attract billions of dollars in private capital to 
expand infrastructure, due in large part to the stable regulatory 
environment for natural gas pipelines. The Federal Energy Regulatory 
Commission process for reviewing, approving and siting natural gas 
infrastructure generally works well in supporting the construction of 
necessary infrastructure on a timely basis. The ability to develop 
natural gas infrastructure on a timely and efficient basis reduces 
natural gas price volatility and creates additional competitive 
opportunities for natural gas consumers. In short, the natural gas 
model works well for the nation. And given its environmental attributes 
as the cleanest fossil fuel, natural gas can and should play a larger 
role in achieving compliance with climate change mandates than is 
suggested by the economic modeling of the climate bills introduced to 
date.
    Two issues regarding natural gas pipelines and climate change 
legislation bears specific mention to this Committee:

          First, both S. 1733 (the Clean Energy, Jobs and American 
        Power Act) and H.R. 2454 (the American Clean Energy and 
        Security Act, as passed by the House) define FERC-
        jurisdictional interstate natural gas pipelines as regulated 
        industrial entities, and therefore require pipelines to 
        purchase emission allowances and incur other compliance costs. 
        These pipelines, however, would be the only regulated 
        industrial entities that could not unilaterally adjust the 
        price of their product or service to reflect the cost of 
        compliance. Instead, these pipelines must seek approval from 
        the Federal Energy Regulatory Commission (FERC) to recover such 
        costs in the rates charged for pipeline transportation service. 
        Traditional rate case proceedings are ill-suited to addressing 
        these costs, because such costs are likely to be unpredictable 
        and are likely to vary from year to year. In addition, 
        pipelines will be price takers in the allowance market and will 
        have little practical ability to control the magnitude of such 
        costs. What's more, the current market environment for pipeline 
        transportation service has been one in which many pipelines and 
        their customers have negotiated rates or settlements wherein 
        the pipeline has contractually agreed not to seek a rate 
        adjustment for years into the future. In fact, many of the new 
        pipelines built to transport unconventional natural gas 
        production to consumers are premised on negotiated rate 
        contracts with terms that last a decade or more. This 
        legislation would add a significant new cost that was not 
        anticipated when such contracts were entered. Yet, if these 
        compliance costs cannot be recovered by the pipelines, their 
        ability to meet investor expectations and attract capital in 
        the future would be negatively impacted.
          INGAA urges the Congress to clarify this situation by 
        directing the FERC to create a rate ``tracker'' that would 
        allow pipelines to recover the costs associated with a cap-and-
        trade program, notwithstanding current contractual 
        arrangements. Without such a tracker mechanism, many pipelines 
        could face financial stress not of their own making, as a 
        result of a change in national policy. This would be an 
        unintended consequence that requires Congressional action as 
        climate change legislation moves forward.
          Second, INGAA members operate pipeline systems that span 
        multiple states and often multiple regions of the country. A 
        hodge-podge of state or regional greenhouse gas regulations 
        would undermine the cost-effective management of these pipeline 
        systems and ignores the inherently interstate nature of our 
        facilities and this commerce. To provide an effective response 
        to what is, after all, a global issue, INGAA believes that 
        federal climate change policy must preempt state and regional 
        cap-and-trade systems, greenhouse gas reporting requirements, 
        and greenhouse gas reduction performance standards. S. 1733, 
        unfortunately, goes in the wrong direction by encouraging 
        states to develop their own greenhouse gas programs and 
        regulations. INGAA hopes that you will support a federal 
        response that includes clear federal preemption of duplicative 
        state regulations and that also supersedes any inconsistent 
        regulations adopted pursuant to other federal statutes.

    Mr. Chairman, thank you for the opportunity to submit written 
comments on this important set of issues. Please let us know if you 
have any questions.
                                 ______
                                 
            Statement of the American Public Gas Association
    The American Public Gas Association (APGA) appreciates this 
opportunity to submit testimony and commends the Committee for holding 
this important hearing on the role of natural gas in mitigating climate 
change.
    APGA is the national association for publicly-owned natural gas 
distribution systems. There are approximately 1,000 public gas systems 
in 36 states and over 720 of these systems are APGA members. Publicly-
owned gas systems are not-for-profit, retail distribution entities 
owned by, and accountable to, the citizens they serve. They include 
municipal gas distribution systems, public utility districts, county 
districts, and other public agencies that have natural gas distribution 
facilities.
    APGA remains extremely concerned in regard to the potential impacts 
climate change legislation will have on public gas systems. Climate 
change legislation will certainly have a significant impact upon the 
natural gas industry as well as on the price of natural gas.
    Natural gas is the cleanest, safest, and most useful of all fossil 
fuels. It is also domestically produced, abundant and reliable. The 
inherent cleanliness of natural gas compared to other fossil fuels, a 
growing domestic supply and superior wells-to-wheels efficiency of 
natural gas equipment, means that substituting gas for the other fuels 
will reduce the emissions of the air pollutants that produce smog, acid 
rain and exacerbate the ``greenhouse'' effect. For these reasons, it is 
logical to assume that natural gas will play a critical role in the 
reduction in greenhouse gas emissions.
    Natural gas is the lowest CO2 emission source per BTU 
delivered of any fossil fuel. National policy should facilitate the use 
of natural gas instead of other more carbon-intensive fuels where 
appropriate. For example, using gas-fired water heaters for homes 
instead of electric resistance water heaters ultimately reduces 
greenhouse gas emissions by one-half to two thirds. Simply put, 
increasing the direct-use of natural gas is the surest, quickest and 
most cost-effective avenue to achieve significant reductions in 
greenhouse gases and therefore should be a critical component of any 
climate change legislation.
    In June, 2009 APGA, the Interstate Natural Gas Association of 
America and others released a study conducted by the Gas Technology 
Institute (GTI) entitled ``Validation of Direct Natural Gas Use to 
Reduce CO2 Emissions''. A copy of the study is attached to 
this testimony. The study analyzed the benefits of increased direct use 
of natural gas as a cost-effective means to increase full fuel cycle 
energy efficiency and reduce greenhouse gas emissions. Using the 
National Energy Modeling System (NEMS), the study concluded that the 
increased direct use of natural gas will reduce primary energy 
consumption, consumer energy costs, and national CO2 
emissions. A win-win-win for U.S. environmental and energy policy.
    The study demonstrated, among other things, that using revenues 
such as allowances from a cap-and-trade program to provide incentives 
for original natural gas end-use applications and conversions to 
natural gas appliances from their electric counterparts will provide 
substantially higher and immediate return values in energy efficiency 
and carbon output reductions than an equal investment in electric 
applications. Another finding of the study was that subsidies provided 
to increase the direct use of natural gas, together with increased 
efforts in consumer education and R&D funding, would provide the 
following benefits by 2030:

   1.9 Quads energy savings per year;
   96 million metric tons CO2 emission reduction per 
        year;
   $213 billion cumulative consumer savings;
   200,000 GWh electricity savings per year; and
   50 GW cumulative power generation capacity additions 
        avoided, with avoided capital expenditures of $110 billion at 
        $2,200/kW.

    Unfortunately, APGA is concerned that over the years federal 
policies have moved toward an all-electric society and have not 
recognized the benefits of the direct-use of natural gas. One example 
of this can be found in the manner in which the Department of Energy 
(DOE) calculates appliance efficiency. The DOE measurement takes into 
account energy solely consumed at the ``site'', measuring the energy 
used by the product itself.
    The site-based measurement of energy consumption ignores the energy 
spent in production, generation, transmission and distribution. For 
example, according to DOE's point of use consumer disclosure labels for 
appliances, an electric water heater may appear to consumers to be over 
60% more efficient than a gas water heater despite the fact that 
current national generation, transmission and distribution efficiency 
for central station electricity is, according to the U.S. Energy 
Information Agency, only 29.3% efficient while the transmission and 
distribution of natural gas directly to the consumer is 90.1% 
efficient. Ignoring these energy losses makes electric-resistance 
heating appliances appear more efficient (allowing them to receive a 
superior DOE efficiency rating).
    This site-based measurement has placed natural gas appliances at an 
unfair marketing disadvantage and as a result there has been a marked 
increase in shipments of electric water heaters and a decrease in 
shipments of natural gas water heaters. This increase in electric water 
heaters will come with an increase in greenhouse gas emissions given 
that electric water heaters emit 2.5 times the amount of greenhouse gas 
emissions as natural gas water heaters given the current make up of the 
sources of U.S. electric generation today. Renewable energy generation 
is poised to grow in the future, but makes up less than 2% (excluding 
hydro-electric) of generation today. Conversion from electric to 
natural gas appliances will provide a more immediate emissions 
reduction strategy than the many years it will take for large scale 
deployment of wind, solar and other renewable technologies.
    Rather than a site-based measurement for energy consumption, APGA 
has advocated a ``source-based'' or ``total energy'' analysis that 
measures energy from the point at which energy is extracted through the 
point at which it is used. A total energy analysis provides a more 
accurate assessment of energy use, efficiency, as well as greenhouse 
gas emissions.
    In May, the National Academies of Sciences (NAS) completed a study 
that recommended that DOE move to a full-fuel-cycle measurement of 
energy consumption stating that this measurement would ``provide the 
public with more comprehensive information about the impacts of energy 
consumption on the environment, the economy, and other national 
concerns. . .'' APGA strongly supports this recommendation and looks 
forward to working with the Committee towards its adoption.
    Another recently completed study from the Potential Gas Committee 
(PGC) shows the largest ever recoverable domestic resource base for 
natural gas at nearly 2,100 TCF. This is a 35% increase from the 
previous finding released two years ago and largest ever estimate from 
the PGC. Federal policy should seek to maximize every BTU of this 
domestic and low-carbon fuel by encouraging greater direct use into our 
homes and businesses for heating and cooking and other appropriate 
uses. Direct use into the home is the highest and best use of this 
country's precious natural gas resources.
    APGA appreciates this opportunity to submit comments and looks 
forward to working with the Committee towards fully utilizing the 
benefits of the direct-use of natural gas in efforts to reduce 
greenhouse gas emissions.
                                 ______
                                 
               Statement of the American Gas Association
                           executive summary
   Natural gas is America's clean, secure, efficient, and 
        abundant fossil fuel.
   Residential natural gas consumers, who use the fuel for 
        essential human needs, have a 30-year record of reducing 
        consumption and greenhouse gas emissions, and have shown the 
        critical role that natural gas can play in addressing climate 
        change.
   Natural gas, because it has the smallest carbon footprint of 
        any fossil fuel is part of the energy efficiency and climate 
        change solution.
   Natural gas has the potential to make major contributions to 
        attaining the nation's climate change goals, and these 
        contributions will be maximized if they nation makes the right 
        policy choices, including:

    --Making efficiency and resource decisions based upon full-fuel-
            cycle data that gives a complete picture of resources used 
            and carbon emissions
    --Requiring carbon-footprint labeling on appliances so that 
            consumers realize the consequences of their choices
                              introduction
    The American Gas Association (AGA) represents 202 local energy 
utility companies that deliver natural gas to more than 65 million 
homes, small businesses, and industries throughout the United States. 
AGA member companies deliver gas to approximately 170 million Americans 
in all fifty states. Natural gas meets one-fourth of the United States' 
energy needs.
    AGA commends the Committee for exploring the role of natural gas in 
mitigating carbon emissions and climate change. In the conversations on 
these important topics that have occurred over the last two years in 
both chambers of Congress the critical role that natural gas can play 
has been largely overlooked. In recent months the importance of natural 
gas has at last been recognized, but it has focused on the role of 
natural gas in generating electricity. AGA believes that increased 
focus is necessary on the ways that the direct use of natural gas--in 
furnaces, hot water heaters, and kitchen stoves--can reduce the 
nation's carbon footprint--not twenty years from now but today. The 
irony is that this 19th Century technology is available to solve a 21st 
Century problem.
natural gas is america's clean, secure, efficient, and abundant fossil 
                                  fuel
    Natural gas is America's cleanest and most secure fossil fuel. 
Natural gas is essentially methane, a naturally-occurring substance 
that contains only one carbon atom. When burned, natural gas is the 
most environmentally-friendly fossil fuel because it produces low 
levels of unwanted byproducts (SOX, particulate matter, and 
NOX) and less carbon dioxide (CO2) than other 
fuels. Upon combustion natural gas produces 43% less CO2 
than coal and 28% less than fuel oil. Moreover, almost all of the 
natural gas that is consumed in America is produced in North America, 
either in the United States or Canada, with the vast majority of that 
being produced in the United States. Only a small portion--1 to 2%--is 
imported from abroad as liquefied natural gas.
    Natural gas is also the most efficient of the fossil fuels. 
Approximately 90% of the energy value of natural gas is delivered to 
consumers. In contrast less than 30% of the primary energy involved in 
producing electricity reaches the consumer. Additionally, natural gas 
is an abundant fuel. Recent prodigious discoveries of shale gas have 
significantly added to this abundant resource base. As the Potential 
Gas Committee recently reported, gas reserves have grown nearly fifty 
percent in the last several years. Indeed, America has at least 100 
years of natural gas in the ground in North America. Moreover, changes 
in economics and technology will continue to increase our resource base 
estimates in the future, as they have consistently done in the past.
    Natural gas is used to meet essential human needs for small-volume 
customers. The majority of the homes in this country use natural gas, 
and in this sector 98% of all gas is used for space heating, water 
heating, and cooking, while the remaining 2% is used for clothes drying 
and other purposes. This fuel is, therefore, used for essential human 
needs rather than for luxuries. Natural gas is, therefore, an essential 
fuel for America.
    There are two important facts about natural gas that are either 
little known or often overlooked:

   America's residential natural gas customers have led the 
        nation in reducing their consumption of natural gas--and their 
        greenhouse gas emissions--over the last 30 years and can 
        continue, with appropriate policies, to reduce consumption 
        further. It takes less natural gas to serve 65 million homes 
        today than it took to serve 38 million homes in 1970.
   Natural gas is not part of the climate change problem; 
        rather, it is part of the climate change solution because it 
        offers an immediate answer to reducing greenhouse gas emissions 
        with existing technology, and it has the smallest carbon 
        footprint of all fossil fuels.
  residential gas consumers have demonstrated that the direct use of 
   natural gas can lead the way in reducing america's greenhouse gas 
                               emissions
    Residential natural gas customers provide a sterling example of the 
role natural gas can play in addressing climate change. This group has 
consistently reduced its per-household consumption of this fuel--and 
the carbon emissions resulting from its use--for more than 30 years. On 
a national basis, residential customers have reduced their average 
natural gas consumption by approximately 30% since 1980. The success of 
residential and commercial natural gas consumers is illustrated by the 
fact that they have reduced their per-household consumption so 
dramatically that there has been virtually no growth in sectoral 
emissions in nearly four decades despite an increase in natural gas 
households of over 70%. Stated another way, total annual residential 
natural gas consumption is lower today than it was in the 1970s, 
despite the fact that the number of natural gas households has 
increased more than 70% from 38 million to 65 million. Consumption of 
natural gas in the residential sector, on a national average basis, is 
shown in the following graph:*
---------------------------------------------------------------------------
    * Graph has been retained in committee files.
---------------------------------------------------------------------------
    Both research and anecdotal evidence make clear that there are 
proven drivers for reducing natural gas consumption and the carbon 
emissions associated with natural gas consumption--increased appliance 
efficiency and increased building efficiency, supplemented by a variety 
of education and incentive programs. AGA believes that continuing to 
pursue appliance efficiency and building efficiency policies is the 
optimal means to achieve further reductions in consumption in this 
sector. This admirable record of reducing consumption can continue by 
employing an intensive focus upon energy efficiency and building codes 
and standards measures, which for three decades have led to 
dramatically reduced natural gas consumption (and emissions).
    The reductions in consumption per household experienced over the 
past three decades are largely attributable to tighter homes and more 
efficient natural gas appliances. These factors will undoubtedly 
provide the foundation for continued future reductions in consumption 
and, hence, greenhouse gas emissions. Moreover, natural gas utilities 
are aggressively promoting decoupled rate structures that allow them to 
promote conservation and efficiency consistent with shareholder 
interests. Nearly 40% of all residential natural gas customers are 
served by gas utilities that have decoupled rates or that are engaged 
in state proceedings that are presently considering decoupled rates. 
Rate decoupling is important to energy efficiency because it breaks the 
link between utility revenue recovery and customers' energy 
consumption.
    using natural gas in homes and businesses is art of the energy 
                 efficiency and climate change solution
    Many misguidedly believe that because natural gas is a fossil fuel 
it is one of the causes of greenhouse gas emissions and, as result, a 
contributing factor to climate change. In fact, however, natural gas is 
part of the climate change solution. As mentioned previously, natural 
gas is a fuel that emits low levels of traditional pollutants such as 
NOX and SOX. With regard to greenhouse gas 
emissions, natural gas, because it has only one carbon atom, emits less 
carbon when consumed than any other fossil fuel. As a result, natural 
gas has the potential to be a vehicle to move the nation toward its 
greenhouse gas reduction goals. For the same reasons, natural gas is an 
essential element in the push for optimizing our natural resources and 
increasing our energy efficiency.
    There are significant differences in efficiency between natural gas 
and electricity. Approximately 90 percent of the energy value in 
natural gas is delivered to the home. With electricity less than 30 
percent of the primary energy value reaches the customer. The largest 
difference in efficiency for electricity is lost as waste heat at the 
generating station, as well as line losses in transmission and 
distribution. These radically different efficiencies produce the 
significant differences in both efficiency and carbon emissions between 
electric and natural gas appliances.
    The full potential for natural gas efficiencies is demonstrated 
most dramatically by the carbon footprint of the natural gas water 
heater. The average natural gas water heater emits approximately 1.7 
tons of CO2 per year. In contrast, the average electric 
water heater results in more than twice as much--3.8 tons per year. The 
difference between the two could not be more dramatic, and it becomes a 
multiple of three when the comparison is made between a high-efficiency 
natural gas water heater and a high-efficiency electric water heater. 
These numbers are based on national averages, and, as a result, actual 
differences will vary from area to area.
    The same differences in efficiency and emissions follow when 
comparing an all-electric home with a natural gas home. A typical all-
electric home on average produces 10.8 tons of CO2 per year, 
while an all-natural-gas home produces 7.2 tons of CO2 per 
year. Again, these numbers reflect national averages, and actual 
experience will necessarily differ, but the order of magnitude of 
difference remains.
    The plain consequence is that the nation can improve its overall 
energy efficiency as well as reduce its carbon footprint by opting for 
appliances that use natural gas in direct applications (i.e., where the 
natural gas is used to heat air, water, or food). There is the 
opportunity, on a national basis, to improve efficiency dramatically 
and reduce carbon emissions by millions upon millions of tons if we 
utilize more natural gas directly in homes and businesses as the fuel 
for the future.
    Converting small-volume customers to high-efficiency natural gas 
applications is one of the best ways available today to leap forward in 
efficiency and reduce greenhouse gas emissions. As the example above 
demonstrates, converting electric resistance water heaters to natural 
gas can increase efficiency and reduce greenhouse gas emissions by one-
half to two-thirds. Doing so would have the benefit of reducing overall 
energy consumption, costs, and the need to construct new electricity 
generating plants--a critical problem in a carbon-constrained 
environment--and electric transmission lines.
    Encouraging the direct use of natural gas by consumers is, 
therefore, an important tool to meet the nation's greenhouse gas goals. 
In other sectors of the energy industry, the steps necessary to reduce 
greenhouse gas emissions are years or decades away--e.g. deployment of 
additional nuclear generating stations or carbon capture and 
sequestration. In contract, natural gas is here today to reduce 
greenhouse gas emissions in the immediate future. It is not only the 
increased use of natural gas for electricity generation (which is not 
an issue central to AGA) that promises reductions in greenhouse gas 
emissions, but also the increased usage of natural gas in home heating, 
water heating, and cooking that has the potential to bring near-term 
reductions in greenhouse gas emissions.
 measuring energy efficiency and consumption on a ``full-fuel cycle'' 
     asis will maximize natural gas as a potent climate change tool
    This spring the National Academy of Sciences completed a study 
under contract with the U.S. Department of Energy as required by the 
Energy Policy Act of 2005. The study was to determine whether the more 
appropriate means of measuring energy efficiency was ``sited-based'' or 
``source-based'' measurement of consumption and efficiency. The former 
looks only to the site of the appliance consuming energy. The latter 
looks to the full fuel cycle--in the case of natural gas from the 
wellhead to the burner tip. In the case of natural gas, site-based 
analysis looks to the relative efficiency of a particular appliance. 
Source-based analysis instead looks to see how much of the energy taken 
from a gas well does productive work at the site of the appliance. In 
essence the source-based analysis leads to the conclusion that in the 
case of natural gas 90% or so of the primary energy results in 
productive effort while in the case of electricity only 30% or so of 
the primary energy results in productive effort.
    The report of the National Academy of Sciences concludes that, 
where different fuel sources can be utilized for a particular appliance 
(e.g., hot water heaters), the full-fuel-cycle (or source-based) 
analysis is most appropriate because it presents the most complete 
picture of the relative usage of primary resources. With today's focus 
on reducing greenhouse gas emissions, the results of the National 
Academy Study take on particular relevance because carbon (greenhouse 
gas) emissions in a particular application closely parallel the full-
fuel-cycle analysis. (A copy of the National Academy of Sciences report 
is attached.)
    If the nation establishes a goal of reducing its carbon emissions, 
it is essential that the nation's policy decisions be based on 
information that will promote that goal. Site-based measurements of 
energy usage and energy efficiency will not lead to maximum reductions 
in carbon dioxide. Those will only be achieved by measuring energy 
usage and energy efficiency on a source, or full-fuel cycle basis. 
Congress here faces a fork in the road--one way leads down the 
traditional path, which will result in erroneous decisions. The other 
way leads down the path of new and fresh analysis that maximizes carbon 
reductions.
    A simple example illustrates the point. Let us look again at water 
heaters. If we compare water heaters on a site basis, we can see that a 
natural gas water heater and an electric water heater are each 90% 
efficient. This comparison ignores, however, the modest energy losses 
in delivery for natural gas and the major losses (70%) for electricity. 
This picture, even using source-based energy, gives only the efficiency 
comparison. As noted previously, when one looks at it from a carbon 
perspective it is starker--the electric water heater is responsible for 
twice as much carbon dioxide as the natural gas water heater. If 
Congress does not change the nation's course on this very fundamental 
issue it will have missed a historic opportunity to do the right 
thing--from both an efficiency and a carbon perspective.
    Attached is a short piece of legislative language that would 
implement this important change in approach for both energy efficiency 
policy and carbon policy.
carbon footprint labeling for appliances will promote carbon reductions
    Currently major home appliances bear labels, called EnergyGuide 
labels, that show the yearly estimate operating cost of an appliance. 
For simplicity, these labels are based upon national averages for 
energy prices. The EnergyGuide label allows the consumer to compare the 
relative annual operating costs of the various appliances from which he 
or she might chose. The purpose of the EnergyGuide label is to give the 
consumer relevant information on the comparative operating costs and 
first-costs of the appliances available so that he or she can make an 
optimal decision.
    H.R. 2454, the American Clean Energy and Security Act of 2009, 
passed by the House on June 26, 2009 (the Waxman-Markey climate change 
bill takes the Energy Guide labels one step further in the dawning 
carbon-reduction age. Section 234(h) of the Waxman-Markey bill requires 
that EnergyGuide labels be expanded to include the carbon emissions 
associated with appliances. For an American public increasingly 
interested in climate change issues and that will, as we move forward, 
be increasingly attentive to carbon emissions, providing this 
additional information will be more than useful. Consumers will be able 
to assess the carbon consequences of their appliance purchases. They 
will, for the first time, be able to balance relative carbon emissions 
with first-costs.
    Mandating this additional information will provide useful 
information to consumers. Doing so will undoubtedly result in carbon 
reductions. Moreover, requiring carbon labeling will not impose costs 
on either manufacturers or consumers. The necessary data for creating 
these labels is readily available, and the requisite calculations are 
not unduly complex. As the labels are already required, it is simply a 
matter of adding one data point to the labels. AGA urges the Committee 
to embrace the carbon labeling provision found in the H.R. 2454.
                                 ______
                                 
          Statement of the American Trucking Associations, Inc
    The American Trucking Associations (ATA) appreciates the 
opportunity to submit written testimony concerning the use of natural 
gas in over the road trucking fleets. ATA is a federation of motor 
carriers, state trucking associations, and national trucking 
conferences created to promote and protect the interests of the 
trucking industry. ATA's membership includes trucking companies and 
industry suppliers of equipment and services. Directly and through its 
affiliated organizations, ATA encompasses over 7,000 companies and 
every type and class of motor carrier operation.
    For the reasons set forth below, natural gas currently is not a 
viable solution for most long-haul trucking operations; however, 
natural gas could be an acceptable fuel alternative for certain short-
haul applications within an industry as diverse as trucking.
                               background
    The trucking industry is the lynchpin of the transportation system, 
hauling nearly 70% of all the domestic freight transportation tonnage 
in the United States and accounting for more than 80% of the nation's 
freight bill. Over 80% of the communities in the U.S. receive their 
goods exclusively from trucks. Trucking also accounts for over 70% of 
the value of trade between the U.S. and Mexico and Canada. Simply put, 
without the trucking industry, the U.S. economy would come to a 
grinding halt.
    Diesel fuel is the lifeblood of the trucking industry. The trucking 
industry consumes 39 billion gallons of diesel fuel each year. For most 
companies, diesel fuel is the second highest operating expense after 
labor. As the price of diesel fuel has increased, the trucking industry 
has searched for ways to increase its fuel economy andvhas pursued 
several alternative fuel options. The search continues, as we have not 
found viable alternative to diesel fuel; although the industry 
continues to experiment with using natural gas in certain applications.
    Natural gas is a fuel comprised mostly of methane, with small 
amounts of propane, ethane, helium and water. Like certain other 
alternative fuels, natural gas could be an acceptable fuel choice for 
specific applications within an industry as diverse as trucking. 
Natural gas engines can either be spark ignition or compression 
ignition with pilot injection (i.e., using a 5% diesel injection to 
initiate combustion), with the later retaining the general properties 
of a diesel engine but requiring a dual-fueling system.
    Natural gas may be used as a transportation fuel in its compressed 
form (CNG) or liquefied form (LNG). Because of low energy density, CNG 
is not practical for long distance, heavy-duty truck applications. CNG 
is being successfully used in shorter range, heavy-duty applications 
such as refuse trucks, concrete mixers, and municipal buses.
    LNG may present a viable alternative for certain trucking 
applications. LNG is cryogenically liquefied (i.e., converted to a 
liquid by reducing its temperature to approximately -260F) and has 
higher energy content per volume than CNG (although still significantly 
lower than diesel). LNG's energy density makes it more acceptable for 
longer routes, although the lack of a competitive refueling 
infrastructure suggests that this alternative is not currently viable 
for long-haul applications.
                               discussion
    As with most alternative fuels, natural gas has certain advantages 
and disadvantages compared to diesel fuel. We discuss each of these in 
more detail below.
A. The Economics of Natural Gas
    One of the biggest obstacles to using natural gas in the trucking 
industry is the cost of a natural gas truck. Natural gas trucks sell at 
a premium to heavy duty dieselngines for Class 8 trucks ($40,000--
$70,000 more).\1\ Federal (and state) tax incentives are available to 
purchasers of natural gas trucks to narrow the price differential 
between diesel and natural gas trucks; however, these incentives are 
not sufficient to completely offset the natural gas truck price 
premium.
---------------------------------------------------------------------------
    \1\ There are currently two natural gas engine classes: (1) a spark 
ignition, 320 horsepower version that sells at a $40,000 premium to its 
diesel counterpart; and (2) a 450 horsepower, compression ignition 
version that sells at a $70,000 premium to its diesel counterpart.
---------------------------------------------------------------------------
    The trucking industry is incredibly competitive. There are more 
than 600,000 companies registered with the U.S. Department of 
Transportation and 96 percent of them are small businesses that operate 
fewer than 20 trucks. In an industry with operating expenses that often 
exceed 98% of collected revenue, trucking companies cannot afford to 
increase their capital expenses by purchasing natural gas trucks that 
cost significantly more than the trucks that their competitors are 
operating.
    LNG fuel tanks are constructed from \1/4\'' thick stainless steel 
and add significant weight to the truck, which may negatively impact 
truck productivity.\2\ For example, two 119 gallon tanks weighing 
approximately 1,000 pounds would reduce the payload of a cargo tank 
truck carrying ethanol by over 150 gallons. Thus, more trucks would be 
required to haul an equivalent amount of product, which negatively 
impacts fuel consumption, emissions, and the cost of transporting 
freight. It should be noted that many trucking operations do not 
operate at the maximum legal weight and the productivity of these 
operations would not be adversely impacted by the weight penalty 
associated with natural gas trucks.
---------------------------------------------------------------------------
    \2\ A 119 gallon tank weighs approximately 500 lbs., while a 72 
gallon tank weighs approximately 270 lbs.
---------------------------------------------------------------------------
    One positive economic aspect of natural gas trucks is that natural 
gas currently sells at a significant discount to diesel fuel on a 
diesel gallon BTU equivalent basis. While both diesel and natural gas 
prices fluctuate, through 2009 LNG sold at a significant discount to 
ultra low sulfur diesel fuel (i.e., approximately 75 cents to $1/gallon 
cheaper). Natural gas trucks, however, are less fuel efficient than 
their diesel counterparts. Spark ignited natural gas engines have a 
reduced fuel economy of 7% to 10%, while compression-ignition natural 
gas engines have about a 1% fuel economy penalty. As a result, some of 
the economic benefit of less expensive natural gas is given up in the 
form of lower fuel efficiency.
    Notwithstanding the fact that natural gas is less expensive than 
diesel fuel, the additional capital cost associated with purchasing 
natural gas trucks compared to diesel trucks makes natural gas a 
challenging economic alternative for most trucking companies. Due to 
the competitive nature of the trucking industry, significant financial 
incentives would be required to address the higher cost of natural gas 
trucks, before they can be considered a viable alternative to diesel 
trucks.
B. Infrastructure Concerns
    The second major obstacle to the use of natural gas as an 
alternative fuel for the trucking industry is the lack of a competitive 
refueling infrastructure. Most long-haul trucks are not centrally 
refueled and do not travel regular routes. Running out of gas on the 
side of the road is a significant challenge, as LNG mobile refueling is 
not an option and the truck would have to be towed to a refueling 
station. The ubiquitous nature of diesel refueling stations 
accommodates that uncertainty. Unfortunately, it is virtually 
impossible for over-the-road fleets to find LNG fueling outlets.
    LNG trucks must be refueled at specialized stations that are 
configured for the specific truck. Putting aside the issue of refueling 
compatibility, many of the natural gas fuel stations in this country 
are owned and operated by municipalities, and prior contractual 
arrangements would have to be made before commercial trucks could use 
these municipal LNG refueling stations. Since the product is dispensed 
at -260 degrees Fahrenheit, employee training and the provision of 
personal protective equipment also may be necessary.
    Building out an LNG refueling infrastructure will take time and an 
enormous amount of money. An LNG filling outlet with a refill 
capability that is comparable to the time necessary to refuel a diesel 
truck costs over $500,000. There also may be permitting challenges 
associated with the construction of an LNG refueling system, as 
government officials and permitting authorities have limited exposure 
to LNG refueling stations.
    It is not sufficient to have a single LNG vendor with stations 
built at strategic locations along key freight corridors. Absent a 
competitive refueling infrastructure, trucking companies could face 
unreasonably high prices at individual retail LNG stations that have no 
competition in a particular geographic area. While competition exists 
in the natural gas industry, the high barriers to entry for retail LNG 
refueling stations may slow the development of a competitive refueling 
infrastructure. A competitive LNG refueling model would require the 
presence of multiple entities selling LNG in the same geographic area.
C. Operational Challenges
    Using LNG as an alternative fuel also creates operational and 
maintenance challenges for the trucking industry.
    LNG On-Board Tanks.--Some fleets have experienced significant 
problems with LNG fuel tanks. These tanks are double-walled 
construction with a vacuum between the two walls (like a giant thermos 
bottle). The vacuum serves as a temperature barrier. In some cases, 
fleets reported a loss of the vacuum due to tank manufacturing issues 
that manifest themselves months and even years after being placed into 
service. The vacuum can be replenished, but the process is costly and 
is not a permanent solution. Impacting a tank (such as during a 
collision or accident) can also result in a lost vacuum. As vacuum 
pressure decreases, fuel temperature rises, causing internal tank 
pressure to rise. The pressure relief valve built into the tank vents 
natural gas into the atmosphere, which affects the amount of fuel 
available for use and offsets the environmental advantages of using 
LNG.
    Operating Range.--An LNG truck equipped with two 119 gallon tanks 
has an operating range of approximately half of the typical diesel 
long-haul truck. These tanks are extremely heavy and negatively impact 
truck productivity for those fleets that haul freight at the truck's 
legal weight limit.
    Maintenance Costs.--A natural gas engine may require injectors to 
be replaced more frequently than a diesel engine, which increases 
operating expenses. For spark-ignition natural gas engines, replacement 
of spark plugs, ignition modules and various sensors also add 
additional maintenance costs.
    On the positive side of the maintenance expense ledger, natural gas 
engines require fewer oil changes. Oil change intervals for LNG trucks 
are three times longer than diesel engines.
    Training.--Natural gas engines operate differently than diesel 
engines and in-house mechanics will require approximately 60 hours of 
specialized training. Finding a qualified natural gas mechanic is more 
difficult than finding a diesel mechanic. The local truck dealer may 
not have the requisite experience, tools or parts to quickly perform 
repairs. As a result, some fleets have reported that the downtime for 
repairs is significantly longer for natural gas engines.
    Methane Exposure.--Maintenance shops that will work on natural gas-
fueled vehicles should include a methane detection system and a methane 
evacuation system. Recommendations on the safe operation and 
maintenance of natural gas vehicles are available from the National 
Fire Protection Association and the Society of Automotive Engineers. 
One ATA member reports spending over $150,000 on infra-red sensors, 
modified lighting and electrical systems, and an air evacuation system.
D. Environmental Implications
    Particulate matter (PM) and nitrogen oxide (NOX) 
emissions from LNG-fueled trucks are similar to diesel trucks 
manufactured in compliance with EPA's 2010 diesel emission standards.
    Lifecycle carbon emissions from a natural gas engine compare 
favorably to diesel engines. Depending upon the source of the natural 
gas and the liquefaction efficiency rate, natural gas can reduce 
CO2 emissions by 15%-23%. Note, however, that methane is 20-
times more potent than CO2 as a greenhouse gas. As LNG in 
fuel tanks warms, methane is released to the environment through a 
pressure relief valve. In fact, depending upon ambient temperatures, an 
LNG truck could vent most of its fuel over a 7-10 day period. The 
venting of methane from trucks parked over an extended period could 
result in a net increase in greenhouse gas emissions compared to diesel 
fuel.\3\
---------------------------------------------------------------------------
    \3\ While trucking companies strive to improve utilization rates of 
their capital equipment, the current low demand for freight 
transportation services provides an immediate example of circumstances 
where trucks may be parked for an extended period of time.
---------------------------------------------------------------------------
                               conclusion
    Natural gas is a plentiful, domestically-produced energy source 
that could help to reduce our dependence on petroleum imports. There 
are numerous hurdles that must be overcome, however, before LNG trucks 
become a truly viable alternative for mainstream trucking. The most 
significant obstacles to LNG are the enormous purchase price premium 
associated with a natural gas truck compared to an equivalent diesel 
truck and the lack of a competitive LNG refueling infrastructure. If 
Congress enacts financial incentives to ensure that the price of an LNG 
truck is equivalent to a diesel truck and that cost-effective LNG 
refueling facilities can be constructed, then LNG trucks may be a 
viable alternative for the small segment of the industry that is 
centrally-refueled.
    For LNG to achieve greater penetration in the trucking industry, 
additional incentives are necessary to ensure the development of an 
adequate competitive refueling infrastructure.
    ATA appreciates this opportunity to discuss potential to increase 
the use of natural gas in the over the road trucking fleets. If you 
have any questions concerning the issues raised in this statement, 
please contact Richard Moskowitz at (703) 838-1910.
                                 ______
                                 
       Statement of Hon. Sean Parnell, Governor, State of Alaska
    Dear Chairman Bingaman and Ranking Member Murkowski,
    The State of Alaska commends the Senate Committee on Energy and 
Natural Resources for its recent hearing on the role of natural gas in 
mitigating climate change. We wish to comment on this and other topics 
related to the Clean Energy Jobs and American Power Act (S. 1733). S. 
1733, which aims to drastically modify U.S. fossil fuel consumption, 
stimulate greater use of renewable energy resources, and address the 
challenges of climate change adaptation, involves some of the most 
important issues facing the State of Alaska.
    Alaska supports the transition to lower-carbon and renewable 
energy. However, as a major exporter of carbon-based energy, producing 
approximately 13 percent of the nation's oil supply and receiving more 
than 80 percent of its unrestricted general fund revenues directly from 
oil and gas operations, the State cannot ignore the potential economic 
consequences of a ``cap-and-trade'' system. We are currently preparing 
analyses that assess the possible impacts of this legislation on State 
revenues, the economic viability of our oil refineries, and future 
construction of an Alaska natural gas pipeline. The State fears this 
act may disadvantage domestic fossil fuel producers and shift 
production overseas, resulting in lost revenues and jobs while reducing 
our nation's energy security.
    While climate change legislation could pose economic threats to our 
state, Alaska is also primed to help lead a clean energy economy. In 
the Alaska natural gas pipeline, the State of Alaska offers a promising 
low-carbon energy option, which could provide a vital bridge to other 
clean energy alternatives. Alaska also holds vast renewable energy 
potential, from hydropower, to biomass, wind, geothermal, solar, and 
ocean power.
    In the area of adaptation, Alaska is already facing a host of 
serious developments related to climate change. This includes 
addressing the impacts to critical infrastructure associated with 
accelerated coastal erosion, increased storm effects, sea ice retreat, 
and permafrost melt. Efforts to protect and relocate Alaskan 
communities are already underway and the State values the partnerships 
we have formed with many federal agencies and other entities. More 
resources, however, are needed along with a designated federal agency 
lead to coordinate the federal efforts.
    Coupled with climate change impacts are opportunities, including 
the potential for increased marine access to Arctic waters and the 
resources they contain. The United States is slowly waking to the fact 
it is an Arctic nation and the importance of the Arctic in general. It 
is imperative that this legislation not foreclose possible 
opportunities in the Arctic.
    Enclosed you will find the State's analysis of provisions in S. 
1733. This document identifies key priorities for Alaska and a number 
of areas for improvement. Some of the items the State advocates for in 
this bill include:

   Adequate funding for climate change adaptation: the State 
        supports sufficient funding to address Alaska's pressing 
        adaptation needs on various fronts, including protecting 
        critical and valuable infrastructure.
   Measures to preserve domestic refineries: Alaska calls for 
        provisions aimed to protect Alaska's refineries, which are 
        essential to our economy and cold weather fuel needs, as well 
        as uniquely vulnerable to increased costs posed by cap-and-
        trade legislation.
   Fair allocations for Alaska: the State is concerned that the 
        Environmental Protection Agency (EPA) has underestimated 
        emissions in Alaska, based on estimates provided to Senator 
        Feingold by EPA. This could disadvantage the state as a whole 
        in the distribution of allowances.
   Avoidance of unfunded mandates: Alaska opposes burdensome 
        and unrealistic unfunded mandates that may be created through 
        new climate change programs.
   Respect for states' rights: the State supports the 
        protection of states' rights and notably recognition of the 
        State of Alaska's role as primary trustee over fish and 
        wildlife.
   Exclusion of problematic broad policy statements: Alaska 
        opposes broad policy statements that open the door to stricter 
        enforceable regulations and future litigation.
   Emphasis on domestic production: the State supports 
        expanding access and incentives for responsible domestic 
        onshore and offshore oil and gas exploration as part of a 
        strategy for creating a secure energy future.
   Promotion of the natural gas pipeline: the State seeks to 
        promote the Alaska natural gas pipeline as a clean and reliable 
        fuel source which would provide significant economic benefits 
        for the nation, consistent with the Alaska Natural Gas Pipeline 
        Act of 2004 (P.L. 108-324, 118 Stat. 1220).
   Carbon capture and sequestration incentives: Alaska supports 
        the commercial deployment of carbon capture and sequestration 
        (CCS) technologies, and in particular, sequestration as a 
        result of Enhanced Oil Recovery (EOR) projects.
   Program flexibility: The State believes that effective 
        mitigation and adaptation programs must acknowledge regional 
        differences. Alaska has particular concerns regarding the 
        proposed natural resources adaptation framework.
   Focus on monitoring and research: Alaska supports 
        collaborations among federal, State, and other partners in 
        monitoring and research that will lead to better decisions in 
        the management of land and marine resources.
   Exclusive role of climate change legislation: We believe 
        climate change legislation should be the sole instrument for 
        addressing climate change mitigation, not the strained use of 
        existing statutes such as the Endangered Species Act or the 
        Clean Air Act.

    We respectfully request that this material be included in the 
hearing record and appreciate the opportunity to share our views.
attachment.--state of alaska comments on clean energy jobs and american 
                          power act (s. 1733)
                    senator boxer's chairman's mark
                           introductory notes
    This document describes the positions of the State of Alaska on 
notable elements of Senator Barbara Boxer's Chairman's Mark of the 
Clean Energy Jobs and American Power Act (S. 1733), which was 
introduced by Senators John Kerry and Barbara Boxer. The Alaska 
Departments of Environmental Conservation, Fish and Game, Law, Natural 
Resources, Revenue, Transportation and Public Facilities, and the 
Governor's Washington, DC office contributed to the analysis of this 
bill.
    While particular design elements of ``cap-and-trade'' legislation, 
like S. 1733 and the American Clean Energy and Security Act of 2009 
(H.R. 2454), raise broad concerns about the economic interests of 
Alaska, this document focuses instead on specific provisions of S. 
1733. The State is currently preparing separate analyses of the 
possible impacts of this legislation on State revenues, the economic 
viability of Alaska's oil refineries, and future construction of an 
Alaska natural gas pipeline.
    In many ways, Alaska is ground zero for obvious and costly climate 
change impacts. Alaska is currently experiencing coastal erosion, 
increased storm effects, sea ice retreat and permafrost melt. The 
villages of Shishmaref, Kivalina, and Newtok have already begun 
relocation plans and the U.S. Army Corps of Engineers has identified 
over 160 additional rural Alaskan communities threatened by erosion.
    The effects of climate change are expected to occur most rapidly 
and be most pronounced at higher latitudes. Thus, no discussion about 
climate change is complete without recognition of the issues facing the 
Arctic. Surprisingly, in the 925-page bill, offered as a U.S. response 
to climate change, the word ``Arctic'' appears only once.
    The State of Alaska strongly encourages that the following key 
components be incorporated in any climate change legislation:

   Mitigation and adaptation strategies that account for 
        regional differences and avoid a ``top-down'' approach, likely 
        to produce inflexible and inefficient policy;
   avoidance of broad policy statements that open the door to 
        stricter enforceable regulations and future litigation;
   an effort to spare states from burdensome and unrealistic 
        unfunded mandates;
   emphasis on climate change legislation as the sole 
        instrument for addressing climate change mitigation, rather 
        than the strained use of existing statutes, such as the 
        Endangered Species Act or the Clean Air Act;
   incentives for a diverse spectrum of clean energy 
        alternatives;
   respect for states' rights, and notably recognition of a 
        state's role as primary trustee over fish and wildlife;
   a focus on studying the Arctic climate and environment;
   appropriate funding for adaptation efforts in Alaska where 
        there is a pressing need to respond on numerous fronts, 
        including the protection of critical infrastructure;
   aid for consumers burdened by climate change-related 
        regulations;
   provisions aimed to protect Alaska's refineries, which are 
        essential to our economy and cold weather fuel needs, as well 
        as uniquely vulnerable to increased costs posed by cap-and-
        trade legislation; and
   promotion of Alaska's natural gas pipeline as a clean, 
        reliable, long-term fuel source.

    In the remainder of this document, the State considers how S. 1733 
addresses these and other priorities important to Alaska.
                State Positions and Analysis of S. 1733
               section 1. short title; table of contents
Findings. (Sec. 2)
   Alaska Natural Gas Pipeline Projects. The State supports the 
        addition of a finding, that the completion of the Alaska 
        Natural Gas Transportation Projects is vital to the country to 
        provide a clean fuel alternative to coal and petroleum as a 
        bridge to power generation that does not involve the combustion 
        of fossil fuels. This finding would be consistent with the 
        Alaska Natural Gas Pipeline Act of 2004 (P.L. 108-324, 118 
        Stat. 1220).
   Arctic Impacts. The State supports the addition of a finding 
        that the impacts of climate change are expected to occur first 
        and be most severe in the Arctic and in the higher latitudes, 
        creating unique adaptation needs in these areas.
  Division A--Authorizations for Pollution Reduction, Transition, and 
                               Adaptation
               title i--greenhouse gas reduction programs
            Subtitle A--Clean Transportation
Greenhouse Gas Reductions through Transportation Efficiency; 
        Transportation Greenhouse Gas Emission Reduction Program 
        Grants. (Sec. 112-113)
   Funding. The State fears Section 112 would create a 
        substantial unfunded mandate and shift resources away from 
        Alaska's transportation priorities. S. 1733 would amend Title 
        VIII of the Clean Air Act to require the EPA Administrator, in 
        consultation with the Alaska Department of Transportation and 
        Public Facilities (DOT), to establish national greenhouse gas 
        (GHG) emission reduction goals. States and metropolitan 
        planning organizations (MPOs) would, in turn, be required to 
        develop targets consistent with the national goals. The State 
        would need to perform extensive data gathering and modeling, 
        compute baseline emissions, and develop new strategies and 
        programs to meet their goals. Section 113, which outlines a 
        grant program for transportation GHG reduction, does not 
        clearly provide funding to states for planning. If Alaska is 
        unable to secure sufficient funding, it would be forced to 
        divert resources from other programs, such as transit and road 
        improvements, in order to absorb the new costs. The State 
        supports a funding mechanism that will ensure adequate 
        assistance to states working to comply with this new mandate.
   Adequate Time Frame. The State has concerns about the time 
        requirements for data production and analysis. Adequate time is 
        necessary to produce data on local conditions. Default national 
        data does not accurately reflect Alaska's environmental 
        conditions and emissions. The State believes this legislation 
        should contain provisions ensuring states have sufficient time 
        to collect and incorporate local data.
    The State also supports inclusion of a statutory process to extend 
        State target deadlines should federal agencies fail to meet 
        deadlines or should there be legal changes to models or 
        methodologies. New standardized models and methods adopted may 
        differ from those used to establish the 2005 emissions 
        reduction baseline. If this is the case, analysis would be 
        necessary to properly compare new results with the 2005 
        baseline. If EPA and DOT lag in making this adjustment, it will 
        shorten the timeframe states have to meet their deadlines.
    Furthermore, the State fears the timeline for new regulations in 
        this section is not realistic. Regulations must be proposed 
        within 12 months and promulgated within 18 months of enactment. 
        Preparing regulations and completing the public process for 
        adopting the regulations can take months under ideal 
        circumstances. If the regulation process is not completed on 
        schedule, states and MPOs would be left with insufficient time 
        to achieve emission reduction targets.
   Authority. The State also questions whether states possess 
        the requisite authority to carry out their new duties under 
        this section. State transportation programs generally do not 
        operate transit, rail, or intercity bus systems, control land 
        use, or regulate the amount of driving or method of vehicular 
        propulsion. This authority is traditionally reserved for local 
        government planning and zoning departments. Yet it will be 
        impossible to meet ambitious emissions targets without 
        regulating these activities. Furthermore, Section 112 holds 
        MPOs to a lesser standard than states, though MPO emission 
        plans are central to meeting state targets.
   Public Health. The State also has reservations about use of 
        the term ``public health,'' which has certain connotations 
        within the Clean Air Act. A provision may be necessary to 
        ensure the term does not invoke actions related to the Clean 
        Air Act Section 109(b)(1), which directs EPA to set ambient air 
        quality standards to ``protect the public health'' and allow 
        for an adequate margin of safety. Recent EPA actions have shown 
        an increased propensity for moving beyond the agency's 
        traditional authority.
   Surface Transportation. The State believes the language of 
        this section should be clarified to describe ``surface'' 
        transportation-related greenhouse gas emissions reduction 
        targets in all cases. Further, the term ``surface 
        transportation-related'' should be defined to specifically 
        exclude maritime (except ferries), rail, and off-road vehicles.
   Lead Planning/Modeling Agency. The State supports 
        establishing the U.S. Department of Transportation, not the 
        EPA, as the lead agency regarding the development of 
        transportation planning and modeling tools. S. 1733 does this.
   Vehicle Miles Traveled. The State is concerned by provisions 
        creating goals for reduced ``vehicle miles traveled.'' 
        Construction of the natural gas pipeline may create large 
        short-term increases in vehicle miles traveled, but will 
        generate benefits that far outweigh these increases. The State 
        supports an exception for large construction projects promoting 
        clean energy.
   Clean Air Act Incorporation. Section 112 also raises concern 
        because of its incorporation into the Clean Air Act. The 
        provision could subject planning and activities to burdensome 
        Clean Air Act statutes and regulations.
            Subtitle F--Energy Efficiency and Renewable Energy
Renewable Energy. (Sec. 161)
   Grants for Renewable Resource Programs. The State supports 
        the nation's transition to increased reliance on renewable 
        energy. Alaska possesses vast renewable energy potential, 
        including hydro, biomass, wind, geothermal, solar, and ocean 
        power. S. 1733 authorizes EPA grants for projects that increase 
        the quantity of energy that a state uses from renewable 
        resources, with priority to applicants in states with a binding 
        Renewable Portfolio Standard. The State approves of the 
        provision's goal.
    The State, however, has concerns about the definition of 
        ``qualified hydropower,'' used in Section 102. It appears 
        hydropower can be considered ``qualified'' in two ways. First, 
        incremental gains or capacity additions to projects in place 
        before 1988 are considered qualified hydropower. Second, energy 
        produced from capacity added after 1988 to a dam that was 
        originally in place for reasons other than power generation 
        qualifies. This narrow definition would exclude large portions 
        of existing hydropower, making it difficult for Alaska to meet 
        a Renewable Portfolio Standard and compete for grants under 
        Section 161, despite having an abundance of hydropower. The 
        definition would also leave out new hydro projects. The State 
        supports the expansion of the definition of ``qualified 
        hydropower.''
Energy Efficiency in Building Codes. (Sec. 163)
   National Building Codes. The State opposes setting national 
        energy efficiency building codes. S. 1733 would create national 
        codes for residential and commercial buildings, in order to 
        meet national energy efficiency targets. The EPA Administrator 
        would publish an annual report on energy efficiency building 
        code adoption and compliance by states. Though penalties for 
        noncompliance are not defined in S. 1733, Alaska opposes the 
        existence of national standards in this area. A federally 
        mandated, universal energy code is a poor fit for a state with 
        Alaska's vast size and varied conditions.
            Subtitle H--Clean Energy and Natural Resources
Clean Energy and Accelerated Emission Reduction Programs. (Sec. 181)
   Clean Energy Incentives. The State supports Section 181, 
        which rewards companies that switch from power sources with 
        higher emissions than the 2007 power sector average to cleaner 
        fuels, including natural gas, and Section 182, which would 
        establish a new federal grant program encouraging investment in 
        advanced natural gas technologies.
                  title iii--transition and adaptation
                      Part 1--Domestic Adaptation
            Subpart A--National Climate Change Adaptation Program
National Climate Change Adaptation Program. (Sec. 341)
   Existing Programs. The State supports the inclusion of 
        language to clarify that the proposed National Climate Change 
        Adaptation Program (NCCAF) will not replace existing federal 
        programs already providing state and local governments and 
        tribes with funds for projects that will assist in adaptation. 
        The NCCAF should be a supplemental source of funding that 
        prioritizes meeting urgent needs.
Climate Services. (Sec. 342)
   Coordination. The State believes a lack of specificity in 
        the bill's natural resources adaptation strategy could hamper 
        coordination and produce a duplication of efforts. In this 
        section, the Department of Commerce (NOAA) is tasked with 
        developing a National Climate Service. Section 365 creates a 
        Natural Resources Climate Change Adaptation Panel, chaired by 
        the Council for Environmental Quality. Section 367 establishes 
        a National Climate Change and Wildlife Science Center. These 
        provisions leave ambiguity as to how the bodies will interact. 
        At the State level, federal agencies have competed for 
        leadership and funds in the climate change arena. The vagueness 
        in these provisions could produce a similar dynamic.
            Subpart B--Public Health and Climate Change
National Strategic Action Plan; Advisory Board. (Sec. 353-354)
   Public Health. The State supports the inclusion of a section 
        dedicated to addressing public health. However, the bill calls 
        for development of a Health Impact Assessment. The requirement 
        that Health Impact Assessments be conducted by the federal 
        government within the National Environmental Policy Act (NEPA) 
        process has produced challenges in Alaska. Additionally, no 
        funding mechanism is provided to develop these assessments or 
        the strategic plan called for by the bill. The section also 
        lacks a mandate for State or Native representation on the 
        Advisory Board.
            Subpart C--Climate Change Safeguards for Natural Resources 
                    Conservation
Natural Resources Climate Change Adaptation Plan; Natural Resources 
        Climate Change Adaptation Strategy; Natural Resources 
        Adaptation Science and Information. (Sec. 365-367)
   Mission of Panel. The State believes the purpose of the 
        Natural Resources Climate Change Adaptation Panel should be 
        expanded to address other forms of adaptation, such as 
        infrastructure. As introduced, the bill lacks a strategy for 
        coordinating federal policy on climate change effects outside 
        of the natural resources area.
Federal Natural Resource Agency Adaptation Plans; State Natural 
        Resources Adaptation Plans. (Sec. 368-369)
   Flexibility. The State fears the natural resource adaptation 
        framework in S. 1733, like that in H.R. 2454, is too top-down 
        driven for success. The bill calls for each federal agency to 
        develop a natural resource adaptation plan, with which 
        subsequently-formed state plans must be consistent. Climate 
        impacts, however, differ regionally and locally, requiring 
        maximum flexibility. Development of a national plan will 
        hamstring local identification and prioritization of issues and 
        associated strategies to address them, stifle innovation, and 
        prevent the local ``buy-in'' vital to effective implementation. 
        A national focus also impedes the development of regional 
        strategies.
    States should be allowed to negotiate cooperative natural resource 
        agreements with the federal government on a state-by-state 
        basis with maximum flexibility. In the face of significant 
        intrusion by the federal government on a state's authority to 
        regulate fish and game, states may reasonably prefer departing 
        from the national strategy. If a state does so, however, it 
        will be penalized through denial of funding under programs in 
        this subtitle and potentially other federal programs. The 
        scenario is counterproductive and could be alleviated with 
        greater flexibility.
   Competing Interests. The State fears efforts to assist 
        species in adapting to climate change and ocean acidification 
        will require controlling human activities to reduce other 
        stressors on these species. Large new conservation units may be 
        carved out and human activities in migration corridors could be 
        substantially limited. The bill does not state how the 
        adaptation strategy and planning called for is to be reconciled 
        with human population growth, resource development, commercial, 
        and other human activities. With this approach, other competing 
        interests of importance to the people of Alaska will be 
        marginalized.
National Resources Climate Change Adaptation Account. (Sec. 370)
   Other Statutes. The State believes the bill should 
        specifically de-link existing statutes, such as the Endangered 
        Species Act (ESA), from the climate change policy process. The 
        State opposes use of the ESA as a vehicle for carrying out 
        climate change policy. Section 370 provides for an expansion of 
        ESA programs, which, without further guidance, could result in 
        significant increases in listings that provide little benefit 
        to those species. The bill should include language affirming 
        that climate change legislation is the appropriate instrument 
        for responding to climate change and that ESA should retain its 
        traditional role of conserving species most at risk.
   Corps of Engineers. The State also believes this section 
        should be modified to explicitly grant the U.S. Army Corps of 
        Engineers the authority to use Natural Resources Climate Change 
        Adaptation Account funding for coastal erosion reduction 
        projects and infrastructure adaptation.
   Funding Allocation. The State appreciates that, of the funds 
        made available to states in this account, a portion (six 
        percent) is set aside for coastal agencies. Coastal states will 
        have unique adaptation needs. To ensure adequate funding where 
        climate change impacts are most severe, though, the State 
        advocates for a separate allocation for Arctic adaptation 
        efforts.
National Wildlife Habitat and Corridors Information Program. (Sec. 371)
   State's Role. The State fears this section undermines the 
        State's role as primary trustee over fish and wildlife. The 
        proposed National Fish and Wildlife Habitat and Corridors 
        Information Program centers around developing Geographic 
        Information System (GIS) databases and maps to support 
        decision-making in this area. The State approves of this 
        approach. The stated purpose of the effort, however, is to 
        allow the Secretary of the Interior to recommend how the 
        information developed ``may be incorporated'' into relevant 
        State and federal plans that affect fish and wildlife including 
        land management plans, and the State Comprehensive Wildlife 
        Conservation Strategies. Further, the Secretary is granted 
        authority to ``ensure that relevant State and federal plans 
        that affect fish and wildlife (1) prevent unnecessary habitat 
        fragmentation and disruption of corridors; (2) promote the 
        landscape connectivity necessary to allow wildlife to move as 
        necessary to meet biological needs, adjust to shifts in 
        habitat, and adapt to climate change; and (3) minimize the 
        impacts of energy, development, water, transportation, and 
        transmission projects and other activities expected to impact 
        habitat and corridors.'' The State is leery of this expansion 
        of federal authority. To be successful, adaptation efforts must 
        respect the primary roles and authorities of State fish and 
        wildlife agencies in managing fish and wildlife and be built on 
        this precept.
   Landscape Conservation Planning Programs. The relationship 
        of this program to existing landscape conservation planning 
        programs (such as the Landscape Conservation Cooperatives) 
        should also be clarified.
            Subpart D--Additional Climate Change Adaptation Programs
Coastal and Great Lakes State Adaptation Program. (Sec. 384)
   Funding Formula. The State approves of this program's focus 
        on coastal states. By factoring in the proportion of shoreline 
        miles, the formula also acknowledges that a state's amount of 
        coastline is an important consideration in assessing adaptation 
        needs. Once again, however, the State feels the formula should 
        account for the unique needs experienced in the Arctic and high 
        latitudes.
             Division B--Pollution Reduction and Investment
               title i--reducing global warming pollution
            Subtitle A--Reducing Global Warming Pollution
Reducing Global Warming Pollution. (Sec. 101)
          ``International Offset Credits.'' (Clean Air Act [CAA] Sec. 
        744)

   International Offsets. The State supports the inclusion of 
        international offsets (the ability for companies to reduce 
        emissions outside the U.S. and have it count towards domestic 
        reductions). Like H.R. 2454, S. 1733 allows international 
        offsets, though the portion of overall offsets comprised by 
        international offsets is smaller in S. 1733 than in H.R. 2454.
Definitions. (Sec. 102)
          ``Definitions.'' (CAA Sec. 700)

   Alaska Refineries. Alaskans are uniquely dependant on in-
        state refineries for their fuel needs. Alaska has limited fuel 
        storage and is located thousands of miles from the nearest non-
        Alaskan refinery. The state's refineries are particularly 
        vulnerable to increased costs because they are relatively 
        simple on the Nelson Complexity Index, meaning they operate at 
        lower levels of economic efficiency than more sophisticated 
        refineries which can extract more refined product from a barrel 
        of crude oil. If Alaska's refineries are disadvantaged to the 
        point of closing, it would likely produce a wide range of 
        negative consequences across the state. These may include 
        higher costs associated with importing fuel by tanker and 
        building storage tanks in addition to increased economic 
        burdens on Alaska's rural communities.
    The Chairman's Mark includes provisions granting small business 
        refiners additional time to comply with the Pollution Reduction 
        and Investment program and distributes additional allowances to 
        small business and medium refineries. These provisions could 
        help Alaska's refineries, but may not be sufficient to protect 
        them from substantial costs.
    The State would support an exemption for certain domestic 
        refineries to prevent regional market failures and promote the 
        interest of regional energy security. One way of achieving this 
        is through modifications to the definition of ``covered 
        entities'' in the Clean Air Act. First, the language in S. 1733 
        could be amended to match the corresponding language in H.R. 
        2454, requiring that a stationary source producing petroleum 
        products do so in ``interstate commerce'' to be covered under 
        CAA Section 700(13)(B). Second, CAA Section 700(1)(F) 
        subsection (viii) for ``petroleum refining'' could be removed. 
        These modifications would exempt refineries, like those in 
        Alaska, that sell virtually all of their saleable product in-
        state.
   Embedded Emissions, Direct Emissions, and Fossil Fuel Based 
        Carbon Dioxide. The State supports adding definitions for 
        Embedded Emissions, Direct Emissions, and Fossil Fuel Based 
        Carbon Dioxide to clarify that natural gas produced at the 
        wellhead or flowing through a pipeline will not be burdened 
        with the requirement of emission allowances for the carbon 
        dioxide that may one day be produced when the natural gas is 
        burned.
   Natural Gas Liquids. The State seeks clarification on this 
        section, which differs from H.R. 2454 in its definition of 
        natural gas liquids as being ``ready for commercial sale or 
        use.'' This change raises concern given the value natural gas 
        liquids bring in a major gas sale scenario.
Disposition of Allowances for Global Warming Pollution Reduction 
        Program. (Sec. 111)
   Fair Allocation of Allowances. The State is very concerned 
        about the disposition of allowances for Alaska under a cap-and-
        trade regime. An EPA memo provided to Senator Feingold 
        indicated that the agency drastically underestimated emissions 
        in Alaska. The document gave the false impression that Alaska 
        would be sufficiently accommodated through the provision of 
        free allowances under H.R. 2454. EPA's estimates for capped 
        emissions in 2012 appear to have been based exclusively on 
        Alaska's electric generation, primarily electricity generated 
        for retail electricity sales, leaving out all facilities that 
        generate their own power, such as oil and gas fields and some 
        military bases. As a result, EPA estimated the state's 
        emissions at three million tons per year (MMt/yr). For the same 
        year, the State's models estimated capped emissions at 24.2 
        MMt/yr. This inaccuracy could substantially disadvantage Alaska 
        in the distribution of allowances.
   Emission Allowances for Alaska Natural Gas Transportation 
        Projects. The State supports specific free emission allowances 
        for the operation of Alaska Natural Gas Transportation 
        Projects. The 1,700 mile Alaska Gas Pipeline will be a source 
        of substantial CO2 emissions, estimated to be 
        between 20-50 percent of total Alaskan capped emissions.

          ``Electricity Consumers.'' (CAA Sec. 772)

   Regulatory Commission Approval. This section describes an 
        allocation process for allowances to electric utilities with a 
        requirement that applicants first seek approval from the 
        Regulatory Commission of Alaska. This requirement could create 
        a costly unfunded mandate for the State as regulatory 
        proceedings have become contentious and expensive.
   Hydropower Projects. See discussion for section 161.

          ``Home Heating Oil and Propane Consumers.'' (CAA Sec. 774)

   Heating Oil Allocation. CAA Section 774 addresses 
        allocations to states based on domestic oil and propane 
        consumption and, as written, is unfavorable to Alaska. Free 
        allowances for heating oil and propane would be allocated to 
        the states based on each state's relative share of total 
        domestic heating oil and propane consumption. Alaska consumes a 
        significant amount of oil due to heating degree days and the 
        prevalence of heating oil use across the state. Heating oil and 
        propane, however, appear to be weighted equally. Thus, states 
        like California and Texas that may consume more propane for 
        barbecue grills and hot tubs than Alaska consumes heating oil, 
        would receive larger shares. The State believes heating oil and 
        propane should be separated for allocation purposes.

          Exchange of State-Issued Allowances.'' (CAA Sec. 777)

   State-Issued Emission Allowances. Although Alaska is only an 
        observer of the Western Climate Initiative (WCI), it supports 
        WCI's position that the work of the states should be integrated 
        into a new climate regime, rather than completely preempted. 
        This bill would integrate state efforts by exchanging regional 
        allowances for federal allowances.

          ``Commercial Deployment of Carbon Capture and Sequestration 
        Technologies.'' (CAA Sec. 780)

   CCS in High-Cost Locations. The State supports the 
        commercial deployment of carbon capture and sequestration (CCS) 
        technologies, and in particular, sequestration as a result of 
        Enhanced Oil Recovery (EOR) projects. CCS is afforded special 
        treatment through the ``bonus allowance value,'' which is 
        essentially a subsidy when compared to the value of purchased 
        or freely distributed allowances.
    The State supports EOR activities in Alaska, especially on the 
        North Slope. This activity produces multiple benefits. 
        Sequestration of CO2 in a known, well-defined 
        hydrocarbon reservoir and trap is inherently safer than in 
        those that are less defined. Furthermore, increased production 
        due to EOR will lengthen oil field life. Since a gas pipeline 
        from the North Slope is economically dependent on the oil field 
        facilities, increasing oil field life improves the economics of 
        a gas pipeline. Gas, as a fuel source, is more environmentally 
        friendly than other carbon fuel sources.
    The costs of CCS on the North Slope may still be prohibitive, 
        however, even with a boost from these allowances and incentives 
        through carbon costs. Costs have been found to be significantly 
        higher for CCS on the North Slope than the averages published 
        for the Lower 48, primarily due to the North Slope's location 
        and weather. The State supports inclusion of provisions that 
        account for greater expenses in high-cost locations in order to 
        make CCS economically feasible in these areas.
Ensuring Real Reductions in Industrial Emissions. (Sec. 141)

          ``Definitions; Eligible Industrial Sectors.'' (CAA Sec. 762, 
        763)

   Foreign Competition for Domestic Refineries. These sections 
        protect certain manufacturing industries from ``off-shoring'' 
        and foreign competition, but specifically exclude domestic 
        refineries. The State believes domestic refineries should be 
        protected as well.
                     title ii--program allocations
State and Local Investment in Energy Efficiency and Renewable Energy. 
        (Sec. 202)
   Allocation Formula. The allocation method in this section 
        unfairly disadvantages Alaska. While 30 percent of the 
        allowances are granted to states on an equal basis, 30 percent 
        is allocated based on population and another 40 percent is 
        allocated based on state energy consumption as a share of total 
        domestic consumption. By these standards, Alaska would receive 
        fewer allowances than almost any other state. This proposal is 
        unfair to Alaska because the state has more heating degree days 
        and thus Alaskans use more energy on average than residents of 
        other states, costs are highest in rural Alaska where incomes 
        are typically lowest, and switching to other fuel sources is 
        not possible or cost effective in most cases for rural 
        Alaskans. The State would support an increased percentage 
        distributed equally among states, measuring energy consumption 
        per capita rather than as a share of total consumption, or 
        allocating some allowances based on energy costs as a share of 
        per capita income using Census data.
   Indian Tribes. In addition, the State supports Section 202, 
        which provides for the distribution of allowances to Indian 
        tribes, which may benefit some rural areas of Alaska.
                           Additional Issues
    Domestic Production.--The State believes S. 1733 should be modified 
to expand access and incentives for responsible domestic onshore and 
offshore oil and gas exploration and production. The U.S. Department of 
Energy's recent forecast for growth in the energy sectors shows demand 
for fossil energy continuing to increase in the nation, and to remain 
above 80 percent of the total portfolio of energy supply through 2030 
and beyond. Therefore, it is clear that fossil fuels will be needed as 
a bridging fuel in the coming decades, and access to domestic 
production, and specifically clean-burning natural gas, is imperative. 
Increased domestic production, carbon mitigation, expanded development 
of renewables, and long-term nuclear energy planning is the only viable 
path to a secure energy future.
    OMB Funding Criteria.--The State believes the Office of Management 
and Budget should be tasked with developing common criteria federal 
agencies can use to prioritize funding to state and local governments 
and tribes for infrastructure and other projects addressing climate 
change vulnerabilities. Existing funding criteria may not be 
appropriate for this purpose. For example, in sparsely populated but 
more vulnerable areas like western Alaska, federal assistance may be 
withheld despite great vulnerability if the primary criterion for 
funding is the number of people or the dollar value of infrastructure 
at risk.
    EPA Limitation Provision.--S. 1733 does not include important 
language related to the Environmental Protection Agency that appeared 
in H.R. 2454. The House bill contains language preventing the EPA from 
requiring performance standards on stationary sources under the federal 
cap. The State feels limitation language like that in the House bill 
should be included in S. 1733 and that EPA officials should not set 
climate change policy.
    Adaptation Priorities.--The State has identified the following as 
high priorities and areas of need with respect to adaptation:

   Changing Risks. The State supports collaboration between the 
        states, federal agencies, and academia to challenge traditional 
        assumptions on weather and climate. This effort should focus on 
        data collection and analysis, forecasting models, hydrology, 
        flood plains and inundation, coastal and riverine erosion, 
        critical infrastructure, and related topics.
   Community Profile. The State believes the initial focus and 
        study on adaptation should be on Alaskan coastal and riverine 
        communities. These communities are currently threatened due to 
        climate change and cannot relocate without extreme disruption 
        and costs.
   Evacuation Routes. The State seeks federal assistance in 
        identifying, designing, constructing, and maintaining all-
        weather evacuation routes from endangered communities to safe 
        havens from approaching storms.
   Safe Havens. The State seeks federal assistance in selecting 
        and equipping safe havens near the endangered communities, with 
        full consideration of the hydrology, geology, and current and 
        more accurate digital mapping. These safe havens should be 
        outfitted with sufficient housing, water and fuel sources, and 
        communications capabilities.
   Shoreline Protection and Stabilization. The State supports a 
        program of shoreline protection and stabilization and considers 
        such projects as the most effective means of protecting against 
        the sudden onslaught of storms.
   Science, Analysis, and Informed Decisions. The State calls 
        for creating and sustaining a program of coordinated, 
        collaborative scientific examination and study of the Arctic 
        climate and environment.
   Other Key Areas. Alaska's needs will also encompass other 
        key areas such as consequences to natural resources, national 
        security, infrastructure, emergency response capacity, etc., 
        resulting from climate change impacts due to diminishing Arctic 
        sea ice and from ocean acidification.
                                 ______
                                 
               Statement of Daimler Trucks North America
    Daimler Trucks North America (DTNA) appreciates Chairman Bingaman 
and Ranking Member Murkowski for holding an important hearing on the 
role of natural gas in mitigating climate change. DTNA is a leader 
among US truck manufacturers in introducing natural gas technology in 
its lineup of trucks. We strongly believe that natural gas, 
particularly in the truck sector, is a viable solution to reducing 
greenhouse gas emissions, lowering diesel consumption, and reducing 
fuel costs.
    Earlier this year Daimler's Freightliner brand introduced its first 
natural gas-powered truck. The Freightliner Business Class M2 112 NG is 
ideal for port operations, utilities, and municipalities and other 
short and medium-haul trucking applications. By next year Freightliner 
will offer natural gas technology in 90 percent of its truck 
applications.
    Daimler is committed to natural gas because of its inherent 
advantages over petroleum-based fuel. For example, it produces lower 
fuel costs both today and for tomorrow. Today diesel averages $2.54/
gallon whereas CNG averages $1.73/gallon. And annually, natural gas 
technology can save an estimated $10,000 in fuel and operating costs 
per truck. Freightliner's natural gas trucks are cleaner too. Our 
trucks already meet the Environmental Protection Agency's (EPA) 2010 
standards with 85 percent lower NOX emissions than its 
diesel counterpart. Most importantly, the United States has an abundant 
supply of natural gas that may allow natural gas vehicle operation for 
years to come. According to the Energy Information Administration, 
proven reserves in the US are continuing to increase.
    Natural gas powered trucks are perfect for short and medium-haul 
trucking. Today's natural gas trucks are ideally suited for 300 miles a 
day usage. For companies that rely on short and medium-haul distances, 
for example at ports and in local municipalities, natural gas is both 
economical and efficient.
    Although natural gas trucks have distinct advantages, we recognize 
challenges continue to exist, particularly for long-haul trucking. The 
lack of a national network of natural gas stations is the leading 
obstacle facing natural gas long-haul trucking. Less than 1,000 natural 
gas stations exist in the US. By comparison, there are over 120,000 gas 
stations. Technology costs still remain high too. The incremental cost 
of a typical natural gas truck is $45,000 more expensive than a 
comparable truck with a conventional diesel engine. Engine technology 
is still a work in process, especially for long-haul heavy trucks that 
need a lot of power and must meet 2010 EPA emissions standards.
    Daimler Trucks believes these challenges can be overcome in a 
relatively short period of time given the right mix of vehicle, fuel, 
and infrastructure incentives. The alternative motor vehicle tax credit 
and natural gas refueling property credit are both important tools for 
stimulating demand. New grant opportunities for natural gas vehicle and 
engine development are also critical to natural gas' future.
    Daimler Trucks urges the Congress is support natural gas technology 
and recognize its value as a clean, abundant, domestically-produced 
fuel in the debate over climate change.
                                 ______
                                 
                        Statement of NGVAmerica
                            i. introduction
    NGVAmerica appreciates the opportunity to provide the following 
statement concerning the role of natural gas in mitigating climate 
change. NGVAmerica is a national organization dedicated to the 
development of a growing and sustainable market for vehicles powered by 
natural gas, biomethane and natural gas-derived hydrogen. NGVAmerica 
represents more than 100 member companies, including: vehicle 
manufacturers; natural gas vehicle (NGV) component manufacturers; 
natural gas distribution, transmission, and production companies; 
natural gas development organizations; environmental and non-profit 
advocacy organizations; state and local government agencies; and fleet 
operators.
    On October 28, 2009, the Senate Energy & Natural Resources 
Committee conducted a hearing to review the role of natural gas in 
mitigating climate change. A number of industry representatives were on 
hand to discuss the potential positive impact of increased natural gas 
use. NGVAmerica's statement specifically addresses how the increased 
use of natural gas vehicles (NGV) can play an important role in 
reducing greenhouse gas emissions from the transportation sector and 
provide other important benefits.
    One of the most important points to consider when assessing the 
potential role of natural gas in mitigating climate change associated 
with the transportation sector is the recent findings concerning the 
increased availability of domestic natural gas supplies. This point is 
critical because, in the past, questions have been raised about whether 
the U.S. has sufficient domestic resources to support the increased use 
of natural gas as a transportation fuel. Those concerns have now been 
dispelled given the recent extraordinary expansion of the U.S. natural 
gas resource base. Over 85 percent of natural gas used in the U.S. 
today in produced in the U.S. (most of the rest is produced in Canada). 
By 2030, the U.S. Energy Information Administration forecasts that 97 
percent of the natural gas used will be produced in the U.S. Therefore, 
the U.S. natural gas resource base could easily support a growing NGV 
market. Increasing the use of NGVs will help reduce greenhouse gas 
emissions and lessen reliance on foreign oil imports.
    Natural gas is widely recognized as a low-carbon fuel, the cleanest 
of all the fossil fuels. Extensive analysis indicates that the natural 
gas when used as a transportation fuel reduces carbon dioxide 
equivalent emissions by 20--30 percent compared to gasoline and diesel. 
These benefits are based on full-fuel cycle analyses that have been 
conducted by federal and state environmental authorities. In addition, 
natural gas when used as a transportation fuel is quite competitive 
with the current generation of renewable fuels and is capable of being 
blended with renewable fuel or sourced completely from renewable 
feedstocks (e.g., landfill methane gas). Renewable natural gas 
currently is the cleanest transportation option available anywhere. The 
benefits of renewable natural gas often are overlooked due to the focus 
on liquid biofuels. NGVs also provide benefits in terms of reductions 
in criteria pollutants as well, a point underscored by the fact that 
some of the cleanest internal combustion engines in the world are 
fueled by natural gas.
    In addition to the public policy advantages, NGVs are a proven 
technology that is available today. In fact, in most areas of the 
world, NGV use is growing at a rapid pace. In the U.S. the market is 
growing but at a much slower pace than elsewhere. Because the 
technology is available now, NGVs can help offset greenhouse gas 
emissions, and petroleum imports immediately without delay. 
Accelerating the use of natural gas for transportation will lead to 
increased economic activity associated with increased production of 
domestic natural gas, installation of fueling infrastructure and 
vehicle development. Natural gas sells as a considerable discount to 
petroleum motor fuels and all other alternative fuels, so its use can 
help businesses save money. With the right policies in place, the U.S. 
could rapidly accelerate the use of NGV.
    Congress already has taken a number of steps to encourage greater 
use of natural gas and other alternative transportation fuels. These 
steps were enacted as part of the Energy Policy Act of 2005 and 
SAFETEA-LU. These incentives include tax credits for alternative fueled 
vehicles, alternative fuel infrastructure and alternative fuel use. 
Consumers and businesses alike are benefiting from the congressional 
action that was taken to encourage the increased use of alternative 
fuels. However, much more must be done if the U.S. is going to address 
climate change and reduce its reliance on petroleum. This effort will 
require sustained and significant federal support since the risks 
associated with this effort are simply too great for private industry 
to undertake alone in the timeframe needed. Moreover, this effort will 
require a mix of different transportation fuels to fill the void 
provided by petroleum, since no one single fuel appears likely to 
supplant petroleum. Natural gas in particular can play an important 
role in fueling medium- and heavy-duty vehicles and high fuel use 
passenger car and light truck fleets.
Summary of Recommendations
          1. Extend the current tax incentives for natural gas as a 
        transportation fuel. These incentives were adopted as part of 
        the Energy Policy Act of 2005 and SAFETEA-LU 2005. Most of 
        these incentives are set to expire at the end of 2010. The NAT 
        GAS Act of 2009 (S. 1408) would extend these incentives and 
        improve on them by making certain modifications. We urge the 
        Senate Energy & Natural Resources Committee members to support 
        enactment of this law.
          2. Encourage the production of renewable natural gas by 
        providing a tax credit for renewable energy projects that 
        inject renewable natural gas into the natural gas pipeline 
        system.
          3. Provide appropriate treatment for NGVs in the climate 
        change bill. Previous versions of the bill have encouraged 
        electric-drive vehicles and liquid biofuels over all other 
        alternative fuel options. There are many reasons to support the 
        increased use of electric vehicles and liquid biofuels. 
        However, transportation policy also should include a strong 
        role for NGVs. That means ensuring that federal R&D efforts aid 
        in improving the next generation NGVs and developing hybrid 
        vehicles that use natural gas engines. Moreover, it is 
        important to adopt policies that encourage public utilities to 
        play a role in development the market for NGVs.
                ii. u.s. domestic supply of natural gas
    The U.S. is fortunate to have a significant resource base of 
natural gas. As recently as several years ago, there was concern that 
U.S. and North American production would soon start to decline due to a 
rapidly dwindling resource base. However, the past year has seen an 
almost complete turn around in the outlook for natural gas. Energy 
analysts from across the spectrum are now heralding the new age of 
natural gas production here in the U.S. and possibly elsewhere in the 
world as shale gas production is now economically feasible. Many now 
point to the Colorado School of Mines' Potential Gas Committee's 
report\1\ issued in June to highlight the changing outlook. Based on 
the figures published by the PGC, the U.S. now has a 90-plus year 
resource base of natural gas instead of the 65 year resource base 
believed to exist in 2006.
---------------------------------------------------------------------------
    \1\ See Potential Gas Committee Press Release--http://
www.mines.edu/Potential-Gas-Committee-reports-unprecedented-increase-
in-magnitude-of-U.S.-natural-gas-resource-base.
---------------------------------------------------------------------------
    MIT's Technology Review devotes its November/December cover page 
story to discussing the remarkable turn of events here in the U.S.\2\ 
The article describes how some analysts think the assessments of the 
production capabilities of the northeast's Marcellus Shale are much 
larger than estimated by PGC. The article describes how the Marcellus 
could be the second largest natural gas field in the world, second only 
to a massive offshore field shared by Iran and Qatar. Daniel Yergin and 
Robert Ineson, of the respected Cambridge Energy Research Associates, 
recently authored an article for the Wall Street Journal, entitled, 
``America's Natural Gas Revolution--A `shale gale of unconventional and 
abundant U.S. gas is transforming the energy market.'''\3\ The article 
claims that the biggest energy innovation of the decade is the 
development of unconventional natural gas. The article also indicates 
that ``shale gas plays around the world could be equivalent to or even 
greater than current proven natural gas reserves.'' The conclusion of 
this article is that natural gas is likely to play a much larger role 
in the world's energy mix in future years.
---------------------------------------------------------------------------
    \2\ ``Natural Gas Changes the Energy Map'', MIT Technology Review 
(November/December 2009).
    \3\ WallStreet Journal (November 3, 2009).
---------------------------------------------------------------------------
    With abundant domestic supplies, natural gas use in transportation 
becomes increasingly attractive. Policy makers should no longer be wary 
about whether we have the natural gas supplies to support its use as a 
transportation fuel. To put the potential in perspective, consider that 
we currently use roughly about the same amount of total energy for on-
road transportation as we do for all natural gas purposes (e.g., 
electric generation, commercial, residential). Therefore, replacing 10-
20 percent of transportation fuel use with natural gas would increase 
natural gas use by only 10-20. The U.S. natural gas vehicle industry is 
focusing its marketing efforts on capturing an increased share of the 
medium-and heavy-duty market and a share of the light-duty high-fuel 
fleet market. Since 30 percent of the petroleum used for transportation 
is diesel fuel and since NGVs are the only alternative fuel that can 
capture a significant share of the diesel market, the industry's 
strategy makes sense for the NGV industry and public policy.
          iii. climate change benefits of natural gas vehicles
    Natural gas is a recognized low-carbon fuel. In the past several 
years, extensive analyses have been conducted to determine the full 
fuel cycle emissions impact of NGVs. These reports indicate that 
natural gas reduces greenhouse gas emissions by up to 30 percent when 
compared with gasoline and diesel fuel. The most recent reviews have 
been conducted by the California Air Resources Board (CARB), which 
conducted an exhaustive review of different transportation fuels as 
part of its effort to develop the nation's first low-carbon fuel 
standard.\4\ This standard requires a 10 percent reduction in carbon 
intensity of transportations fuels by 2020. CARB has determined that 
natural gas exceeds the requirements of the program and, therefore, has 
exempted it from the regulatory requirements. Businesses that supply 
natural gas for the transportation market, however, are free to become 
regulated entities if they wish to earn credits under the program.
---------------------------------------------------------------------------
    \4\ See CARB Low Carbon Fuel Standard--http://www.arb.ca.gov/fuels/
lcfs/lcfs.htm. CARB's website includes numerous documents detailing the 
greenhouse gas impacts of different transportation fuels including 
assessments of LNG, CNG, and renewable natural gas. The renewable 
natural gas papers include assessments of CNG and LNG from biomethane. 
The California Energy Commission similarly has published an extensive 
review of the well-to-wheel analysis of different transportation fuels. 
The results of the CEC analysis are contained here: http://
www.energy.ca.gov/2007publications/CEC-600-2007-004/CEC-600-2007-004-
REV.PDF.
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    The LCFS assigns a carbon intensity factor to different fuels based 
on a full fuel cycle analysis, i.e., well-to-wheels. According to CARB, 
the carbon intensity of natural gas is 68 gCO2e per mega-
joule (MJ). The carbon intensity for gasoline and diesel fuel is 95.85 
and 94.71, respectively. Thus, natural gas is estimated to be 29 
percent less carbon intensive when compared with gasoline. Natural gas 
is estimated to be 20 percent less intensive than diesel fuel when used 
in medium or heavy duty vehicles; CARB currently assumes a 10 percent 
fuel efficiency penalty for heavy-duty NGVs, thus the reason for the 
reduced carbon benefits. The carbon intensity of renewable natural gas 
(i.e., biomethane produced from organic waste) is estimated to be 11-13 
gCO2e per MJ. At 11.25 gCO2e/MJ, renewable CNG 
from landfill gas has the lowest of any fuel reviewed by CARB--even 
lower than biodiesel (unadjusted for indirect land-use) at 13.70 
gCO2e/MJ. The reductions for renewable natural gas are 
nearly 90 percent when compared with gasoline and diesel fuel. To 
highlight the viability of renewable natural gas, a short summary of 
existing projects involving biomethane is provided below.
    The greenhouse gas emission benefit of NGVs is expected to continue 
to improve in the future as new automotive technologies become 
available. In fact, a recent National Academy of Science (NAS) report, 
entitled Hidden Costs of Energy: Unpriced Consequences of Energy 
Production and Use\5\ includes some very positive findings concerning 
natural gas vehicles. The report, which analyzed vehicle technologies 
as of 2005 and 2030, essentially projects that with further expected 
improvements in vehicle technology and fuel efficiency, natural gas 
powered vehicles will provide superior benefits in terms of criteria 
pollutant reductions and greenhouse gas emissions compared to nearly 
all other types of vehicles, even electric and plug-in electric 
vehicles. The report's findings include an assessment of the full fuel 
cycle benefits of different transportation fuels and vehicles, and 
include an assessment of the energy and emissions associated with 
producing motor vehicles. The NAS report's assessment of natural gas 
calculates the emissions in terms of grams of CO2-equivalent 
per mile, not per mega-joule. The total emission reduction benefits 
projected in the NAS report are more modest than those reported by 
CARB, which did not include emission associated with vehicle 
production. The NAS report indicates that natural gas vehicles 
currently provide about an 11 percent reduction in CO2-
equivalent emissions compared with gasoline passenger vehicles, but it 
projects that this benefit will grow to 21 percent by 2030 with 
improvements in fuel efficiency.
---------------------------------------------------------------------------
    \5\ National Academy of Science (October 2009): http://www.nap.edu/
catalog/12794.html
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    Natural gas also can be used to provide hydrogen for fuel cell 
vehicles. Nearly all of the hydrogen used in the U.S. today is reformed 
from natural gas. We previously have provided statements to Congress on 
the role natural gas can play in accelerating the introduction of 
hydrogen fuel cell vehicles. We would be happy to provide such 
information to the committee if it is interested.
      iv. example of renewable natural gas transportation projects
    While the number of renewable natural gas projects in the U.S. 
remains small, it is worth highlighting several of these projects to 
show that this fuel has real potential.\6\
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    \6\ One of primary reasons that the number of biomethane projects 
in the U.S. is growing slowly is that the federal government provides a 
significant tax incentive from producing electricity from biogas on 
site, but no incentive for producing and using biomethane. The size of 
the tax incentive has skewed the use of biogas toward on-site 
electricity generation. Legislation has been introduced in the House 
and the Senate (HR 1158 and S. 306) to provide a more level playing 
field for biomethane production.
---------------------------------------------------------------------------
    The McCommis Landfill in Dallas, Texas is currently supplying 4.5 
million cubic feet of natural gas per day. This is the energy 
equivalent of producing 35,000 gallons of gasoline per day. The 
biomethane is currently being injected into the natural gas pipeline 
system nearby. However, Clean Energy, a major provider of natural gas 
for transportation use, owns the rights to the natural gas and has 
plans for someday using this fuel as a transportation fuel.
    In California, Waste Management, North America's largest waste 
management company, and Linde North America, recently began producing 
LNG at the Altamont Landfill near Livermore, California. The LNG will 
be used to fuel hundreds of refuse collection trucks. Waste Management 
and Linde have said the facility is expected to produce up to 13,000 
gallons a day of LNG.
    In Texas, manure from dairy farming operations is being converted 
into methane at the Huckabay Ridge facility. The facility is capable of 
processing manure from up to 10,000 cows. According to published 
reports, this facility produces 650,000 million BTU a year, which is 
equates to a gasoline gallon production rate of almost 14,000 gallons 
per day. The biomethane at this facility is sold as pipeline-grade 
natural gas.
    In Ohio, the Solid Waste Authority of Central Ohio (SWACO) is 
currently producing biomethane from landfill waste and converting it to 
CNG. The fuel is then used to fuel a small number of vehicles at the 
company's Green Energy Center. The production at this facility 
currently is only about 250,000 gallons per year, much smaller than 
other facilities identified. However, SWACO plans to expand its 
operations, and will have the capability of annually producing 5--10 
million gasoline gallons. SWACO currently plans to sell the biomethane 
to local utility pipelines.
    Prometheus Energy and the Bowerman Landfill in Orange County, 
California have partnered to turn landfill gas into LNG. The fuel is 
being used to fuel local transit buses and garbage trucks. The plant 
installed at the site is currently producing about 1,000 gallons of LNG 
per day, but is expected to increase daily production to 5,000 gallons.
    In Europe, biomethane for transport is catching on much faster than 
in the U.S. In fact, Sweden currently estimates that fifty-five percent 
of the natural gas used in vehicles in that country is biomethane. To 
facilitate the use of biomethane, several European countries also have 
policies that require pipelines to accept the transport of biomethane. 
An excellent summary of developments in Europe was prepared by the 
Goteborg Business Region and Biomethane West.\7\
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    \7\ See Fueling the Future; http://www.businessregiongoteborg.com/
download/18.450110ae10c3994eae68000922/
BiomethaneV_FuelingTheFuture.pdf.
---------------------------------------------------------------------------
    The U.S. Department Office of Energy Efficiency & Renewable Energy 
recently prepared a white paper on the potential of using renewable 
natural gas.\8\ The document provides an excellent overview of the 
benefits and potential for renewable natural gas.
---------------------------------------------------------------------------
    \8\ Renewable Natural Gas: Current Status, Challenges, and Issues 
(Sept. 2009); http://www1.eere.energy.gov/cleancities/pdfs/
renewable_natural_gas.pdf.
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   v. enact incentives that encourage the use of natural gas vehicles
    In order to achieve the potential benefits of increased natural gas 
use, NGVAmerica urges the Finance Committee and Congress to enact the 
NAT GAS Act (S. 1408, HR 1835). In addition, we also would urge the 
Congress to enact legislation supporting the production of renewable 
natural gas.

                              NAT GAS Act

    Both the House and Senate have introduced legislation to advance 
the use of NGVs. The bills, S. 1408 and H.R. 1835, are very similar. 
Importantly, both would extend the current incentives for natural gas 
users that have been in place since 2006. The bill's also modify and 
expand the incentives to make them more effective. These incentives are 
about to expire at the end of this year (in the case of the credit for 
sale of CNG or LNG) and next year (in the case of the incentive NGV 
purchases and fueling infrastructure development). The bills also 
include federal authority to carry-out much needed research and 
development (R&D) necessary to improving the quality and performance of 
the next generation of NGVs. Extending the effective dates of these 
expiring provisions would help continue the progress made by natural 
gas fueled vehicles in displacing gasoline and diesel. Extending the 
effective date also would send a clear message to fleets and other 
vehicle owners that Congress supports the use of alternative fuels like 
natural gas as an energy security and climate change strategy for the 
mid-and long term. Adoption of these incentives is critical to ensuring 
that the U.S. takes advantage of the significant opportunity provided 
by its large natural gas resource base. NGVs are a solution that can 
have an immediate impact on petroleum imports, economic activity and 
greenhouse gas emission reductions. For all these reasons, it is 
imperative that the Congress enact the NAT GAS Act.
Renewable Natural Gas Legislation
    S. 306, the Biogas Production Incentive Act, introduced by Senator 
Nelson (D-NE), would establish a $4.27 per MMBTU tax credit for the 
production of renewable gas. Representative Higgins (D-NY) also has 
introduced similar legislation in the House (H.R. 1158). The U.S. 
Congress currently supports the expanded use of domestic renewable 
resources through a variety of tax incentives and other programs. Up to 
this point, Congress has focused primarily on measures that support the 
production of renewable liquid transportation fuels or renewable 
electricity. In the U.S., however, natural gas represents 23 percent of 
the energy consumed. Natural gas is the fuel of choice to provide 
residential and commercial heat for space and hot water in most 
applications and is used to produce steam in a variety of commercial 
and industrial applications.
    Natural gas is also the fuel that provides the energy to 
manufacture many industrial products including aluminum, steel, glass, 
chemicals, fertilizer, and ethanol. Incentivizing the production of 
renewable gas from sources that include animal manure, landfills, 
renewable biomass and agricultural wastes will support expanding the 
role of renewables into this existing energy sector, where little 
opportunity exists today. It will also create another business 
investment prospect for renewable project developers and the potential 
to expand rural economies while supporting existing industrial jobs and 
dramatically reducing carbon emissions.
    Renewable natural gas is a versatile form of bio-energy. It can be 
used directly at the site of production, or placed in the pipeline to 
support a variety of residential commercial or industrial applications. 
Renewable natural gas produced from renewable sources, including animal 
manure, landfills, renewable biomass and agricultural waste, can be 
produced at high efficiencies, ranging from 60-70 percent. 
Additionally, all of the technology components to produce renewable gas 
from this variety of sources exist today. Renewable natural gas can be 
delivered to customers via the existing U.S. pipeline infrastructure. 
It can provide a renewable option for many heavy industries, which 
could save existing industrial jobs in a carbon constrained economy--
while creating new rural green jobs. As noted earlier, renewable 
natural gas also can be an excellent transportation fuel. Renewable 
natural gas production in digesters provides the agricultural sector 
additional environmental benefits by improving waste management and 
nutrient control.
    For all the reasons discussed here, the Congress should adopt a new 
tax credit specifically encouraging the production of renewable natural 
gas.
                     vi. climate change legislation
    The Congress currently is considering a number of proposals to 
address climate change. At this point, it is difficult to determine 
which proposals likely will be enacted into legislation. However, we 
offer the following comments in regards to some of the major themes 
that have been put forward. Several of the introduced proposals call 
for accelerated introduction of more fuel efficient vehicles and 
specifically encourage efforts to commercialize electric vehicles. We 
support such efforts but believe that the legislation should be 
expanded to specifically include NGVs. As noted above, the Congress 
should extend the current tax incentives for NGVs. This would 
accelerate their introduction and deliver immediate greenhouse gas 
emission reductions. Some climate change proposals also would allocate 
a portion of the proceeds from carbon allowance sales to the Department 
of Energy or Environmental Protection Agency for advanced vehicle 
research. These proposals again have largely focused on the role of 
electric vehicles and their contribution to reducing greenhouse gas 
emissions. Such efforts also should include NGVs. There also have been 
proposals to encourage electric utilities to facilitate the development 
of electric charging infrastructure. Natural gas utilities also could 
play a major role in facilitating the use of low-carbon fuels and their 
infrastructure. Legislation should encourage natural gas utilities to 
make investments in natural gas fueling infrastructure and upgrades to 
their distribution systems that will enable greater use of natural gas 
vehicles and use of renewable natural gas.
    Climate change legislation also should not discourage businesses 
from selling more natural gas for transportation purposes. Natural gas 
is a low-carbon fuel and its use should be encouraged, not discouraged. 
As described above, substituting natural gas for petroleum provides 
significant climate change benefits. Therefore, cap-and-trade 
provisions should not include natural gas sales for transportation when 
capping utilities sales of natural gas. If sales of natural gas for 
transportation are included in the cap imposed on utilities, gas 
utilities will have no incentive to grow new markets for natural gas as 
this will only increase their burden to obtain offsets so that they can 
continue to serve their traditional customers (e.g., residential, 
commercial). Rather than working to facilitate a transition to greater 
natural gas use in transportation, climate change legislation, if not 
correctly drafted, could result in utilities viewing increased use of 
natural gas for transportations as a burden to them.
                            vii. conclusion
    NGVAmerica appreciates the opportunity to provide this statement. 
We look forward to working with the committee as it crafts legislative 
proposals to address climate change and energy security in ways that 
will diversify the mix of fuels used in transportation.





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