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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 
(II) 

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

JEFF BINGAMAN, New Mexico, Chairman 

BYRON L. DORGAN, North Dakota 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

MARIA CANTWELL, Washington 

ROBERT MENENDEZ, New Jersey 

BLANCHE L. LINCOLN, Arkansas 

BERNARD SANDERS, Vermont 

EVAN BAYH, Indiana 

DEBBIE STABENOW, Michigan 

MARK UDALL, Colorado 

JEANNE SHAHEEN, New Hampshire 

LISA MURKOWSKI, Alaska 

RICHARD BURR, North Carolina 

JOHN BARRASSO, Wyoming 

SAM BROWNBACK, Kansas 

JAMES E. RISCH, Idaho 

JOHN MCCAIN, Arizona 

ROBERT F. BENNETT, Utah 

JIM BUNNING, Kentucky 

JEFF SESSIONS, Alabama 

BOB CORKER, Tennessee 

ROBERT M. SIMON, Staff Director 

SAM E. FOWLER, Chief Counsel 

MCKIE CAMPBELL, Republican Staff Director 

KAREN K. BILLUPS, Republican Chief Counsel 
(III) 

C O N T E N T S 

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 

(1) 

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. 
2 

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 pro-
3 

tect 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 
4 

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 
5 

* Figures 1–7 have been retained in committee files. 

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 petroleumbased 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, heavyduty 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 policybased 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. 

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 
6 

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, 
7 

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 
8 

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 electricityintensive 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 
9 

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 
10 

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 
11 

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 
12 

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. 
13 

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 crisscrossing 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. 
14 

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. 
15 

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, trad-
16 

ing, 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 KerryBoxer, Energy Jobs and American Power Act. 
17 

* Document has been retained in committee files. 

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. 

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 
18 

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 worldclass 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. 
19 

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. 
20 

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 
21 

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. 
22 

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. 
23 

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. 
24 

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 wellconsidered, 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 costeffective 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. 
25 

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 gamechanger in terms of how we think about natural gas availability, 

supply, and how it can integrate into not only energy security, also 
26 

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 
27 

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. 
28 

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. 2Frontier 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. 

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, unconventional1

and frontier2 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. 

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 
29 

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 
30 

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 re-
31 

sources, 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-asusual 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 WaxmanMarkey 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. 
32 

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 smogproducing 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 tech-
33 

nology 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 gasfired 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 coalfired 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. 
34 

* Appendix has been retained in committee files. 

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.)* 

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. 
35 

* Figures 1–3 have been retained in committee files. 

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).* 

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). 
36 

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 gasfired 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 
37 

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—— 
38 

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 
39 

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 newbuild gas plant, we think it would add about 1 cent per kilowatthour 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 
40 

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 
41 

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 devel-
42 

opments 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 
43 

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 coalfired 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. 
44 

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 lowcarbon 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 
45 

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 
46 

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. 
47 

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. 
48 

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? 
49 

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 
50 

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 
51 

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 Houseincented—— 

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 
52 

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— 
53 

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 WaxmanMarkey, 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. 
54 

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 
55 

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 utiliza-
56 

tion 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 
57 

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 
58 

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. 
59 

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.] 

(61) 

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 gasfired 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 
62 

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, gasfired 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. 
63 

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? 
64 

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. 
65 

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 midterm 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. 
66 

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 equiva- lent 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. 
67 

• 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? 
68 

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 coalfired 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 strong-
69 

ly 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 
70 

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. 
71 

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 
72 

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 be-
73 

1 Joel Bluestein, Coverage of Natural Gas Emissions and Flows Under a Greenhouse Gas Capand-Trade Program (Pew Center on Global Climate Change, December 2008) http:// 

www.pewclimate.org/docUploads/NaturalGasPointofRegulation09.pdf. 

lieve 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 Change1—would cover 95% of CO2 emissions from natural gas while affecting 

a reasonable number of facilities. 

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 
74 

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. 
75 

Plant Carbon 

reduction 

Natural Gas 

Price 

Capture Cost 

($/ton captured) 

SubCritical Coal 

(Baseline) 

baseline $6-8 N/A 

Add on 20% Post 

Combustion Capture 

20% $6-8 $150-$200 

New Natural Gas 

Combined Cycle 

60% $6-8 $0 

Polygeneration/IGCC 

with 90% Capture 

90% $6-8 $90-$150 

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 coalfired 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. 
76 

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 

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 
77 

which offsets and technology are constrained did the electric sector use significantly more gas 

and less coal than in the reference case by 2030. 

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. 

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? 
78 

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 
79 

* Graph has been retained in committee files. 

$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. 

Costs Gas Turbine (GT) CCGT Coal 

Capital Costs Low Mid High 

Operating Costs High Mid Low 

Intended Use Peaking Intermediate Baseload 

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. 

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 allin 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 
80 

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 
81 

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 
82 

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 lowcarbon 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 manip-
83 

ulation. 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? 
84 

• 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 plugin 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: 
85 

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 
86 

• 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. 
87 

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 gasfired (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 
88 

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 USproved 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 
89 

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). 
90 

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 transpor-
91 

tation 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. 
92 

• 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. 
93 

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 longterm 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. 
94 

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 con-
95 

tinue 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 widescale 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 
96 

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 
97 

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 of-
98 

fers 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. 
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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 
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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 
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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 costeffective 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 re-
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peal 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: 
103 

• 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 
104 

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 mar-
105 

ket 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 plugin 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, 
106 

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? 
107 

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. 
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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 
109 

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 
110 

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 
111 

transportation of coal. In 2007, coal was roughly 40 percent of total freight rail tonmiles 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 
112 

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). 
113 

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. 
114 

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, upfront 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 
115 

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 
116 

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 fossilfuel 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. 
(117) 

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 
118 

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. 
119 

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 wellsto-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 
120 

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 
121 

* Graph has been retained in committee files. 

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:* 

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 be-
122 

lieves 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 allelectric 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 dec-
123 

ades 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 nearterm 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, 
124 

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 
125 

1There 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. 2 A 119 gallon tank weighs approximately 500 lbs., while a 72 gallon tank weighs approximately 270 lbs. 

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. 

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. 

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 longhaul 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 refuel-
126 

3While 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. 

ing 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 inhouse 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

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 
127 

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-andtrade 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. 
128 

• 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; 
129 

• 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 
130 

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 transportationrelated’’ 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. 
131 

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. 
132 

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. 
133 

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. 
134 

• 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, welldefined 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. 
135 

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. 
136 

• 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 gaspowered 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. 
137 

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. 
138 

1See Potential Gas Committee Press Release—http://www.mines.edu/Potential-Gas-Committee-reports-unprecedented-increase-in-magnitude-of-U.S.-natural-gas-resource-base. 2 ‘‘Natural Gas Changes the Energy Map’’, MIT Technology Review (November/December 

2009). 3WallStreet Journal (November 3, 2009). 

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 report1 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. 

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. 

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 
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4See 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. 5 National Academy of Science (October 2009): http://www.nap.edu/catalog/12794.html 

6One 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. 

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. 

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 heavyduty 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 Use5 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. 

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

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 
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7See Fueling the Future; http://www.businessregiongoteborg.com/download/ 

18.450110ae10c3994eae68000922/BiomethaneVlFuelingTheFuture.pdf. 8 Renewable Natural Gas: Current Status, Challenges, and Issues (Sept. 2009); http:// 

www1.eere.energy.gov/cleancities/pdfs/renewablelnaturallgas.pdf. 

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

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. 

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. 
141 

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, capand-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 
142 

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. 

Æ