<DOC>
[109 Senate Hearings]
[From the U.S. Government Printing Office via GPO Access]
[DOCID: f:42268.wais]
S. Hrg. 109-1020
THE IMPACT OF CLEAN AIR REGULATIONS ON NATURAL GAS PRICES
=======================================================================
HEARING
before the
SUBCOMMITTEE ON CLEAN AIR, CLIMATE CHANGE, AND NUCLEAR SAFETY
of the
COMMITTEE ON ENVIRONMENT AND PUBLIC WORKS
UNITED STATES SENATE
ONE HUNDRED NINTH CONGRESS
SECOND SESSION
__________
FEBRUARY 9, 2006
__________
Printed for the use of the Committee on Environment and Public Works
Available via the World Wide Web: http://www.access.gpo.gov/
congress.senate
__________
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COMMITTEE ON ENVIRONMENT AND PUBLIC WORKS
ONE HUNDRED NINTH CONGRESS
SECOND SESSION
JAMES M. INHOFE, Oklahoma, Chairman
JOHN W. WARNER, Virginia JAMES M. JEFFORDS, Vermont
CHRISTOPHER S. BOND, Missouri MAX BAUCUS, Montana
GEORGE V. VOINOVICH, Ohio JOSEPH I. LIEBERMAN, Connecticut
LINCOLN CHAFEE, Rhode Island BARBARA BOXER, California
LISA MURKOWSKI, Alaska THOMAS R. CARPER, Delaware
JOHN THUNE, South Dakota HILLARY RODHAM CLINTON, New York
JIM DeMINT, South Carolina FRANK R. LAUTENBERG, New Jersey
JOHNNY ISAKSON, Georgia BARACK OBAMA, Illinois
DAVID VITTER, Louisiana
Andrew Wheeler, Majority Staff Director
Ken Connolly, Minority Staff Director
----------
Subcommittee on Clean Air, Climate Change, and Nuclear Safety
GEORGE V. VOINOVICH, Ohio, Chairman
CHRISTOPHER S. BOND, Missouri THOMAS R. CARPER, Delaware
JIM DeMINT, South Carolina JOSEPH I. LIEBERMAN, Connecticut
JOHNNY ISAKSON, Georgia FRANK R. LAUTENBERG, New Jersey
DAVID VITTER, Louisiana BARACK OBAMA, Illinois
C O N T E N T S
----------
Page
FEBRUARY 9, 2006
OPENING STATEMENTS
Carper, Hon. Thomas R., U.S. Senator from the State of Delaware.. 18
Inhofe, Hon. James M., U.S. Senator from the State of Oklahoma... 13
Jeffords, Hon. James M., U.S. Senator from the State of Vermont.. 16
Lautenberg, Hon. Frank, U.S. Senator from the State of New Jersey 12
Voinovich, Hon. George V., U.S. Senator from the State of Ohio... 1
WITNESSES
Bluestein, Joel, president, Energy and Environmental Analysis,
Inc............................................................ 36
Prepared statement........................................... 109
Responses to additional questions from:
Senator Jeffords......................................... 113
Senator Lieberman........................................ 115
Senator Voinovich........................................ 114
Gerard, Jack N., president and CEO, American Chemistry Council... 38
Prepared statement........................................... 117
Responses to additional questions from:
Senator Jeffords......................................... 118
Senator Voinovich........................................ 119
Gruenspecht, Howard K., Ph.D., Deputy Administrator, Energy
Information Administration, U.S. Department of Energy.......... 20
Prepared statement........................................... 49
Responses to additional questions from:
Senator Jeffords......................................... 64
Senator Lieberman........................................ 60
Senator Voinovich........................................ 61
Smith, Arthur E., Jr., senior vice president and environmental
counsel, NiSource, Inc., accompanied by: Paul Wilkinson,
American Gas Association....................................... 35
Prepared statement........................................... 90
Responses to additional questions from:
Senator Jeffords......................................... 100
Senator Voinovich........................................ 96
Wehrum, William, Acting Assistant Administrator, Office of Air
and Radiation, U.S. Environmental Protection Agency............ 23
Responses to additional questions from:
Senator Jeffords......................................... 64
Senator Lieberman........................................ 89
Senator Voinovich........................................ 86
ADDITIONAL MATERIAL
Charts:
Comparison of Growth Areas and Emissions..................... 6
Natural Gas Consumption...................................... 9
Ohio Residential Natural Gas Prices.......................... 11
Percent of Electricity Generation From Coal.................. 7
Percent of Electricity Generation From Natural Gas........... 8
Projected Domestic Natural Gas Supply & Consumption.......... 10
Total U.S. Manufacturing Employment.......................... 16
Statement, American Forest & Paper Association................... 122
THE IMPACT OF CLEAN AIR REGULATIONS ON NATURAL GAS PRICES
----------
THURSDAY, FEBRUARY 9, 2006
U.S. Senate,
Committee on Environment and Public Works,
Subcommittee on Clean Air, Climate Change,
and Nuclear Safety,
Washington, DC.
The subcommittee met, pursuant to notice, at 9:30 a.m. in
room 628, Senate Dirksen Building, Hon. George V. Voinovich
(chairman of the subcommittee) presiding.
Present: Senators Voinovich, Inhofe, Jeffords, Carper, and
Lautenberg.
Senator Voinovich. This hearing will come to order. I thank
all of you for coming.
OPENING STATEMENT OF HON. GEORGE V. VOINOVICH, U.S. SENATOR
FROM THE STATE OF OHIO
Before I begin, I would like to express my disappointment
that EPA was unable to submit their testimony before this
hearing even 2 hours before it was scheduled to begin. Our
committee rule is, that if there is a witness who is scheduled
to testify at a hearing of a committee or subcommittee they
shall file 100 copies of the written testimony at least 48
hours before the hearing. If a witness fails to comply with
this requirement, the presiding officer may preclude the
witness's testimony. After conferring with Senator Carper, the
Ranking Member of the committee, I must protect the committee's
rules and its members and now allow the EPA testimony to be
submitted for the record.
I understand that there are lots of steps involved with
finalizing an agency's testimony and having it approved by the
Administration. As I mentioned to you, Mr. Wehrum, I know that
you are embarrassed today. I would like you to convey back to
the Agency that I expect that this is going to be the last time
that this is going to occur.
As my colleagues on the committee know, I have long been
concerned about our Nation's competitiveness. If our children
and grandchildren are going to enjoy the same opportunities
that we have had, we must develop what I refer to as the new
infrastructure of competitiveness. The President has recognized
this need by announcing the American Competitiveness Initiative
and embracing most of the math and science education
recommendations of the National Academy of Sciences, the study,
``Rising Above the Gathering Storm.''
He also made a commitment to move America toward energy
independence--I like to refer to this as the second declaration
of independence--to make us less reliant on foreign sources of
energy, especially from countries that do not share our values
and could hold us hostage. If you had sat in on the Foreign
Relations hearings that I did, you would be shaking in your
boots in terms of 11 percent of our oil coming from that part
of the world.
Today's hearing is about a key component of energy
independence: harmonization of our energy, environmental and
economic policies. Nowhere is our failure more apparent than in
terms of natural gas.
The United States has the highest natural gas prices in the
world. We have the highest natural gas prices in the world. It
has had a devastating impact. Families in over 60 million homes
that use natural gas for heat are struggling to pay their
utility bills. Thank God that this winter has been not as bad
as we had expected.
High prices have permanently shut down 17 nitrogen
fertilizer plants representing 20 percent of our production
capacity. In fact, today I met recently with our folks in the
Farm Bureau. Farmers in Ohio are planting less corn and more
wheat and soybeans because they do not need nitrogen
fertilizer.
Chemical manufacturers went from being the most successful
export industry in the history of our Nation in the late 1990's
to a net importer. An official from Bayer warned me 3 years
ago, came to my office 3 years ago and said jobs would be sent
overseas unless something was done about high prices of natural
gas. Since they remain high, last week he told me that today
instead of 22,000 employees in the United States, they now have
14,000. Those jobs have disappeared, and I am not sure they
will ever come back.
Our environmental policies have played a role in
exacerbating the demand for natural gas and limiting the
supply. This hearing will examine a relationship that many cite
as one of the causes for high natural gas prices: that our
clean air regulations have increased natural gas demand because
electricity can be generated cleaner from it than from coal.
It is important that the American public understand the
context of this discussion. We have made great progress in
reducing our emissions, considering the growth of the economy.
This hearing is about how to best continue to improve our air
quality.
I think you can see from the chart that is here is that in
terms of the six worst emissions that we have, and that is from
1990, we are talking about, yes, from 1990, we have had an
increase in our gross domestic product of 187 percent. We have
had an increase in the miles traveled by automobile of 171
percent. Our energy consumption has gone up 47 percent, and our
population 40 percent.
So we have a growing economy and a lot of things that we
are doing that are causing a lot more emissions in this
country. Yet in spite of that, we have been able to reduce our
emissions significantly since that time. The point is, we are
making progress. I think there is some tendency sometimes out
there to say it is getting worse. The fact is, it is getting
better if you compare it with how our economy is growing.
I am going to focus mainly on what has occurred since
enactment of the Clean Air Amendments of 1990 which required
cuts in power plant emissions. On chart 2, this chart shows
that over the past 20 years, the percentage of electricity
generated from coal has significantly decreased from an energy,
economic and national security perspective. This is bad news,
as coal is our most abundant and lowest cost domestic energy
source. We are the Saudi Arabia of coal. We have over 250 years
of coal supply.
Chart 3, over the same period, the percentage of
electricity generated from natural gas has increased greatly.
Thus as the percentage of coal decreased in the 1990's, natural
gas generation increased to meet electricity demand. As stated
earlier, natural gas is used by many different consumers. From
1990 to 2005, while production remained basically flat, the
percentage of natural gas used to generate electricity
increased from 19 percent to 27 percent. You see 1990, and then
the use of natural gas went up to 27 percent.
This rise, without a reciprocal increase in supply, has led
to an escalation of natural gas prices and a reduction in
industrial use. The electric sector is projected to increase
use by 3 more percentage points by 2020. But this analysis is
based on the current regulatory situation and does not
anticipate the initiatives that we have seen here in the last
couple of years dealing with greenhouse gas emissions.
Although this hearing is not about supply, which Chairman
Inhofe covered in a 2004 hearing, it is a big part of the
story. If you look at the chart there, the consumption is
expected to outpace the domestic production by a great deal. So
the difference is projected to be made up by liquified natural
gas, imports from other countries, and unfortunately, just like
oil, we have some real concern about liquified natural gas.
The question that people are asking who are in the
countries that are going to produce it is, are we going to be
able to go forward with the terminals that we have talked
about. There is a lot of concern about what we call not in my
back yard. We don't want them here.
I was up in the Bay of Fundy, they are talking about a
liquefied natural gas port there. People in the community, that
is just off of Maine, they don't want it. So there is a lot of
concern about whether or not we are going to get this liquefied
natural gas that folks say we are going to get.
Simply put, if we increase demand through our policies,
then we must also increase our supply. That is why I am a co-
sponsor of the bill introduced this week by Senators Domenici
and Bingaman to open the Gulf of Mexico's Lease 181 area of
drilling, 100 miles of the Florida coast. This could provide
heat for 15 years for nearly 5 million homes, enough for all of
Ohio's households.
We also took action in the recently enacted Energy bill. I
think the public has not fully appreciated what is in that
bill. It encourages more production in public lands, in
Alaska's Natural Petroleum Reserve, promotes the construction
of those LNG terminals I just talked about, increases the use
of clean coal technologies, nuclear power and renewables, which
will diminish the use of natural gas for electricity
generation.
However, there is no immediate solution to reduce high
natural gas prices. I think that is really something that we
should be level with the public about. Since 1990, natural gas
prices have increased substantially, more than tripling for
families in my State, with an average price of $16.76 per 1,000
cubic feet in November 2005.
To relieve this burden, we have increased LIHEAP funding by
about 73 percent since I came to the Senate in 1999, and we are
working to provide more funding right now. In considering our
environmental policies, we must bear in mind the impact on the
impoverished and understand that we have already greatly
improved our air quality, because LIHEAP is not a solution. We
have to deal with the issues of increasing our supply.
I look forward to hearing from the witnesses about what we
can learn from the past 15 years as we continue to improve the
environment and protect our health. With natural gas prices
already through the roof, families and peoples' jobs are
depending upon us to take into account the impact of clean air
regulations on our Nation's energy and economic policies.
[The prepared statement of Senator Voinovich follows:]
Statement of Hon. George V. Voinovich, U.S. Senator from the
State of Ohio
The hearing will come to order. Good morning and thank you all for
coming.
As my colleagues on this committee know, I have long been concerned
with our Nation's competitiveness. If our children and grandchildren
are to enjoy the same opportunities that we have had, we must develop a
new infrastructure of competitiveness.
The President has recognized this need by announcing the American
Competitiveness Initiative and embracing most of the math and science
education recommendations in the National Academy of Sciences study:
``Rising Above the Gathering Storm.'' He also made a commitment to move
America toward energy independence. I refer to this as the `Second
Declaration of Independence' to make us less reliant on foreign sources
of energy--especially from countries that do not share our values and
could hold us hostage.
Today's hearing is about a key component of energy independence--
harmonization of our energy, environmental, and economic policies.
Nowhere is our failure more apparent than natural gas prices.
The United States has the highest natural gas prices in the world--
which is having a devastating impact:
<bullet> Families in the over 60 million homes that use natural gas
for heat are struggling to pay their utility bills;
<bullet> High prices have permanently shutdown 17 nitrogen
fertilizer plants, representing 20 percent of our production capacity--
in fact, farmers in Ohio are planting less corn and more wheat and
soybeans because they do not need nitrogen fertilizer;
<bullet> Chemical manufacturers went from being the most successful
export industry in the history of our Nation in the late 1990's to a
net importer; and
<bullet> An official from Bayer warned me 3 years ago that jobs
would be sent overseas unless something was done about high prices, and
since they remain high, he told me last week that their U.S. employment
has been reduced from 22,000 jobs in 2002 to 14,000.
Our environmental policies have played a role in exacerbating the
demand for natural gas and limiting the supply. This hearing will
examine a relationship that many cite as one of the causes for high
natural gas prices--that our clean air regulations have increased
natural gas demand because electricity can be generated cleaner from it
than from coal.
It is important that the American public understand the context of
this discussion. [CHART 1] We have made great progress in reducing our
emissions considering the growth of the economy. This hearing is about
learning how best to continue to improve our air quality.
I am going to focus mainly on what has occurred since enactment of
the Clean Air Act Amendments of 1990, which required cuts in power
plant emissions. [CHART 2] This chart shows that over the past 20 years
the percent of electricity generated from coal has significantly
decreased. From an energy, economic, and national security perspective,
this is bad news as coal is our most abundant and lowest cost domestic
energy source. We are the Saudi Arabia of coal with over 250 years of
supply.
[CHART 3] Over this same period, the percent of electricity
generated from natural gas has increased greatly. Thus, as the
percentage of coal decreased in the 1990's, natural gas generation
increased to meet electricity demand.
As stated earlier, natural gas is used by many different consumers.
[CHART 4] From 1990 to 2005, while production remained basically flat,
the percentage of natural gas used to generate electricity increased
from 19 to 27 percent. This rise without a reciprocal increase in
supply has led to an escalation of natural gas prices and a reduction
in industrial use. The electric sector is projected to increase use by
three more percentage points by 2020, but this analysis is based on the
current regulatory situation--it does not anticipate proposals by some
of my colleagues.
Although this hearing is not about supply, which Chairman Inhofe
covered in a 2004 hearing, it is a big part of this story. [CHART 5]
Out to 2030, consumption is expected to continue to outpace domestic
production by a great deal. Some of this difference is projected to be
made up by liquefied natural gas (LNG) imports from other countries--
unfortunately, just like oil.
This is unacceptable since we have resources at home that we are
not accessing. Simply put, if we increase demand through our policies,
then we must also increase supply. That is why I am a cosponsor of a
bill introduced this week by Senators Domenici and Bingaman to open the
Gulf of Mexico's Lease 181 Area to drilling 100 miles off the Florida
coast. This could provide heat for 15 years for nearly 5 million
homes--enough for all of Ohio's households.
We also took action in the recently enacted Energy bill to:
<bullet> Encourage more production on public lands and in Alaska's
National Petroleum Reserve;
<bullet> Promote the construction of LNG terminals and a pipeline
from Alaska; and
<bullet> Increase the use of clean coal technologies, nuclear
power, and renewables--which will diminish the use of natural gas for
electricity generation.
However, there is no immediate solution to reduce high natural gas
prices today. [CHART 6] Since 1990, natural gas prices have increased
substantially--more than tripling for Ohio families, with an average
price of $16.76 per thousand cubic feet in November 2005. Ohioans are
struggling to pay their utility bills, especially the poor and elderly
on fixed incomes.
To relieve this burden, we have increased LIHEAP funding by about
73 percent since I came to the Senate in 1999 and are working to
provide more funding right now. In considering our environmental
policies, we must bear in mind the impact on the impoverished and
understand that we have already greatly improved our air quality
because LIHEAP is not a solution.
I look forward to hearing from the witnesses about what we can
learn from the past 15 years as we continue to improve the environment
and protect public health. With natural gas prices already through the
roof, families and people's jobs are depending upon us to take into
account the impact of clean air regulations on our Nation's energy and
economic needs.
Thank you.
[The referenced charts follow:]
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Senator Voinovich. Senator Lautenberg.
OPENING STATEMENT OF HON. FRANK R. LAUTENBERG, U.S. SENATOR
FROM THE STATE OF NEW JERSEY
Senator Lautenberg. Thanks very much. Mr. Chairman, I
commend you for calling this hearing and giving us an
opportunity to learn more about this problem that affects
American families across the country, that is, the soaring
price of natural gas. Now, last year the average price of
natural gas, as the Chairman mentioned, was three times higher,
more than three times higher, the average price, during the
1990's, the decade in which gas prices were relatively stable.
This increase hits families hard. It drives up their home
heating bills or electricity bills, the cost of manufactured
goods. There seems to be a consensus among today's witnesses
that there are a number of causes for soaring gas prices.
The first is increased demand. In 1950, as we saw on the
charts, if your eyesight was terrific, the type size was a
little hard from here, but anyway, that in 1950, natural gas
represented just 16 percent of the total energy consumption of
the United States. Today, natural gas meets almost 24 percent
of our energy needs. Another factor in the rising cost, and
since we are focused in this hearing on the cost side of
things, we have to look at how our progress was so slow in
improving energy efficiency.
Now, we know we can do a better job of conserving energy
when we try. After the Arab oil embargo in 1973, our country
got serious about conserving oil. We applied our American
ingenuity and by 1990, our vehicles used about 40 percent as
much fuel as they did in 1973. Energy efficiency is vital to
our national interest today as it was 33 years ago. We have to
recommit ourselves to the goal.
Now, these are the main reasons in my view for the rise in
gas prices, and not the Clean Air Act. What I am concerned
about, Mr. Chairman, is that we are looking in the kind of
wrong direction, I think, if we are going to compare the use of
natural gas and to the requirements of the Clean Air Act and
suggest those are the reasons for the increased price, the
outrageous increased price. It is true that natural gas has
become more popular because it is a clean form of energy. That
is one of its advantages.
But blaming high gas prices on the Clean Air Act is like
blaming obesity on the fact that human beings have to eat to
survive. The Clean Air Act has been one of our most successful
environmental laws, saving lives and preserving our
environment. As a grandfather of a child who has asthma,
childhood asthma, and it is a tough condition. When we look at
the statistics, we see that the growth in childhood asthma has
almost been exponential, and other respiratory diseases. We
have to fight to protect those young people from further damage
to their health.
So I think, Mr. Chairman, that we have to be circumspect
about where the price of natural gas, how it comes about, and
the effects on the standard of health that we have in this
country. We already know that the benefits of the Clean Air Act
have vastly outweighed the cost. I don't ignore the terrible
penalty that the high price of natural gas imposes on families
across the country. It is an essential factor in the lives and
well-being of our people. But at the same time, so is the
quality of the air that we breathe.
So Mr. Chairman, I thank you for doing this. I
unfortunately can't stay, but I appreciate the fact that you
have brought up the subject. I think that we have to again look
very carefully at the consequences of pointing a finger of
blame for natural gas price increases on anything that
otherwise improves the health of our population.
Thank you.
Senator Voinovich. Thank you, Senator Lautenberg.
Senator Inhofe, we are very happy to have you here.
Senator Inhofe. Thank you, Mr. Chairman.
OPENING STATEMENT OF HON. JAMES M. INHOFE, U.S. SENATOR FROM
THE STATE OF OKLAHOMA
First of all, let me say we are honored to have Senator
Voinovich as the Chairman of the Clean Air Subcommittee. I
don't think there is anyone who knows more about the clear air
problems and the Clean Air in the country. I would say this,
too, Senator Lautenberg, that we were supporters of the Clean
Air Act. If you look at what has happened since the Clean Air
Act in terms of the amount of, in terms of what has happened in
the way of pollution, we are driving more miles, the air is
cleaner, so it is a success story.
I don't think anyone is saying it is the Clean Air Act.
What we are saying is that one of the basic things we learned
was supply and demand. You can't conserve your way out of this
problem we have right now, we need to be drilling offshore. We
need to be increasing our supply. That is kind of the basic
philosophical difference that we have on this committee.
But in the case of Senator Voinovich, back when I was
chairman of this subcommittee, he was Governor of Ohio. He came
and testified before this committee, and brings that expertise
that others don't have. So I appreciate the fact that you are
taking on that responsibility.
Two years ago, in March 2004, the full committee held an
oversight hearing discussing the relationship between the
environmental policies and natural gas. At that hearing,
members of this committee heard testimony from witnesses
representing a variety of industries. The witnesses at that
hearing stated that high natural gas prices are destroying U.S.
manufacturing. In fact, the Rhode Island Governor, who was
here, Governor Carcieri, testified that, ``Soon, the Northeast
may no longer be able to offer industry a competitive venue
unless the rising cost of energy is addressed.''
In my State of Oklahoma, the Oklahoma Farm Bureau has
testified that the cost of fertilizer has gone up. You
mentioned this in the State of Ohio. This is all over the
country. That has an effect on the cost of everything that is
produced out there.
I realize that this is a demand-side focused hearing,
asking the extent to which the Clean Air Act has impacted
natural gas. All of the evidence from the EIA, which is an
independent organization, the Energy Information Agency, all
the way from the EIA to the Natural Petroleum Council to
today's witnesses, agree that it certainly has. Members of this
committee probably recall Governor Carcieri's plain statement
that, ``Federal and State policy has encouraged the use of
natural gas because it is clean-burning.''
We have had all these hearings about the pollutants in the
air. Everybody does agree on this, that natural gas is clean-
burning. So the demand is much greater. But demand alone does
not make prices spike. But demand without corresponding supply
increases does. That is very basic.
One could conclude after reading the New York Times or
rhetoric from the environmental groups that the United States
is increasing natural gas production, but the facts show just
the opposite.
This chart from the EIA shows just how much domestic
production of natural gas has declined. People will say in
their testimony it hasn't declined. It has declined. There it
is, right in front of you. The EIA's consumer guide,
``Residential Natural Gas Prices, What Consumers Should Know,''
states that, ``one of the most significant factors why prices
are so high is due to weak production.''
I investigated the reasons why our Nation is experiencing
what has been called by many stakeholders, including the
American Chemical Council, a natural gas crisis. My analysis of
the situation and conclusions were recently published in the
Energy Law Journal. This is this document right here. I
included this graph from Dr. Jeffrey Currie, managing director
of Goldman Sachs and Company in that article. Dr. Currie
testifies that the loss in industrial demand was massive, a 20
percent permanent decline that resulted in the loss of at least
200,000 manufacturing jobs.
Senator Voinovich has talked about the manufacturing jobs
that he has lost in the State of Ohio. We haven't lost that
many in Oklahoma because we didn't have that kind of a
manufacturing base. But it is real. It is there. They are going
to Western Europe and other places where, as you mentioned, the
cost of natural gas here is the highest in the world. This
demand-side focused hearing and this chart depicts an economic
phenomenon known as, ``demand destruction.''
Now, how could anyone look at this and say that there is
not that relationship in supply and demand up there that we are
talking about? It is fairly level. If you look all the way from
1993 to the year 2000, you have your employment, manufacturing
employment and your wellhead natural gas prices, they are
horizontal, they are parallel to each other. Then all of a
sudden, you have the price increase and at the same time, look
at what has happened to employment. This is what happened to
your jobs in Ohio. There it is, right there. As you can see,
when natural gas prices increased to excessive levels, the
demand for that gas drops as plants close down and people lose
their jobs.
I am troubled that the price situation has not improved
since the committee's last hearing. In fact, some members
continue to oppose new domestic production or even importing
gas in the form of LNG. Further, to their own States'
detriment, they advocate for air policies that would increase
those price pressure all the more, such as opposing new source
review reforms and advocating plant by plant mercury controls,
as well as calling for the imposition of carbon caps.
The loop between environmental regulation is clear, as the
congressional Joint Economic Committee stated, ``Environmental
laws passed in the 1980's and 1990's and their subsequent
regulations encourage utilities to use clean-burning natural
gas rather than coal or oil.'' Even California's Energy
Commission concurs, concluding that natural gas has allowed
power plant developers to meet local air quality regulations
and implement the Federal Clean Air Act.
It is time that policymakers recognize that our actions in
Congress can significantly affect the cost of natural gas. It
is such a basic concept, I was speaking this morning to one of
the consumer advocates in the State of Oklahoma. Her name was
Hannah Robson. She was talking about the fact that her gas
prices have increased, have tripled, actually, since last year
at this time. She said, ``don't people in Washington understand
the basic concepts of supply and demand?'' I had to say no.
Thank you, Mr. Chairman.
[The prepared statement of Senator Inhofe follows:]
Statement of Hon. James M. Inhofe, U.S. Senator from the
State of Oklahoma
I want to start off by thanking my friend and subcommittee
Chairman George Voinovich for holding this hearing. Senator
Voinovich has a unique understanding how environmental
policies, specifically air regulations, affect consumers and
businesses.
Nearly 2 years ago, in March 2004, the full committee held
an oversight hearing discussing the relationship between
environmental policies and natural gas. At that hearing,
members of this committee heard testimony from witnesses
representing a variety of industries.
The witnesses at that hearing stated that high natural gas
prices are destroying U.S. manufacturing. In fact, Rhode Island
Governor Carcieri testified that, ``Soon, the Northeast may no
longer be able to offer industry a competitive venue unless the
rising cost of energy is addressed.'' Oklahoma Farm Bureau Vice
President stated that high natural gas prices have forced the
closure of 25 percent of domestic fertilizer industry and that
those high prices threaten what's left, and increase U.S.
dependence, not just on foreign sources of energy, but on
fertilizer.
I realize that this is a demand-side focused hearing asking
the extent to which the Clean Air Act has impacted natural gas.
All of the evidence, from the EIA to the National Petroleum
Council, to today's witnesses agrees that it certainly has.
Members of this committee probably recall Governor Carcieri
plain statement that, ``Federal and State policy has encouraged
the use of natural gas, because it's clean-burning.''
Yet, demand alone does not make prices spike, but demand
without a corresponding supply increase does. One could
conclude after reading the New York Times or rhetoric from
environmental groups that the United States is increasing
natural gas production, but the facts show just the opposite.
This chart from the Energy Information Administration shows
just how much domestic production of natural gas has declined.
EIA's consumer guide, ``Residential Natural Gas Prices:
What Consumers Should Know'' states that: ``One of the most
significant factors why prices are so high is due to ``Weak
Production.''
I investigated the reasons why our Nation is experiencing
what's been called by many stakeholders including the American
Chemistry Council, a natural gas crisis. My analysis of the
situation and conclusions were recently published in the Energy
Law Journal.
I included this graph from Dr. Jeffrey R. Currie, managing
director of Goldman, Sachs & Co. in that article. Dr. Currie
testified that ``[t]he loss in industrial demand was massive: a
20 percent permanent decline that resulted in the loss of at
least 200,000 manufacturing jobs.''
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
This is a demand-side focused hearing, and this chart depicts an
economic phenomenon known as ``demand destruction.''
As you can see, when natural gas prices increase to excessive
levels, the demand for that gas drops as plants close down and people
lose their jobs.
I am troubled that the price situation has not improved since the
committee's last hearing. In fact, some members continue to oppose new
domestic production or even importing gas in the form of LNG.
Further, to their own State's detriment, they advocate for air
policies that would increase those price pressures all the more, such
as opposing new source review reforms and advocating plant-by-plant
mercury controls, as well calling for the imposition of carbon caps.
The link between environmental regulations is clear. As the
congressional Joint Economic Committee stated, ``environmental laws
passed in the 1980's and 1990's, and their subsequent regulations,
encouraged utilities to use clean burning natural gas rather than coal
or oil.''
Even California's Energy Commission concurs, concluding that
natural gas has allowed power plant developers ``to meet local air
quality regulations that implement the Federal Clean Air Act.''
It is time that policymakers recognize that our actions in Congress
can significantly exacerbate our natural gas crisis, and that we must
keep the welfare of our manufacturing sector and the communities
dependent foremost in mind as we legislate.
Senator Voinovich. Senator Jeffords.
OPENING STATEMENT OF HON. JAMES M. JEFFORDS, U.S. SENATOR FROM
THE STATE OF VERMONT
Senator Jeffords. Mr. Chairman, the Environmental
Protection Agency was asked to testify at this hearing at the
minority's request with advance notice. EPA failed to produce
written testimony for this hearing on a topic as important as
the Administration's, as the price of natural gas.
More than 15,000 people work at EPA, and yet the Agency
could not produce a few pages of written testimony for us. I am
extremely disappointed. Mr. Wehrum, at the appropriate time, I
would like to know how this happened.
This testimony is critical, as we are supposed to be
examining whether the Clean Air Act has had any effect on
natural gas prices. I hope we will look carefully at what the
evidence shows. I do not believe the Clean Air Act plays a
major role on the current high natural gas prices.
As many of the witnesses will testify, recent natural gas
price spikes are the result of many factors, including weather,
imports, market speculation and the ratio of actual production
for proven capacity. While new gas power generation has
increased, there are many reasons besides environmental
considerations that make gas more attractive for new power
plants than coal. These reasons are detailed by the Energy
Information Administration in its testimony and Clean Air Act
regulations are but one among many factors cited here.
The EIA also points out that between 1990 and 2000,
electricity generation from coal grew by a larger amount than
electricity generation from natural gas. Moreover, new gas
generation typically replaces older, less efficient gas
generation, leading to more electricity being generated from
less gas.
All of these factors suggest that we should look very
carefully in suggesting that the Clean Air Act played a
significant role in driving the demand for increased natural
gas use in electricity. It is also worth noting that human
health and environmental benefits to the Clean Air Act greatly
outweigh any cost. For example, the Office of Management and
Budget has estimated that the benefits of the acid rain
provision of the Clean Air Act outweigh the cost by somewhere
between 2 and 20 times. EPA estimates that this provision has
saved more than 18,000 lives per year and had enormous benefits
for our forests, lakes and streams. The country still has a
long way to go to improve air quality.
The committee's first and foremost responsibility is to
protect public health and the environment. The Clean Air Act
does just that. We must be mindful that as beneficial as the
use of natural gas to generate electricity and heat for our
homes and produce commodities has been to the public health by
improving the air quality, it has also had real environmental
impacts on our country's public and private lands.
We heard compelling testimony in March 2004 in this
committee that Federal environmental laws were not sufficient
to protect the property of landowners farming adjacent to
natural gas wells. We have now weakened those laws. The new
2005 Energy Law exempts natural gas and oil production sites
from Clean Water Act stormwater permit requirements. It exempts
hydraulic fracturing from the Safe Drinking Water Act.
By deregulating natural gas through these provisions of the
new Energy Law we have provided another incentive to use
natural gas as opposed to other energy sources.
Thank you, Mr. Chairman, for holding this hearing, and I
look forward to hearing from the witnesses.
[The prepared statement of Senator Jeffords follows:]
Statement of Hon. James M. Jeffords, U.S. Senator from the
State of Vermont
Mr. Chairman, the U.S. Environmental Protection Agency was asked to
testify at this hearing at the Minority's request with advanced notice.
EPA failed to produce written testimony for this hearing, on a topic as
important to the Administration as the price of natural gas. More than
15,000 people work at EPA, and yet the Agency could not produce a few
pages of written testimony for us. I am extremely disappointed. Mr.
Wehrum, how did this happen? This testimony is critical, as we are
supposed to be examining whether the Clean Air Act has had any effect
on natural gas prices.
I hope we will look carefully at what the evidence shows. I do not
believe the Clean Air Act plays a major role in our current high
natural gas prices. As many of our witnesses will testify, recent
natural gas price spikes are the result of many factors, including
weather, imports, market speculation, and the ratio of actual
production to proven capacity.
While new gas-fired generation has increased, there are many
reasons besides environmental considerations that make gas more
attractive for new power plants than coal. These reasons are detailed
by the Energy Information Administration (EIA) in its testimony, and
clean air regulations are but one among many factors cited there. The
EIA also points out that between 1990 and 2000, electricity generation
from coal grew by a larger amount than electricity generation from
natural gas. Moreover, new gas generation typically replaced older,
less-efficient gas generation, leading to more electricity being
generated from less gas.
All of these facts suggest that we should be very careful in
suggesting that the Clean Air Act played a significant role in driving
the demand for increased natural gas use in the electricity sector.
It is also worth noting the human health and environmental benefits
of the Clean Air Act greatly outweigh any costs. For example, the
Office of Management and Budget has estimated that the benefits of the
acid rain provisions of the Clean Air Act outweigh the costs by
somewhere between 2 and 20 times. EPA estimates that this provision has
saved more than 18,000 lives per year and had enormous benefits for our
forests, lakes and streams.
The country still has a long way to go to improve air quality. This
committee's first and foremost responsibility is to protect public
health and the environment. The Clean Air Act does just that. We must
be mindful that as beneficial as the use of natural gas to generate
electricity, heat our homes, and produce commodities has been to public
health by improving our air quality, it has also had real environmental
impacts on our country's public and private lands.
We heard compelling testimony in March of 2004 in this committee
that Federal environmental laws were not sufficient to protect the
property of landowners farming adjacent to natural gas wells. We have
now weakened those laws. The new 2005 Energy law exempts natural gas
and oil production sites from Clean Water Act stormwater permit
requirements. It exempts hydraulic fracturing from the Safe Drinking
Water Act. By deregulating natural gas through these provisions of the
new Energy law, we have provided another incentive to use natural gas
as opposed to other energy sources.
Thank you, Mr. Chairman, for holding this hearing. I look forward
to hearing from the witnesses.
Senator Voinovich. Thank you. Senator Carper.
OPENING STATEMENT OF HON. THOMAS R. CARPER, U.S. SENATOR FROM
THE STATE OF DELAWARE
Senator Carper. Thanks, Mr. Chairman. To our witnesses,
welcome. We are delighted that you are here.
Senator Jeffords spoke of his disappointment in not having
EPA's testimony on a more timely basis. Our Chairman spoke to
that as well. I realize that people at EPA could have prepared
their testimony a month ago, and sometimes you have to get it
approved by other folks up the food chain. I would say to not
so much maybe at EPA but those other folks who have to look at
the testimony that you prepared that not only do we expect you
to meet your obligation, but we expect them to help you meet
your obligation to provide us with testimony on a timely basis.
I have a statement I would like to offer for the record, if
I could, Mr. Chairman. I will just say very briefly, this is an
issue we have to get our arms around. There are all kinds of
things we need to do. We need to work on the supply side and on
the demand side. We need to do both, and I think we will have
an opportunity to consider both of them as we get into this
year.
We have this huge abundance of coal. We have the technology
to burn it cleanly. We need to incentivize that technology and
make sure that as new utility plants are built in this country,
and frankly in other countries, that they use American
technology and that we find ways to use this resource that we
are blessed with abundantly and create a lot of the electricity
that otherwise we are creating through natural gas.
We have the ability to do a lot more with wind than we ever
could before. I reminded my colleagues, when I went through the
southern part of California a while ago, mile after mile after
mile of windmill farms generating a lot of the electricity
needs for that part of our country. We have a big GE operation
in Newark, DE, where they are developing next generation solar
energy cells, as we try to make them more competitive in terms
of providing electricity in a variety of places, and they are
coming along very nicely.
I am an advocate of next generation nuclear power plants
and finding, investing some considerable resources into
disposing of the waste product from our nuclear power plants.
It is all part of that. Conservation is a big part of it as
well. This summer is, right now it is cold, they are
forecasting snow maybe for this coming weekend.
But in a few months it will be warm and the summer will be
hot. The air conditioners that are being sold in this country
today have a new CAIR requirement, it is a CAIR 13 requirement,
which compared to the CAIR 8 requirement or a CAIR 10
requirement which would have otherwise been in effect means
that we are going to be using a lot more energy in this new air
conditioners.
Altogether, because of this new CAIR requirement for more
energy efficient air conditioners, there are about 150 power
plants I am told we will not have to build between now and
2020. There is a lot of stuff that we can do, conservation,
alternative forms of energy, clean coal technology, next
generation nuclear.
Finally supply. There is a supply out there, and it is not
all up off of the coast of Alaska. There is probably some extra
supply down in the Gulf of Mexico that we ought to have the
opportunity to explore and to do so in ways that are safe and
sound. So it has to be both of them, and I know that the
Chairman shares this opinion, I suppose we all do.
The price of natural gas is hurting our folks this winter
as we try to heat our homes. It is killing us as we try to
compete with the rest of the world. Whether it happens to be in
agriculture, fertilizer products, chemical products, and so
forth, people who use natural gas a fair amount, the fact that
we pay $10 and other places around the world they are paying $1
or $2, we can't compete with that. We need to be able to
compete successfully.
So Mr. Chairman, I am delighted we are here, glad we are
having this conversation. I am not going to be able to be here
for all the panels. But this is one of those rare panels where
I will actually read every word of your testimony. This is
something I am very much interested in, and delighted that you
are here with us. Thank you.
Senator Voinovich. Thank you, Senator Carper.
I think, I have been saying this for the last 7 years, that
it is time to harmonize our environment, our energy and our
economic interests in this country. The dilemma that we are
faced with today is how do we continue to improve our
environment and public health and at the same time deal with
the crisis that we have in terms of high natural gas prices
that are impacting on our brothers and sisters who are less
able than we are, and even just ordinary Americans, that these
high costs are impacting upon decisionmaking in other areas of
their lives.
Last but not least, how do we deal with the loss of jobs
that we continue to see? There isn't any immediate answer to
it. Our constituents are saying, we need the jobs, we can't
afford the high natural gas costs. So I think somehow we have
to figure out how we are going to move on this rapidly. So I am
hoping maybe we can get some insights from some of our
witnesses today.
We are very pleased today to have Dr. Gruenspecht, Deputy
Administrator for the Energy Information Administration. We
think you guys do a really good job. We are always quoting you.
Bill Wehrum, who is the Acting Assistant Administrator for
EPA's Office of Air and Radiation, Mr. Wehrum, you have been
before this committee in the past, and we welcome you also.
We will begin the testimony with Dr. Gruenspecht.
STATEMENT OF HOWARD K. GRUENSPECHT, Ph.D., DEPUTY
ADMINISTRATOR, ENERGY INFORMATION ADMINISTRATION, U.S.
DEPARTMENT OF ENERGY
Mr. Gruenspecht. Thank you, Mr. Chairman and members of the
committee. I appreciate the opportunity to appear before you
today to discuss developments affecting natural gas use,
particularly in the power sector. My testimony reviews some
changes that have occurred over the last 15 years and our
projections through 2030.
As several of you have mentioned, EIA is an independent
statistical and analytical agency within the Department of
Energy. We do not promote, formulate or take positions on
policy issues. But we do produce data, analyses and forecasts
that are meant to assist policymakers, help markets function
efficiently and inform the public.
We also don't have to clear our testimony, which is very
helpful.
[Laughter.]
Mr. Gruenspecht. In the aftermath of statutory and
regulatory changes designed to increase the competitiveness of
natural gas markets, wellhead natural gas prices moderated
substantially during the 1990's relative to what was
experienced during the 1980's. Gas consumers, particularly
electric sector and large industrial users, also benefited from
increasingly competitive natural gas transportation markets
during this period, further reducing their delivered cost.
However, as I think all of you have mentioned, over the
last 5 years, natural gas prices have indeed climbed
significantly. The average wellhead price last year was
estimated at $7.26 per 1,000 cubic feet in 2004 dollars, more
than triple the average wellhead price during the 1990 to 1999
period. Obviously as you go up the chain to residential
consumers, prices are significantly higher.
Turning to consumption, natural gas use in the United
States fell from 22.1 trillion cubic feet in 1972 to 16.2
trillion cubic feet in 1986, and then back up to about 22.7
trillion cubic feet in 1997. Since then, as has been mentioned,
consumption has been relatively stable. Consumption of natural
gas for electricity generation has increased from a range of
3.2 to 3.9 trillion cubic feet during the early 1990's to 5.1
to 5.8 trillion cubic feet over the last few years. Rising use
of natural gas by electric generators over the past decade has
been roughly offset by a decline in natural gas use in the
industrial sector, and the residential and commercial use has
been pretty flat. The overall use therefore has been pretty
flat.
Continuing to look at the data, it is clear that natural
gas generation has become more efficient since 1990. Gas use
has increased about 84 percent but gas generation has increased
by 118 percent, in large part due to the shift toward more
efficient combined-cycle units.
A lot of new gas-fired generating capacity has been built--
230 gigawatts between 1990 and 2005. Again, nearly all the
capacity added was natural gas-fired, as Figure 2 in my written
testimony shows. That technology allows capacity to be added in
modest increments, close to major load centers with a
relatively short construction time. That technology, along with
favorable natural gas prices during the 1990's, that we are
unfortunately not experiencing now, the 1987 repeal of the
provisions of the Power Plant and Industrial Fuel Use Act that
had previously prohibited the use of natural gas by new
generating units, and Clean Air Act provisions favoring the use
of inherently cleaner fuels all played some role in driving
this outcome.
The natural gas share of generation has not grown nearly as
rapidly as its share of capacity. Under present natural gas
market conditions, which are a cause of concern, many of the
new natural gas plants are not operating very intensively and
older, less efficient oil and natural gas plants are being
retired.
I expect EPA will discuss the Clean Air Act and emission
reductions. I would point out that emission reductions in the
electric power sector were mostly achieved by adding emission
control equipment or switching to lower sulfur coal at many of
the Nation's coal plants. Cumulative retirements of coal-fired
units between 1990 and 2004 represented less than 2 percent of
that capacity and were generally concentrated among smaller
units.
I would also add that some of the smaller industrial and
commercial users of dirtier fuels, or less inherently clean
fuels, face some of the same issues. Pollution control is less
cost-effective on smaller units. So we saw less residual fuel
oil being burned in the commercial and industrial sector, and
less coal being burned in the commercial and industrial sector,
although they were never really big users. Those areas also
switched toward natural gas.
Although natural gas consumption grew more in percentage
terms than coal generation between 1990 and 2005, coal
generation actually increased by a larger amount in absolute
terms. A major reason that so few coal plants were added during
the 1990's relates to the need for the type of capacity that
utilities needed. As you all know, load is not flat. It varies,
has peaks and valleys.
In 1990, the average capacity factor of coal-fired power
plants was only 59 percent while the average capacity factor of
nuclear plants and other baseload technology was only 66
percent. These relatively low rates of utilization left
substantial room for increases in coal and nuclear generation
without the need to add new capacity.
Turning from historical data to long-term projections, our
latest long-term outlook was issued in December 2005. It is
based on existing Federal laws and regulations in effect as of
October 1, 2005. We included sections of the Energy Policy Act
of 2005 that establish specific tax credits, incentives or
standards, as well as the Clean Air Act Interstate Rule and the
Clean Air Mercury Rule. We don't try to project what
appropriations action is going to be taken on other parts of
the bill. That's why we don't have to clear our testimony.
In the Annual Energy Outlook 2006 reference case, we do
expect wellhead prices for natural gas to decline from current
levels in real terms to a level of $4.50 per 1,000 cubic feet
in 2016. That is in 2004 dollars again, real dollars. Lower
than we are today, but not nearly as low as the prices during
the 1990's. After 2016, we expect wellhead prices to increase
again, reaching nearly $6 in real terms by 2030.
In terms of consumption, we do expect total demand to
increase from now through about 2020 and then to remain
relatively stable through 2030. The projected leveling off
after 2020 is driven by changes in the mix of fuels to generate
electricity, as we expect natural gas at those prices to lose
market share to coal during the latter half of the projection
period, sort of the reverse of what happened over the last
period of time. So we expect natural gas demand for electricity
generation to grow, but actually after 2020 we think it will be
back down in favor of coal.
Between 2019 and 2030, we expect natural gas consumption in
the electric power sector to decline by about 15 percent.
Again, that is all under current laws and regulations. As some
of the opening statements recognized, changes in those laws and
regulations could have a significant impact. We expect demand
for electricity to continue to grow over the next 10 years.
Both natural gas and coal generation will increase as existing
plants are used more intensively. Renewable generation will
grow, in part due to the Energy Policy Act provisions.
But after 2010, we expect capacity additions to be
increasingly dominated by new coal plants. We also have some
nuclear capacity additions due, in our reference case, to the
provisions of the Energy Policy Act. Barring unexpected
problems and developing control technologies, we don't expect
the Clean Air Interstate Rule and the Clean Air Mercury Rule to
pose a significant barrier to the expansion of coal-fired
generation. However, previous EIA analyses suggest that other
types of emission regulation, particularly if greenhouse gas
limits are included, could have a significant impact on
projected coal use.
That completes my testimony, Mr. Chairman. Thank you. I
realize I have gone a little over. I would be glad to answer
any questions you or the other members may have.
Senator Voinovich. Thank you, Mr. Gruenspecht.
Mr. Wehrum.
STATEMENT OF WILLIAM WEHRUM, ACTING ASSISTANT ADMINISTRATOR,
OFFICE OF AIR AND RADIATION, U.S. ENVIRONMENTAL PROTECTION
AGENCY
Mr. Wehrum. Thank you, Mr. Chairman.
I will begin by saying a couple of things. It is an honor
and a privilege to have the opportunity to speak to this
subcommittee. It is my responsibility to have testimony
prepared and submitted to the subcommittee reasonably before
the scheduling of the hearing. I failed in that responsibility.
For that, I apologize to you.
I will say three things. One, these issues are
extraordinarily important to EPA and to the Administration. So
our failure to submit testimony on time is not a reflection of
lack of interest or lack of concern about these issues.
The second thing is, if I have the privilege of speaking
with you again, I will commit to you that this is not going to
happen again.
The last thing I will say is, we stand ready to assist this
subcommittee in its investigation and are prepared to submit
additional information, respond to questions and provide the
data and information that you need to fully vett this question.
At the beginning of this Administration, the President
issued the National Energy Plan to address a vast array of
energy-related policy issues and developed a flexible, market
based program, Clear Skies, to achieve our Nation's air quality
goals without compromising our economic growth and energy
security.
In developing these initiatives, the Administration exerted
great care to structure policies that are protective of human
health and the environment while ensuring continued diversity
of fuel use. Taken together, the NEP and Clear Skies
acknowledge the important role that coal, our most abundant
energy resource, plays in the mix as a source of low cost and
abundant electricity. By the same token, these efforts directly
help to alleviate demands on our Nation's gas supply and can be
part of the long-term solution for our Nation's environmental
and energy priorities.
Natural gas has increasingly been used in the electric
power generating sector over the last 15 years. Between 1990
and 2003, 115 gigawatts of new combined cycle gas, which is 690
units, was added to the fleet, compared with only 11 gigawatts
of new coal capacity, representing 68 new units.
It is clear that Clean Air Act requirements have an effect
on natural gas utilization and supply. Many different programs
affect the operation of utilities and large industrial units.
EPA has not seen evidence, however, that its regulations of the
power sector are a substantial factor in the pricing of natural
gas.
EPA has taken many steps to design regulations and policies
which maintain our Nation's diverse fuel mix. I will first look
back at three major programs already adopted that affect the
power sector. I will then talk about our recent actions and
plans for the future.
Enacted in 1990 by Congress, the Acid Rain Program was
tailored specifically to the power sector to reduce
SO<INF>2</INF> and NOx emissions from power plants. The
centerpiece of the program is an innovative market-based cap
and trade approach. This cap and trade approach provides
greater certainty that emissions reductions will be achieved,
while at the same time allowing industry the flexibility they
need. By embracing markets, allowing flexibility and requiring
accountability, the Acid Rain Program has had only small
impacts on natural gas markets.
EPA's NOx-MSIP call is another cap and trade program. It is
designed for the seasonal control of NOx emissions from
electric power industry in the eastern United States. During
the development of the program, EPA forecast there would be
some fuel switching to natural gas. However, as with the Acid
Rain program, we found that the relative share of gas in the
generation mix does not change substantially.
EPA's New Source Review Program allows for facilities to
plan for the ability to combust multiple fuels, so long as
state-of-the-art technology applies to the combustion of each
fuel. Since NSR was first enacted in 1977, we have seen
variation in the choice of fuels companies use to meet
industrial energy demand. There have been periods of expanded
coal use and periods of expanded natural gas use. We don't have
information indicating that NSR has been a significant driver
in this variation.
EPA finalized the Clean Air Interstate Rule, the Clean Air
Mercury Rule and the Clean Air Visibility Rule in 2005. These
rules give industry flexibility in how to achieve needed
emissions reductions, allowing industry to make the most cost
effective reductions and limiting impacts on consumers. If
States choose to participate in the CAIR and CAMR, and I
apologize for reverting to acronyms, but it comes with the
territory, the CAIR and CAMR are cap and trade programs. Power
plants would be allowed to choose the pollution reduction
strategy that best meets their needs.
To address natural gas supply and demand concerns, EPA
designed these programs to achieve large emissions reductions
through the installation of pollution controls on coal-fired
units, rather than by switching to natural gas. From analysis
that EPA released last fall, we expect these three programs
combined will increase natural gas prices by about 1.6 percent
in 2010, and about 2.8 percent in 2020.
It is important to note that beyond the regulatory
programs, the Clean Air Act authorizes many voluntary
partnerships that work to provide more natural gas supply by
encouraging companies to improve the efficiency of natural gas
delivery and use. EPA analysis indicates that in 2010, these
voluntary programs will have reduced national demand for
natural gas by about 3 percent.
For example, in 2004, Natural Gas STAR, one of our programs
which is a partnership between EPA and the oil and natural gas
industry, offset the equivalent of 61 billion cubic feet of
natural gas. Natural Gas STAR's accomplishment is just one
example of the environmental and energy savings benefits that
can be achieved by well-designed voluntary programs.
Importantly, EPA has taken many extensive efforts to design
regulations and policies which maintain our Nation's diverse
fuel mix. I can assure you that in implementing its mandate to
protect public health and the environment, EPA will remain
vigilant in its assessment of the impact that various policies
may have on fuel use and will be particularly sensitive to
natural gas cost and supply issues.
Thank you for the opportunity to be here. I would be happy
to answer any questions.
Senator Voinovich. Thank you, Mr. Wehrum.
Dr. Gruenspecht, in your testimony, the fourth figure in
your testimony shows that the EIA projects natural gas prices
to be at their peak now, with a significant reduction in the
next 10 years, before prices start increasing again. What
assumptions have you made, first of all, how fast are they
going to come down? Is it going to happen the 9th or 10th year?
Then second, what presumptions have you made? Have you
presumed that the liquefied natural gas, the Energy bill that
we passed, is going to be a reality? Do you take into
consideration the possibility of drilling Lease 181? Just what
are the things that you base your statistics on?
Mr. Gruenspecht. That is a very good question and I will
try to answer. First of all, price is the hardest thing to look
at, because we are operating, as has been suggested, in an area
where supply seems to have not been very responsive to price,
and demand is not very responsive to price. So very small
shifts in either demand or supply can have a big impact on
price. We have seen that this winter, where a warm January has
led to a very sharp drop in prices. We are not comfortable
where they are, but they have dropped a lot from where they
were if we were having this hearing a month ago.
So in our long-term price projections, we try to abstract
from all of the short-term factors, which are important. We do
have liquefied natural gas coming on in greater quantity. In
2005, imports were about the same as in 2004. Even with the
existing terminals that we have now, the five that we have, and
there are some others under construction, we do expect
liquefied natural gas imports to increase over time.
We do not have in our projection the area 181 sale, because
current laws and regulations, current regulations, anyway, rule
out the 181 sale. I do understand that the Department of
Interior yesterday released a draft proposal involving some
future leasing, although I am not familiar with details.
We do have some increases in unconventional gas, tight
sands gas, which has started to be a success story.
Senator Voinovich. What is that again?
Mr. Gruenspecht. Tight sands gas and some coal bed methane
increases. So those are reflected in our projections. It is a
tight balance between supply and demand, but we do see the
liquefied natural gas and some of the unconventional gas
resources, and also some recovery in the Gulf. Obviously, in
2005 we have a significant issue with gas production in the
Gulf of Mexico, due to the hurricanes.
So those are the types of factors that we have included in
the short run. Over time, we have the Alaska Pipeline coming
in, although that doesn't come in until about 2015. So we do
have pipeline gas coming down from Alaska in this long run
projection.
So it is LNG, pipeline gas from Alaska, tight sands gas,
and coal bed methane but conventional gas production is pretty
anemic. We also have pipeline imports from Canada being pretty
anemic. Canada has supplied about 15 percent, 16 percent of our
gas. We expect that to fall off.
Senator Voinovich. Could you put that down on a piece of
paper in terms of what are your presumptions based on, so we
can get some sense of what happens, for example, if things
become destabilized over in the Middle East?
Mr. Gruenspecht. Absolutely.
[The referenced information follows:]
Liquefied Natural Gas (LNG).--What would happen to U.S. LNG
imports, if the Middle East continues to be destabilized and LNG
terminals are not built?
The Energy Information Administration's (EIA) Annual Energy Outlook
2006 (AEO2006) projections do not specifically address how foreign
political instability affects world LNG markets, but the AEO2006 does
address the question of the potential impacts of reduced LNG supplies
on U.S. energy markets in one of the sensitivity cases analyzed. The
AEO2006 Low LNG Supply case assumes LNG supplies are significantly
restricted. As a result, future LNG imports remain slightly below 1.4
trillion cubic feet per year through 2030, which is about 31 percent of
the 4.4 trillion cubic feet projected to be imported in the reference
case.
As a result of the reduction in LNG imports, the wellhead price of
natural gas in the Low LNG Supply case is projected to be between 4 and
10 percent higher between 2010 and 2030 than in the reference case. In
2030, the natural gas wellhead price is $0.44 per thousand cubic feet
(mcf) higher, increasing from $5.92 per mcf (2004 dollars) in the
reference case to $6.36 per mcf in the Low LNG Supply case. As a result
of these higher prices, domestic natural gas production is 6 percent
higher, at 22.0 trillion cubic feet, and domestic natural gas
consumption is 6 percent lower, at 25.3 trillion cubic feet.
The higher gas prices in the Low LNG Supply case have the greatest
impact on natural gas consumption in the electric power-sector because
that sector is the most price-sensitive, and due to the competition
between natural gas and coal for power generation. In the Low LNG
Supply case, electric power sector-natural gas consumption is projected
to be 21 percent lower than in the reference case, at 5.0 trillion
cubic feet in 2030.
Senator Voinovich. I think we are talking about liquefied
natural gas coming from Qatar.
Mr. Gruenspecht. We don't model specifically where it comes
from. But Qatar is definitely a big source of gas; also
Trinidad and Tobago. Liquefaction facilities, I believe, we
have built in Nigeria; there are some being built up in Norway
and Russia. So there are a lot of places. But Qatar is an
important source of gas.
Senator Voinovich. Then you also have in your information,
or to your knowledge, do you know where these LNG facilities
are supposed to be built, or are projected to be built here in
the United States?
Mr. Gruenspecht. In terms of receiving?
Senator Voinovich. Yes.
Mr. Gruenspecht. We do see a need for more terminals, but
our crystal ball is not good enough to actually say exactly
where they are. We do presume that there are some new terminals
to serve the East Coast. We do have two terminals under
construction on the Gulf that we assume are built and come into
use.
There is some supply of liquefied natural gas both to
Florida and Southern California, although exactly where those
terminals are located, we cannot say. For instance, it is
possible to locate in Baja, Mexico and serve Southern
California, but we would not presume that. But we can certainly
tell you what areas are served by liquefied natural gas.
Senator Voinovich. So the two things that I am concerned
about is one, if the Middle East continues to be destabilized,
the impact that could have, and then recently someone said they
were concerned that folks over there were concerned that we
would build the terminals to take the liquefied natural gas. So
the two come together in terms of speculating if that doesn't
happen, what impact would that have on your projections.
Mr. Gruenspecht. We would be glad to provide that.
Senator Voinovich. I would also like to get from you if,
for example, we got Lease 181, because it is an enormous amount
of natural gas, with that kind of information, it really helps
us in terms of our decisionmaking.
Senator Jeffords.
Senator Jeffords. Mr. Wehrum, I want to understand better
what happened to your testimony. When did your testimony go to
OMB?
Mr. Wehrum. It began, the first draft went to OMB on
Monday, Senator.
Senator Jeffords. Did you or your staff receive any
direction from any member of this committee or staff not to
produce written testimony?
Mr. Wehrum. No, Senator.
Senator Jeffords. Did you or your staff receive any request
to alter your testimony?
Mr. Wehrum. The preparation of testimony, Senator, is a
collaborative effort. It begins with EPA and we prepare our
first draft of the document. But EPA is but one part of the
Administration. So it is common practice when preparing
testimony of this sort that it is submitted to other offices
within the Executive, including OMB, including in this case DOE
and others, so that they have an opportunity to review our
testimony and make sure that our testimony is consistent with
their understanding of these issues.
Senator Jeffords. Did that review result in changes?
Mr. Wehrum. Yes, Senator.
Senator Jeffords. Mr. Wehrum, EPA has projected that
implementation of its current set of Clean Air Act regulations
will not lead to widespread fuel switching, is that correct?
Mr. Wehrum. In preparing our testimony and preparing for
this hearing, Senator, we focused on the impact of Clean Air
regulations on the power sector. It happens to be the sector
for which we have the most information and it seems to be the
most highly relevant for purposes of the topic of this hearing.
After our review of the array of regulations that apply to
the power sector already and those that will come to apply in
the future, our assessment is that we expect some fuel
switching has occurred as a result of our regulations from coal
into natural gas and some fuel switching will occur in the
future from coal into natural gas.
Our goal, particularly for the regulations we have adopted
in the recent past, those that we have developed and
implemented, was to maintain the fuel diversity within the
power generating sector, while at the same time meeting our
environmental responsibilities. We have sought to strike a
balance and hit that sweet spot, so that we protect the
environment and human health, but at the same time, we do it in
the smartest possible way and in a way that is designed to
minimize impacts on the fuel diversity and the fuel choices
within the power sector.
Senator Jeffords. If the Clean Air Act contributes to
higher natural gas prices, would it be responsible to public
policy to fail to implement the Act on that basis?
Mr. Wehrum. Senator, as I said a moment ago, our
projections, both our assessment of regulations that have been
adopted so far and our projections with regard to regulations
that have not yet come into effect but that have been adopted,
such as CAIR and CAMR and the Cleaner Visibility Rule is that
they will have small incremental effect on natural gas
utilization within the power sector. We do expect some small
amount of fuel switching out of coal and into gas.
So in answer to your question, our goal is to be as smart
as we possibly can in implementing our regulations and in
designing our regulations, so that where we do expect an
impact, which we do expect with these regulations, we try to
design it in such a way that it is not going to have a
significant impact on the overall fuel variability and
diversity within the power sector.
Senator Jeffords. If I understand your testimony correctly,
it appears that the three main pieces of the Clean Air Act that
apply to electricity generation do not appear to have
substantially affected natural gas prices. Is that correct?
Mr. Wehrum. Yes, Senator. Our assessment is that the
regulations that have been implemented, as well as those that
will be implemented, are going to have an impact on natural gas
utilization in the power sector. We have projected that they
will have an impact, therefore, on natural gas pricing. But
based on the information we have available, we project the
impact to be relatively small.
Senator Jeffords. Well, that is your projection, is it that
future rules will also not have such an effect on gas prices?
Mr. Wehrum. In the case of my testimony, I focused on CAIR
and CAMR and the Cleaner Visibility Rule. Our projections are
that we expect an effect, but the effects should be small,
Senator.
Senator Jeffords. Thank you very much. I appreciate your
answers.
Senator Voinovich. Senator Inhofe.
Senator Inhofe. Thank you, Mr. Chairman.
I am just as upset as anyone else is that we didn't get the
testimony in advance as we were supposed to get, and all that,
but let's don't carry this too far. During the Browner
administration, we never had it in here. I remember Carol what
was her name, Kay McKinty, is that right? Anyway, she was CEQ
of the White House at that time in the Clinton White House.
Senator Jeffords was chairman at that time. It was very rare we
got anything in advance.
That doesn't excuse you, we need to have it, I think you
have already expressed enough regret on that. So we don't need
to beat that dog any longer.
Mr. Gruenspecht, you state in your testimony and I am
reading here that stringent greenhouse gas limits could result
in a major shift from coal to other fuels for electric
generation. I think that is significant. I would like to have
you give a little more detail about that.
Mr. Gruenspecht. Perhaps unlike some of the other emissions
issues that have been dealt with in the Clean Air Act, mostly
with technology, adding emissions controls--were there to be,
say, a cap and trade program, and again, we are not advocating
that it is just a description--were there to be a cap and trade
program for greenhouse gas emissions that included carbon
dioxide and were that program to involve a significant permit
price, say, an allowance price for carbon dioxide, that would
have a very significant impact on the delivered prices of
different fuels, particularly coal, which is of the fossil
fuels, the most carbon dioxide- or carbon-rich.
There are several studies that EIA has done in response to
various requests I think from various members of this committee
and others. So depending on what the program was and whether or
not it had a safety valve, you could see very large impacts on
relative fuel prices and those would have an effect, we
project, on what fuel gets used in existing facilities and also
what new facilities get built. So that is really where we are.
Senator Inhofe. OK. While I am asking this question, put
our chart No. 2 back up, because I have another question I want
to ask concerning that.
But I had a question I was going to ask a panel member of
the next panel. But in light of some of the things that you
said that were quite unexpected, at least to me, I would like
to direct this at you instead, Mr. Wehrum. In a 2003 article,
economist Lynn Keasling of the Reason Foundation and Richard
Methune of the Federal Reserve Bank in Chicago wrote, ``Air
quality regulations have led to a situation in which the only
economical way to build new power plants is to fuel the
facilities with natural gas.'' They further state, ``This
emphasis on natural gas as the way to achieve air quality
improvements without dramatically increasing power generation
costs has had the unforeseen consequence of reducing the
resilience of natural gas markets.'' Many others agree.
Are you seriously telling us by your testimony that the
uncertainty caused by unclear New Source Review regulations has
had absolutely no impact on the Clean Air regulations?
Mr. Wehrum. No, Senator, that is not my testimony. If I may
digress for one moment, to make a correction to an answer for
Senator Jeffords, the testimony went to Interagency Review on
Tuesday of this week, not Monday of this week, Senator Inhofe,
and I apologize for that mistake.
Senator Inhofe. Very minimal impact, is that what you are
saying? You said very minimal impact?
Mr. Wehrum. In answer to your question, we clearly, ``we''
meaning EPA and the Clean Air regulations that we have
developed clearly impose significant costs on the power sector.
There is no doubt about that. The last estimates that I saw
were that when constructing a new coal-fired power plant,
anywhere from 20 to 30 percent roughly of the installation cost
that goes into the project is the cost of the air pollution
controls necessary to meet the standards that we have adopted.
So, that is not an insubstantial cost of installing and
operating a facility such as a coal-fired power plant. Costs
are similarly applied even to natural gas-fired power plants of
the sort that have been installed over the past few years. So
we clearly impose costs on the industry, Senator, there is no
doubt about that.
What I was attempting to convey is, well, let me say two
other things. Part of the difficulty of putting this testimony
together is, we are one factor, we being the Agency and the
regulations that we implement. We are one factor of many that
affect fuel availability, fuel supply and ultimately pricing.
So we had great difficulty frankly trying to discern as best
possible how much of an impact that we have had.
So my testimony is that we have evidence that we certainly
have had an effect in terms of imposing costs, control costs,
on the industry. We have had an effect in that we know that
fuel switching has occurred for purposes of complying with our
regulations and our standards. What we don't have is evidence
indicating that those costs and those effects were a
significant or a substantial factor in the supply issues that
Dr. Gruenspecht has testified about, or the current pricing
situation.
Senator Inhofe. Is it your intention to get that
information, to develop it?
Mr. Wehrum. We would certainly endeavor to do that,
Senator.
Senator Inhofe. My time has expired, but I would like to
have both of you look at this chart here. You heard my
description of it first. This did not come from you, Dr.
Gruenspecht, but do you agree in the conclusion that I have
when you look at the spike in the price and the jobs dropping
down that there is that relationship and it does exist?
Mr. Gruenspecht. You are referring particularly to 2001?
Senator Inhofe. That is correct.
Mr. Gruenspecht. There certainly seems to be a correlation
there. Causation is again very tough to sit at the table and
establish. So give me a chance to think about it, and perhaps I
could get back to you for the record.
Senator Inhofe. That would be fine. I call it a no-brainer.
But thank you very much.
[The referenced information follows:]
Natural Gas Prices and Employment.--The Energy Information
Administration has not conducted any analysis of its own on the
question of the impact of rising natural gas prices on manufacturing
sector employment. A July 2005 Department of Commerce study ``Impacts
of Rising Natural Gas Prices on the U.S. Economy and Industries''
(https://www.esa.doc.gov/ngfr.cfm) included the following statement:
``We found that higher natural gas prices in the 2000 to 2004
period had a somewhat mild depressing effect on GDP but a more serious
negative effect on employment, especially outside of manufacturing. We
estimated that in 2000 and 2002 these higher prices reduced real GDP
growth by 0.2 percentage points in each of these years. For 2003 and
2004, the growth rate was unaffected. In terms of jobs, total civilian
employment was lower by an average 489 thousand jobs in each of those
years. Manufacturing employment was lower by an average 79 thousand
jobs, about 16 percent of the total civilian jobs lost.
There is no clear evidence, except for nitrogenous fertilizer
manufacturing, that higher natural gas prices were the primary reason
for the poor economic performance of natural gas intensive industries
during 2000 to 2004. These higher prices were certainly an additional
burden on these industries, but their performance was already
deteriorating prior to the onset of higher gas prices.''
Senator Inhofe. How about you, Mr. Wehrum?
Mr. Wehrum. Senator, I am not in a position to answer the
question.
Senator Inhofe. OK, thank you very much.
Senator Voinovich. Senator Jeffords.
Senator Jeffords. Mr. Gruenspecht, in your review, have you
seen power companies planning for future baseload capacity in
natural gas?
Mr. Gruenspecht. Our sense is that, as the testimony
indicated, a lot of combined-cycle capacity was built. I think
some people who invested in that capacity may regret that they
have invested in it. But it was built, it was put in place, it
is there. We do believe it will be used as electricity demand
grows.
But we would think that under the fuel price conditions
that we project, it would be less attractive to continue making
those kinds of investments. There will obviously be some
regional variation, and certainly we expect some new gas
capacity to be built beyond what people already have. But
again, a lot of what was built, we believe, was planned at a
time--I have described what gas prices were like in the 1990's.
The late 1990's is a period when a lot of that capacity was
built.
We are projecting some relief in gas prices from where they
are today. But as I said in response to an earlier question, we
don't think gas prices are likely to get any place near where
they were in the 1990's. Because of that, that technology is
probably less attractive.
But you will find certain parts of the country where it
would still be built.
Senator Jeffords. Some have claimed that high natural gas
prices are the result of increased demand for natural gas in
the power sector due to the Clean Air Act. Assuming for the
purposes of argument the Clean Air Act did result in some
increase in natural gas generation, can you tell us what effect
that has had on current high natural gas prices?
Mr. Gruenspecht. What I would say is this. In the electric
power sector, once you have gas capacity, and I know you are
from New England and New England is an area that has built a
lot of new natural gas capacity, demand in that sector is not
very price-responsive because electric providers will
understandably pay almost anything to keep the lights on, so to
speak. So, as the electric power sector has become a major user
of natural gas, and I did describe how that has increased, in
addition to thinking about the level of natural gas consumption
one has to think about the price responsiveness. In the case of
electric power providers, their demand is not very price-
responsive.
Residential demand is not very price-responsive. When it is
cold, people use more. It is responsive to the weather, but it
is not very responsive to the price. Generally people keep
their house warm and they struggle with paying the bills.
So one thing that has happened with increased use of
natural gas for electric generation is the proportion of total
demand that is responsive to price is smaller. The industrial
sector is one of the really few remaining places where demand
is responsive to price.
So you have this supply that is not very responsive to
price. You have the demand of the electric sector that is not
very responsive to price. You have demand in the residential
sector not very responsive to price. So when things don't add
up, you see, No. 1, prices rising a lot, which is of great
concern, obviously. No. 2, it appears that the equation gets
balanced by adjustments primarily in the industrial sector. I
think that is a description of what has been going on.
Senator Jeffords. In your testimony you note that between
1990 and 2005 coal generation in the power sector increased by
27 percent, which in absolute terms was larger than the
increase in natural gas generation in the power sector.
Assuming that is true, then doesn't it make clear that many
electric power generators chose to continue using coal, rather
than switching to natural gas, while continuing to comply with
the Clean Air Act?
Mr. Gruenspecht. I think there is no doubt that the effect
of the Clean Air Act has been to favor inherently cleaner
fuels. So if you are comparing the world with the Clean Air Act
to the world without the Clean Air Act, we think in the latter
case you would see more coal than you are seeing, and less gas.
But for the most part, the response of people who owned
existing coal plants has not been to retire them. I cited
retirement statistics; in fact, very few coal plants have been
retired. The response of coal plant operators has primarily
been to retrofit their facilities with emissions controls and
continue to increase the utilization rate of those facilities.
Again, in 1990, the utilization rate was relatively low,
for both coal and nuclear facilities, compared to what they are
today. So that has been sort of a good news story, I think, in
that we have been able to get more power out of the same
baseload facilities.
But again, the nuclear plant utilization rate is now in the
low 90 percent, it is not going to get much higher. The coal
one has risen substantially. There may be a little room for it
to get higher. But at some point, there does need to be new
baseload. At a time when people thought gas prices were $2 a
million Btu at the wellhead, people were thinking combined-
cycle would be a good intermediate-to-baseload technology. With
the higher natural gas prices, that is less attractive. We
expect to see more coal plants built, despite the capital costs
that Mr. Wehrum mentioned.
Senator Jeffords. Thank you very much.
Senator Voinovich. My theory is that Clean Air regulations
exacerbated the demand for gas and I think some of our
environmental policies limited the supply. So we had two things
coming together.
In the process of doing that, you mentioned that in terms
of price, the residential homeowner has to pay it because they
have nowhere to go. The industrial user has some place to go,
and they leave. In your study of what has happened, have you
taken into consideration in your projections the tremendous
loss in jobs that we have had in the manufacturing sector,
particularly that sector that uses natural gas for feed stock,
fertilizer, the chemical industry?
Your projections also show very, very tepid growth. In your
projections, what are you looking at in terms of where
manufacturing is going in this country?
Mr. Gruenspecht. As the question points out, there are
certain areas of manufacturing, particularly fertilizer,
certain bulk chemicals, that are very natural gas-intensive.
For those types of activities, there is no question that the
perception of what the price of natural gas is going to be is
critical to their location decision. There is just no way
around that.
For other types of manufacturing activities, fuel costs
would be one factor that would be important to them. There is
no question that it is important. But there would be other
factors that would also determine their location.
Senator Voinovich. Then your projections, if I'm not
mistaking it, 1 percent growth, is that it?
Mr. Gruenspecht. Right. I need to go back and check, but
certainly the growth in the energy intensive manufacturing, we
see it as slower than the growth of the overall economy.
Senator Voinovich. I would be interested to see what your
projections are for the next 10 years, vis-a-vis the previous
10 years in terms of where we were, to get a feel for just what
is happening in terms of our economy.
Mr. Gruenspecht. I will get that for you.
Senator Voinovich. If you are capable of doing that.
Mr. Gruenspecht. I hope so.
[The referenced information follows:]
Energy-Intensive Manufacturing.--What are your projections for
energy-intensive manufacturing industries and the overall economy for
the next 10 years compared with the previous 10 years?
From 1995 to 2005, the overall economy grew at an annual rate of
3.3 percent per year, while energy-intensive manufacturing grew at an
annual rate of 0.4 percent per year. While the economy experienced a
recession in 2001 and slow growth in 2002, energy-intensive
manufacturing was hit even harder, such that energy-intensive
manufacturing showed almost zero growth between 2000 and 2005. However,
in our Annual Energy Outlook projections, the growth rates are expected
to increase from recent levels. Between 2005 and 2015, the projected
annual growth rates are 3.1 percent per year for the overall economy
and 1.5 percent per year for energy-intensive manufacturing.
Senator Voinovich. Good. I only have this comment, and that
is that because we have not sat down as a Nation and looked at
our energy economy and environment, and looked at cost
benefits. I think Senator Jeffords and Senator Carper made very
good points, and Senator Lautenberg. We have terrific benefits
over on the health side. But we kind of look at things without,
we just look at energy, I call them the silos. We go over here,
we look at environment over here, we look at economy over here.
If somebody doesn't just sit back and look at this in terms
of a long-range plan, how do you balance these up in terms of
your policies that the Nation is going to undertake? What is
your comment on that? Don't you think maybe it might be a good
idea to start to look at the big picture and weigh all these
things so we are doing things in a more rational way?
Mr. Gruenspecht. Is that for me?
[Laughter.]
Senator Voinovich. Yes.
Mr. Gruenspecht. For better or for worse, EIA--I have to
describe it, and I have only been there 3 years--is a smaller
picture Agency. Clearly, just as a citizen, as regards whatever
I have done in the past in my life--I have worked in other
types of positions and in academia--sure, there is a need to do
that. The way we look at things at EIA, maybe it is self-
serving, you can think of it as a marathon race where one group
or one analyst has to do it all, provide the whole integrated
picture from beginning to end. Or you can look at it as a relay
race.
At EIA, given the statute that created EIA, we do deal with
a very particular part of it. So we don't deal with the health
benefits, and while we might talk about emissions, but we don't
talk about air quality, because we don't deal with dispersion
modeling. Is there a need, as a citizen, would I be happy if
people would look at that? Sure.
But EIA's mission is, I think, very valuable for looking at
one piece of it very closely so that piece is not forgotten.
You probably need some people who look at the whole thing in a
less detailed but more holistic way. You probably need other
people who look at individual parts in more detail.
So it is very hard to disagree, and I wouldn't disagree on
a personal level. But I don't think the EIA, given its statute,
is in a position to do that.
Senator Voinovich. The reason I raise it, I recall that
when I was Mayor of Cleveland, and perhaps, Senator Inhofe,
when he was Mayor of Tulsa, we would have all these programs to
create jobs in the city, Federal programs. Then we had the
Environmental Protection Agency, which had these new
regulations that made it more difficult in terms of
manufacturing.
I kept asking myself, do these people ever sit down and
talk to each other and figure it out? I have to tell you
something, we really have to think about that, I think, as a
country. If we don't start, and I talk about the infrastructure
of competitiveness, we have to start to think of things
differently than we have in the past.
If we keep doing the silos, that is, you do your thing,
somebody else does another, we are in real deep trouble.
Because the competition out there is more formidable than ever
before. We could perhaps be a little bit lax in some of the
things we are doing. I think we are at the stage right now
where if we don't get on this thing pretty rapidly, it is going
to really have a dramatic impact on the standard of living of
our people in this country.
I have no other comments.
Senator Inhofe.
Senator Inhofe. I just want to, I was shown by my staff in
this publication that we actually put together the quote by
Alan Greenspan when he said, ``We have been struggling to reach
an agreeable tradeoff between environmental and energy concerns
for decades. I do not doubt that we will continue to fine tune
our areas of consensus. But it is essential that our policies
be consistent.''
Do you agree, Dr. Gruenspecht, that our policies are not
consistent right now? I'm having a hard time here, Mr.
Chairman.
Mr. Gruenspecht. Well, again, given where I come from, we
generally don't take positions on policy. But I will say that
yesterday, Mr. Greenspan's former lead person on energy joined
the Energy Information Administration.
Senator Inhofe. Well, you might go back and ask him and
then get back to me.
Mr. Gruenspecht. I will go back and have a discussion with
him.
[Laughter.]
Senator Inhofe. Give me the answer for the record, then.
Mr. Gruenspecht. Thank you, sir. I appreciate your letting
me squeeze away.
[The referenced information follows:]
It is certainly the case that some Federal policies have tended to
increase demand for natural gas, at the same time as other Federal
policies have served to constrain natural gas supply. In combination,
the result has been that natural gas prices have been higher and more
volatile than otherwise would have been the case. It is to be expected
that these policies have had these implications. In this vein, Alan
Greenspan noted in 2003 that:
``We, in the United States, have long struggled to reach an
agreeable tradeoff between environmental and energy interests in our
public policy debates. This process will no doubt continue. Through it,
we must reach policies that strike a balance among competing concerns
while avoiding inconsistencies. For example, we cannot, on the one
hand, encourage the use of environmentally desirable natural gas in
this country while being conflicted on larger imports of liquefied
natural gas (LNG) on the other. The result of such contradictions are
debilitating spikes in prices.''
He also has noted the following: ``. . . there are still numerous
unexploited sources of natural gas production in the United States. We
have been struggling to reach an agreeable tradeoff between
environmental and energy concerns for decades. In a sense, there are
two value systems, the economic value system and the environmental
value system, and there is no mechanistic tradeoff. As an economist, I
cannot provide a clear mathematical formulation to allow you to compute
that tradeoff; this is a judgment that the Congress will have to
make.''
Senator Voinovich. We want to thank you very much for being
here this morning. Mr. Wehrum, I know the next time you come
back, we are going to probably have that testimony a week
before.
[Laughter.]
Mr. Wehrum. Signed, sealed and delivered, Senator.
Senator Voinovich. Thank you.
Our next panel we have testifying, we thank you panelists
for being here. Arthur Smith, who is testifying on behalf of
the American Gas Association. He is the senior vice president
and Environmental Counsel for NiSource. Mr. Joel Bluestein, who
is president of Energy and Environmental Analysis. Jack Gerard,
who is president and CEO of the American Chemistry Council.
Mr. Smith, we will begin with you.
STATEMENT OF ARTHUR E. SMITH, JR., SENIOR VICE PRESIDENT AND
ENVIRONMENTAL COUNSEL, NISOURCE, INC., ACCOMPANIED BY: PAUL
WILKINSON, AMERICAN GAS ASSOCIATION
Mr. Smith. Thank you, Senators. Good morning. My name is
Arthur Smith. I am senior vice president and environmental
counsel with NiSource. NiSource, Inc. is a member of the
American Gas Association. NiSource is the parent company name.
It does have an electric power company in Indiana and natural
gas companies serving 3.7 million natural gas customers,
including 1.4 million natural gas customers in Ohio. As a
matter of fact, in 66 out of 88 counties in Ohio, it goes under
the name of Columbia Gas of Ohio.
As has been pointed out, natural gas markets have been
extremely tight in the last 5 years with supply unable to keep
pace with rising demand. New supply initiatives are critical to
correcting this imbalance. But demand side actions are also
necessary, particularly on the efficient use of natural gas for
electricity generation.
There is no doubt that increased natural gas demand from
the power sector has contributed to the natural gas price
volatility. As has been pointed out, from 1999 to 2005, there
was significant installation of natural gas-fired combined
cycle plants as well as lower efficiency peaking plants.
While most of this capacity is outside of EPA's trading
programs, it is certainly true that easier environmental
permitting for these gas-fired units contributed to this
growth. Other factors, such as energy markets, the low capital
cost for the equipment and the then-low natural gas prices,
also caused this growth. New coal-based generation was
generally discouraged by environmental regulatory costs as well
as the uncertainty in terms of the future requirements.
As a result, electricity, power companies have increasingly
relied on less efficient natural gas peaking technology to meet
increasing power demand. This trend of increased natural gas
usage will likely continue until there is significant
investment in new fuel diverse, baseload power capacity,
including increased market penetration of efficient coal
technologies, solar, wind and efficient natural gas combined
heat and power systems.
As an example, with our power company, NIPSCO, since about
2002, NIPSCO invested $250 million in pollution control
equipment to comply with EPA's trading programs. Without adding
any new generation capacity, NIPSCO did increase its natural
gas usage during this period. I suspect that is fairly typical
from the power utility sector.
New generation and energy efficiency that would reduce this
natural gas usage is not encouraged within EPA's trading
programs for those plants larger than 25 megawatts. Moreover,
if there is a desire to increase baseload generation with lower
carbon intensity, the efficiency of the new generation needs to
be significantly higher than the coal generation technologies
currently in the permitting stage.
I agree with you, Senator, that public policymakers must
certainly consider both energy and environmental goals when
developing regulations that impact the electricity generation
sector. That is environmental goals must be achieved in concert
with pursuit of greater fuel diversity generation and energy
efficiency in the electric generation mix.
Thank you.
Senator Voinovich. Thank you.
Mr. Bluestein.
STATEMENT OF JOEL BLUESTEIN, PRESIDENT, ENERGY AND
ENVIRONMENTAL ANALYSIS, INC.
Mr. Bluestein. Thank you, Mr. Chairman and members of the
committee, for the opportunity to testify today. My name is
Joel Bluestein, and I am the president of Energy and
Environmental Analysis, Inc., located in Arlington, VA.
There is a common belief that the recent boom in gas power
plant construction is the cause of increased gas consumption
for power generation, that the recent focus on gas-fired power
plants is due primarily to environmental regulations, and that
if we could just change the existing environmental regulations,
there would be a big shift to coal-fired power plants, gas
consumption would go down and gas prices would go back to $3.
Unfortunately, there is little data to support these
suggestions.
The historical data clearly show that gas-fired electricity
generation has been increasing continuously and at about the
same rate since at least 1990, well before the recent boom in
power plant construction and the increase in natural gas
prices. Despite the construction of over 200 gigawatts of new
gas-fired capacity in the last 6 years, the growth rate of gas-
fired generation has not increased. In fact, it declined
slightly from 2002 through 2004.
Not only have the new gas power plants not increased gas
consumption, they actually have reduced gas consumption
relative to what would have occurred in their absence. This is
because many of the new plants were built in regions that were
already dependent on older, less efficient gas power plants. In
these regions, the new, more efficient plants have displaced
the older, less efficient power plants, reducing the amount of
gas that would have otherwise been consumed.
This increased efficiency has reduced natural gas
consumption for power generation by about 1 trillion cubic feet
in 2004, about 15 percent lower than it would otherwise have
been. That said, there are some States in which utility
regulations are allowing incumbent utilities to continue to use
older, less efficient plants, while new, more efficient plants
sit idle or under-utilized. Remedying this situation is one way
to rapidly reduce the amount of gas consumed for power
generation.
The question raised in this hearing is whether or how much
Clean Air regulation has led to the increased use and
construction of gas-fired power plants. In fact, air regulation
is only one of many drivers for the use of gas, and probably
not the most important one. Our environmental regulations do
not single out gas for priority treatment. The most significant
differentiation between fuels historically has been to set less
stringent limits for coal plants than for gas plants.
While gas plants are cleaner than coal-fired plants, our
environmental regulations set more stringent limits for cleaner
plants, such that the cost per ton of NOx control for new
natural gas plants can be higher than the equivalent cost for
new coal plants. In addition, many of the recent environmental
programs have been cap and trade programs, which provide great
compliance flexibility, and are designed to avoid forcing the
shutdown of older, high-emitting plants. Both the EIA and the
EPA have done numerous studies, both retrospectively and
prospectively, to look at the effect of these programs. It has
been found that the effect on fuel switching is very small.
If anything, these programs have under-valued the
efficiency and low emissions benefits of gas-fired plants by
providing them with fewer trading allowances than provided to
coal plants with the same output. So gas plants are not getting
preferential treatment on emission regulation.
The recent generation of gas power plants was planned
during the late 1990's and was built by independent, non-
utility power developers expecting to compete in a
restructured, competitive power market. There was a premium on
being the first plant into that market. Natural gas prices were
below $3. Combined with a low capital cost, about half the cost
of a coal plant, high efficiency, short construction time,
smaller footprint, more flexibility in locating, more
operational flexibility and other advantages, gas plants were
the obvious choice. Any plausible change in environmental
regulation would have had little effect on the choice of gas
technology over coal at that time.
The economics of new plant construction have changed
significantly now. Higher gas prices have resulted in higher
electricity prices, creating a very high value for coal-fired
generation. The U.S. Department of Energy is currently tracking
about 135 planned or proposed plans comprising 80 gigawatts of
new coal generation. While not all of these proposed plants
will ultimately be built, all of them are designed to cost
effectively meet the current emission requirements for
conventional pollutants.
In discussing the construction of new coal plants, it is
commonly asserted that passage of the Clear Skies Act will
facilitate the construction of new coal plants by providing
certainty regarding regulation of conventional pollutants.
While this is true, it ignores the fact that uncertainty over
future regulation of CO<INF>2</INF> emissions is an even larger
impediment for potential builders of coal plants. An increasing
number of power companies are making clear that they cannot
commit to investment in new coal plants without reasonable
certainty on their future CO<INF>2</INF> liability. They are
suggesting that it may not be less regulation, but more
comprehensive for pollutant regulation that would help
accelerate the construction of new coal plants.
Coal continues to be the backbone of our electricity supply
system and increased use of clean coal generation is one
important component of a response to high gas prices. However,
environmental regulation has not been the primary reason for
the recent growth in gas generation and going forward,
environmental regulation can actually encourage increased coal
use if it addresses CO<INF>2</INF> as well as conventional
pollutants.
Given the importance of the natural gas supply demand
issue, we need to focus on near-term supply and efficiency
responses that can provide benefits in the shorter term. Thank
you, and I will be happy to respond to questions.
Senator Voinovich. Thank you, Mr. Bluestein.
Mr. Gerard.
STATEMENT OF JACK N. GERARD, PRESIDENT AND CEO, AMERICAN
CHEMISTRY COUNCIL
Mr. Gerard. Thank you, Mr. Chairman, Senator Inhofe and
Senator Jeffords. It is a pleasure to be here today. We
appreciate the opportunity to testify on behalf of the 900,000
men and women in the business of chemistry in the United
States, an industry that is essential to our economic well-
being as well as our national security.
I would like to focus my comments today on the consequences
of high natural gas costs on the chemical industry and by
extension on the manufacturing sector generally. Chemistry
consumes more than 10 percent of the Nation's natural gas. We
use it to run our plants and it is the key ingredient in the
products we make. Since our products are found in 96 percent of
all manufactured goods, it is safe to say that natural gas is a
key ingredient to the Nation's manufacturing economy.
Last year, the Nation's natural gas bill topped $200
billion for the first time in history, as compared to $50
billion in 1999. Higher natural gas costs, according to the
National Association of Manufacturers, are a major reason why
the Nation has lost 2.9 million manufacturing jobs since 2000.
In a few short years, the United States has gone from having
some of the lowest natural gas costs in the industrialized
world to the highest cost market. The impact has been
staggering.
In a few short years, the U.S. chemical industry has lost
more than $50 billion in business to overseas operations and
more than 100,000 high paying jobs in our industry have
disappeared. Put another way, the chemical industry went from
posting the highest trade surplus in the Nation's history in
the late 1990's to becoming a net importer in 2002.
Other impacted industries include forests and paper,
agriculture, aluminum and steel, carpets, bedding and
furniture. They all have a similar story. For example, since
2002, 36 percent of the U.S. fertilizer industry has been shut
down or mothballed. Since 2000, the forest products industry
has closed 232 mills, lost 182,000 jobs or roughly 12 percent
of their entire employment.
How did this happen? When you look at the data, the answer
to us is quite clear: too little supply being chased by rapidly
increasing demand. For example, since the 1990's, there has
been a 35 percent spike in natural gas consumption by the
utility sector. That is 1.5 trillion cubic feet of new demand.
In that same period of time, domestic natural gas production
remained flat, or as the chart showed earlier, has actually
declined.
Existing sources of supply were unable to meet new sources
of demand. When the supply response was needed, it didn't come.
To us, the real failure of Government policy was that it did
not open up new sources of natural gas supply to meet demand
growth. Government stood by while short supplies of natural gas
led to a price bidding war that drove more than 10 percent of
the industrial demand out of the market, referred to earlier as
demand destruction.
For too many years, U.S. policy has been trying to have it
both ways. It can't continue. It is failing millions of
Americans whose livelihoods depend on reliable supplies of
natural gas at affordable prices. The high price of natural gas
is driving the global chemical industry out of the United
States. For example, today there are more than 120 world-scale
chemical plants, plants that cost more than $1 billion apiece,
that are under development around the world. Only one of those
is slated for the United States.
Business Week calls it the hollowing out of the Nation's
industrial core. By contrast, 50 of those 120 new chemical
plants are being built in China.
That is why it is so frustrating to us as an industry to
see proposals in Congress that would extend the off limits
signs in the outer continental shelf out to 150 and 250 miles
off Florida's coast, even as Cuba is hiring Chinese energy
interests to explore and drill for energy in waters that are
barely 45 miles off the Florida coast. It is time for a change.
It is time to strive for balance and reason.
Senator Voinovich, to your point earlier, we need to
harmonize our policy in the United States to protect our
economic well-being. Three quick suggestions we believe the
Congress can do. First is to continue to curb demand through
efficiency and conservation. Second is to diversify our fuel
sources. In the 1990's, natural gas-fired power generation
emerged as a technology of choice. Today there are other good
choices, advanced clean coal, nuclear power, renewables and
others.
Last, we need to increase supply. We can no longer escape
the fact that our Nation's currently available supply of
natural gas can no longer meet the Nation's growing demands. We
must increase access to new sources of supply that are
currently off limits to use.
In conclusion, the issue is restoring balance to the U.S.
natural gas policy in a way that helps manufacturers compete in
global markets, permits utilities to branch into leading edge
technologies and ensures a reliable and affordable supply of
natural gas for America's homes and businesses.
Thank you again for the opportunity to testify. I am happy
to answer any questions.
Senator Voinovich. Thank you, Mr. Gerard.
We are going to have at least one set of questioning for 6
minutes for each of us. I would like to take my 6 minutes and
give each of you 2 minutes to comment upon what you have just
heard here. Mr. Bluestein, Mr. Gerard, Mr. Smith, you have
heard each other's testimony. I would be interested in any
other additional comments that you would like to make before
this committee.
Mr. Smith. One thing I would like to point out is the
importance of the natural gas for heavy manufacturers like
members of the American Chemical Association. A lot of these
plants and many more have the capability of not only using
natural gas for feedstock, but for very efficient onsite
generation of electricity supplies. A lot of your members,
Jack, I am sure, have this kind of onsite generation, which is
a very efficient form of using natural gas for power
generation.
It is also important for their economic well-being, because
they can moderate their price, expected price of energy costs.
It also keeps them in the country if they make that kind of
investment.
One of the ways that that can be linked up to EPA's trading
program is to allow increased flexibility for the power
companies to buy the electricity coming from the onsite
generation, because you get the benefit of increased power
coming into the electric grid system, as well as the ability to
offset some of the financial costs of the onsite generation.
That kind of linkage of power generation outside of each of
EPA's trading programs can be brought into the trading
programs, so investment capital can flow into that kind of
capital.
Senator Voinovich. Mr. Bluestein.
Mr. Bluestein. Thank you.
I think there is no disagreement here about the concern
over high gas prices. I think everyone understands that. I
think in particular, the concern for the effect on consumers
and industry and businesses, I don't think there is any
disagreement about that.
I think even most of the solutions we agree on, and all the
Senators have listed a wide range of solutions, of different
kinds of supply options, energy efficiency. I don't think
anybody disagrees that we need to make better use of our coal
resources through new clean technology.
I think the issue today is how important is environmental
regulation in that list of responses to the natural gas price
issue. I guess my message simply is, I think it is pretty low
on the list. I think of all the things that we have listed
today, it is probably the lowest on the list, and at best, it
is a mid- to long-term response. Any new power plants built
today are not going to come online for 5 or 10 years.
So there are more effective things, there are quicker
things. I think those are the ones that we need to focus on.
Because those are not so easy to do, either. I think that is my
basic message.
Senator Voinovich. Mr. Gerard.
Mr. Gerard. Mr. Chairman, if I could add just another
thought or two on the consequences of what we are seeing in our
industry, and again by extension, to the whole manufacturing
sector. I am not sure we fully appreciate the ripple effect
that these fundamental decisions or choices have across our
entire economy. Every job created in the chemical industry, for
example, has a multiplier effect of 5.5 jobs in other industry
sectors.
One of the things we have often talked about in our sector
is what we refer to as the brain drain, or the impact we are
having on sciences, the engineers in this country and others.
As we move our facilities overseas, one particular company that
is a U.S.-based entity, has been here for many years, has just
built a multi-billion research and development facility in
China. They hire Chinese engineers, Chinese scientists and
others to do the R&D that typically would be done on our shores
with our scientists, engineers, et cetera.
Today the chemical industry is second only to the defense
industry in the amount of money we spend on research and
development. Annually, we spend $22 billion for research and
development in this country as an industry. One out of every
eight patents that is issued by the patent office goes to our
industry.
We have multiplier effects up and down the entire economy.
When you look at the business of chemistry, we impact close to
26 percent of the entire employment in the United States.
So when we are pushed offshore by matters like natural gas
prices, we are taking those multipliers, we are taking all that
activity that we once did here in the United States, and we are
siting it in China, we are siting it in the Middle East, we are
siting it wherever we can get our feedstock at a reasonable
price.
Dow Chemical's chairman testified a few months ago here in
the Senate Energy and Natural Resources Committee. He had a $4
billion facility slated for Freeport, TX. Due to natural gas
prices, that facility has now been moved to Oman. Why? Because
the natural gas price is killing them. They will take with them
their research and development people, the scientists and
others, and will hire those in other parts of the world.
So I think there are much bigger impacts here than just
finding affordable natural gas for the chemical industry or
others. We need to think about our basic R&D capability, the
technology development that we have that comes from industries
like ours. So I would hope that would be part of this
harmonization or understanding of how we harmonize policies in
the United States to protect our economic and national security
interests.
Senator Voinovich. I just wanted to comment that the report
that was asked for by two of our Senators from the National
Academy of Sciences emphasized that. We're talking about the
brain drain, and we're not producing the scientists and
engineers that we need in the country. They tied that in with
the whole issue of energy independence, how the two go
together. I think you have brought that pretty clearly to our
attention.
Senator Jeffords.
Senator Jeffords. I defer to Senator Inhofe.
Senator Inhofe. Mr. Chairman, Senator Jeffords has kindly
agreed that if I only just take 2 minutes instead of 6, I can
go ahead. I have to go back to the office.
First of all, I think there are some things we all agree
on. We do have a crisis. We need all of the above, nuclear,
clean coal technology, renewables. That is what really our
effort here is.
The question, I have two quick questions, real quickly. One
would be, for Mr. Gerard, that according to Mr. Bluestein's
testimony, uncertainty with respect to mandatory CO<INF>2</INF>
control inhibits more coal use. In your opinion, if the United
States were to ratify the Kyoto Treaty, would your industry
most likely benefit, or would the strains that you are already
experiencing increase even more?
Mr. Gerard. We think the strains would increase even more.
Senator Inhofe. Second, I would like to, I couldn't seem to
get anyone to agree, it seems to be pretty obvious to me, on my
chart No. 2, does that make sense to you, that there is a
relationship between the price of natural gas and----
Mr. Gerard. Well, like you, Mr. Chairman, having lost
100,000 jobs in our industry directly related to that increased
natural gas price, we believe there is a direct correlation.
Like you, we think that is a no-brainer. It is clearly
happening.
Senator Inhofe [continuing]. Thank you, Mr. Gerard, and
thank you, Senator Jeffords, Mr. Chairman.
Senator Voinovich. Before you go, we talked about this
harmonizing. I would like to suggest that perhaps you talk to
the leader and maybe Senator Jeffords could talk to his leader,
about perhaps getting a group of us together from both this
committee and the Energy Committee, to sit down and start to
look at this whole picture as to how do we harmonize, new
regulations versus the need for more energy, so that we could
come back with some kind of maybe a comprehensive
recommendation on how we deal with this current crisis that we
have, recognizing that we want to maintain, continuing to
improve our environment and public health.
Senator Inhofe. I think that is an excellent idea, and I
would certainly do that. Thank you, Mr. Chairman, thank you,
Senator Jeffords, for letting me go ahead here.
Senator Voinovich. Thank you.
Senator Jeffords.
Senator Jeffords. Mr. Smith, all four of your
recommendations about how we might best meet America's natural
gas energy demand all relate to increasing supply. Do you have
any other recommendations on how prices could be reduced from a
demand side approach or otherwise?
Mr. Smith. The written testimony that you are probably
referring to did spend a lot of time on the supply side of the
equation.
Senator Jeffords. Yes.
Mr. Smith. In my oral testimony, I also indicated the
importance of the focusing on the demand side, particularly as
it pertains to the power sector. Because that is the
incremental growth that has put increasing pressures on natural
gas volatility.
That is where I think, and that is where I spent my time in
my oral testimony, talking about the importance of encouraging
new, efficient baseload and having the environmental
regulations give credit for energy efficiency. Because I think
with that kind of signal, there will be more signals for using
natural gas at a higher efficiency which will reduce that
demand.
Most of the natural gas-fired plants during that 5-year
window, up to 2005, were either simple cycle turbines at 30
percent efficiency and combined cycle at 60 percent efficiency.
Well, with the diminution of the market for the 60 percent
efficient plants, because of the high price for natural gas,
you know, unfortunately a lot of the natural gas being utilized
by the power sector is being consumed at 30 percent efficiency.
That is very low on the scale, considering that you can get up
as high as 80 percent efficiency with combined heat and power
systems.
So I think that demand equation, it is the utilization of
natural gas, can be as important as some of the supply options.
Senator Jeffords. You mentioned a number of factors
affecting natural gas prices, including weather, the mature
nature of existing gas fields, and demand side issues, such as
increased use of natural gas for electricity generation. Do you
favor relaxing environmental regulations, including Clean Air
Act regulations, as a means of reducing natural gas prices?
Mr. Smith. No. No, I think the pollution control
requirements are critically important for the country. However,
the stringency needs to be related to how it gets done. How it
can get done can count clean, new baseload capacity and energy
efficiency to accomplish the same environmental goals, but
reduce the natural gas demand.
For many historical reasons, the Environmental Protection
Agency has never counted energy efficiency as a way of
achieving an environmental objective. They are starting. But
even though there has been a lot of talk about pollution
prevention, why energy efficiency pollution prevention hasn't
been incorporated into the base Clean Air Act programs remains
a mystery.
Senator Jeffords. Thank you.
Mr. Bluestein, in your testimony, you state that future
carbon dioxide regulation might actually accelerate the
construction of new coal plants. Would you elaborate on that
for me?
Mr. Bluestein. As I said, we are starting to hear more and
more power company executives, and we heard a lot of this
yesterday in various events, say that it is very difficult for
them to commit to construction of new coal-fired power plants
that are going to be around for 40 or 50 years without having
some certainty on how those are going to be treated on
CO<INF>2</INF>.
They are not suggesting that the United States implement
the Kyoto Protocol. But they are looking to other, more recent
proposals, including some that have been proposed in the
Senate, that look at very gradual reductions, sometimes using
various kinds of economic safety valves, that would let them
know where they are headed and allow them to make investments
and to find the investment capital. It is not just the
companies, it is the investors who have to put up the money and
are concerned about whether that is going to be a good
investment.
So there are starting to be proposals that start to address
the issue, but also give industry and the investment community
some comfort that we can do this in a reasonable way and would
allow companies to go forward with more construction of coal
plants.
Senator Jeffords. Again to you, what evidence is there that
the increased demand for natural gas in the electricity
generation is a substantial factor in current high natural gas
prices? Aren't there other factors that impact the price of
natural gas to a greater degree?
Mr. Bluestein. Well, like anything, the price of gas is
dependent on a lot of factors. For example, it is related to
the world price of oil. Last year, we saw the price of gas
increase from the spring, around $6 to just before the
hurricanes about $8. A lot of that was due to the high world
price of oil.
Certainly the increased demand for natural gas from the
power sector is one important piece of the gas price issue. I
wouldn't say that it is not important. But there are other
factors as well, including the supply side. Again, the gas
price issue has a lot of different factors. I think the key is
which ones are most significant and which ones can we most
quickly and effectively influence.
Senator Jeffords. Thank you, Mr. Chairman.
Senator Voinovich. Thank you, Senator Jeffords.
Mr. Smith, when you were testifying, you were talking about
the fact that, why did we go to natural gas. You did mention
easier permitting, low capital costs and low gas costs. We have
had a big debate in this committee over New Source Review. We
are trying to get some kind of certainty in regard to its
importance to knowing what is going to be expected.
What impact, from your perspective, has this uncertainty
about New Source Review had on decisions that were made in
terms of natural gas?
Mr. Smith. Well, in permitting, the smaller natural gas
generation, of course, you have to go through New Source
Review. Typically that is a process that well understood and
you do the analysis and that process for new generation has not
been a real impediment. I think it has slowed some of the newer
natural gas-fired generation, but it hasn't been a block to
that new generation. That is one reason why the ease of
permitting caused a lot of that type of generation to come into
the market.
Where it has had more of an effect is the application of
New Source Review for existing generation, which is the bulk of
the baseload capacity in the country. Most of the new gas
generation is intermittent and peaking. So New Source Review,
as it is applied for the bulk of the baseload generation, has
had an impact, because that is when you get into the debate on
the interpretation of when you trigger New Source Review. I
think it is probably a true statement that because of that
uncertainty there have not been a lot of efficiency
improvements in the existing generation fleet, and therefore
that extra amount of baseload capacity has not come into the
market.
Senator Voinovich. I have heard complaints about, the fact
is that I want to make my plant more efficient and bring my
costs down, but I have an unimaginable line to go through in
terms of regulations. So you just throw up your hands and say,
we are not going to do it. I think your emphasizing efficiency
is something that we ought to start to pay more attention to.
You have a lot of customers in Ohio.
Mr. Smith. Yes, sir.
Senator Voinovich. I was lucky that through our local gas
company, somebody signed me up, I had an opportunity to sign up
for $8 per MCF. I remember when I did that for 3 years, and my
wife said, you're crazy to do that. I said, no, I don't think I
am. We have a lot of people that are paying $12 and $13 per
MCF.
What is your company telling these people about how those
costs are going to come down? That is the big question I have,
everywhere I go. My natural gas costs are eating me up, even,
look, I am in a modest, middle class neighborhood. Even the
restaurants are saying because of oil costs and because of
natural gas costs, people are not coming in and eating any
more. One woman said, I think I am going to have to go out of
business, Senator.
What are you telling people? What do we need to do to bring
them down as soon as possible?
Mr. Smith. Sir, with demand and supply, on that knife's
edge, it has caused very large price swings with very small
events. As you know, before this winter, we had larger events
with the hurricanes. We have been increasing our communications
with our customers to conserve, to be careful about what they
use. We have tried to get them to sign up to fixed price
programs, like you had the foresight to do, as well as
encouraging programs to help the lower income people for their
payment for natural gas.
But these are short-term things.
Senator Voinovich. The thing is, they are looking down,
what is it going to be next year or the year after, and what
things have to happen for that to occur. Right now, LIHEAP, we
don't have enough money for LIHEAP. The fact of the matter is,
we need more money.
Are your companies saying to our folks at the Office of
Budget and Management that hey, we need some more money in this
area, because we have a lot of folks out there that are going,
you know.
Mr. Smith. I believe the American Gas Association has been
active in that regard. But as you say, this is just a short-
term situation. The important question is how we get more
supply and demand efficiency so we can get off of that knife's
edge that is causing the pricing volatility. That is the long-
term answer.
Senator Voinovich. Would you be talking, the American Gas
Association, telling the President to go forward? I understand
he has the authority to go forward with leasing 181. We have a
bill in that does it, another bill from two Senators from
Florida that says we shouldn't do it. But I thought the
Administration could do that. What options are available right
now without getting legislation to them to increase that
supply?
Mr. Wilkinson. Senator, my name is Paul Wilkinson. I am
vice president for Policy Analysis at the American Gas
Association. We would agree with you that Lease Sale 181 should
go forward as quickly as possible. Given the supply constraints
that we have heard about this morning and the impact on the
industrial sector that has been talked about this morning, and
given the fact that you cannot drill for gas off the East Coast
of the United States, you can't drill off the West Coast of the
United States, you can't drill in the Eastern Gulf of Mexico,
you can't drill in much of the Rocky Mountains, we don't have a
pipeline down from Alaska, we have not completed a new LNG
import facility in three decades, we would like to see action
on all those fronts.
We are very aggressive supporters of LIHEAP, that is a
stop-gap measure. The efficiency side of the equation is being
addressed. The average residential natural gas consumer in this
country consumes 25 percent less gas per household per year
today than it did in 1980. Homes are tighter, equipment is more
efficient. We have applications in the industrial sector that
used to be 30 percent efficient, now they are 99 percent
efficient.
So because of these prices, people are moving aggressively
forward on their own to increase their energy efficiency. The
bottom line is that we will not see moderation in prices and
stability in prices until we increase supply.
Senator Voinovich. I have taken probably more of my time
than I want, but without objection, I would like to have--what
is your name again?
Mr. Wilkinson. Paul Wilkinson.
Senator Voinovich. Paul Wilkinson, that you submit to us
your best thoughts on what it is that we can do to get this
supply up and what impact you believe it might have on my
answering the lady that run's Marta's Restaurant that maybe
some of her customers might come back here in the next year or
so, because there is some hope that their natural gas costs are
going down. Would you do that?
Mr. Wilkinson. Certainly, Senator.
Senator Voinovich. Is that all right with you, Senator
Carper?
Senator Carper. Yes.
Senator Voinovich. We would like to have you submit that to
us. Thank you.
Senator Carper.
Senator Carper. Thanks, Mr. Chairman. To our witnesses, I
apologize for slipping out of here. Senator Voinovich has spent
a fair amount of time trying to figure out how to make our
country more competitive with the rest of the world. Part of it
is a world class, educated work force and making sure our kids
know how to read, write, think, do math and science stuff when
they come out of our schools, go out into the work force. Part
of it is trying to figure out how to make us more competitive
on health care. We spend a whole lot more money than the rest
of the world on health care. Frankly, outcomes aren't any
better in a lot of instances.
I have been looking at health care information technology,
Mr. Chairman, trying to figure out how to save costs and save
lives on that. I am pleased to be able to come back before you
and finish up here.
I am going to ask each of you to give me a takeaway,
because I missed your comments. I am going to read your
prepared testimony. But I want to ask each of you to give me a
takeaway that, if you remember nothing else today, Senators,
remember this point or maybe two.
But I have a specific question, if I could, for Mr. Smith.
In testimony, I want to say 3 years ago, before, I think it was
the House Committee on Energy and Commerce, a fellow named Jeff
Curry, who was the managing director of Goldman Sachs at the
time, may still be, but he stated, ``The core problem with the
U.S. natural gas market is inadequate infrastructure.'' I think
he went on to say, ``Although public attention has been focused
on the ability to grow the natural gas supply,'' and we have
talked about that, heard about that just a moment ago, he said,
``the underlying storage and transportation are the primary
constraints on both supply and demand growth.''
So I guess what I want to ask you is, do you agree that the
lack of natural gas infrastructure is having a significant
impact on natural gas markets? Second, if we had more supply
today, do you think we could move it to where it is needed? We
talked a little bit about this pipeline from Alaska and this
area off of Florida. But in Congress, I support, I know Senator
Voinovich has supported the construction of this new pipeline
from Alaska. But is there more we could be doing to bring that
project or other projects to market?
If you could just take maybe a minute or two on that, I
would be grateful.
Mr. Smith. With the new areas of natural gas supply, you
are going to have a shift of where you have to bring the supply
into the existing distribution system in the United States. So
with that shift, you do have to have additional natural gas
transmission to bring that new supply to market.
I know AGA, as well as INGA, has been very involved with
what has become a fairly lengthy process of getting the
permitting to put in the transmission pipeline. I know our
company is looking to build a pipeline in New York State, we
are one of the equity partners in that, called the Millennium
Pipeline, which is one of those pipelines that would allow the
Canadian natural gas to come in to the New York area, all the
way down to one of the more constricted metropolitan areas, the
New York metropolitan area.
That pipeline has been in the permitting stage for about 8
years. It is increasing, with the pipeline coming through, into
an urban area, it maybe a 1,000 mile pipeline, but if there is
2 miles coming through a developed neighborhood, that presents
a challenge. Because there is considerable public input into
the construction.
So we have been looking, and I think we have testified in
front of committees about how you can get the public input into
the NEPA evaluation up front and quickly, and then come to a
decision, rather than--because that delay, if you come up with
new supply and you don't have the ability to bring in the
natural gas through a transmission pipeline, you still don't
have the supply.
Senator Carper. All right. Thank you. I am going to come
back to you for a closing thought, a takeaway, if you will. But
I am going to move over here to Mr. Gerard and ask if you would
give me a good takeaway. If you think of all the stuff that
you've said or maybe others have said that you think we ought
to take home with us, what would it be?
Mr. Gerard. From our vantage point, Senator, as we talked
earlier about job loss in the industrial community, in the
United States, which has been significant over time, first and
foremost, we think the quickest, shortest term answer to a lot
of this is to increase supply. There has to be conservation and
there has to be improvements in efficiency. In our industry, we
believe that makes good business sense.
Last year, we gave awards to 11 companies who improved
their power efficiency such that those 11 companies saved
enough energy to heat and power Minneapolis for 1 year, that's
11 companies. So we believe efficiency and conservation makes
good business. We are on that road now. But we can't do it on
our own.
Secondarily, and perhaps more importantly today is, we have
to increase supply. We believe the 181 debate is a good start.
But that is not a long-term policy. That will provide us 5 TCF
roughly, in a market that consumes about 22 on an annual basis.
But longer term, we have to adjust our energy policy in this
country. We are the only developed Nation I am aware of that
denies access to our vast energy resources.
It is frustrating for industries like ours to see what is
going on in Cuba today. Ninety miles off of our coast, they
have hired and have contracts with the Chinese. Because of our
understanding with the Cubans, they are drilling within 50
miles of our coast. Yet the debate in the Congress is over
locking up another 150 to 250 miles off the coast of Florida.
To us, it doesn't make a bit of sense. It is illogical and we
wonder why we are all going to other places in the world to
build our facilities.
A quick signal to the marketplace that we are going to open
up 181 in the short term and develop a longer term gas policy
that is going to provide the stability we need, we believe,
will be the signal the market needs to moderate gas prices in
the short term.
Senator Carper. Good. Thank you.
Mr. Bluestein.
Mr. Bluestein. I think there is agreement across the board
here about the importance of addressing natural gas prices. We
have heard many ways to approach that through increased supply,
increased end use efficiency, increased use of coal resources
and new clean coal generation. I think all those are very
important. Clearly the efficiency options are the quickest that
we can get and some of the supply options are the next
quickest.
In terms of this hearing, the effect of environmental
regulation as a factor in increasing gas prices I think is on
the bottom end of that list. The only other comment is that in
terms of allowing the construction of new coal plants, that
environmental regulation needs to address four pollutants,
including CO<INF>2</INF>, for the industry to be able to take
that action that they want to take.
Senator Carper. I'm sorry, I didn't fully understand your
last sentence. Just say the last sentence again.
Mr. Bluestein. That there is a lot of interest in promoting
new coal generation. What we are hearing from power companies
is that they would like to do that, but they need some
certainty on CO<INF>2</INF> regulation.
Senator Carper. OK, good, thanks. Would you say that one
more time?
[Laughter.]
Senator Carper. All right, Mr. Smith, real quick, closing
comments.
Mr. Smith. We need to work on both supply as well as the
demand side of the equation. I think supply has been addressed.
Demand side, I think if we are trying to encourage new baseload
generation, and more reliance on efficient generation, then I
think we need to encourage, the environmental regime, whatever
it is, needs to consider and count the attributes of that
efficiency.
Senator Carper. Good. My thanks to each of you. Thank you,
Mr. Chairman.
Senator Voinovich. I would like to thank the witnesses for
being here today. I look forward to hearing some
recommendations from you. After the committee is adjourned, I
would like to spend some time talking with you about some ideas
I have on how you can get information to this committee.
Thank you very, very much for being here today.
[Whereupon, at 11:48 a.m., the subcommittee was adjourned.]
[Additional statements submitted for the record follow.]
Statement of Howard Gruenspecht, Deputy Administrator, Energy
Information Administration, U.S. Department of Energy
Mr. Chairman and Members of the Committee:
I appreciate the opportunity to appear before you today to discuss
developments affecting natural gas use, particularly in the power
sector. My testimony focuses on natural gas market changes that have
occurred over the last 15 years and projections through 2030.
The Energy Information Administration (EIA) is an independent
statistical and analytical agency within the Department of Energy. We
are charged with providing objective, timely, and relevant data,
analysis, and projections for the use of the Congress, the
Administration, and the public. We do not take positions on policy
issues, but we do produce data, analysis, and forecasts that are meant
to assist policymakers in their energy policy deliberations. Because we
have an element of statutory independence with respect to the analyses,
our views are strictly those of EIA and should not be construed as
representing those of the Department of Energy or the Administration.
Before turning to long-term projections, this testimony reviews
historical data related to recent trends in natural gas prices and
uses.
recent history, 1990-2005
Natural Gas Prices
Natural gas markets were significantly restructured during the
1980s through enactment of statutes such as the Natural Gas Policy Act
of 1978 and the Natural Gas Wellhead Decontrol Act of 1989 and by
Federal Energy Regulatory Commission orders designed to increase the
competitiveness of natural gas markets through unbundling and the
workout of pre-existing take-or-pay contracts.
In the aftermath of these actions, the average wellhead price fell
considerably from the level of $4.25 per thousand cubic feet (mcf)
(Note: all prices are in 2004 dollars unless otherwise noted) reached
in 1984. Between 1990 and 1999, wellhead prices averaged $2.28 per mcf
and remained below $2.64 each year during this period. Natural gas
consumers, particularly large electric sector and industrial users,
also benefited from increasingly competitive natural gas transportation
markets during this period, further reducing their delivered cost.
More recently, natural gas prices have climbed significantly. The
average wellhead price in 2000 was $3.98 per mcf, 75 percent higher
than the average price during the 1990s, and wellhead prices averaged
$4.34 per mcf between 2000 and 2004. The average wellhead price in 2005
is estimated at $7.26 per mcf, more than three times the average price
during the 1990s.
Natural Gas Use by Sector
Natural gas consumption in the United States fell from 22.1
trillion cubic feet (tcf) in 1972 to 16.2 tcf in 1986. Between 1986 and
1997, consumption rose to 22.7 tcf. Since 1997, overall consumption has
been relatively stable near this level.
Residential and commercial consumption of natural gas has also been
relatively flat over the past decade (Figure 1). Over 60 million
households in the United States are currently heated with natural gas,
and natural gas continues to be the fuel of choice for about two-thirds
of new single-family houses. Consumption in the residential and
commercial sectors is driven largely by the seasonal demand for space
heating.
Annual consumption of natural gas for electricity generation has
increased from a range of 3.2 to 3.9 tcf during the early 1990s to an
estimated range of 5.1 to 5.8 tcf from 2000 to 2005. Although the
overall trend shows increasing use in this sector, consumption varies
from year to year, driven largely by weather, electricity demand, and
any disruption in alternative generation facilities.
Rising use of natural gas by electric generators over the past
decade has been roughly offset by a decline of natural gas use in the
industrial sector, which uses more natural gas than any other sector.
Industrial consumption reached 9.7 tcf in 1997, a level second only to
peak levels in the 1970s, and decreased to an estimated 7.8 tcf in 2005
as natural-gas-intensive manufacturing activities responded to recent
natural gas price developments.
Natural Gas in Electricity Generation
An increase in natural gas generation does not necessarily imply a
commensurate increase in natural gas consumption by electric generators
if the efficiency of generation is also changing. The gap between the
118-percent increase in natural gas-fired generation (from 309 billion
kilowatthours to an expected value of 673 billion kilowatthours)
between 1990 and 2005 and the smaller 84 percent increase in natural
gas used by electric generators over the same period implies that the
average efficiency of all natural gas generation improved by roughly 16
percent.
The increase in the apparent efficiency of natural gas generation
over the past 15 years largely reflects the recent introduction of
increasingly efficient and reliable natural gas generating
technologies, notably advanced combined-cycle units. Between 1999 and
2005, over 230 gigawatts of new generating capacity was added and
nearly all of it was primarily natural-gas- fired (Figure 2). This rate
of generating capacity expansion has not been seen since the 1970s. The
availability of this technology, which allowed capacity to be added in
modest increments close to major load centers with a relatively short
construction time, along with attractive natural gas prices during the
1990s, the 1987 repeal of provisions in the Power Plant and Industrial
Fuel Use Act that had previously prohibited the use of natural gas by
new electric generating units, and Clean Air Act provisions favoring
the use of inherently cleaner fuels all played some role in driving
this outcome.
It is also worth noting that rapid growth in natural gas capacity
does not necessarily imply a commensurate increase in natural gas
generation if the new plants are not used very intensively. Under
present natural gas market conditions, many of the new natural gas
plants are not operating very intensively, and older, less efficient
oil and natural gas plants are being retired. If all the natural gas
plants added between 1990 and 2005 were running at just a 50 percent
utilization rate (which would be substantially more than the actual
experience) while the older natural gas plants continued to operate,
the increase in natural gas generation would have been about 1,150
billion kilowatthours, more than three times the actual increase.
Over the same 1990 to 2005 period, amendments to the Clean Air Act
have required the power industry to significantly reduce emissions. The
Clean Air Act Amendments of 1990 (CAAA90) called for reductions in the
annual emissions of sulfur dioxide (SO<INF>2</INF>) by electricity
generators in the power sector. SO<INF>2</INF> emissions had to be
reduced to approximately 12 million tons in 1996, 9.48 million tons per
year from 2000 to 2009, and 8.95 million tons per year thereafter. The
CAAA90 also called for significant reductions in nitrogen oxide
emissions (NOx), setting boiler-type specific NOx emissions standards
for each plant.
Between 1990 and 2005 both SO<INF>2</INF> and NOx emissions in the
power sector fell significantly, with SO<INF>2</INF> emissions
declining over 30 percent while NOx emissions declined over 40 percent
(Figure 3). These reductions were mostly achieved by adding emissions
control equipment or switching to lower sulfur subbituminous coal at
many of the Nation's coal plants. However, reducing these emissions has
not led to a reduction in coal generation. In fact, despite few new
plants being added between 1990 and 2005, coal generation in the power
sector increased from 1,572 billion kilowatthours to 2,001 billion
kilowatthours, a 27 percent increase. While natural gas generation grew
more in percentage terms, coal generation actually increased by a
larger amount in absolute terms, 429 billion kilowatthours versus 364
billion kilowatthours over this period.
Cumulative retirements of coal-fired units between 1990 and 2004
were less than 2 percent of coal-fired capacity and were concentrated
among smaller units. Generally speaking, it is less cost-effective to
retrofit emissions controls on smaller coal-fired generating units than
on larger ones. In this regard, smaller coal-fired generators faced
choices similar to those facing industrial boilers that used coal or
residual fuel oil, which often responded to emissions control
requirements by switching to natural gas or curtailing their
operations.
A major reason that so few coal plants were added during the 1990s
is that most generating companies did not need large new baseload power
plants that are designed to operate at high utilization rates
regardless of seasonal and diurnal variations in total electricity
demand. In 1990, the average capacity factor for power sector coal
plants was only 59 percent, while the average for nuclear plants,
another baseload technology, was only 66 percent. These relatively low
rates of utilization left substantial room for increases in coal and
nuclear generation without the need to add new capacity. With the
growth in electricity demand that has occurred over the last 15 years,
existing coal and nuclear plants are now being used more intensively,
and power companies are starting to plan for new baseload capacity.
projections, 2005-2030
Near-Term Projections
Over the next few years, natural gas prices and consumption are
likely to vary with weather and economic conditions. Currently natural
gas prices remain high relative to historical prices, but they have
declined in recent weeks because of a warmer-than-normal winter in most
parts of the country to date. EIA's February 2006 Short-Term Energy
Outlook (STEO) projects that the wellhead price will average roughly
$7.90 per mcf in both 2006 and 2007 (nominal dollars). These prices
reflect both limited supplies as well as the projected prices for
competing fuels. Overall, domestic dry natural gas production in 2005
is estimated to have declined by 2.7 percent, mostly because of
hurricane-related disruptions in production in the Gulf of Mexico. As
the recovery from the hurricanes continues, dry gas production is
projected to increase by 3.0 percent in 2006 and by 1.3 percent in
2007. On January 27, working gas in storage stood at an estimated 2,406
billion cubic feet (bcf), which is the highest stock level for this
time of year since 1989. Natural gas stocks are 296 bcf above 1-year
ago and 529 bcf above the 5-year average.
Summer weather in 2006 is expected to be cooler than the summer of
2005, which was one of the hottest on record. As a result, demand for
natural gas for production of electricity is expected to fall in 2006
and then increase in 2007.
Long-Term Projections
The long-term projections discussed here are drawn from the
reference case of the Annual Energy Outlook 2006 (AEO2006), which was
released in December 2005. The AEO2006 is based on Federal and State
laws and regulations in effect on October 1, 2005, including those
sections of the Energy Policy Act of 2005 that establish specific tax
credits, incentives, or standards. However, the potential impacts of
pending or proposed legislation, regulations, and standards--or of
sections of legislation that have been enacted but that require funds
or implementing regulations that have not been provided or specified--
are not reflected in the projections. The AEO2006 also includes the
provisions of the Clean Air Interstate Rule (CAIR) and the Clean Air
Mercury Rule (CAMR), issued by the U.S. Environmental Protection Agency
(EPA) in March 2005. These rules are expected to result in large
reductions of emissions from power plants.
The AEO2006 is not meant to be an exact prediction of the future
but represents what might happen, given technological and demographic
trends, current laws and regulations, and consumer behavior as derived
from known data. EIA recognizes that projections of energy markets are
highly uncertain and subject to many random events that cannot be
foreseen, such as political disruptions and technological
breakthroughs. In addition to these phenomena, long-term trends in
technology development, demographics, economic growth, and energy
resources may evolve along a different path than expected in the
projections. The AEO2006 includes many alternative cases intended to
examine the implications of such uncertainties.
Natural Gas Prices
In the AEO2006 reference case, average wellhead prices for natural
gas in the United States decline from $5.49 per mcf (2004 dollars) in
2004 to $4.46 per mcf in 2016 as the availability of new import sources
and increased drilling expand available supply (Figure 4). After 2016,
wellhead prices are projected to increase gradually, reaching $5.92 per
mcf in 2030. Growth in liquefied natural gas (LNG) imports, Alaskan
production, and lower-48 production from unconventional sources is not
expected to be large enough to completely offset the impacts of
resource depletion and increased demand in the lower-48 States (Figure
5).
Natural Gas Supply
Domestic dry natural gas production is projected to increase from
18.5 tcf in 2004 to 21.6 tcf in 2019, before declining to 20.8 tcf in
2030 in the AEO2006 reference case. Net pipeline imports of natural
gas, are expected to decline from 2004 levels of 2.8 tcf to about 1.2
tcf by 2030 due to resource depletion and growing domestic demand in
Canada.
To meet a projected demand increase of 4.5 tcf from 2004 to 2030
and to offset an estimated 1.6-tcf reduction in net pipeline imports,
the United States is expected to depend increasingly on imports of LNG.
Net LNG imports in the AEO2006 reference case are projected to increase
from 0.6 tcf in 2004 to 4.4 tcf in 2030. Besides expansion of three of
the four existing onshore U.S. LNG terminals (Cove Point, Maryland;
Elba Island, Georgia; and Lake Charles, Louisiana) and the completion
of two U.S. terminals currently under construction, new facilities
serving the Gulf Coast, Southern California, and New England are added
in the reference case.
Natural Gas Consumption
The total demand for natural gas is projected to increase at an
average annual rate of 1.2 percent from 2004 to 2020, then to remain
relatively stable through 2030. The demand for natural gas in the
residential, commercial, and industrial sectors is projected to
increase steadily, but at a rate well under 1 percent per year from
2004 to 2030. The projected leveling off in total natural gas
consumption after 2020 is driven by changes in the mix of fuels used to
generate electricity, as natural gas is expected to lose market share
to coal in the electric power sector during the latter half of the
projection period. Natural gas consumption in the electric power sector
is projected to grow at the relatively rapid rate of 1.2 percent per
year between 2004 and 2019, before it begins to decline. Between 2019
and 2030, natural gas consumption in the power sector is expected to
decline by 15 percent. Over the entire 2004 to 2030 period, natural gas
consumption in the power sector increases from 5.3 tcf to 6.4 tcf.
Electric Power Sector Generation and Capacity Additions
The demand for electricity is expected to grow at an average rate
of 1.6 percent per year through 2030. To meet this growth, the power
sector will increase its use of coal, natural gas, renewable fuels, and
nuclear power (Figure 6). In the mid-term, over the next 10 years, both
natural gas and coal generation increase as existing plants are used
more intensively. Renewable generation also grows as new plants
stimulated by the tax credit extension in EPACT2005 are added. For
example, between 2004 and 2015, coal generation in the power sector is
projected to increase from 1,954 billion kilowatthours to 2,239 billion
kilowatthours, while natural gas generation grows from approximately
619 billion kilowatthours to 902 billion kilowatthours, and renewable
generation grows from 323 billion kilowatthours to 448 billion
kilowatthours.
After 2010, capacity additions are expected to be increasingly
dominated by new coal power plants and coal generation grows
significantly (Figure 2). For example, through 2005 natural gas plants
accounted for over 90 percent of the capacity added in the expansion
that began in 1999. However from 2010 on new coal plants are expected
to account for 57 percent of total capacity additions, while natural
gas technologies account for 36 percent, renewable plants account for 5
percent, and nuclear plants accounts for the remainder. Even with
higher fuel prices, natural gas plants, because of their lower
construction costs, are generally the most economical choice for plants
that are needed to operate less intensively. Over the entire 2005 to
2030 time period, 174 gigawatts of new coal capacity, including 19
gigawatts of coal-to-liquids plants in the industrial sector, are added
to make liquid fuels and electricity.
Clean Air Interstate Rule and Clean Air Mercury Rule
Our projections show that increases in coal-fired generation are
expected to occur despite significant reductions in sulfur dioxide
(SO<INF>2</INF>), nitrogen oxide (NOx), and mercury emissions that are
required because of recently promulgated regulations. The EPA issued
the CAIR in March 2005. CAIR caps emissions of SO<INF>2</INF> for the
District of Columbia and 28 states in the East and Midwest. CAIR is
scheduled to supersede Title IV of the Clean Air Act through the use of
a cap-and-trade approach. Phase I of CAIR comes into effect in 2010 for
SO<INF>2</INF> and Phase II enters into effect in 2015. CAIR will also
regulate NOx emissions. Each affected State will be subject to two NOx
limits under CAIR: a 5-month summer season limit and an annual limit.
These caps are expected to stimulate additions of emission control
equipment to some existing plants.
In March 2005, EPA also issued the CAMR, which establishes a cap-
and-trade approach to reduce mercury emissions from coal-fired power
plants in the United States. In addition to nationwide caps, each new
and existing coal-fired power plant must meet mercury emissions
standards based on its coal type. Mercury has to be reduced in two
phases: the national Phase I mercury cap is 38 short tons in 2010 and
the Phase II cap is 15 short tons by 2018, though emissions banking is
allowed. Several States have also adopted or are considering mercury
control regulations for power plants within their jurisdictions.
In order to meet CAIR and other State requirements, power companies
are projected to add flue gas desulfurization equipment to 141
gigawatts of capacity. Because of these actions and the growing use of
lower-sulfur coal, SO<INF>2</INF> emissions are projected to drop from
10.9 million short tons in 2004 to 3.7 million short tons in 2030, a
66-percent decline (Figure 3). National NOx emissions are projected to
decrease from 3.7 million short tons in 2004 to 2.2 million short tons
in 2030, a decline of 41 percent. The primary compliance option for
reducing NOx will be the addition of selective catalytic reduction
equipment to 118 gigawatts of generating capacity. To comply with CAMR,
power companies are expected to reduce their mercury emissions from
over 50 tons in 2004 to 15 tons by 2030, a decline of more than 70
percent. Power companies are expected to retrofit about 125 gigawatts
of capacity with activated carbon injection technology in order to
comply with CAMR.
Although EIA does not anticipate that the emissions limits in CAIR
and CAMR will lead to significant fuel switching away from coal, other
types of emissions regulations could have such an effect. For example,
several recent EIA analyses have found that stringent greenhouse gas
limits could result in a major shift from coal to other fuels for
electricity generation.
conclusions
There are major uncertainties with any projection that looks out
even a few years. For longer term projections like those in the
AEO2006, key uncertainties include the rate of technological change,
the rate of economic growth, unforeseen policy changes, and changes in
consumer preferences. The AEO2006 includes numerous cases to examine
many of these uncertainties. These include alternative economic growth
cases, alternative fuel price cases, and many alternative technology
cases. Generally, the only cases showing much greater use of natural
gas in the power sector were those with much lower natural gas prices
than are projected in the reference case.
This completes my testimony, Mr. Chairman. I would be glad to
answer any questions you and the other members may have.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Responses by Howard Gruenspecht to Additional Questions from
Senator Lieberman
Question 1. Please state in absolute terms the extent to which
coal-fired power plant capacity was increased after November 15, 1990.
Please state in absolute terms to the extent to which natural gas-fired
power plant capacity was increased after November 15, 1990.
Response. EIA data on generating capacity records the commercial
operating date by month and year. During the period December 1990
through 2004, 13,010 megawatts (net summer capacity) of coal-fired
generating capacity entered commercial service. Note that most of this
capacity entered service in the first half of the period. By 1993, 7088
megawatts (54 percent) had entered service, and by 1996, 11,330
megawatts (87 percent) had entered service. Because of the long lead--
times required to develop coal-fired generating capacity, it is likely
that most of this capacity was under construction or in the advanced
planning stages prior to November 15, 1990.
During the same December 1990 through 2004 period, 227,130
megawatts of gas-fired generating capacity entered commercial service.
In contrast to the coal capacity additions, the additions of gas-fired
capacity are concentrated in the latter part of the period. During 2000
through 2004, 183,486 megawatts of gas-fired capacity (81 percent of
the total) entered service. In 2002 and 2003 alone, 101,772 megawatts
of capacity (45 percent of the total) entered service.
Question 2. Please assess the impact of the following factors on
natural gas demand since 1990: the cost of natural gas, capital costs
for new natural gas plants, opportunities for siting such plants, the
time required to build such plants, and responsiveness to load changes
of gas-fired power plants. Please compare or contrast the effect of the
requirements of the Clean Air Act and EPA's implementation thereof to
or with the factors enumerated in the previous sentence in terms of
their impact on natural gas demand.
Response. Cost of Natural Gas: Generally through the 1990's and
into the early part of this decade the price of natural gas was,
compared to current prices, moderate. Between 1990 and 2002, the
average annual wellhead price of natural gas ranged from a low of $1.55
per thousand cubic feet to a high of $4 per thousand cubic feet. In
2002 the average annual price was $2.95 per thousand cubic feet. In
contrast, the annual average for 2005 through November is estimated by
EIA at $7.28 per thousand cubic feet. Since the price of fuel is a
major cost factor for generating plants, moderate gas prices were
important in encouraging the development of gas-fired plants.
Capital Costs for New Natural Gas Plants.--Natural gas plants have
significantly lower capital costs than coal-fired plants. EIA estimates
that a new coal plant costs two to three times as much per megawatt of
capacity as a new gas plant. This lower capital cost was a major
attraction of gas-fired capacity to the independent power developers
who built most of the new gas-fired capacity. Since these independent
power producers did not have guaranteed markets or regulated returns on
investment, they preferred relatively low-cost investments that reduced
the amount of capital at risk.
Opportunities For Siting Such Plants.--Compared to coal plants,
gas-fired plants require less land and have fewer potential
environmental impacts, and are therefore easier to site.
Time Required To Build Such Plants.--EIA estimates that the lead-
time for installing a new gas-fired plant is about two to 3 years,
compared to 4 years for a coal plant. The shorter lead-time was
attractive to developers, as it allowed them to more quickly turn their
capital investment into a revenue-producing asset.
Responsiveness to Load Changes of Gas-Fired Power Plants.--Gas-
fired combustion turbine plants (in essence, ground-mounted jet
engines) have a unique ability to quickly respond to changes in load.
Combustion turbines can go from shut-down to full load to shut down
again in a matter of minutes. In contrast, a coal plant takes hours to
go from cold shutdown to full load, and coal plants are not designed
for frequent startups and shut-downs. This makes gas-fired turbines
ideal for meeting brief daily peak loads. Of the 227,130 megawatts of
gas-fired capacity built during the period December 1990 through 2004,
83,348 megawatts (37 percent) are combustion turbines. (Most of the
balance is combined cycle capacity, a more complex technology that also
makes use of combustion turbines but does not have the same load-
following flexibility.)
Compare Or Contrast The Effect Of The Requirements Of The Clean Air
Act And EPA's Implementation With The Factors Discussed Above.--We have
not performed the analysis necessary to assess the relative importance
of the Clean Air Act and its amendments and the other factors discussed
here in encouraging the development of gas-fired generation since 1990.
Such an analysis would be complex due to the many factors at work and
their interplay. It does seem clear that the Clean Air Act increased
the cost of building and operating new coal plants, and to that extent
encouraged the use of other fuels. However, as noted above, other
factors also encouraged developers to turn to gas-fired plants and
these factors likely would have been influential even in the absence of
the Clean Air Act and its amendments.
Question 3. Throughout the 1990's a number of States, as well as
the Federal Energy Regulatory Commission, restructured electricity
ratemaking or deregulated it. Please describe the impact of electricity
restructuring or deregulation on the building of new natural gas power
plants and the demand for natural gas.
Response. Federal and State Government actions encouraged or (at
the State level) even mandated the sale of existing generating capacity
to independent power producers. These policies also encouraged the
development of new generating capacity by independent power producers.
During the same period, State and Federal environmental regulation made
the construction and operation of new coal-fired units more costly than
in the past.
As also noted in the response to Question 2, independent power
producers operated in relatively open markets without the security of
cost-based rates for their power sales, guaranteed sales areas, or
regulated return on investment. In this deregulated environment, they
sought to limit the financial and technical risks involved in building
new generating capacity. Even regulated utilities were often risk-
averse, due to a history of State regulators imposing financial
penalties for nuclear and coal projects that critics claimed were
excessively costly or unnecessary.
This regulatory environment encouraged power project developers,
and particularly independent power producers, to seek lower-cost and
lower-risk generating options. Gas-fired plants were most often the
choice. Compared to coal-fired plants, gas-fired plants generally have
lower capital costs, can be built more quickly, can be more easily
sited (due to smaller space requirement and fewer environmental
impacts), and have fewer environmental risks.
With respect to natural gas demand, we have not analyzed the
relative importance of regulatory policy in encouraging the development
of new gas-fired plants compared to other factors. As noted in the
answer to Question 2, such an analysis would be complex due to the many
factors at work and their interactions. Nonetheless, there is no
question that the growth in electric power sector demand between 1990
and 2004 contributed significantly to overall growth in demand for
natural gas.
______
Responses by Howard Gruenspecht to Additional Questions from
Senator Voinovich
Question 1. As discussed at the hearing, please provide a detailed
accounting of your assumptions that lead you to predict that natural
gas prices are at their peak now and will fall over the next 10 years.
Please also provide any sensitivity analyses that EIA has completed to
show what happens to natural gas prices if these assumptions are wrong.
Response. The projected decline in natural gas prices through 2016
reflects a growing abundance of gas supply relative to slower projected
growth in gas consumption. The rise in domestic natural gas prices
after September 1, 2005, reflected a short-term supply disruption
caused by the temporary loss of gas (and oil) production capacity in
the Gulf of Mexico region due to hurricane damage, the expectation of
normal winter weather, and relatively tight natural gas markets. Henry
Hub natural gas prices have fallen by more than 50 percent since their
high in December 2005. On the demand side, high gas prices are
projected to slow the construction and use of gas-fired electricity
generation and growth in residential, commercial, and industrial gas
consumption.
Over the next 10 years, the development of new liquefied natural
gas (LNG) terminals and the expansion of existing LNG terminals are
projected to augment domestic natural gas supply. The Annual Energy
Outlook 2006 (AEO2006) reference case assumes that two new LNG
terminals currently under construction will be completed before 2010.
These LNG terminals are the Cheniere Energy, Inc. terminals in
Freeport, Texas (1.5 billion cubic feet per day) and Cameron Parish,
Louisiana (2.6 billion cubic feet per day), which are scheduled for
completion in 2008 and 2009, respectively. The AEO2006 reference case
also assumes that expansions of existing terminals that have been
approved and proposed as of September 1, 2005, will proceed as planned.
This includes the proposed expansion of 0.8 billion cubic feet per day
at Cove Point, Maryland, and approved expansions of 1.1 billion cubic
feet per day at Lake Charles, Louisiana, and 0.54 billion cubic feet
per day at Elba Island, Georgia.
Projected incremental lower-48 gas production through 2015 comes
primarily from unconventional gas resources (i.e., tight sands, gas
shales, and coalbed methane), which are increasingly economic due to
the projected improvement of well drilling, well completion, and
formation fracturing technologies, along with favorable wellhead gas
prices. Technically recoverable unconventional resources of 458.8
trillion cubic feet are assumed in the AEO2006 reference case (300.3
trillion cubic feet of tight gas, 83.3 trillion cubic feet of shale gas
, and 75.2 trillion cubic feet of coalbed methane). Rates of
technological progress are also key assumptions in the AEO2006. The
major technology assumptions underlying unconventional gas exploration
and development are presented in Table 1.
Table 1. Assumed Rates of Technological Progress for Unconventional Gas Recovery
----------------------------------------------------------------------------------------------------------------
Technology Type Item Type of Deposit Rate
----------------------------------------------------------------------------------------------------------------
Advanced exploration & natural Increases success rate. All types.............. 0.2 percent/year
fracture detection.
Geology technology modeling and Improves EUR per well.. All types.............. 0.25 percent/year
matching.
More effective, lower damage well Improves EUR per well.. All types.............. 0.25 percent/year
completion & stimulation technology.
Advanced well completion technologies Improves EUR per well.. Tight Sands............ 10 percent by 2016
Gas Shales............. 20 percent by 2016
Mitigation of environmental Increases proportion of All types.............. 1 percent/year
constraints. areas currently
restricted that become
available for
development.
----------------------------------------------------------------------------------------------------------------
EUR: Estimated Ultimate Recovery
In addition to the AEO2006 reference case, 31 cases were developed
to reflect the uncertainty surrounding the reference case assumptions.
The cases that show the most variation in the lower-48 natural gas
wellhead price are shown in Figure 1. A description of these cases can
be found in Appendix E of the AEO2006 (http://www.eia.doe.gov/oiaf/aeo/
pdf/appendixes.pdf). The natural gas prices in all of the AEO2006 cases
reflect the balance between supply and demand.
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
There are many factors that influence natural gas prices within the
context of the Annual Energy Outlook. Among the more important factors
that impact oil and gas supply and demand projections are: the assumed
world oil price path, world oil and gas resources, economic growth, as
well as fuel technology assumptions. This information is contained in
the AEO2006, which can be found at http://www.eia.doe.gov/oiaf/aeo/
index.html.
Question 2. As discussed at the hearing, please provide an analysis
that compares your projections for the next 10 years for natural gas
prices and natural gas use by sector compared to what you projected for
the previous 10 years.
Response. In the Annual Energy Outlook, natural gas prices and
consumption are determined through the interaction of energy supply and
demand among all fuels and in all sectors. The model used to make the
projections contained in the AEO, the National Energy Modeling System
(NEMS), is updated annually based on currently available data, the
passage of new laws or regulations effecting energy markets, normal
weather conditions, current trends in technological progress, current
consumer behavior, and improvements in modeling approaches.
Exhibits 1-5, below, illustrate how EIA's midterm natural gas
wellhead prices and delivered prices by sector have changed.
The key elements which determine domestic natural gas supplies in
NEMS include: conventional lower-48 finding rates; estimated ultimate
recovery for unconventional gas plays; drilling, lease equipment and
operating costs; conventional and unconventional drilling levels;
lower-48 offshore supply; Canadian natural gas supply; and liquefied
natural gas (LNG) imports. These elements are re-evaluated annually as
new data become available.
Over the last few years, projections for two key sources, onshore
lower-48 conventional production and pipeline imports from Canada, have
changed dramatically as new data has shown smaller field discoveries
and higher production decline rates than previously anticipated.
Considerable uncertainty still remains with regard to the supply,
costs, and distribution of the remaining resources and the potential
rate of technological progress that affects both the size of the
recoverable resources and the costs of recovery. The progression of EIA
changes to its domestic oil and natural gas models has led to the use
of more data and ultimately better informed projections of future
delivered natural gas prices and lower projected future gas consumption
over time (see Exhibits 6-9).
Since 1996, EIA has produced annual evaluations of the accuracy of
the Annual Energy Outlook (AEO). The forecast evaluation examines the
accuracy of AEO forecasts dating back to AEO82 by calculating the
average absolute percent errors for several of the major variables for
AEO82 through AEO2004. The latest evaluation can be found at http://
www.eia.doe.gov/oiaf/analysispaper/forecast--eval.html.
Question 3. You stated that ``very small shifts in either demand or
supply cm [sic] have a big impact on price.'' You also stated that
natural gas demand by electric power providers and residential users is
not very price responsive but ``the industrial sector is one of the
really few remaining places where demand is responsive to price.''
Please explain the impact on home heating and electricity prices and
employment in the industrial sector if a policy creates a shift in the
demand or supply of natural gas.
Response. In the tight natural gas market situation we are in
today, relatively small changes in either the supply or demand
situation can have a large impact on natural gas prices. For example,
in recent months, warmer-than-normal weather conditions have led to
lower than expected natural gas use for home heating. This has had a
dramatic impact, with natural gas spot prices at the Henry Hub falling
from over $15 per million Btu in December to under $7 today. What
impact a particular policy might have would depend on the specifics of
the policy and the market conditions that exist when it takes affect.
However, over time, the existing tight market situation should improve
as high natural gas prices stimulate the development of new supplies
and provide consumers an incentive to reduce their energy use.
High natural gas prices do have an impact in all sectors of the
economy. In the residential sector, natural gas accounts for 65 percent
of heating energy use and 68 percent of water heating energy use. In
electricity markets, natural gas is becoming an increasingly important
fuel. Between 1999 and 2005, nearly 95 percent of all new power plants
added were fueled by natural gas and the share of generation from
natural gas grew from 15 percent to 18 percent. High natural gas prices
also contribute to high electricity prices because natural gas-fired
plants frequently set electricity prices in competitive power markets.
The impacts of high natural gas prices vary from industry to
industry. A report to Congress, Impact of Rising Natural Gas Prices on
the U.S. Economy and Industries, released by the Department of Commerce
in July of 2005 (https://www.esa.doc.gov/ngfr.cfm), found that there is
no clear evidence, except for nitrogenous fertilizer manufacturing,
that higher natural gas prices were the primary reason for the poor
economic performance of natural-gas-intensive industries during 2000 to
2004. Higher natural gas prices were certainly an additional burden on
these industries, but their performance was already deteriorating prior
to the onset of higher prices. For the nitrogenous fertilizer industry,
as much as 13 percent of the annual level of employment from 2000 and
2004 was lost due to higher natural gas prices. For the remaining four
industries studied in detail, including petrochemicals, all other basic
organic chemicals, plastics, and iron and steel, the Department of
Commerce study found that only 4 percent or less of the jobs from 2000
and 2004 were lost due to the rise in natural gas prices.
______
Responses by Howard Gruenspecht to Additional Questions from
Senator Jeffords
Question 1. What was the natural gas share of total electric
generation in the United States in 1970 (pre-environmental regulation)
compared to today?
Response. In 1970, natural gas accounted for 24.3 percent of total
net electricity generation (372.9 billion kilowatt-hours out of a total
of 1535.1 billion kilowatt-hours). In 2005, preliminary full year data
show that natural gas accounted for 18.6 percent of the total (751.3
billion kilowatt-hours out of a total of 4037.4 billion kilowatt-
hours).
Question 2. We heard that the United States has the highest natural
gas prices in the world, but we've also heard a lot about high gas
prices in Europe recently. What are the current prices of natural gas
and LNG in Western Europe? Historically, how have prices in the United
States and Western Europe compared?
Response. According to International Energy Agency data, which are
also posted on the Energy Information Administration's (EIA) Web site
at (http://www.eia.doe.gov/emeu/international/gasprice.html), 2004
industrial natural gas prices were the highest in Switzerland at $8.90
per million Btu and the lowest in Finland at $4.30 per million Btu (the
most recent comparative date available). These rankings are based on 10
Western European countries for which data exist and on U.S. data,
although not all countries have data for each year. In 2004, U.S.
natural gas prices for households were ranked 4th at $6.20 per million
Btu (out of 7 countries). The rankings have varied since 1998, although
Switzerland is the highest in every year. The United States ranked 9th
(out of 10 countries) in 1998; 4th (out of 9 countries) in 2000; 6th
(out of 8 countries) in 2002.
__________
Responses by William Wehrum to Additional Questions from
Senator Jeffords
Question 1. What was the natural gas share of total electric
generation in the United States in 1970 (pre-environmental regulation)
compared to today?
Response. We have coordinated our response to this question with
DOE, and therefore defer to the response submitted by Mr. Gruenspecht.
Question 2. We heard that the United States has the highest natural
gas prices in the world, but we've also heard a lot about high gas
prices in Europe recently. What are the current prices of natural gas
and LNG in Western Europe? Historically, how have prices in the United
States and Western Europe compared?
Response. We have coordinated our response to this question with
DOE, and therefore defer to the response submitted by Mr. Gruenspecht.
Question 3. In designing programs meant to achieve the Nation's air
quality goals, what is EPA's objective with regard to the impact on
energy prices and economic growth? Does the Agency take these factors
into account and work with the Department of Energy and the Energy
Information Agency to minimize such impacts?
Response. In the beginning of this Administration, the President
issued the National Energy Plan (NEP). In the NEP, EPA was directed,
among other things, to review New Source Review (NSR) regulations with
regard to their impact on investment in new electric generation and
refinery capacity, efficiency and environmental protection. EPA was
also directed to propose legislation that would establish a flexible,
market-based program to significantly reduce and cap emissions of
sulfur dioxide, nitrogen oxides, and mercury from electric power
generators. EPA designed Clear Skies legislation and the related
rulemakings--the Clean Air Interstate Rule and the Clean Air Mercury
Rule our New Source Review regulations and the Clean Air Visibility
Rules--to be part of the solution. Our guiding principle in the design
of these programs was to achieve national air quality goals without
compromising economic growth and energy security. In putting forth
these initiatives, we worked closely with our colleagues at the
Department of Energy (DOE) and the Energy Information Administration
(EIA).
Question 4. Since passage of the Clean Air Act in 1990, how much
has natural gas use increased in the United States? What is the status
of natural gas demand over the last decade? What factors have resulted
in increased use of natural gas in the power sector?
Response. Natural gas use in the United States has increased about
6 percent overall since the passage of the Clean Air Act of 1970.\1\
Over the last decade (from 1995 to 2004), total demand has been
relatively flat. However, the mix of natural gas use and its increased
use for electric power generation has changed. The significant increase
in the use of natural gas in the power sector that occurred over the
last decade resulted primarily due to two factors. First, real natural
gas prices substantially declined over that period (see Figure below)
and second, the power industry could procure and install natural gas
combined cycle electric generation in relatively shorter time periods
than similarly sized coal plants. Moreover, natural gas combined cycle
plants are nearly twice as efficient as natural gas steam units, while
also being much cleaner from an air emissions standpoint. The repeal of
sections of the Power plant and Industrial Fuel Use Act (FUA, 1978) in
1987, further contributed to the increased use of natural gas in the
power sector. As a result, natural gas and oil could again be used to
fuel large new baseload electric power plants and restrictions on gas-
and oil-burning industrial boilers, turbines, and engines were lifted.
---------------------------------------------------------------------------
\1\ (Derived from Energy Information Administration, Annual Energy
Review, August 2005.)
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Question 5. Please provide a comparison and analysis of the cost of
new coal fired electricity generation and new combined cycle natural
gas units during the mid 1990's. As part of your analysis, please
compare new units with and without Best Available Control Technology
requirements in terms of cents per kilowatt hour. Please indicate the
extent to which such costs are capital costs, fuel costs, and fixed or
variable operating and maintenance costs.
Response. The figure, below, is a cost comparison of new coal-fired
generation and new combined cycle natural gas units during the mid
1990's. It shows new units with and without Best Available Control
Technology (BACT) requirements. As shown, new coal-fired plants with
BACT controls are significantly more expensive than combined cycle gas-
fired power plants either with or without BACT. This economic situation
generally led to the building of new combined cycle base load units to
handle additional electricity demand (in areas where there was no
excess capacity of existing coal-fired generation) rather than new
coal-fired generation, because such units were predicted to be more
economical to operate, and had many other attractive features. In 1999,
the National Petroleum Council summarized the advantages of natural gas
combined cycle:
``. . . Notwithstanding volatility, five circumstances have
led to the choice of natural gas as the preferred fuel for new
generating stations. One, the heat rate on combined-cycle gas
generation plants gives a strong economic advantage. Two, the
capital cost of a combined-cycle gas-fired plant is
approximately $500 to $650 per megawatt, compared to $1,000 to
$1,500 per megawatt for coal-fired plants. Three, the
construction time for the combined-cycle plants is
approximately 2 years versus 5 to 7 years for coal-fired
plants. Four, in a deregulated environment, electricity
generators seek the short possible time between the decision to
build and point at which capital costs are recovered. Gas-fired
plants have the shortest construction time. Five, it is far
easier to obtain permits for new combined-cycle gas plants than
for coal-fired plants.''\2\
---------------------------------------------------------------------------
\2\ (National Petroleum Council, Natural Gas Meeting the Challenges
of the Nation's Growing Natural Gas Demand, Volume II Task Group
Reports, December 1999.)
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Note: The costs for new plants and fuels are based on various
reports issued by Department of Energy and Energy Information
Administration. The plant costs have been adjusted for the plant size
and the year of operation, using the GDP implicit price deflator
reported by Department of Commerce. The delivered cost for natural gas
in this analysis is $2.70/MMBTU and the delivered cost for coal is
$1.26/MMBTU. The costs of environmental controls are based on EPA's
---------------------------------------------------------------------------
Integrated Planning Model.
Question 6. Please analyze the contention that the Clean Air Act
has shifted the balance of electricity generation from coal to natural
gas. Using EPA's National Energy System data base, please discuss the
amount of coal versus natural gas generation built between 1990 and
2003, and your projections for 2004 and beyond.
Response. Some observers have considered the limited number of
coal-fired units and many natural gas units that have been built as an
indication that the Clean Air Act has itself shifted the balance away
from coal and toward natural gas. EPA's National Electricity Energy
System Data base, which supports our electric generation modeling,
indicates that between 1990 and 2003, 115 GW of new combined-cycle
capacity has been added (690 units), while approximately 11 GW of new
coal-fired capacity (68 units) has come online.\3\ Seventy-eight
percent of this new combined-cycle capacity has come online since 2000,
while 5 percent of the coal-fired capacity has come online in the same
timeframe. From 2004 to 2007, we expect approximately 37 GW of new
combined-cycle capacity (31 units) and approximately 1.2 GW of new coal
fired capacity (4 units). As indicated previously, however, many
different factors concerning the construction, permitting and fuel
costs associated with natural gas versus coal units have come into play
during this period which affect decisions concerning the installation
of new capacity. The Figure immediately below shows this same effect
occurring since the 1980's continuing into the next decade before
narrowing after 2020. More broadly, as noted in the second figure,
natural gas consumption for electric power generation has increased
relative to other economic sectors since the late 1980's. Overall,
coal-fired and natural gas generation increased substantially since
1980. While EPA predicts a gradual rise in both coal and natural gas
used for electric power generation between now and 2020, projections
for coal in the 2020-2030 range show increased coal utilization
relative to natural gas.
---------------------------------------------------------------------------
\3\ Note that in addition to this combined-cycle capacity,
approximately 1,900 turbines with a capacity of 87 GW were built in
this timeframe for peaking purposes. These units consume relatively
small amounts of natural gas.
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Question 7. As you know, natural gas prices have risen
substantially since 1999. What effect has this had on the economics of
natural gas based electricity generation? How will these high prices
affect the economics of natural gas fired generation in the future?
Response. After 1999, natural gas prices rose substantially for a
variety of reasons that the Energy Information Administration addressed
in its testimony. This increase has now changed the economics
considerably. Before the price increase, generation costs favored
natural gas combined-cycle generation regardless of the environmental
requirements. Today's higher natural gas prices are in turn increasing
the operating costs of combined-cycle gas facilities relative to the
costs for new coal-fired power plants. The figure below shows how this
leads to changes in the comparative costs for new base load coal
capacity versus natural gas capacity, however consideration for peaking
capacity is different. Overall, the increase in natural gas prices is
expected to lead to an increase in building of new coal-fired units in
the future.
[GRAPHIC NOT AVAILABLE IN TIFF FORMAT]
Note: The costs for new plants and fuels are based on various
reports issued by Department of Energy and Energy Information
Administration. The plant costs have been adjusted for the plant size
and the year of operation, using the GDP implicit price deflator
reported by Department of Commerce. The delivered cost for natural gas
in this analysis is $6.22/MMBTU and the delivered cost for coal is
$1.50/MMBTU. The costs of environmental controls are based on EPA's
Integrated Planning Model.
Question 8. In your oral testimony you discussed the effect of
existing Clean Air Act programs on the power sector and noted that
``EPA has not seen evidence, however, that its regulations of the power
sector are a substantial factor in the pricing of natural gas.'' Please
provide an analysis of the effect of existing Clean Air Act programs on
natural gas prices and fuel mix for the power sector. In particular,
please provide specific analyses regarding the following programs: New
Source Performance Standards, New Source Review, the Acid Rain Program,
and the NOx SIP call.
Response. Many different provisions of the Clean Air Act may affect
both the construction and operation of electric generating units and
may influence fuel choices by the power industry. Electric generating
units may be considered to be major sources subject to Title V
permitting requirements. Other aspects of the Clean Air Act, including
State implementation of National Ambient Air Quality Standards, may
have an impact on fuel choices in particular States or regions. EPA has
not retrospectively analyzed the impact of all Clean Air Act programs
on fuel choices in the electric power generation sector and is unable
to quantify, in the aggregate, all direct and indirect costs
attributable to Federal and State implementation of the Act. However,
EPA has carefully analyzed the potential impact of regulatory
approaches on price and fuel mix when developing regulations for the
four programs for which you requested specific analysis: the Acid Rain
Program, the NOx SIP Call, the New Source Performance Standards, and
New Source Review.
new source performance standards
In development of new source performance standards (NSPS), EPA has
tried to incorporate approaches that encourage the efficiency of energy
generation. The NSPS for NOx for power plants are ``output-based.''
Input-based emission limits had been the traditional method to regulate
power plants until we amended the NSPS for power plants in 1998. An
output-based standard establishes emission limits in a format that
limits emissions per the amount of useful energy generated, not the
amount of fuel burned. In addition to the output-based format, the NOx
NSPS has a single emission limitation for power plants that is
applicable regardless of fuel type. We sought not to limit the control
options available for compliance, but to provide flexibility for
cheaper and less energy intensive control technologies (i.e., by
allowing the use of clean fuels for reducing NOx emissions). The clean
fuel approach fits well with pollution prevention, which is one of the
EPA's highest priorities. The fuel cost differential between gas and
coal is one of the main concerns with the application of gas-based
technologies for the reduction of NOx from coal-fired boilers.
Therefore, the revised NOx limit was based on what a well-controlled
coal-fired unit could achieve so as not to force the conversion to gas-
firing.
In development of an NSPS, EPA assesses the regulatory impacts on
options available for potentially affected firms, such as the option of
substituting a different fuel (i.e., natural gas) versus the added
regulatory costs of burning coal. NSPS are based on best demonstrated
technology considering costs. Therefore, in developing an NSPS we try
to minimize adverse effects on fuel markets or supplies. In the past we
have subcategorized the NSPS for steam generating units by fuel type so
as not to adversely affect one or the other.
new source review
New Source Review (NSR) is a preconstruction permitting program
that serves two important purposes. First, it ensures that air quality
is not significantly degraded from the addition of new and modified
major air pollution sources such as industrial boilers and power
plants. In areas with air that doesn't meet air quality standards, NSR
helps prevent new emissions from slowing progress toward cleaner air.
In areas with clean air, especially pristine areas like national parks,
NSR helps prevent new emissions from significantly worsening air
quality. Second, the NSR program assures that any large new or modified
industrial source that significantly increases emissions will install
state-of-the-art controls.
NSR works by requiring a permit before construction can begin on a
new facility or on a modification to an existing facility that
significantly increases emissions. The main requirement to obtain the
permit is to install state-of-the-art control technology. Control
technology decisions for a source are made on a case-by-case basis for
the source being proposed. In areas that do not meet ambient air
quality standards, sources must install Lowest Achievable Emission Rate
(LAER) technology and also offset their emission increases. If a
company is proposing to build a coal-fired power plant in such areas,
the control technology decision will consider technologies demonstrated
for controlling emissions from coal-fired boilers. Likewise, if a
company proposes a gas-fired plant, the decision considers technologies
applicable to such a plant. In attainment areas, the control technology
decision (known as BACT) also allows for consideration of cost and
energy impacts.
Since the NSR program was first enacted in 1977, we have seen
variation in the choice of fuels companies use to meet industrial
energy demand. There have been periods of expanded use of coal, and
periods of expanded use of natural gas. As noted previously, the
variation was driven by changing market forces and various other
factors.
The President's National Energy Policy Report directed the EPA, in
consultation with the Department of Energy (DOE) and other relevant
agencies, to review the NSR program and to issue a report on the impact
of the program on investment in new utility and refinery generation
capacity, energy efficiency, and environmental protection. EPA
identified several clarifications to rules and guidance to improve NSR
applicability provisions and to help address the extreme demands being
placed on our Nation's energy supply infrastructure.
Over the last 5 years, EPA has made some significant reforms to the
NSR program in order to remove regulatory barriers to beneficial
projects at existing facilities. Examples of beneficial projects
include those that would improve reliability, safety, and efficiency,
as well as those that would reduce emissions. Because the reforms, like
the NSR program as a whole, operate independently of fuel choice, they
should not affect fuel choice.
acid rain program
The Acid Rain Program, enacted in 1990, requires significant
reductions in SO<INF>2</INF> and NOx emissions from power plants
nationwide. The centerpiece of the program is an innovative, market-
based cap and trade approach to achieve a nearly 50 percent reduction
in SO<INF>2</INF> emissions from 1980 levels.
This cap and trade approach provided greater certainty that
reductions in emissions would be achieved and sustained by giving
industry a performance standard--the SO<INF>2</INF> emissions cap--and
unprecedented flexibility in how to achieve the needed emission
reductions, through emission allowance trading. To assure compliance,
sources provide a full accounting of their emissions through continuous
monitoring and reporting, and face automatic consequences for failing
to comply. The objective was for sources to find the most cost-
effective means for limiting SO<INF>2</INF> emissions and to be
responsible for achieving those emission reductions. There was no
government second guessing or lengthy permit reviews.
By employing markets, allowing flexibility, and requiring
accountability, the Acid Rain Program has had only minimal impacts on
fuel markets. The program has not shifted the power industry away from
coal-fired generation, which has actually increased since that time.
Compliance occurred largely through two measures: fuel switching from
higher to lower sulfur coals, and installation of scrubbers. EPA's
assessment indicates that when Phase I of the Acid Rain Program began
in 1995, close to 60 percent of the SO<INF>2</INF> emission reductions
occurred through the switching to lower sulfur coals and close to 30
percent happened through the use of scrubbers.
Fewer than 2 percent of the reductions happened from switching to
natural gas and about 2 percent of the reductions occurred from
generation unit retirements.\5\ EIA and MIT's Center for Energy and
Environmental Policy have performed similar evaluations with similar
results.<SUP>6,}7</SUP> EPA has just finished the sixth year of
implementation of the Phase II of the Acid Rain Program. EPA's
monitoring of the program during this time indicates that compliance
has largely occurred through continued coal-fired generation switching
to lower sulfur coals and the installation of a limited number of
additional scrubbers. There have been a few coal-fired generation unit
closures. As Table 1 shows, however, fossil fuel fired electric
generation from coal as a percentage of total electricity generation
from fossil fuels has decreased slightly from 2000 to 2004, while
generation from natural gas as a percentage of total electricity
generation from fossil fuels has increased over the same period. Coal-
based generation declined from approximately 73.4 percent of
electricity generation from fossil fuels in 2000 to about 70.7 percent
in 2004, while natural gas generation increased from 22.4 percent of
electricity generation from fossil fuels in 2000 to approximately 25.0
percent in 2004, resulting in a total change in generation mix between
coal and gas on the order of 5 percent during this period.
---------------------------------------------------------------------------
\5\ U.S. Environmental Protection Agency, National Allowance Data
Base, Version 2.11 and Acid Rain Scorecard Report, 1996.
\6\ Energy Information Administration, The Effect of Title IV of
the Clean Air Act Amendments of 1990 on Electric Utilities: An Update,
March 1997.
\7\ Denny Ellerman et. al., Markets for Clean Air The U.S. Acid
Rain Program, 2000.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Overall, capacity utilization of coal-fired generation continues to
rise, increasing to a national average of 72 percent in 2004. Over
longer timeframes, the relative share of total fossil generation has
not changed substantially. The percentage of generation from natural
gas remained around 20 percent, whereas, the coal-fired percentage
remained around 75 percent.
nox sip call
The NOx SIP Call program is a cap and trade program that EPA
designed under Clean Air Act authority governing the interstate
transport of pollutants. It regulates seasonal NOx emissions from the
electric power industry and industrial sources in the eastern United
States to reduce smog (ozone levels). Currently, 19 States and the
District of Columbia are participating in the program.\8\ EPA designed
the program so that most of the reductions would occur through the
installation of advanced post-combustion controls on coal-fired
generation units. During the development of the program, EPA forecast
there would be some limited fuel switching to natural gas, increasing
its use by the power sector in the States covered by the program one to
2 percent, but found this would not result in an appreciable increase
in natural gas prices.\9\
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\8\ The NOx SIP Call States include AL, CT, DC, DE, IL, IN, KY, MA,
MD, MI, NC, NJ, NY, OH, PA, RI, SC, TN, VA, WV.
\9\ U.S. Environmental Protection Agency. ``Economic Impact of the
NOx SIP Call on Electric Power Generation'', paper presented at the
Electric Utilities Environment Conference, January 1999.
---------------------------------------------------------------------------
Table 2 shows the fossil fuel-fired electric power generation mix
at facilities covered by the program before the program began in 2002
and during the first 2 years of implementation. Natural gas use is
actually slightly lower in 2003 and 2004 than 2002 while coal and oil
use increased. Specifically, natural gas represented 12 percent of net
generation in 2002 and 11 percent in 2004, while coal remained around
85 percent. Again, the relative share of the generation mix does not
change substantially.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
While the generation mix has remained relatively stable, there have
been substantial improvements in the Nation's air quality in our
efforts to address smog. A recent EPA report shows that in most of the
metropolitan areas of the East, after weather corrections, ozone
reductions through government-sponsored programs doubled over the last
2 years due to the NOx SIP Call.\10\
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\10\ U.S. Environmental Protection Agency, Evaluating Ozone Control
Programs in the Eastern United States: Focus on the NOx Budget Trading
Programs, 2004, August 2005.)
Question 9. Please provide an analysis of the impact of future
regulatory programs on natural gas prices and fuel mix for the power
sector, specifically the Clean Air Interstate Rule, the Clean Air
Mercury Rule and the Clean Air Visibility Rule (CAIR/CAMR/CAVR),
comparing the base case with and without these rules. Please also
provide a projection of the effect of these rules combined on natural
gas prices at the Henry Hub for 2010 and 2020.
Response. Modeled on Clear Skies legislation, the Clean Air
Interstate Rule (CAIR), Clean Air Mercury Rule (CAMR)--and the Clean
Air Visibility Rule (CAVR) that EPA finalized in 2005 were designed to
ensure that we can achieve dramatic air quality benefits that do not
compromise economic growth and our energy mix. The CAIR/CAMR rules,
based on the Acid Rain Program and the NOx SIP call, will give industry
flexibility in how to achieve the needed emission reductions, allowing
industry to make the most cost-effective reductions and limiting
impacts on consumers. CAVR also has a provision that allows States
individually or regionally to set up cap-and-trade programs to operate
in place of current technology standards.
If States choose to participate in the CAIR and CAMR cap and trade
programs as EPA recommends, power plants would be allowed to choose the
pollution reduction strategy that best meets their needs (e.g.,
installing pollution control equipment, switching to lower sulfur
coals, buying excess allowances from plants that have reduced their
emissions beyond required levels). EPA has set overall emission levels
that are needed to meet air quality goals, and allows market forces to
influence the best compliance options for various facilities. Also, the
CAIR and CAMR programs are phased in over time with considerable
advance notice to allow the power industry and fuel markets to adjust
and avoid price increases that rapid changes may produce.\11\ CAVR goes
into effect in 2014.
---------------------------------------------------------------------------
\11\ For CAIR, the first phase of the program commences in 2009 for
NOx and in 2010 for SO<INF>2</INF>. The second phase for both
pollutants begins in 2015. For CAMR, the first phase is in 2010 and the
second phase is in 2018.
---------------------------------------------------------------------------
In Clear Skies legislation, CAIR and CAMR, EPA tried to ensure a
level playing field, including phased-in reductions, for example, and
reasonable control levels that could be achieved with cost-effective
reductions. The large emission reductions required by Clear Skies are
set so that rational, economic installation of pollution controls on
coal-fired units can occur rather than by switching to natural gas.
From analysis that EPA released in the fall 2005, the Figure below
shows what EPA expects to occur for the electric generation mix with
and without (base case) CAIR, CAMR, and CAVR.\12\ The differences from
the base case between natural gas and coal-fired generation are almost
imperceptible.
---------------------------------------------------------------------------
\12\ U.S. Environmental Protection Agency, Multi-Pollutant
Analysis: CAIR/CAMR/CAVR, October 2005.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Additionally, EPA expects that these three programs combined will
at most increase natural gas prices by 1.6 percent in 2010 and 2.8
percent in 2020 at Henry Hub and be much less of an impact directly on
consumers, who will pay for added transmission and distribution costs
that will be largely unaffected by these rules.\13\ EPA has performed
sensitivity analysis using higher natural gas prices which shows that
even at prices significantly higher than recent levels, gas prices
would not increase beyond originally forecasted levels of 1.6 percent
in 2010. After 2010, EPA found that assuming higher natural gas prices
actually has the effect of reducing the impact of EPA regulations on
natural gas prices because it becomes more cost-effective to use other
sources of fuels to meet electricity demand.\14\
---------------------------------------------------------------------------
\13\ Henry Hub is the pricing point for natural gas distribution in
the East from the Southeast and Outer Continental Shelf. EPA's
sensitivity analysis increased gas prices by 75 percent, 100 percent
and 150 percent.
\14\ Ibid.
---------------------------------------------------------------------------
Many believe that natural gas prices are likely to be higher over
the next several decades than the Agency used in our analysis. Higher
gas prices would make switching to natural gas as a compliance option a
less attractive economic option, therefore if gas prices turn out to be
higher, there is likely that there will be even less switching to
natural gas than EPA projected.
Question 10. Please list and discuss any air programs not listed
above that reduce the demand for natural gas.
Response. EPA runs a number of voluntary partnerships authorized
under the Clean Air Act that work to provide more natural gas supply by
encouraging companies to improve the efficiency of natural gas delivery
and use, improve electric end-use efficiency, and provide new renewable
energy sources. EPA analysis indicates that in 2010, these voluntary
programs will have reduced national demand for natural gas by 3
percent. For example, in 2004, the Natural Gas STAR program, a
voluntary partnership between EPA and the oil and natural gas industry,
offset the equivalent of 61 billion cubic feet of natural gas. Since
the Program began in 1993, Natural Gas STAR partners have reduced
natural gas/methane losses by 405 billion cubic feet (Bcf). At the same
time, these companies have saved over a $1.2 billion by keeping more
gas in their systems for sale in the market. EPA's flagship Energy STAR
program has been very successful at reducing natural gas and
electricity demand. For example, in 2004, with the help of ENERGY STAR,
Americans saved 125 billion kilowatts and 25,000 megawatts of peak
power, the amount of peak energy required for about 25 million homes.
This energy savings represented about 4 percent of total U.S.
electricity demand in 2004. Energy STAR and Natural Gas STAR are just
two examples of the environmental and energy savings benefits that can
be achieved by a well-designed voluntary effort.
Question 11. Does the Agency believe that Clean Air Act regulations
are a substantial factor in the pricing of natural gas? Is this
conclusion based on a review of the available information and a
considered analysis of that information, including publicly released
projections and previous agency analysis or does it simply reflect an
overall lack of information regarding the effect of EPA's Clean Air Act
regulations on natural gas prices?
Response. Clean Air Act regulations impose a cost on the regulated
community that affects the demand for natural gas, although we do not
believe it is a substantial factor in the pricing of natural gas. More
importantly, the Agency is sensitive to of the need to design
regulations and policies which maintain our Nation's diverse fuel mix
and is committed to being a part of the solution to the challenges
faced by our Nation's energy supply infrastructure.
The Bush administration has worked to advance clean coal
technologies and encourage their use in the generation of electricity.
This policy not only ensures a secure source of electricity supply, but
also increases the availability of natural gas for critical industrial
and residential uses. An important element of this policy is the
enactment of Clear Skies. It is a powerful tool to address fuel supply
issues.
Question 12. Have the answers to the previous questions been
reviewed and approved by the Office of Management and Budget?
Response. Yes. Developing answers to Congress is a collaborative
effort and interagency review is a common practice in the Federal
Government. OMB, along with other agencies like DOE, was offered an
opportunity to comment on these materials.
Question 13. A recent study funded by EPA has found that 67 percent
of the mercury in rain at an Ohio River valley site originated from
power plants. The study was conducted between 2003 and 2004 in
Steubenville, OH. These results were known within the Agency in April
2005. They are directly relevant to the question of the development of
hot spots as a result of the cap and trade of mercury air emissions.
Why then were they not even mentioned in the Clean Air Mercury Rule
(CAMR) promulgated in May of 2005? Why does the CAMR conclude that only
8 percent of U.S. Mercury deposition comes from power plants without
reference to this study? Doesn't that suggest that the CAMR rule may be
fundamentally flawed?
Response. The Steubenville study was not relied on in the CAMR
rulemaking because it had not undergone peer review or been finalized
as of our court-imposed deadline for completing CAMR. EPA's air quality
modeling in support of the Clean Air Mercury Rule (CAMR) showed that
about half of the mercury deposited in the area around Steubenville
comes from U.S. power plants, while up to 70 percent of mercury
deposition in areas just east comes from U.S. power plants. The
Steubenville study cannot be directly compared with the model results
because the Steubenville study included sources other than U.S. power
plants and used a different timeframe for its analysis. However, the
results appear to be generally consistent with our modeling in
suggesting that a significant fraction of the mercury deposited in the
area comes from power plants. As power plants in the area respond to
CAIR and CAMR by installing scrubbers, SCRs, and mercury-specific
controls this fraction will be reduced--more than an 80 percent
reduction in Ohio and about a 90 percent reduction in neighboring
States of Pennsylvania and West Virginia.
Question 14. We understand that this study and its results were
presented to EPA Headquarters personnel, including Jeff Holmstead,
during the summer of 2005. Is that correct? Please provide the notes,
slides and other presentation materials from that meeting and any other
meetings relating to this issue.
Response. A presentation on the preliminary results from the
Steubenville mercury deposition source apportionment study was given to
Jeff Holmstead on July 5, 2005. Note that the results presented to Jeff
Holmstead were still preliminary and are part of the deliberative
process.
Question 15. We understand that a presentation of these results was
made to Mr. Tim Oppelt, Acting Director of EPA's Office of Research and
Development on April 27, 2005. That presentation references additional
analysis to finalize results, which were projected to be completed
within a month of April 2005. Are the final results complete? Please
provide them if so.
Response. The presentation given to Tim Oppelt on April 27, 2005
provided preliminary results from the Steubenville Study. After the
presentation, additional analyses have been performed and peer reviewed
although the study has not yet been published.
Question 16. Slide 6 of the presentation to Mr. Oppelt demonstrates
that 90 percent mercury emissions reductions from the coal-fired
utility industry can achieve approximately 50 percent reductions in
total mercury deposition over the Ohio River valley. The Agency has
finalized a rule asserting that delisting the industry (and the
elimination of the requirement to do a MACT standard) is justifiable on
the basis that only an insignificant amount of mercury deposition is
attributable to domestic power production. Is the Agency's position
consistent with the facts presented to Mr. Oppelt?
Response. As part of the analysis to support the 112(n) revision
notice EPA estimated the resulting change in mercury deposition for the
continental United States resulting from a 100 percent reduction in
U.S. power plant emissions--a utility ``zero-out'' analysis. EPA then
estimated the change in mercury deposition after CAIR and furthermore
after CAMR. Based on these model runs, we estimate that CAIR and CAMR
will reduce most of the mercury deposition due to power plants in the
Ohio River Valley in large part because CAIR is particularly effective
in reducing oxidized mercury emissions--those most likely to deposit
within the United States.
Question 17. According to the presentation provided to Mr. Oppelt
there are other sites being studied. Please produce the results of
those studies.
Response. The other sites you reference are not operated by EPA
(most of the sites mentioned are operated by the University of
Michigan, a collaborator in the Steubenville study). To date, EPA has
not been given access to data from these sites. In addition, the data
from these sites are measurement data and the statistical source
apportionment models would have to be applied to these data to generate
results similar to those presented from the Steubenville study.
Question 18. One of the slides in the Oppelt presentation (Slide
16) describes the researchers' ``Planned Next Steps''--have any of
these next steps have been taken? If not, why not?
Response. Several of the next steps on slide 16 have been taken.
Specifically, the review of the receptor modeling results has been
completed; analyses of peak events were conducted to support
interpretation of the final results; materials were prepared for EPA
and OAR dissemination; and a manuscript has been prepared and submitted
for publication. The remaining items, listed under ``Future Work,'' are
future research analyses that we plan to undertake as additional data
from Steubenville, and other sites operated by others outside of EPA
become available to EPA researchers.
Question 19. In the preamble to the final revision of the December
2000 finding on HAPs emissions (including mercury) from electric power
plants, EPA said that if new information became available that raises
the possibility of utility-attributable hotspots EPA would take
appropriate action. This study clearly raises that possibility. What
appropriate action will EPA take to deal with hotspots?
Response. Through the authority of section 111 of the Clean Air
Act, EPA has the requirement to review and revise, as necessary, the
new source performance standards (NSPS) every 8 years. In addition to
that statutory provision, the Agency did clearly articulate in the
preamble that appropriate actions would be taken should utility-
attributable hotspots be identified in the future. At this point, we do
not believe it is appropriate to link the preliminary Steubenville
results causally to the identification of a utility-attributable
hotspot. There are numerous other coal combustion sources within the
Steubenville perimeter, which also likely contribute to the measured
mercury deposition.
It is worth noting that elevated deposition does not necessarily
translate into elevated levels of methylmercury in fish because of the
complex ecosystem processes (for example, methylation and
bioaccumulation rates) that must occur. The Office of Air and Radiation
will continue to work with the Office of Research and Development to
ensure that our decisions are informed by the best available science
including the Steubenville study once it is published.
Question 20. In a trading program, firms operating in a market
decide where emissions reductions will take place, rather than a
regulatory authority requiring that particular sources control
emissions. There is therefore no assurance under such a program that
reductions will take place where they are needed to protect public
health. Now that we know that there is at least one place in the
country where utilities are responsible for most of the mercury
deposition, and there are likely to be many others, does EPA plan on
changing its rule to require that reductions will take place in areas
where they are needed? Will EPA continue to insist on mercury trading,
despite the evidence presented in the Steubenville study?
Response. EPA does not plan to change the rule at this time and
continues to support the cap and trade approach. Under a cap-and-trade
approach, most of the reductions are projected to result from larger
units installing controls and selling excess allowances, due to
economies of scale realized on the larger units versus the smaller
units. Indeed, EPA's modeling of trading programs demonstrates that
large coal-fired Utility Units, which tend to have higher levels of Hg
emissions, will achieve the most cost-effective emission reductions.
These units are more likely to over-control their emissions and sell
allowances, than to not control and purchase allowances. This model
prediction is consistent with principles of capital investment in the
utility industry. Under a trading system where the firms' access to
capital is limited, where the up-front capital costs of control
equipment are significant, and where emission-removal effectiveness
(measured in percentage of removal) is unrelated to plant size, the
utility company is most likely to allocate pollution-prevention capital
to its larger facilities than to the smaller plants (since more
allowances will be earned from the larger facilities). Economies of
scale of pollution control investment will also favor investment at the
larger plants. Further, insofar as large coal-fired Utility Units tend
to be newer and/or better maintained than medium-sized and small
facilities, it can be expected that companies will favor investments in
plants with a longer expected lifetime.
These modeled predictions are consistent with the pattern of
behavior that EPA and others have observed over the past decade through
implementation of the SO<INF>2</INF> emissions trading program under
Title IV of the CAA. Thus, under a cap-and-trade program, Hg reductions
result from units that are most cost effective to control, which
enables those units that are not considered to have cost effective
control alternatives to use other mechanisms for compliance, such as
buying allowances. By contrast, regulating pursuant to a control regime
like section 112(d) does not result in the cost efficiencies that are
attendant a cap-and-trade program For example, under section 112(d),
each facility must meet a specific level of emission control, which can
result in increased compliance costs, particularly for the smaller
Utility Units given economies of scale.
It is important to note that the Steubenville site was selected in
part because it was anticipated that it would be affected by utility
emissions, which is consistent with CAMR modeling analyses. The
relative contribution of local and regional coal combustion sources,
such as electric utilities, to mercury deposition in other areas of the
country will vary significantly.
Question 21. According to an article published in Greenwire on
February 15, 2006, EPA's Policy Advisor to the Assistant Administrator,
Jason K. Burnett, is reported as saying that ``the Agency has known all
along that the industrial Midwest stands out as a region where mercury
would be driven up by industrial sources.'' If that is so, why does the
fact sheet on the EPA web page for the CAMR say that mercury from U.S.
power plants is only 1 percent of the global pool? Why is there a bar
chart on the EPA web page showing less than 8 percent of the deposition
in the United States is coming from U.S. power plants? Were these
documents accurate when they were created? Are these documents still
accurate? If not, does EPA have plans to correct them?
Response. The Agency has clearly and consistently communicated that
there are regional differences in mercury deposition from U.S. sources,
including power plants. In the preamble to the final 112(n) Revision
Rule we describe not only the average utility deposition but the 90th
percentile, the 99th percentile, and the maximum deposition in Table
VI-5 on 70 FR 16019. The technical support documents show that a
significant fraction of the deposition in parts of the Midwest is from
U.S. sources (see http://www.epa.gov/ttn/atw/utility/aqm--oar-2002-
0056-6130.pdf). Maps showing the regional variation have been used in
congressional testimony (see Testimony of Jeffrey Holmstead Assistant
Administrator, U.S. Environmental Protection Agency, Before the Energy
and Air Quality Subcommittee, Energy and Commerce Committee, U.S. House
of Representatives, May 26, 2005), by your colleagues on the Senate
floor, and in many other venues. While containing some uncertainty,
this information was and is the Agency's best estimate of the
contribution of mercury deposition from various sources.
While communicating the regional differences, we also have
communicated that mercury exposure is generally a global issue since
ninety percent of the fish and shellfish we eat are from the marine
environment; and nearly 80 percent of those are imported. Because the
United States represents just a few percent of global man-made mercury
emissions, we cannot expect a quick fix to the global mercury problem
from controls on U.S. sources.
For the foreseeable future, EPA advises that women who may become
pregnant, pregnant women, nursing mothers, and young children carefully
observe the joint EPA-FDA Fish Advisory issued last year. We are also
committed to working collaboratively with those countries that are the
largest sources of airborne mercury to help them reduce those emissions
to the global pool. Our actions reduce our contribution to the global
pool and promote the technologies so other countries can follow our
lead.
Question 22. EPA used the Community Multi-scale Air Quality model
to estimate mercury deposition. However the modeling utilized a 36
kilometer grid, which is too large a grid to distinguish local
deposition. A smaller grid, such as a 12 kilometer grid would do a much
better job of portraying the local impact of power plants on mercury
deposition. Given this new study, will EPA redo the modeling with a
smaller grid size, such as 12 kilometers?
Response. EPA's reasoning for using a 36-km grid square size was
discussed in the final CAMR and supporting documentation. This
documentation outlined three reasons for using a 36-km grid square size
as opposed to a smaller size. First, the larger grid size would account
for Hg deposition that enters a watershed through subsurface inflow and
runoff, as opposed to a smaller grid size which may only account for
direct inputs to surface water. Second, in larger water bodies where
there is substantial fishing activity, the fish species consumed by
humans are likely migratory and the accumulation of Hg in these fish
will come from deposition over a larger area. Third, many anglers may
catch fish from a variety of water bodies in a watershed; thus, a
larger grid size would account for this fishing pattern.
Question 23. Please provide all documents in your possession
authored by you or received by you from persons outside EPA that relate
to the Steubenville study, mercury trading and mercury hotspots.
Response. I am supplying you with all responsive documents in my
possession that are not privileged.
Question 24. In January, a month after EPA proposed to revise the
fine particle ambient air quality standards (PM<INF>2.5</INF> NAAQS),
EPA issued a draft regulatory impact assessment (RIA) of the costs and
benefits of the proposed standards and several alternatives. The Clean
Air Act requires that the Administrator set the NAAQS based on what is
requisite to protect public health with an adequate margin of safety,
and precludes consideration of costs until later in the process when
the standards are being implemented. Nonetheless, the RIA can provide
useful information for the public and congressional debate regarding
the NAAQS and can assist States and EPA when they implement the NAAQS.
I am concerned that the public and congressional debate will not
benefit from a final RIA that takes the same analytical approaches as
the draft RIA. As EPA acknowledged in the draft RIA and in briefings to
Senate staff, the draft RIA has some significant limitations. Chief
among these is that it focuses on the costs and benefits of achieving
the proposed and alternative PM<INF>2.5</INF> standards in 5 cities,
rather than on a national basis. EPA staff indicated that the final RIA
will correct some of these limitations and will have some significant
differences from the draft RIA, although EPA is unlikely to have time
to release another draft for public comment before finalizing the RIA.
Because I am concerned that the RIA will not provide information
that I believe would be useful for congressional and public debate of
the PM<INF>2.5</INF> NAAQS and for later State implementation efforts,
please provide a national cost-benefit analysis for attainment of each
of the following sets of standards:
------------------------------------------------------------------------
Annual Daily
------------------------------------------------------------------------
15 35
15 30
14 35
14 30
14 25
------------------------------------------------------------------------
As you did in the draft RIA, please use a hierarchy of controls.
The first level of controls should include two programs: a national cap
and trade program for power plant SO<INF>2</INF> and NOx emissions at
the levels that can be achieved at a cost of $2000 per ton and a
national cap and trade program for industrial boilers that can be
achieved at the same cost effectiveness level. The second level of
controls should be diesel retrofit programs funded at the levels
contained in the Presidents 2007 budget every year for the next 10
years. For areas projected to be out of attainment after those controls
are imposed, for each area, please follow the control hierarchy EPA
intends to use in the final RIA.
In addition to projecting the health benefits and monetizing them,
please project which areas would come into attainment using the control
scenarios described above. In projecting the benefits, please model
premature mortality associated with PM exposure as a non-threshold
effect, that is, with harmful effects to exposed populations regardless
of the absolute level of ambient PM concentrations.
Before conducting this analysis, please discuss details with my
staff so that we can ensure the analysis is useful.
Response. For the final rule on the National Ambient Air Quality
Standards for Particulate Matter, which will be issued by court-imposed
deadline of September 27, 2006, EPA will be preparing a final
Regulatory Impact Assessment (RIA). As part of this RIA, EPA plans to
estimate nationwide costs and benefits of illustrative implementation
strategies to demonstrate how the Nation might attain the proposed
standards in 2020, along with costs and benefits of partial attainment
strategies in 2015. Our benefits assessment will include an analysis of
the incremental health benefits, including preventing premature
mortality, in each of these years across the entire Nation. In addition
to the proposed standards, we plan to analyze the costs and benefits of
an alternative combination of standards of 14 mg/m<SUP>3</SUP> annual
and 35 mg daily among other options. We will also provide a more
limited assessment of the costs and benefits of the proposed annual
standard of 15 mg/m<SUP>3</SUP> combined with a 30 mg/m<SUP>3</SUP>
daily standard. In analyzing these alternative standards, we will
evaluate a wide range of potential emissions controls, including local
measures, and where appropriate and necessary, regional control
programs for certain pollutants and sectors. These programs may, if
necessary and cost-effective, include industrial boilers and diesel
retrofits as part of the overall mix of controls. As part of the
outputs of our modeling exercise, we will project areas that attain and
any residual non-attainment areas. As in the benefits analysis for the
proposed rule, we will include estimates of changes in premature
mortality based on a threshold set at natural background (which is
functionally equivalent to assuming a non-threshold model given current
and projected baseline ambient PM concentrations) among other options.
Given the tight schedule for completing this RIA, we have already begun
our analysis. We do not believe that we have sufficient time or
resources to extend the analysis to encompass your request. We would be
happy to brief EPW or your staff on progress with the analysis or
details of the methodology. We will also be happy to share the results
of this analysis with you as soon as we can.
Question 25. In its recent brief before the United States Court of
Appeals for the District of Columbia Circuit regarding EPA's Equipment
Replacement Rule, (ERP), EPA argues that a plant cannot replace itself
in its entirety (or in large part) by rebuilding itself in increments
of 20 percent or less because of EPA's aggregation policy. As an
initial matter, is there anything specific in the current aggregation
policy that directly prohibits a plant from rebuilding itself 20
percent at a time over 5 years? Please identify and describe this
policy. Is the aggregation policy under review in any way? Are any
changes to the aggregation policy being considered that would allow
plants to rebuild themselves in 20 percent increments, or that would
allow more numerous and greater increases while avoiding NSR when
compared to the current aggregation policy? Please provide all
documents in your possession authored by you or received by you from
persons outside EPA that relate to consideration of changes to the
aggregation policy.
Response. EPA's aggregation policy is in need of clarification. We
concluded this in our 2002 review of the NSR program and our subsequent
Report to the President, which recommended, among other things, that
EPA ``clarify [that] a project would be considered separate and
independent from any other project at a major stationary source unless
the project is dependent upon another project to be economically or
technically viable.'' We are currently working on a rulemaking to
implement this recommendation and expect a proposal by this summer. The
proposal would clarify our current aggregation criteria, not change
them. As part of that clarification, we plan to take a position
consistent with what we have argued in the brief you cite. That is, our
aggregation policy requires aggregation of projects unless they are
technically or economically independent. Further, consistent with our
brief, we believe that a program to rebuild an entire plant in 20
percent increments would comprise a set of actions that were not
independent, and would need to be aggregated for NSR purposes.
I am supplying you with all responsive documents in my possession
that are not privileged.
Question 26. On October 13, 2005, EPA proposed changes to the New
Source Review (NSR) program as it relates to utilities. That same day,
Deputy Administrator Peacock released a memorandum related to NSR
enforcement that stated that ``in deciding which cases to pursue, it is
appropriate to focus on those that would violate our NSR reform rules
and our latest NSR utility proposal which the Agency is releasing
today.'' In order to clarify the application of this document for the
public, please indicate whether the phrase ``our NSR reform rules''
from that document refers or does not refer to the Equipment
Replacement Rule that was stayed by the United States Court of Appeals
for the D.C. Circuit. If you claim that such a clarification is
confidential or privileged, please explain how clarification of the
application of a publicly released document is confidential or
privileged.
Response. The regulated community must comply with all applicable
regulations, including existing NSR requirements. Because the Agency's
Equipment Replacement Rule (ERP) has been stayed by the U.S. Court of
Appeals for the District of Columbia Circuit, it was not part of ``our
NSR reform rules'' at the time of the Peacock Memorandum, and
consequently, the regulated community currently has no legal right to
implement the ERP. We note that, since the D.C. Court vacated the ERP
on March 17, 2006, the ERP continues not to be part of our rules.
Question 27. With regard to the NSR changes proposed by the EPA on
October 13, 2005, how many of EPA's settled and pending NSR enforcement
cases would have been viable, if any of the options proposed by the
Agency in that rulemaking had been in effect at the time of the
violation? If the Agency has not conducted this analysis for some or
all of the cases, will it do so and provide these results to the
committee? If you claim a privilege with regard to this information
please identify the privilege and explain how providing numbers of
cases, without any identifying information, violates the privilege.
Response. The proposed NSR rules plainly and expressly state that
they are to be applied to changes that post-date the rules' respective
effective dates and thus shall not affect the existing enforcement
cases. EPA intends to continue to vigorously pursue the existing
enforcement cases and other matters in negotiations. In addition, EPA
will continue to focus on those cases that would violate our ``NSR
reform rules'' (as described in response to question 24 above) and our
latest utility proposal.
With respect to whether or not EPA has considered, or is
considering, the impact of the rules on the settled and pending NSR
enforcement cases, it is EPA's long-standing policy not to comment on
the specific enforcement-sensitive aspects of the enforcement cases.
That a matter is settled or closed does not cause an otherwise
applicable common law or statutorily based privilege to no longer apply
to that matter. Any assessment performed by attorneys or at the
direction of EPA's attorneys regarding the impact that a newly
promulgated or proposed rule might or might not have on settled or
pending cases would be protected from disclosure by application of the
attorney-client privilege or attorney work product doctrine. EPA has a
number of cases in active litigation at this time, and there are many
common issues of fact and law between these cases and those that are
pending or resolved. Thus, disclosure of an EPA assessment of whether
or not the pending or settled cases would have been viable in light of
the October 13, 2005 rulemaking is privileged.
Question 28. A recent letter written by Stephen D. Page, Director
of the Office of Air Quality Planning, concludes that an analysis for a
coal fired power plant of Best Available Control Technology (or Lowest
Achievable Emissions Rate), under the Clean Air Act, need not include
evaluation of Integrated Gasification Combined Cycle plants. This
letter was issued on December 13, 2005 in response to a letter from Mr.
Paul Plath, of E3 Consulting, Englewood, Colorado. This position, which
was not reached pursuant to notice and comment rulemaking, appears to
be inconsistent with the Administration's expressed desire to promote
the use of IGCC as a means of reducing air pollution, including
emissions of greenhouse gases. Nor does it appear consistent with
previous positions regarding BACT and LAER. I would like to know
whether EPA plans on adopting this position through notice and comment
rulemaking. I would also like to know whether you and/or Administrator
Johnson approved this position and your role in developing and arriving
at this position. When did you first become aware of this issue and did
you make contact with Mr. Plath or other parties outside EPA regarding
this issue prior to issuance of the letter? Which parties and when?
Please provide all documents authored by you or received by you from
persons outside EPA that you have regarding the development, issuance
and approval of this letter.
Response. We are currently considering the possibility of adopting
this interpretation through rulemaking. Both the Administrator and
myself concurred with the Page memo. I played a substantive role in
developing this interpretation. I have not personally been in contact
with Mr. Plath. The issue first came to my attention when it was raised
by petitioners in Title V permit actions. I do not recall the
particular action in which it first was raised. At the request of
outside parties, I had two meetings regarding this issue. The first
meeting occurred on December 2, 2005, and included the following
people: Teresa A. Gorman, Joe Stanko, Hillary Sills, Randy Randol, and
Shawn Glacken. The second meeting took place on March 16, 2006, and
included Vickie Patton and Mark McLeod of Environmental Defense, and
David Hawkins of Natural Resources Defense Council. In addition to
myself, other EPA personnel were in attendance. No additional meetings
were requested.
There are no documents responsive to your request that are not
privileged.
Question 29. A recently leaked memorandum from Deputy Administrator
Marcus Peacock sets out a plan to review the process for National
Ambient Air Quality Standards (NAAQS) in order to see whether that
process can be strengthened. The NAAQS are a cornerstone of the Clean
Air Act and the process for setting NAAQS has widely been heralded a
leading example of exhaustive, peer reviewed scientific effort. The
NAAQS and the processes that have developed these standards have
repeatedly been validated by the courts. The Peacock memo sets an
ambitious plan for reviewing that process and suggesting changes by
April 3, 2006. You, together with Assistant Administrator George Gray
are the recipients of the process and will head up the workgroup. The
secretive nature of the initial memo, the small number of participants
in the process and the speed at which recommendations are to be made
regarding fundamental elements of the Clean Air Act are cause for
concern. Will this review of the NAAQS process be open and public? Who
will participate in the process? Will parties outside the EPA
participate, including representatives of the White House or Office of
Management and Budget? What is the process for implementing any
recommendations that may result? Why is the deadline April 3, 2006?
What concerns about the NAAQS process specifically lead to this review?
Have you had contacts with parties outside EPA prior to or during the
review regarding this issue? Please list these contacts and provide all
documents or information relating to such contacts.
Response. On December 15, 2006, Deputy Administrator Marcus Peacock
issued a memo requesting a ``top-to-bottom'' review of the NAAQS
process. This review was prompted by a desire to ensure that the best
available science is being used to accelerate environmental progress
and protect public health. Because of the importance of the NAAQS
review process, and because the Agency has some discretion over certain
steps in this process, the Administrator wants to ensure that we are
utilizing the most rigorous, up-to-date, and unbiased scientific
standards and methods.
To fulfill the Deputy Administrator's request, EPA established a
working group co-chaired by Dr. George Gray, Assistant Administrator of
EPA's Office of Research and Development, and myself. This working
group comprises a team of experienced managers who have been involved
in the NAAQS review process for many years, including representatives
from our Office of Research and Development, Office of Air and
Radiation, Office of General Counsel, and Office of Policy, Economics,
and Innovation. This team established the structure for our review of
the NAAQS review process, determined how to involve external
stakeholders, and decided what types of outputs will be most helpful
for strengthening the NAAQS review process.
The working group reviewed previous assessments of the NAAQS review
process and other relevant documents. Furthermore, the group developed
a list of key questions that are being used to guide the Agency through
this process. These questions, which are listed below, focus on central
issues such as the timeliness of the NAAQS review process; how to
ensure consideration of the most recent available science; distinctions
between science and policy judgments; and how to identify,
characterize, quantify, and communicate uncertainties in scientific
information.
In addition to helping EPA structure its internal discussions,
these framing questions are being used to solicit input from external
stakeholders. As a first step, on February 10, 2006 George Gray and I
participated in an administrative meeting with members of our Clean Air
Scientific Advisory Committee (CASAC), which is EPA's main scientific
advisory partner in the NAAQS process. We described the charge from the
Deputy Administrator and invited current and former CASAC members to
provide individual input as the process moves forward. In addition to
seeking input from CASAC members, we have scheduled a limited number of
meetings with stakeholder groups that have a history of significant
involvement in the NAAQS review process. The list of meetings that have
occurred to date and the stakeholder groups involved are attached
below. We have also briefed members of your staff as well as of other
congressional committees. The EPA working group took the perspectives
and recommendations expressed during these stakeholder meetings into
consideration as it developed its recommendations to the Deputy
Administrator. Included with the provided documents you will find a
copy of CASAC members and other stakeholders' comments, the workgroup
report to Deputy Administrator Peacock, and other relevant agency
documents.
We recognize both the importance of undertaking a thorough review
and the complexity of the issues involved. Because we hope that the
working group's findings may help inform ongoing NAAQS reviews,
including the reviews of the NAAQS for ozone, lead, nitrogen dioxide,
and sulfur dioxide, we are striving to make rapid progress. Toward this
end, the EPA working group provided initial recommendations to the
Deputy Administrator on April 3, 2006. These recommendations included
key questions about the NAAQS process that need further study, and
basic themes or ideas for further development. This will be an ongoing
process that did not concluded on April 3d, and there will be
additional opportunities for input by a broader group of stakeholders.
key questions for the review of the process for setting naaqs
Timeliness of the NAAQS review process
<bullet> What are your views on the timeliness and efficiency of
the current process for both EPA's and CASAC's reviews of the air
quality criteria and the NAAQS, in terms of the time that is spent
between the start of the review and the publication of the Agency's
proposed decisions on the standards?
<bullet> Can you identify structural changes to the process and/or
key documents (e.g., the Criteria Document, Staff Paper, Risk
Assessment) or changes in the Agency's management of the process that
could shorten this timeframe while preserving an appropriately
comprehensive, transparent and policy-relevant review and allowing
adequate opportunities for CASAC review and advice and for public
comment on these documents?
Consideration of the most recent available science
<bullet> To enhance the Agency's ability to take the best and most
recent available science into account in making decisions on the
standards, can you suggest changes in the process and/or key documents
that could shorten the time between the presumptive cutoff date for
scientific studies evaluated in the review and reaching proposed
decisions on the standards, or that could otherwise facilitate
appropriate consideration of more recent studies?
Distinctions between science and policy judgments
<bullet> Recognizing that decisions on the standards, while based
on the available science, also require policy judgments by the
Administrator, what are your views on how clearly scientific
information, conclusions, and advice are distinguished from policy
judgments and policy recommendations on the standards throughout the
review process?
<bullet> Can you suggest changes in the process and/or changes to
the format and contents of key documents that would help to make these
distinctions clearer?
Identifying, characterizing, quantifying, and communicating
uncertainties in scientific information
<bullet> Recognizing the importance of characterizing and clearly
communicating the uncertainties in the science and quantifying
uncertainties in exposure and risk estimates as explicitly as possible,
what are your views on any changes in the process and/or changes to the
format and content of key documents that might facilitate a more
complete, quantitative, and policy-relevant characterization of
uncertainties?
list of stakeholder meetings and participants
Meeting with Industry Representatives, February 23, 2006
American Petroleum Institute
Electric Power Research Institute
Automobile Alliance
Hunton & Williams
Lyle Isenkower
Ron Wyzga
Valerie Ughetta
Cindy Langworthy
Meeting with State Stakeholders, March 3, 2006
NESCAUM (Northeast States)
California Air Resources Board
Arthur Marin and Phil Johnson
Lynn Terry and Richard Bode
Meeting with Environmental/Public Health Stakeholders, March 3, 2006
American Lung Association
Environmental Defense
Clean Air Trust
Earthjustice
Nat'l Park Conservation Foundation
Paul Billings, Janice Nolan,
Debbie Shprentz, Blake Early
Vickie Patton, John Balbus
Frank O'Donnell
Howard Fox
Mark Wenzler
Meeting with NAS Chairs, March 6, 2006
Health Effects Institute
Johns Hopkins
Dan Greenbaum, Bob O'Keefe
Jon Samet
In addition to these planned stakeholder discussions, this topic
has arisen in numerous other meetings and events. For example, I spoke
at a meeting of the Agricultural Air Quality Task Force on March 1,
2006. I made brief remarks about this issue and fielded questions. More
of these meetings and events were scheduled for the purpose of
discussing this issue. And the issue has generally been addressed in an
informational manner. I have not attempted to list all such events, but
am happy to provide additional information if desired.
Question 30. As follow up to the November 10, 2005 Subcommittee
hearing regarding the Implementation of the Existing Particulate Matter
and Ozone Air Quality Standards, you were asked about the EPA's
Equipment Replacement Rule in the context of the memorandum from Deputy
Administrator Peacock regarding enforcement of New Source Review
requirements. You responded:
``The regulated community must comply with all applicable
regulations, including existing NSR requirements. As your question
points out, the Agency's Equipment Replacement Rule (ERP) has been
stayed by the U.S. Court of Appeals for the District of Columbia
Circuit, and therefore the regulated community currently has no legal
right to rely on ERP to avoid potential NSR liability. The `Peacock
Memorandum' was not intended to circumvent the D.C. Circuit stay or
`legaliz[e] questionable activity.' Indeed, the Agency reserves its
discretion to bring enforcement actions against companies that violate
the law, including those that prematurely rely on ERP. EPA's
enforcement resources are limited, and thus the Agency must expend its
resources wisely. The Peacock Memorandum does not create any rights for
the regulated community and is intended to help focus EPA's enforcement
discretion on those cases that would have the biggest benefit for human
health and the environment.''
NSR cases have been shown to have very large benefits. The EPA
Office of Enforcement recently briefed EPA on its enforcement
activities during the last year and noted that enforcement cases
brought to conclusion during fiscal year 2005 resulted in 1.1 billion
lbs. of pollutant reduction from all media. Of these reductions, nearly
half the reductions, in the vicinity of half a billion pounds, were
from 2 NSR enforcement cases(the Illinois Power/Dynegy case and the
Ohio Edison case. These benefits only take into account a single year
of reductions, with the actual reductions going on for many years into
the future. These two cases represent the vast majority of benefits
from the top ten air cases, which had estimated benefits for a single
year valued at $4.6 billion. With regard to your response quoted above,
are there other cases that would have larger benefits than NSR cases?
If so please identify in generic terms the types of cases that would
have such benefits. Why would the particular cases identified in the
Peacock NSR memorandum be lacking in large benefits?
Response. The October 13, 2005 memorandum stated that as part of
EPA's NSR national priority, the Agency will continue to pursue filed
cases and cases in active negotiation against coal-fired power plants.
In deciding the additional cases to pursue, EPA will focus resources on
those matters that violate the ``NSR reform rules'' and EPA's latest
NSR utility proposal.
Emissions from the electric utility sector are also projected to
decrease dramatically over the next two decades as a result of several
CAA programs, including the Clean Air Interstate Rule, the Acid Rain
Program, and the Clean Air Visibility rule. We describe the EGU
emission reductions from these regulations in detail at 70 Fed. Reg.
61,084 (Oct. 20, 2005). EPA will present supporting analyses in our
supplemental proposal when published.
The emissions reductions from the electric utility sector that will
occur as a result of the enforcement cases and CAA programs mentioned
above will allow the Agency to focus its limited enforcement resources
to pursue NSR violations in other industrial sectors that are known to
have significant emission inventories. Focusing on these sectors has
the potential to produce significant human health and environmental
benefits. The following data is taken from EPA's 2002 National Emission
Inventory (NEI) Data base, and identifies the top twenty-four
industrial sectors in the NEI, excluding utilities:
------------------------------------------------------------------------
Nationwide SO2 Emissions
Sector Point Sources (tpy)
------------------------------------------------------------------------
Pulp and Paper Mills.......................... 448,385
Petroleum Refining............................ 404,154
Combination Utilities......................... 331,858
Oil and Gas................................... 185,000
Cement Manufacturing.......................... 183,599
Food and Kindred Products..................... 153,223
Organic Chemical Production................... 133,995
Primary Smelting of Nonferrous Metals......... 132,898
Inorganic Chemical Production................. 119,992
Primary Production of Aluminum................ 117,548
Misc. Chemical Products....................... 108,322
Coke Ovens and Steel Works.................... 98,651
Misc. Petroleum and Coal Products............. 75,106
Agricultural Chemicals Production............. 73,457
Service Industries............................ 62,865
Plastics Materials and Synthetic Resins....... 61,688
Aluminum Products............................. 32,783
Instruments and Related Products.............. 28,183
Concrete Products............................. 28,104
Metal Mining.................................. 23,398
Glass Products................................ 23,277
Misc. Mineral Products........................ 22,436
Public Administration......................... 21,731
Steam and Air-Conditioning Supply............. 21,229
------------------------------------------------------------------------
------------------------------------------------------------------------
Nationwide NOx Emissions
Sector Point Sources (tpy)
------------------------------------------------------------------------
Natural Gas Production, Transmission, and 575,515
Distribution.................................
Oil and Gas Production........................ 318,210
Pulp and Paper Mills.......................... 302,657
Petroleum Refining............................ 242,648
Cement Manufacturing.......................... 231,674
Organic Chemical Production................... 188,052
Combination Utilities......................... 146,421
Coke Ovens and Steel Works.................... 107,213
Glass Products................................ 82,978
Food and Kindred Products..................... 82,115
Lumber and Wood Products...................... 62,146
Inorganic Chemical Production................. 58,681
Metal Mining.................................. 58,472
Refuse Systems................................ 53,283
Agricultural Chemicals Production............. 51,489
Plastics Materials and Synthetic Resins....... 50,187
Service Industries............................ 43,163
Concrete Products............................. 34,084
Public Administration......................... 28,891
Transportation Equipment...................... 22,342
Primary Production of Aluminum................ 21,891
Misc. Chemical Products....................... 19,174
Misc. Mineral Products........................ 18,795
Textile Mill Products......................... 18,635
------------------------------------------------------------------------
Question 31. You were also asked whether the Illinois Power/Dynegy
and Ohio Edison would have been eligible for filing under the Peacock
memo? You responded: ``[b]oth Illinois Power and Ohio Edison are filed
cases and were prosecuted to successful settlements. It is EPA's long-
standing policy to not comment on specific enforcement sensitive
aspects of individual cases.'' Since those cases are now settled, would
it violate any specific enforcement privilege to indicate whether or
not the application of the Peacock memorandum would have resulted in a
different outcome in those cases? How? If not, please indicate, by way
of yes or no answers, whether such cases would have been impacted by
the Peacock memorandum and whether the Agency would have brought them
if the Peacock memorandum were in effect.
Response. The Agency is unable to comment on specific matters, even
if prosecuted to successful settlements, because any such comments
could be used to affect ongoing litigation. As discussed above, it is
EPA's long-standing policy not to comment on the specific enforcement-
sensitive aspects of the enforcement cases; that a matter is settled or
closed does not cause an otherwise applicable common law or statutorily
based privilege to no longer apply to a matter. Any assessment
performed by attorneys or at the direction of EPA's attorneys regarding
the impact that a newly promulgated or proposed rule might or might not
have on settled or pending cases would be protected from disclosure by
application of the attorney-client privilege or attorney work product
doctrine. EPA has a number of cases in active litigation at this time,
and there are many common issues of fact and law between these cases
and those that are pending or resolved. Thus, disclosure of an EPA
assessment of whether or not the Peacock memorandum would have dictated
a different outcome in the Illinois Power/Dynegy and Ohio Edison
matters is privileged.
Question 32. You were also asked whether the proposed NSR rule was
similar to a previous EPA NSR proposal that was previously rejected by
EPA (as recently as 2002) because it could lead to large emissions
increases without requiring controls. You responded by contending that
the previous approach rejected by EPA (CMA Exhibit B) was not the same
as the proposed rule because the proposed rule determines actual
emissions based on current operating capacity, which is not the same as
the approach in CMA Exhibit B. Furthermore, CMA Exhibit B proposed to
use potential emissions to determine the amount of emissions that must
be offset. We proposed to retain actual emissions for computing the
amount or availability of emissions offsets. For these reasons, the
maximum achievable hourly emissions option of our proposed rule for
EGUs is not the same approach as CMA Exhibit B.
In essence, your contention is that the proposed approach is not a
potential-to--potential test, but is an actuals based test and
therefore would not lead to the same emissions increases as a
potential-to-potential test. However, the assertion that the proposed
rule is not a potential-to-potential test is not supported or
explained. In fact, however, the Agency has previously described the
proposed rule as a potential-to-potential test. In a June 25, 2005
draft of the proposal informally submitted to the Office of Management
and Budget. See EPA-HQ-OAR-2005-0163-0044, at 71 EPA stated that we
believe the potential-to-potential test as proposed in the form of a
maximum hourly emissions test considering controls for CAIR Units is
particularly well suited for striking the required balance between
effective environmental protection at a cost that is not detrimental to
economic growth.)(emphasis added); id. at 68-69 (We do not believe that
a potential-to-potential approach is acceptable for major NSR
applicability as a general matter. Nonetheless, we believe that in
circumstances where use of highly efficient units ensure air quality,
such as those for CAIR Units, a potential-to-potential approach would
be acceptable.) (emphasis added). The Agency has also admitted that a
potential to potential test will lead to large emission increases and
stated that We agree that a potential-to-potential test for major NSR
applicability could lead to unreviewed increases in emissions that
would be detrimental to air quality and could make it difficult to
implement the statutory requirements for state-of-the-art controls. 67
Fed. Reg. at 80,205/2. at 80,205/3.
In light of all of the elements of CMA exhibit B that lead to the
previous EPA criticisms in 1996 and 2002, please explain how the
proposed rule has eliminated all of those elements in such a way that
now allows EPA to claim the proposal would not result in harmful
emissions consequences. Please indicate whether the proposal would
require controls in all instances that CMA exhibit B would not have
required control. If the proposal does not require controls in
situations where sources do not exceed their potential emissions,
please describe such situations. Please explain why the harms arising
from these situations are not equally true under the proposed rule when
compared to CMA Exhibit B.
Response. As you point out, in early versions of the preamble for
our proposal, we described our test as ``the potential-to-potential
test as proposed in the form of a maximum hourly emissions test.''
However, this description was a mischaracterization that was corrected
in subsequent preambles. It is not uncommon for errors to occur in
draft documents that the Agency prepares for review prior to
publication.
With respect to emissions, we believe that the difference in
outcome between the maximum hourly test as EPA has proposed and the
annual emissions test, under current Clean Air Act constraints, would
be significantly less than the difference in outcome between the CMA
Exhibit B potential-to-potential test and the annual emissions test,
under the Clean Air Act constraints that existed in 1988, when EPA
conducted the CMA Exhibit B analysis. This difference arises because
under the various programs of the 1990 Clean Air Act Amendments (for
example, the Clean Air Interstate Rule, Clean Air Visibility Rule, NOx
SIP Call, Acid Rain program), actual annual emissions for EGU have been
significantly constrained. By comparison, before the 1990 Clean Air Act
Amendments, revising those modification rules in CMA Exhibit B could
have had a much greater impact on emissions and air quality. Moreover,
in CMA Exhibit B, the allowable emission rates of course did not
reflect the additional requirements under the Clean Air Act that came
into effect for EGUs after 1990. For this reason, an analysis of the
difference in outcomes undertaken today would be unlikely to have the
same results as the CMA Exhibit B analysis completed in 1988. Public
commenters have asked us to address this question, and we intend to
respond to it as part of our response to the public comments for the
proposed rulemaking.
Concerning when controls might be required under the existing major
NSR program, it is speculation to attempt to determine when any single
facility would undergo a physical change or change in the method of
operation. Should a facility undertake a physical change or change in
the method of operation, it may be the case that the facility would not
trigger major NSR review under the actual-to-projected-actual emissions
test in the current rules. This is because facility actual annual
emissions within the prior 5-year period vary such that there
frequently is a 2-year period with higher baseline actual emissions
than the facility's emissions at the time of the change and higher than
the facility's projected actual emissions.
There is an additional reason that limits the difference in outcome
between the proposed maximum hourly emissions test and the actual-to-
projected-actual emissions test. Like the NSPS test, the major NSR
regulations allow for consideration of an emission unit's operating
capacity in determining whether a change results in an emissions
increase. Under the actual-to-projected-actual test, a source can
subtract from its post-project emissions those emissions that the unit
could have accommodated during the baseline period and that are
unrelated to the change (sometimes referred to as the ``demand growth
exclusion''). That is, the source can emit up to its current maximum
capacity without triggering major NSR under the actual-to-projected-
actual test, as long as the increase is unrelated to the physical or
operational change. We plan to address this point in more detail in our
response to comments on our proposed rulemaking.
There are further differences between the maximum hourly test that
we have proposed and the CMA Exhibit B test. The CMA Exhibit B test is
a true ``potential-to-potential'' test because it compares pre-change
emissions at design capacity to post-change emissions at design
capacity. Our criticisms in 1996 and 2002 concerned the CMA Exhibit B
potential-to-potential emissions increase test. The test in our
proposed rulemaking in 70 FR 61081 (October 20, 2005), is based on the
pre- and post-change actual physical and operating capacity in light of
our view that EGUs generally operate, for at least a short period, at
their actual physical and operating capacity. See 70 FR at 61091/1-2.
Therefore, our proposed test is a test of actual emission increases
based on actual physical and operating capacity, and not a potential-
to-potential test.
If an EGU increases its actual operating capacity over the maximum
actual operating capacity in the past 5 years, it would require major
NSR review under the proposed maximum hourly emissions test. This is
not the case with the potential-to-potential test in CMA Exhibit B. In
the potential-to-potential test, major NSR review would only occur if
an emissions unit increased its design capacity. Major NSR review, and
resulting control technology determinations, are thus more likely to
occur under the proposed maximum hourly emissions test than under the
potential-to-potential emissions test in CMA Exhibit B.
For all these reasons, our proposed test is distinct from a
potential-to-potential test like CMA Exhibit B, and we believe it is
accurate to conclude that it will not result in harmful emissions
consequences.
Question 33. Another question you were asked as follow up to the
November 10, 2005 relates to EPAs recently proposed NSR rule and
whether it would lead to emissions increases. You responded: We do not
expect the proposed rule would lead to emission increases from the
power sector. To the contrary, emissions from the power sector are
projected to decrease dramatically over the next two decades. This is
attributable to several CAA programs, including the Clean Air
Interstate Rule, the Acid Rain Program, and the Clean Air Visibility
rule. The question you were asked, however, was not intended to address
whether emissions from the power sector as a whole will decline over
time due to other programs, but whether the proposed NSR exemption (or
method of calculating increases) allows additional pollutants to be
emitted in comparison to EPAs current NSR regulatory approach? If so,
has EPA calculated in any way the amount of these emissions and will
EPA provide this calculation to the committee?
Response. Power sector SO<INF>2</INF> and NOx emissions will
continue to decline over time, regardless of whether the major NSR
emissions increase test is the actual-to-projected-actual emissions
test or the maximum achievable hourly emissions test. For the reasons
we state in the answer to number 30 above, we do not believe that the
revised emissions test would result in a substantially different
outcome from the actual-to-projected-actual test. We are aware of the
interest in more analysis of the environmental impacts of our proposal.
As we indicated in our 2005 notice, we plan to provide additional
environmental analysis in our supplemental notice, which we expect to
publish this summer.
Question 34. With regard to the issue of emission increases that
could occur as a result of the proposed NSR rule, you were asked about
an EPA memorandum from Adam Kushner that did estimate large increases
from the proposed rule. You were asked: What is the Agency's position
with regard to these case studies? Does the Agency believe that its
proposed changes will not allow such increases in emissions? On what
basis does the Agency reach such a conclusion? You answered as
previously noted, we intend to provide in the near future a thorough
environmental analysis of the NSR proposal in a supplemental proposal.
Please answer these specific questions.
Response. We intend to respond to the analyses in Adam Kushner's
memorandum as part of our response to the public comments for the
proposed rulemaking. As we indicated in our 2005 notice, we plan to
provide additional environmental analysis in our supplemental notice,
which we expect to publish this summer.
Question 35. In relation to the NSR rule signed on December 13,
2005, you were asked: (With respect to the proposed new source review
rule that was signed on October 13, 2005, please produce all documents
(including electronic documents and e-mails) in the Agency's possession
related to the proposed rule, that were prepared or dated prior to
October 13, 2005, including but not limited to:
A. drafts of the preamble or inserts for the preamble;
B. comments on draft rules or preambles;
C. documents discussing the legislative history or legal authority
related to this proposal; and
D. correspondence or other documents related to the proposed rule
that were shown to, given to, or received from people other than
Federal employees or contractors.
Your response to the committee was to state that: (In response to
your request for information on the NSR rule, we have included all non-
privileged documents available at this time.( Please provide a list of
the privileged documents and identify the privilege.
Response. You also requested a list of the privileged documents
responsive to your previous request. I would be happy to speak with you
or your staff about ways that we may be able to fulfill this request.
______
Responses by William Wehrum to Additional Questions from
Senator Voinovich
Question 1. You stated that clean air regulations affect the demand
for natural gas but that it is not a substantial factor in the pricing
of natural gas. However, EIA's testimony states that ``very small
shifts in either demand or supply can have a big impact on price.'' If
clean air regulations affect the demand for natural gas, then based on
EIA's statement haven't they in the past and won't they in the future
impact the price of natural gas?
Response. Many different provisions of the Clean Air Act may affect
both the construction and operation of electric generating units (EGUs)
and may influence fuel choices by the power industry. Electric
generating units may be considered to be major sources subject to Title
V permitting requirements. In general, it is easier to obtain permits
for new gas-fired plants than coal-fired plants. The cost of pollution
control equipment to meet Best Available Control Technology
requirements for coal-fired EGUs also greatly exceeds the cost of such
equipment for gas-fired units. Other provisions of the Clean Air Act
that do not directly regulate EGUs, including State implementation of
the National Ambient Air Quality Standards, may also have an additional
impact on fuel choices in particular States or regions.
EPA has not retrospectively analyzed the impact of all Clean Air
Act programs, many of which are implemented on the State level, on fuel
choices in the EGU sector and other industrial sectors which are large
energy consumers. Therefore, the Agency cannot provide a comprehensive,
quantitative assessment of the impact the implementation of all Clean
Air Act programs on the price of natural gas. As I stated in my
testimony, EPA has not seen evidence that regulations of the power
sector are alone a substantial factor in the pricing of natural gas
although it is certainly an important consideration in many decisions.
With respect to future impact, EPA has recognized that different
approaches to regulation have the potential to affect both fuel choices
and fuel prices in the EGU sector. As a result, the Agency has taken
steps to design programs to avoid such an outcome. The recently
promulgated Clean Air Interstate Rule, Clean Air Mercury Rule, and
Clean Air Visibility Rule are examples of this. EPA's modeling shows
that this suite of regulations will have minimal impacts on energy use
patterns and natural gas prices. They are projected to increase natural
gas prices only in the range of 1-3 percent between 2007 and 2020.
Question 2. You indicate that Clean Air Act programs can affect
natural gas use. Several programs such as the NOx SIP call and Acid
Rain program caused at least some fuel switching to natural gas. Other
statistics indicate an 8 percent shift from coal to gas from 1998 to
2002. Is there danger of death from a thousand cuts -- that small
effects can add up to a much larger effect under the right
circumstances?
Response. EPA believes that Clean Air Act programs can have an
effect on the demand for natural gas and its price, but it has not
determined that over time there has been a substantial impact on price.
CAA programs do not appear to cause substantial shifts in natural gas
usage. In the time period mentioned in your question, both coal and
natural generation increased in real terms, although there was a much
more rapid increase in gas-fired generation. This resulted in a decline
in coal generation as a percent of total generation and an increase in
natural gas generation as a percentage of total generation over that
time period.
As mentioned with respect to question immediately preceding this
question, EPA has taken care to design its suite of major Clean Air Act
rules to avoid major impacts on energy usage and natural gas prices.
Your question points to the need to ensure that future implementation
of the Clean Air Act also take such impacts into account.
Question 3. A substantial amount of new natural gas plants were
built since 1990 with a much smaller amount of coal. This trend is
expected to continue at least through 2007. Aside from any cause and
effect with regard to the Clean Air Act, doesn't this lopsided trend in
of itself cause some concern? Even though many of these natural gas
units may not run much now, they are built and could be subject to
greater utilization in the future. How can we restore balance in new
capacity?
Response. As detailed in question No. 5 below, a significant number
of gas plants were built in the 1990's. From 1990 to 2003 a total of
115, 086 MW of combined cycle gas and 86,643 MW of gas turbine capacity
was built, compared with only 11, 411 MW of coal steam capacity.
Natural gas consumption for generation also increased during this time.
EPA projections examining both a ``base case'' and the effect of CAIR/
CAMR/CAVR also indicate that natural gas generation will increase
relative to coal generation between 2010 and 2020.
EIA projects, however, that a significant amount of the new plants
to be built over the next 10 to 15 years will be coal-fired. Longer
term EPA projections for coal generation in the 2020-2030 timeframe
also show increased coal utilization relative to natural gas.
Therefore, increased construction of coal-fired capacity in the near to
mid-term as well as policies such as CAIR/CAMR/CAVR which are attentive
to their effect on energy usage can assist in maintaining balanced
energy generation. However, market factors such as costs of natural
gas, capital cost, and time required to build a gas plant compared to a
coal plant are likely to have a greater impact on choice of fuel for
new electric power generation.
Question 4. EPA has attempted to design programs to preserve fuel
options in this country. I know that the Agency believes that the Clean
Air Interstate, Mercury, and Visibility Rules have a limited effect on
natural gas. Can you give us some indication of what might happen if
the programs were not designed this way--for example, accelerating
control requirements too much or removing flexible implementation
methods?
Response. EPA's October 2005 Clear Skies analysis revealed that
policies requiring emission reductions beyond what are feasible,
particularly in the shorter term, are likely to lead to increased
pressure on natural gas markets and prices. For example, the Clean
Power Act and Clean Air Planning Act are anticipated to result in
shifts to natural gas as a control option. In the case of the Clean Air
Planning Act, EPA projected a 3-17 percent increase in natural gas
prices between 2010 and 2020. This case indicates that more stringent
standards and less flexible mechanisms can affect natural gas prices
(and consumption).
Question 5. Please provide data on fuel choices for utilities which
have been brought on line since the 1990 Clean Air Act Amendments (list
numbers of power plants each year since 1990 and their fuel choices).
Response. The following table provides the requested information:
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Question 6. Please provide permitting information for coal versus
natural gas plants.
Response. Although permit limits for coal and gas-fired plants have
changed over time, and have decreased considerably for coal plants,
current permit emission rates are generally characterized in the
following table:
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Question 7. Please provide the cost and typical controls for a new
coal power plant compared to a new gas plant.
Response. See below.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
______
Responses by William Wehrum to Additional Questions from
Senator Lieberman
Question 1. Please state in absolute terms the extent to which
coal-fired power plant capacity was increased after November 15, 1990.
Please state in absolute terms to the extent to which natural gas-fired
power plant capacity was increased after November 15, 1990.
Response. The following table provides the requested information:
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Question 2. Please assess the impact of the following factors on
natural gas demand since 1990: the cost of natural gas, capital costs
for new natural gas plants, opportunities for siting such plants, the
time required to build such plants, and responsiveness to load changes
of gas-fired power plants. Please compare or contrast the effect of the
requirements of the Clean Air Act and EPA's implementation thereof to
or with the factors enumerated in the previous sentence in terms of
their impact on natural gas demand.
Response. EPA believes that the primary factors that have lead to
increased use in natural gas in the power sector are the low costs of
natural gas throughout the 1990's and the lower capital cost and time
required to build a gas plant compared to a coal plant. EPA has not
seen evidence that its regulations of the power sector are a
substantial factor in the pricing of natural gas. The figure below
details the relative costs of coal and natural gas plants during the
1990's.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Question 3. Throughout the 1990's a number of States, as well as
the Federal Energy Regulatory Commission, restructured electricity
ratemaking or deregulated it. Please describe the impact of electricity
restructuring or deregulation on the building of new natural gas power
plants and the demand for natural gas.
Response. EPA has not done any significant analysis of the impact
of electricity restructuring or deregulation on the building of new
natural gas power plants and the demand for natural gas. According to
the National Petroleum Council, ``in a deregulated environment,
electricity generators seek the shortest possible time between the
decision to build and point at which capital costs are recovered. Gas-
fired plants have the shortest construction time.''\1\
---------------------------------------------------------------------------
\1\ National Petroleum Council, Natural Gas Meeting the Challenges
of the Nation's Growing Natural Gas Demand, Volume II Task Group
Reports, December 1999.
---------------------------------------------------------------------------
__________
Statement of Arthur E. Smith, Jr., Senior Vice President and
Environmental Counsel, NiSource, Inc. on behalf of the American Gas
Association
introduction
Thank you for the opportunity to testify before the subcommittee.
My name is Arthur E. Smith, Jr. and I am the Senior Vice President and
Environmental Counsel at NiSource Inc. NiSource is headquartered in
Merrillville, Indiana and we are engaged in virtually all phases of the
natural gas and electricity businesses, serving 3.7 million customers
from the Gulf Coast through the Midwest and New England. I am
testifying today on behalf of the American Gas Association which
represents 197 local energy utility companies that deliver natural gas
to more than 56 million homes, businesses and industries throughout the
United States. Natural gas meets one-fourth of the United States'
energy needs and it is the fastest growing major energy source. As a
result, adequate supplies of competitively priced natural gas are of
critical importance to AGA and its member companies. Similarly, ample
supplies of reasonably priced natural gas are of critical importance to
the millions of consumers that AGA members serve. AGA speaks for those
consumers as well as its member companies.
The natural gas industry is at a critical crossroads. Natural gas
prices were relatively low and very stable for most of the 1980's and
1990's. Wholesale natural gas prices during this period tended to
fluctuate around $2 per million Btus (MMBtu). But the balance between
supply and demand has been extremely tight since then, and even small
changes in weather, economic activity or world energy trends have
resulted in significant wholesale natural gas price fluctuations.
Market conditions have changed significantly since the winter of 2000-
2001. Today our industry no longer enjoys prodigious supply; rather, it
treads a supply tightrope, bringing with it unpleasant and undesirable
economic and political consequences most importantly high prices and
higher price volatility. Both consequences strain natural gas customers
residential, commercial, industrial and electricity generators.
As this subcommittee well knows, energy is the lifeblood of our
economy. More than 65 million Americans rely upon natural gas to heat
their homes, and high prices are a serious drain on their pocketbooks.
High, volatile natural gas prices also put America at a competitive
disadvantage, cause plant closings, and idle workers. Directly or
indirectly, natural gas is critical to every American.
The consensus of forecasters is that natural gas demand will
increase steadily over the next two decades. This demand growth will be
driven by the electricity generation market, as natural gas has been
the fuel of choice for over 90 percent of the new generation units
constructed over roughly the past decade. In part, the dominance of
natural gas in this market is attributable to environmental regulations
that promote the clean-burning characteristics of natural gas. The
overall growth in gas usage will occur because natural gas is the most
environmentally friendly fossil fuel and is an economic, reliable, and
homegrown source of energy. It is in the national interest that natural
gas be available to serve the demands of the market. The Federal
Government must address these issues and take prompt and appropriate
steps to ensure that the Nation has adequate supplies of natural gas at
reasonable prices.
executive summary
<bullet> Natural gas markets have been extremely tight for the past
5 years, with supply unable to keep pace with rising demand. New supply
initiatives are crucial to correcting this imbalance, but demand side
actions are also necessary, particularly with regard to the use of
natural gas for electricity generation.
<bullet> Natural gas demand is projected to increase by 37 percent
over the next 15 years, with over 70 percent of this increase
attributable to electricity generation.
<bullet> Natural gas has been the fuel of choice for over 90
percent of the newly constructed generating units over the past decade.
This dominance results from a number of factors, including the
environmental attributes of gas that lead to lower capital costs and
shorter construction lead times relative to other generating options.
<bullet> Public policymakers must consider both energy and
environmental goals when developing regulations that impact electricity
generation. That is, environmental goals must be achieved in concert
with the pursuit of a greater diversity in the electricity generation
mix.
<bullet> The construction of new generating units utilizing clean,
highly efficient new technologies will be most successful in meeting
dual energy and environmental goals. That is, technologies such as
integrated gasification combined cycle (IGCC), nuclear energy, solar,
wind and gas-based combined heat and power systems. These technologies
must be actively encouraged and promoted.
natural gas market conditions
Stability in the natural gas marketplace is crucial to all of
America for a number of reasons. It is imperative that the natural gas
industry and the government work together to take significant action in
the very near term to assure the continued economic growth,
environmental protection, and national security of our Nation. The
tumultuous events in energy markets over the last several years serve
to underscore the importance of adequate and reliable supplies of
reasonably priced natural gas to consumers, to the economy, and to
national security.
There has been a crescendo of public policy discussion with regard
to natural gas markets since the ``Perfect Storm'' winter of 2000-2001,
when tight supplies of natural gas collided with record-cold weather to
yield record natural gas home-heating bills. The vulnerability of the
natural gas market to weather was demonstrated again in the summer of
2005 when weather that was 18 percent warmer than normal pushed more
gas into electricity generators to meet air conditioning demand, and
yet again in September when multiple hurricanes in the Gulf of Mexico
eliminated nearly 25 percent of our total gas supply. The hot summer
pushed natural gas prices upward from the $6 per MMBtu level to roughly
$8, the hurricanes resulted in prices that fluctuated between $12 and
$14 per MMBtu, and a brief cold snap in December produced a price spike
to roughly $15 per MMBtu. Clearly, natural gas markets are higher and
more volatile than at any point in history. Moreover, there is no sign
that this market volatility will abate in the near future.
It is harmful to individual families and to the entire U.S. economy
for natural gas prices to remain both high and volatile. Unless we make
the proper public policy choices--and quickly--we will be facing many
more difficult years with regard to natural gas prices. Of course, when
families pay hundreds of dollars more to heat their homes, they have
hundreds of dollars less to spend on other things. Many families are
forced to make difficult decisions between paying the gas bill, buying
a new car, or saving for future college educations. There are, of
course, State and Federal programs such as LIHEAP to assist the most
needy. But LIHEAP only provides assistance to about 15 percent of those
who are eligible, and it does not provide assistance to the average
working family. These price increases have affected all families those
on fixed incomes, the working poor, lower-income groups, those living
day to day, and those living comfortably.
The impact of unstable natural gas markets on U.S. businesses is
equally disturbing. Since natural gas prices began rising in 2000, an
estimated 78,000 jobs have been lost in the U.S. chemical industry,
which is the Nation's largest industrial consumer of natural gas, both
for the generation of electricity at manufacturing plants and as a raw
material for making medicine, plastics, fertilizer and other products
used each day. Similarly, fertilizer plants, where natural gas can
represent 80 percent of the cost structure, have closed one facility
after another. Glass manufacturers, which also use large amounts of
natural gas, have reported earnings falling by 50 percent as a result
of natural gas prices. In our industrial and commercial sector,
competitiveness in world markets and jobs at home are on the line.
natural gas demand growth and electricity generation
In a study prepared for the American Gas Foundation in February
2005, natural gas demand is projected to increase by 37 percent between
2003 and 2020 under a ``most likely'' energy scenario. Although higher
natural gas prices may moderate some of this projected demand growth,
including the growth in demand for gas-fired electricity generation, we
believe the fundamentals of this document remain sound and the basic
tenets are unchanged. Some of the findings of this report are
summarized below.
About 4.2 quads of gas were consumed to generate electricity in
2003, 19 percent of total U.S. gas consumption. This market share is
projected to increase to 27 percent by 2010 (6.8 quads) and to 33
percent (10.2 quads) by 2020. Thus, by 2020 electricity generators are
expected to be the dominant sector in terms of gas demand, with
consumption 32 percent greater than that of the industrial sector and
61 percent greater than that of the residential sector.
Today, natural gas is the source of about 18 percent of all
electricity generated but this number is projected to increase to 26
percent by 2020. Conversely, 55 percent of all electricity generated
today is coal-based but this percentage is projected to fall to 50
percent by the end of the forecast period.
Electricity generators have been choosing natural gas as a fuel
source in recent years for a number of reasons--low capital cost, the
ability to construct in a modular fashion, economical construction even
for relatively small plants, ease of permitting and short construction
lead times. In addition, natural gas is an environmentally preferable
fuel. When compared to other options, gas offers benefits on a number
of environmental fronts--acid rain, urban smog, visibility, mercury
emissions, water consumption and solid waste production. Much of the
natural gas-based generating capacity added did not face the
environmental uncertainties associated with larger coal-based
generation facilities. While natural gas usage for electricity
generation is not required by environmental regulation, the
environmental characteristics of gas combustion made permitting less
complex in adding incremental electricity generating capacity. For
example, pollution control equipment is often minimal or not required
at all, thus capital costs and construction lead times are both
reduced. Because natural gas combustion also emits significantly less
carbon than coal or oil combustion, the gas-fired facilities added did
not even have the level of ``climate risk'' associated with the other
fuels as a result of their greenhouse gas emissions.
To date, energy and environmental regulations regarding electricity
generating units have not been developed in a unified and consistent
fashion. Public policy must seek to diversify the fuel sources used to
generate electricity, thereby reducing upward price pressure on natural
gas markets, while also reducing the environmental impacts of
electricity generation. These dual goals will most likely be met
through the construction of new and highly efficient generating
technologies. For example, new coal-based IGCC (integrated gasification
combined cycle) units, nuclear units, solar and wind-powered units, and
natural gas-based CHP (combined heat and power) systems must play a
role in the electricity generation future. Existing environmental
policies often do not favor the construction of these new and novel
generating options, rather they promote cleaning up existing sources
that are often used in combination with low efficiency gas peaking
turbines to meet increasing electricity demand.
natural gas supply
For the past 5 years, natural gas production has operated full-tilt
to meet consumer demand. The ``surplus deliverability'' or ``gas
bubble'' of the late 1980's and 1990's is simply gone, as illustrated
in the graphic below that compare actual natural gas production with
production capability (prepared by Energy and Environmental Analysis).
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
No longer is demand met while unneeded production facilities sit
idle. No longer can new demand be met by simply opening the valve a few
turns. The valves have been, and presently are, wide open.
America has a large and diverse natural gas resource; producing it,
however, can be a challenge. Providing the natural gas that the economy
requires will necessitate: (1) providing incentives to bring the
plentiful reserves of North American natural gas to production and,
hence, to market; (2) making available for exploration and production
the lands--particularly Federal lands--where natural gas is already
known to exist so gas can be produced on an economic and timely basis;
(3) ensuring that the new infrastructure that will be needed to serve
the market is in place in a timely and economic fashion.
The estimated natural gas resource base in the United States has
actually increased over the last several decades. In fact, we now
believe that we have more natural gas resources in the United States
than we estimated 20 years ago, notwithstanding the production of
approximately 300 trillion cubic feet of gas in the interim. This is
true, in part, because new sources of gas, such as coalbed methane,
have become an important part of the resource base. Nonetheless, having
the natural gas resource is not the same as making natural gas
available to consumers. That requires natural gas production.
Natural gas production is sustained and grows only by drilling in
currently productive areas or by exploring in new areas. Over the past
two decades a number of technological revolutions have swept across the
industry. We are able today to drill for gas with dramatically greater
success and with a significantly reduced environmental impact than we
were able to do 20 years ago. We are also much more efficient in
producing the maximum amount of natural gas from a given area of land.
A host of technological advances allows producers to identify and
extract natural gas deeper, smarter, and more efficiently. For example,
the drilling success rate for wells deeper than 15,000 feet has
improved from 53 percent in 1988 to over 82 percent today. In addition,
gas trapped in coal seams, tight sands, or shale is no longer out of
reach, and today it provides a major source of supply.
While further improvements in this regard can be expected, they
will not be sufficient to meet growing demand unless they are coupled
with other measures. Regrettably, technology alone cannot indefinitely
extend the production life of mature producing areas. New areas and
sources of gas will be necessary.
Notwithstanding the dramatic impact of innovation upon the natural
gas business, the inevitable fact today is that we have reached a point
of rapidly diminishing returns with many existing natural gas fields.
This is almost entirely a product of the laws of petroleum geology. The
first ten wells in a field may ultimately produce 60 percent of the gas
in that field; yet it may take forty more wells to produce the balance.
In many of the natural gas fields in America today, we are long past
those first ten wells and are well into those forty wells in the field.
In other words, the low-hanging fruit have already been picked in the
orchards that are open for business.
Drilling activity in the United States has moved over time, from
onshore Kansas, Oklahoma and Arkansas to offshore Texas and Louisiana,
and then to the Rocky Mountains. Historically, we have been quite
dependent on fields in the Gulf of Mexico. But recent production
declines in the shallow waters of the Gulf of Mexico have necessitated
migration of activity to deeper waters to offset this decline. These
newer, more expensive, deepwater fields tend to have short lives and
significantly more rapid rates of decline in production than onshore
wells.
The sobering reality is that America's producers are drilling more
wells today than they were 5 years ago. Nevertheless, domestic supply
is struggling to be sustained. U.S. gas producers are on an
accelerating treadmill, running harder just trying to stay in place.
For reasons that are partly due to technology, and partly due to the
maturing of the accessible natural gas resource base, a typical well
drilled today will decline at a faster rate than a typical well drilled
a decade ago. Moreover, because up to half of this country's current
natural gas supply is coming from wells that have been drilled in the
past 5 years, this decline trend is likely to continue.
Before we can meet growing gas demand, we must first replace the
perennial decline in production. The U.S. natural gas decline rate will
be in the range of 26-28 percent this year. In practical terms, if all
drilling stopped today, in 12 months U.S. natural gas production would
be 26-28 percent lower than it is today. The accelerating decline rate
helps explain why U.S. gas deliverability has been stuck in the 52-54
billion cubic feet per day range for the past 8 years, notwithstanding
an increase in gas-directed drilling.
In short, America's natural gas fields are mature--in fact many are
well into their golden years. There is no new technology on the horizon
that will permit us to pull a rabbit out of a hat in these fields.
These simple and incontrovertible facts explain why we are today
walking a supply tightrope. High and volatile natural gas prices have
become the norm and will become increasingly accentuated as the economy
returns to its full vigor. There is no question that high and volatile
natural gas prices are putting a brake on the economy, once again
causing lost output, idle productive capacity, and lost jobs.
If we are to continue to meet the energy demands of America and its
citizens and if we are to meet the demands that will they make upon us
in the next two decades, we must change course. It will not be enough
to make a slight adjustment or to wait 3 or 4 more years to make
necessary policy changes. Rather, we must change course entirely, and
we must do it in the very near future. Lead times are long in our
business, and meeting demand years down the road requires that we begin
work today.
We have several reasonable and practical options. It is clear that
continuing to do what we have been doing is simply not enough. In the
longer term we have a number of options:
First, and most importantly, we must work to sustain and increase
natural gas production by looking to new frontiers within the United
States. Further growth in production from this resource base is
jeopardized by limitations currently placed on access to it. For
example, most of the gas resource base off the East and West Coasts of
the United States and the Eastern Gulf of Mexico is currently closed to
any exploration and production activity. Moreover, access to large
portions of the Rocky Mountains is severely restricted. The potential
for increased production of natural gas is severely constrained so long
as these restrictions remain in place.
To be direct, America is not running out of natural gas, and it is
not running out of places to look for natural gas. America is running
out of places where we are allowed to look for gas. The truth that must
be confronted now is that, as a matter of policy, this country has
chosen not to develop much of its natural gas resource base. We doubt
that that many of the 65 million American households that depend on
natural gas for heat are aware that this choice has been made on their
behalf.
In this vein, the Rocky Mountain region is expected to be a growing
supplier of natural gas, but only if access to key prospects is not
unduly impeded by stipulations and restrictions. Two separate studies
by the National Petroleum Council and the U.S. Department of the
Interior reached a similar conclusion that nearly 40 percent of the gas
resource base in the Rockies is restricted from development, in some
cases partially and in some cases totally. On this issue, the
Department of the Interior noted that there are nearly 1,000 different
stipulations that can impede resource development on Federal lands.
One of the most significant new gas discoveries in North America in
the past 10 years is located just north of the United States/Canada
border in eastern Canadian coastal waters on the Scotian shelf. Natural
gas discoveries have been made at Sable Island and Deep Panuke. Gas
production from Sable Island already serves Canada's Maritimes
Provinces and New England through an offshore and land-based pipeline
system. This has been done with positive economic benefits to the
region and without environmental degradation. This experience provides
an important example for the United States, where we believe that the
offshore Atlantic area has a similar geology.
In some areas we appear to be marching backward. The buy-back of
Federal leases where discoveries had already been made in the Destin
Dome area (offshore Florida) of the eastern Gulf of Mexico was a
serious step backward in terms of satisfying consumer gas demand. This
action was contrary to what needs to be done to meet America's energy
needs. With Destin Dome we did not come full about, as we need to do;
rather, we ran from the storm.
Geographic expansion of gas exploration and drilling activity has
for the entirety of the last century been essential to sustaining
growth in natural gas production. Future migration, to new frontiers
and to new fields, in both the United States and Canada, will also be
critical. Without production from geographic areas that are currently
subject to access restrictions, it is not at all likely that producers
will be able to continue to provide increased amounts of natural gas
from the lower-48 States to customers for longer than 10 or 15 years.
We believe that the same is true in Canada as well.
It is imperative that energy needs be balanced with environmental
impacts and that this evaluation be complete and up-to-date. There is
no doubt that growing usage of natural gas harmonizes both objectives.
Finding and producing natural gas is accomplished today through
sophisticated technologies and methodologies that are cleaner, more
efficient, and much more environmentally sound than those used in the
1970's. It is unfortunate that many restrictions on natural gas
production have simply not taken account of the important technological
developments of the preceding 30 years. The result has been policies
that deter and forestall increased usage of natural gas.
Second, we need to increase our focus on non-traditional sources,
such as liquefied natural gas (LNG). Reliance upon LNG has been modest
to date, but it is clear that increases will be necessary to meet
growing market demand. Today, roughly 97 percent of U.S. gas supply
comes from traditional land-based and offshore supply areas in North
America. Despite this fact, during the next two decades, non-
traditional supply sources such as LNG will likely account for a
significantly larger share of the supply mix. LNG has become
increasingly economic. It is a commonly used worldwide technology that
allows natural gas produced in one part of the world to be liquefied
through a chilling process, transported via tanker, and then re-
gasified and injected into the pipeline system of the receiving
country. Although LNG currently supplies less than 3 percent of the gas
consumed in the United States, it represents 100 percent of the gas
consumed in Japan.
LNG has proven to be safe, economical and consistent with
environmental quality. Due to constraints on other forms of gas supply
and increasingly favorable LNG economics, LNG is likely to be a more
significant contributor to U.S. gas markets in the future. It will
certainly not be as large a contributor as imported oil (nearly 60
percent of U.S. oil consumption), but it could account for 15-20
percent of domestic gas consumption 15-20 years from now if pursued
aggressively and if impediments are reduced.
It is unlikely that LNG can solve the entirety of our problem. A
score of new LNG import terminals have been proposed, some with
capacities in excess of 2.5 billion cubic feet per day. However, given
the intense ``not on our beach'' opposition to siting new LNG
terminals, a major supply impact from LNG may be a tall order indeed.
Third, we must tap the huge potential of Alaska. Alaska is
estimated to contain more than 250 trillion cubic feet of natural gas
enough by itself to satisfy U.S. gas demand for more than a decade.
Authorizations were granted 25 years ago to move gas from the North
Slope to the Lower-48, yet no gas is flowing today nor is any
transportation system under construction. Indeed, every day the North
Slope produces approximately 8 billion cubic feet of natural gas that
is re-injected because it has no way to market. Alaskan gas has the
potential to be the single largest source of price and price volatility
relief for U.S. gas consumers. Deliveries from the North Slope would
not only put downward pressure on gas prices, but they would also spur
the development of other gas sources in the State as well as in
northern Canada.
Fourth, we can look to our neighbors to the north. Canadian gas
supply has grown dramatically over the last decade in terms of the
portion of the U.S. market that it has captured. At present, Canada
supplies approximately 14 percent of the United States' needs. We
should continue to rely upon Canadian gas, but it may not be realistic
to expect the U.S. market share for Canadian gas to continue to grow as
it has in the past or to rely upon Canadian new frontier gas to meet
the bulk of the increased demand that lies ahead for the United States.
The pipelines under consideration today from the Prudhoe Bay area
of Alaska and the Mackenzie Delta area of Canada are at least 5-10
years from reality. They are certainly facilities that will be
necessary to broaden our national gas supply portfolio. We must
recognize, however, that together they might eventually deliver up to 8
billion cubic feet per day to the lower 48 States--less than 10 percent
of the natural gas envisioned for the 2025 market.
There is much talk today of the need for LNG, Alaska gas, and
Canadian gas. There is no question that we need to pursue those
supplies to meet both our current and future needs. Nonetheless, it is
equally clear that, in order to meet the needs of the continental
United States, we will need to continue to look to the lower 48 States.
______
Responses by Arthur E. Smith, Jr., to Additional Questions from
Senator Voinovich
Question 1. How we can increase the supply of natural gas and
reduce natural gas prices today and over the long term.
Response. Because supply and demand are in such a tight balance,
any increase in supply or reduction in demand should have a favorable
impact toward lowering the price of gas or moderating its rise.
Congress can take many steps to increase supply and to reduce demand.
Steps to Increase Supply: Intermountain West.--Congress should
encourage the Administration (BLM, Forest Service) to issue short-term
waivers for expansion of the Rockies (inter-mountain west region)
drilling window for this winter.
Alaskan Natural Gas:
Congress should support efforts to expedite and facilitate the
construction of the Alaskan natural gas pipeline to bring Alaskan
natural gas supplies to the lower 48 States.
Liquified Natural Gas.--Congress should encourage the development
of infrastructure to accept new supplies from LNG.
Natural Gas Pipelines and Facilities.--Congress should encourage
FERC to continue acting on an emergency basis as needed and modify and
implement its rules to accelerate and streamline the permitting and
blanket certificate procedures for natural gas pipelines, especially to
facilitate hurricane recovery efforts.
LIHEAP.--Congress can increase funding for LIHEAP for FY06 up to
the authorized $5.1 billion and consider amending LIHEAP eligibility
criteria to allow larger numbers of low-income residents to take
advantage of the program.
Steps to Reduce Demand:
The fastest growing sector of demand for natural gas is in
electricity generation. Given that natural gas supplies are
constrained, it is not wise to continue to rely on natural gas to
provide 90 percent or more of our new electricity generation capacity.
We support efforts to diversify the electricity generation fuel mix.
Question 2. What changes can we make to our environmental
regulatory schemes to promote more diverse and efficient baseload
generation (such as IGCC and nuclear plants)?
Response. The Clean Air Act has two categories of programs related
to power generation. One program is ``technology-forcing'' and applies
to new facilities, as Congress intended that new facilities have the
best control technology available. The other program controls emissions
from existing power plants. These programs address very legitimate
environmental areas; however, they are not intended to focus on energy
supply needs.
As I testified on February 9, these programs have had an important
effect on the situation during the last 5-6 years, in which there was
significant installation of ``easy'' to permit natural gas fired
generation and significant investment in pollution controls at existing
power plants. When natural gas supply failed to keep-up with the
incremental demand from the power sector, it highlighted the present
energy issue--the need for investment in domestic fuel-diverse baseload
generation.
A more holistic legislative approach on energy and environment
policies would consider how to achieve both energy needs and
environmental objectives. The previous Clear Skies Bill contained some
promise in using fuel-weighted provisions to discourage fuel switching
and providing some limited incentives for IGCCs and energy efficiency.
However, the fundamental direction continued to be a ``control''
program designed to address existing generation, with new sources given
only a limited share of the allocations.
Legislation could take a more holistic approach that promotes fuel
diversity and allows a ``compliance investment'' option for companies
electing to invest in new generation capacity (at existing or new power
facilities). If companies could invest in clean generation, e.g., IGCCs
as a compliance measure, the legislation could harness investment to
achieve the same environmental results through new generation
technology that can also address energy supply needs. Additionally,
this cleaner energy could also address concerns about the need to
reduce carbon intensity in the power sector (e.g., the increased
generation capacity mix with a net increase in energy efficiency can
achieve the same environmental results with a lower carbon intensity).
There are various allocation methods that ``credit'' new cleaner
generation and energy efficiency improvements. Many power companies
with a business focus on traditional coal-fired generation fair well
with such an initial allocation on a fuel weighted basis. In addition,
the allocation would then allow all companies with the compliance
flexibility to invest in additional generation capacity.
Question 3. What do we need to do to address the natural gas
storage and transportation constraints that exist in the United States?
Response. Constraints on Natural Gas Storage and Transportation--
National Environmental Policy Act (NEPA) Recommendations.--In the 35
years since its enactment, compliance with NEPA has taken progressively
longer and longer for natural gas projects. We do not, however, propose
to alter the objectives of NEPA. On the contrary, NEPA remains an
important environmental safeguard, balancing the needs of economic
development with the need to protect environmental quality. Our
suggested solutions deal with the implementation of NEPA, and in
particular, the ways different Federal and State permitting agencies
should work together under the Act.
A number of these solutions were part of the recently enacted
Energy Policy Act of 2005, at least with respect to natural gas
projects approved by the Federal Energy Regulatory Commission (FERC).
We have grappled with the issue of NEPA compliance for many years,
looking specifically at ways to reduce unnecessary delays and improve
cooperation among the many Federal and State agencies that might be
reviewing a proposed project. These suggestions do not alter existing
environmental quality standards. They do, however, increase the level
of accountability, cooperation and efficiency among permitting
agencies--hardly an unfair or unreasonable set of expectations. We
support extending these ideas to all types of energy project reviews
under NEPA, not just FERC-approved natural gas projects.
Recommendation 1. Establish a clearly defined ``lead agency'' for
each type of proposed project.--On any given proposed project for
development, there can be conflict among agencies as to who should take
the lead. There does need to be one lead agency for each type of
project though, and direction from Congress or the Council on
Environmental Quality (CEQ) could resolve such conflict before it
arises. For example, section 313 of the new Energy Policy Act
designates the FERC as the lead agency under NEPA for all projects
requiring an authorization or approval pursuant to the Natural Gas Act;
in other words, all interstate natural gas pipelines, storage
facilities, or LNG import terminals. The lead agency should be one that
has primary responsibility for the ultimate approval of an activity or
project.
Recommendation 2. Allow the lead agency to institute specific
timelines for NEPA reviews.--As stated in AGA's February 6, 2006
comments on the Senate draft NEPA white paper, (page 2 Recommendation
1.2, attached), AGA supports the Senate Task Force's recommendation to
amend NEPA to set an 18-month limit on the time to prepare and complete
an EIS, and to set a 9-month limit on the time to prepare and complete
an EA. We agree with the Senate Task Force that this should be the
rule, and that exceptions should be allowed only in unusual situations
and only when approved by the Council on Environmental Quality (CEQ).
In addition, in order to help the lead agency to meet this deadline,
the lead agency should be allowed to establish specific timelines for
NEPA reviews.
This recommendation is important to keeping the review process
manageable while providing some time certainty to applicants. While
most agencies are willing to work with the sister organizations in a
cooperative manner, our own experience in the gas pipeline industry is
that some agencies will use inaction as a way to delay and even kill a
project. If the lead agency is empowered to set a schedule, and to
establish joint agency meetings and reviews, then the process becomes
more cooperative and efficient as agencies negotiate face-to-face
rather than from some distance. Here again, section 313 of the Energy
Policy Act allows the FERC, for pipeline and LNG projects, to set such
a schedule. However, the Act also states that the FERC should
incorporate any existing timeframes any agency might have to reach a
decision on a permit. An amendment to NEPA should establish that the
lead agency has overall authority to establish a time schedule for
review and all cooperating agencies must act within that timeframe.
Recommendation 3. Ability to enforce a lead agency deadline.--
Ideally, the ability to set a deadline should be coupled with a way to
enforce the deadline, so that agencies take a lead agency deadline
seriously. Several earlier versions of the Energy Policy Act contained
a provision requiring cooperating agencies to either act within the
FERC-approved deadline (for natural gas projects), or else have their
approval ``conclusively presumed.'' Both the Coastal Zone Management
Act (CZMA) and the Clean Water Act contain deadlines for State
enforcement agencies to either make permitting decisions or have their
approval assumed, so the proposals in the Energy bill debate were not
all that unusual. Nonetheless, the Energy Bill Conference Committee
decided to be more conciliatory, by instead allowing an applicant to
appeal an agency permitting-delay to the U.S. Court of Appeals for the
D.C. Circuit. We believe there must be a mechanism applicable to all
involved agencies that allows the lead agency to enforce its schedules.
Recommendation 4. Creation of a consolidated record for a NEPA
review and all permitting decisions.--The lead agency should be charged
with the responsibility to develop a consolidated record for the NEPA
review and EIS development, and all permitting decisions required as a
result. Once again, this encourages the various Federal and State
agencies to work together in a cooperative fashion to develop a
consolidated record. In order to make sure that agencies take this
requirement seriously, Congress should require that this consolidated
record be the record used for all subsequent appeals or administrative
reviews.
A consolidated record is important. Our industry has found that
some agencies have ``sat out'' on FERC NEPA reviews of proposed
projects, and then subsequently appealed FERC's approval decisions and
attempted to develop a de novo review of all the facts previously
considered by FERC and the cooperating agencies. Developing an entirely
new record, when ample opportunity is given to participate in the
development of the first one, is time-consuming and unfair to all of
the agencies that did participate cooperatively. This consolidated
record requirement is a part of the Energy Policy Act with respect to
natural gas projects; it should be considered for other NEPA approvals
as well.
Recommendation 5. Streamline subsequent reviews and permit
approvals for projects managed pursuant to the Pipeline Safety
Improvement Act.--The natural gas industry is facing a huge amount of
work to comply with the safety regulations codified pursuant to the
passage, in 2002, of the Pipeline Safety Improvement Act. The Act
created specific timeframes for all natural gas transmission pipelines
to assess (or inspect) the integrity of all pipeline located in
populated areas. By December of 2012, all pipelines located in these
``high consequence areas'' must have a baseline assessment of their
integrity. These inspections, and any subsequent repairs, will require
significant excavation activity, triggering permit requirements. The
ability to obtain the necessary permits, so that this inspection/repair
activity can be completed pursuant to the congressionally mandated
timeframe, will be critical to the success of the program.
Most of the affected pipelines have already developed an EIS years
ago, as part of any construction or expansion activity. We need to make
certain that the permitting process for the integrity management
program recognizes previous environmental work, and gives pipeline
operators some flexibility to meet requirements that, after all, have
been mandated for safety purposes by Congress.
In the event that a pipeline has work that must be performed
pursuant to compliance with the regulations under the Pipeline Safety
Improvement Act and that particular pipeline segment has never had an
EIS performed on it's facilities, NEPA should allow for expedited
analysis of impacts by the lead agency and the establishment of a
streamlined review schedule for all cooperating agencies that meets the
safety requirements imposed by the Office of Pipeline Safety (OPS)
within the Department of Transportation (DOT) Pipeline and Hazardous
Materials Safety Administration (PHMSA).
Recommendation 6. Make a ``Team Permitting'' opportunity available
on voluntary basis. This voluntary process, would be one similar to the
``Team Permitting'' concept employed within the State of Florida,
pursuant to Chapter 403.075, Florida Statutes, for early coordination
with regulatory agencies, local governments, and special interest
groups for development-related permitting.
An amendment to NEPA could include a section to establish the
opportunity for a developer to engage a lead agency, other regulatory
stakeholders, and interested parties in an open process in which all
NEPA issues could be identified and dealt with to the satisfaction of
those involved. In this voluntary process, an applicant seeking any
Federal permit applicable for NEPA review could enter into a non-
binding agreement with the Federal ``lead agency.'' This would be
initiated by the applicant and would be only on a voluntary basis. Once
initiated by the applicant, the lead agency would notify all potential
cooperating agencies of the opportunity to join this collaborative and
advisory ``Team Permitting Group.'' A Federal notice of such meetings
of the group would be published and any interested party could join the
review process (this could include any environmental group or other
interested party). A schedule for review and processing of all permits
would be developed by the lead agency and the Team Permitting group and
all milestone dates for processing would be met by the applicant as
well as the agencies involved.
In Team Permitting all permitting agencies and interested parties
would meet together and work simultaneously on the technical aspects of
the proposed development and to reduce the overall total impact of the
project. This would also include any necessary mitigation. This
collaborative effort on the technical aspects of the proposal would
greatly help the various regulatory permitting personnel who too often
work in a silo effect as they assess the impact of the proposed
development and any mitigation that might be required. In order to
enter into this voluntary Team Permitting process, the applicant would
pledge, in the beginning, to do what will be referred to as ``net
ecosystem benefits'' which will be over and above any level of
mitigation assigned by the various permitting agencies. No ``net
ecosystem benefits'' would be performed by the applicant until all
timely permits are issued, required mitigation agreed to by the
parties, in accordance with the schedule agreed to in the beginning by
the Team Permitting Group. Their respective regulatory division will
issue all individual required environmental permits from Federal
regulatory agencies, from any State government, as well as any local
government. Again, the agreed to ``net ecosystem benefits'' will not be
performed by the applicant unless all permits are issued in accordance
with the agreed to schedule.
Recommendation 7. Streamline NEPA permit reviews and approvals by
adopting a process similar to the one used pursuant to CERCLA (or
Superfund).
Permitting for projects undergoing NEPA review (especially those
that have an existing EIS) could be managed in a manner similar to the
way in which permits are expedited pursuant to CERCLA. In the early
1980's, Congress faced a similar situation with response actions needed
under the Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), commonly known as Superfund. This legislation
required the EPA or potentially responsible parties to respond to
releases of hazardous constituents. During the initial implementation
of CERCLA, it was quickly recognized that Federal, State or local
requirements imposed significant delays to this critical work. To avoid
these delays, legislation was passed to require EPA to impose all
substantive requirements of these rules, but exempted the projects from
the administrative aspects of Federal, State and local requirements.
Natural gas facilities could be sited, permitted, constructed, repaired
and upgraded, pursuant to an amended NEPA that would have language
similar to the language contained in section 121 of CERCLA.
Under this revised process, during the NEPA review the lead Agency
would act in a manner similar to the role EPA plays in authorizing work
under CERCLA. Applicants would be required to discuss and comply with
substantive requirements of all applicable, relevant and appropriate
requirements (known as ARARs under CERCLA). The public and any affected
Agencies would have an opportunity to comment on all planned work.
However, the approval under NEPA would also constitute approval for all
permits necessary to implement the work. This would greatly streamline
the process to gain approval for needed maintenance or new construction
while still insuring all technical requirements are met.
______
Response by Arthur E. Smith, Jr., to an Additional Question from
Senator Jeffords
Question. Do you think more resources should be directed to this
EPA program?
Response. Many AGA, as well as INGAA, member companies participate
in EPA's Natural Gas Star program. It is voluntary, provides company
recognition for finding ways to conserve natural gas supply and
contributes to technology and best practice exchange and development.
EPA contracts with private consultants to facilitate technical
assistance/exchange with companies and to EPA relative to natural gas
conservation. Additional resources would allow EPA to increase this
technical assistance and provide R&D to advance technologies that can
help detect and reduce fugitive natural gas emissions.
Additional assistance in the way of R&D funding would be of value
to natural gas companies at this time. Many natural gas companies are
focusing resources on DOT requirements for integrity management, adding
new supply/infrastructure and dealing with declining customer usage
with the high natural gas prices. In addition, traditional R&D funding
is declining from FERC, DOE, GRI, and the like. These funding
mechanisms are being reduced and in some cases, eliminated. R&D funding
could advance technologies that improve efficiencies and reduce
emissions. If Congress were to provide more funding for EPA for R&D
that could help the industry more cost effectively detect fugitive
natural gas emissions and develop methods to reduce natural gas leaks,
that would help reduce greenhouse gas emissions and help stretch our
national natural gas resources.
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Statement of Joel Bluestein, Energy and Environmental Analysis, Inc.
Thank you Mr. Chairman and members of the committee for the
opportunity to testify today. My name is Joel Bluestein and I am the
president of Energy and Environmental Analysis, Inc. EEA is located in
Arlington, Virginia and has been providing energy and environmental
consulting services since 1974. Our major areas of expertise include:
<bullet> Analyzing and forecasting the supply, demand and price of
natural gas
<bullet> Analyzing the impacts of energy and environmental policy
on energy markets
We have done this work for industry, government and institutional
clients.
The spot price of natural gas has increased substantially over the
last 5 years. Excluding the temporary effects of the hurricanes in late
2005, the prices have increased from the $2 to $3/MMBtu range to the
$8/MMBtu range. While the prices paid by most consumers have not
increased proportionally, the higher prices have certainly created
hardships for retail gas users as well as for business and industry.
The reason for this rapid increase in gas prices is widely agreed
to be a combination of growing demand and limited supply for natural
gas. Both sides of this equation must be addressed in order to find a
solution. On the demand side, the power generation sector is the
fastest growing component of the natural gas consuming sector. Almost
all of the power plants built in the last 15 years have been gas-fired.
Over 200 GW, of new natural gas-fired power plants have been built in
the last 5 to 6 years, the largest such increase in power plant
capacity in our history.
There is a common belief that these new gas plants are the cause of
the increase in gas consumption for power generation and that the
recent focus on gas-fired power plants is due primarily to
environmental regulation. The corollary to the second belief is that if
we could just somehow change the existing environmental regulations
then there would be a big shift to coal-fired power plants, gas
consumption would go down and gas prices would go back to $3/MMBtu.
Unfortunately, all of these last assumptions are incorrect.
The historical data\1\ clearly show (Figure 1) that gas-fired
electricity generation has been increasing continuously and at about
the same rate since at least 1990, well before the recent boom in power
plant construction and the increase in natural gas prices. From 1990 to
about 1999 there was very little construction of new power plants, in
large part due to the uncertainty about restructuring of the electric
power industry. From 1999 to 2005, over 200 GW of new gas-fired
generating capacity was built in the United States. However, this
construction has not increased the growth rate of gas-fired generation.
In fact, the growth declined slightly from 2002 through 2004.
---------------------------------------------------------------------------
\1\ All data in this testimony are from the U.S. Energy Information
Administration unless otherwise noted.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Not only have the new power plants not increased gas consumption,
they actually have reduced gas consumption relative to what would have
occurred in their absence. This is because many of the new plants were
built in regions that were already dependent on older, less efficient
gas power plants. In these regions, such as Texas and California, the
new, more efficient plants have displaced the older less efficient
power plants, reducing the amount of gas that would have otherwise been
consumed. Figure 2 shows the effect of this efficiency improvement on
gas consumption for power generation. It indicates that the improved
efficiency reduced gas consumption by about 1,000 trillion Btu or 1
trillion cubic feet in 2004. That said, there are some states, such as
Louisiana, in which utility regulations are allowing incumbent
utilities to continue to use older, less efficient plants while new,
more efficient plants sit idle or underutilized. Remedying this
situation is one way to rapidly reduce the amount of gas consumed for
power generation.
The question raised in this hearing is whether or how much clean
air regulation has lead to the increased use and construction of gas-
fired power plants. In fact, air regulation is only one of many drivers
for the use of gas and probably not the most important one.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Our environmental regulations do not single out individual fuels
for priority treatment. The most significant differentiation between
fuels historically has been to set less stringent limits for coal
plants than for gas plants. While there is no question that gas-fired
plants are cleaner than coal-fired plants, our environmental
regulations require more aggressive reductions for cleaner plants such
that the cost per ton of NOx control for new natural gas plants, for
example, can be higher than the equivalent cost for new coal plants. In
addition, many of the recent environmental programs have been cap and
trade programs, which provide great compliance flexibility and are
designed to avoid forcing the shutdown of older, high emitting plants.
If anything, these programs have undervalued the efficiency and low
emissions benefits of gas-fired plants by providing them with fewer
trading allowances than provided to coal plants with the same electric
output. So gas plants are not getting preferable treatment on emission
regulation. And despite their low emissions, natural gas power plants
have faced substantial opposition from local communities and activists
in many parts of the country.
Some of the reasons other than environmental regulation for the
increased construction of gas-fired plants are that the gas plants:
<bullet> Have a much lower capital cost--about half that of coal
plants. This was especially important for the non-utility developers
who built most of the plants in recent years.
<bullet> Require less land--key for construction in many areas near
urban centers with attractive electricity markets.
<bullet> Do not require access to rail or water links for coal
delivery--another advantage for flexibility of siting.
<bullet> Take less time to build--a key advantage during the very
competitive building boom of the last 5 years.
<bullet> Can respond more quickly to changes in load.
<bullet> Require less water--a vital issue in many areas.
The recent generation of power plants was planned during the late
1990's and was built by independent, competitive, non-utility power
developers expecting to compete in a restructured, competitive power
market. There was a premium on being the first plant into that market.
Natural gas prices were below $3/MMBtu. Combined with the low capital
cost, high efficiency, short construction time and other advantages,
gas plants were the obvious choice. Any plausible change in
environmental regulation would have had little effect on the choice of
gas technology over coal at that time.
The economics of new plant construction have now changed
significantly. With the current gas prices, new gas plants are not
economically competitive with coal plants and many are running at very
low levels of utilization or not at all. Today's higher gas prices have
resulted in higher electricity prices in many regions, creating a very
high value for coal-fired generation. The U.S. DOE is currently
tracking about 135 planned or proposed plants comprising 80 GW of new
coal generation (Figure 3). Construction is beginning on a number of
new coal plants. These proposals include plants using supercritical
steam, circulating fluidized bed and integrated gasification combined
cycle technologies. While not all of the proposed plants will
ultimately be built, these new coal plants are designed to cost-
effectively meet all the current emission requirements for conventional
pollutants. Admittedly, it can be difficult to site and permit a coal
plant and there are many regulatory avenues that can be used to delay
construction; however that is also true for gas power plants, wind
farms and most types of energy infrastructure.
In discussing the construction of new coal plants, it is commonly
asserted that passage of the Clear Skies Act will facilitate the
construction of new coal plants by providing certainty regarding
regulation of conventional pollutants. While this is true in part, it
ignores that fact that uncertainty over the future regulation of
CO<INF>2</INF> emissions is an even larger impediment for potential
builders of coal plants. An increasing number of power companies are
making clear that they cannot commit to large investments in new coal
plants with a lifetime of 40 or 50 years without reasonable certainty
on their future CO<INF>2</INF> regulatory liability. They are
suggesting that it may not be less regulation but more regulation in
the form of four pollutant regulation that could help accelerate the
construction of new coal plants.
One other topic related to environmental regulation is the use of
fuel-switching. Fuel-switching usually refers to switching gas-fired
boilers to residual oil during periods of high gas prices, typically
during peak winter heating periods. This is an important option for
limiting peak natural gas prices. Many switchable boilers have
regulatory limits on how much they can switch during the year. States
have the option of reviewing or modifying these limits or suspending
them during periods of limited gas supply. Some States in the Northeast
have prepared to do just that during this winter if necessary. Most of
the new gas-fired plants do not have alternative fuel capability and
requiring them to have oil-back capability is another common suggestion
to address prices. Given current oil prices, switching to oil is not
very attractive economically except during periods of unusually high
gas prices.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
While short-term fuel-switching to oil during peak price periods is
an important mechanism to relieve demand and limit prices for a short
period of time, it does not create significant downward pressure on
overall gas prices. That would require long-term switching or
conversion of gas-fired plants to oil or coal. While conversion to oil
is the more technically feasible option, it could create a significant
increase in our oil consumption. For the newer gas plants, this would
be distillate oil, which competes with diesel fuel, heating oil and jet
fuel. Stimulating a large increase in oil consumption does not seem to
be consistent with our current energy policy goals. That brings us back
to increased use of coal, which I've addressed above.
In short, environmental regulation has not been the primary reason
for the recent growth in gas generation. Going forward, environmental
regulation can best encourage increased coal use if it addresses
regulation of CO<INF>2</INF> as well as conventional pollutants. That
said, any responses related to new power plant construction are mid- to
long-term responses. Given the complexities and importance of the
natural gas supply/demand issues, we should focus our attention on
near-term supply and efficiency responses that can provide benefits in
the shorter term.
______
Responses by Joel Bluestein to Additional Questions from
Senator Jeffords
Question 1. What was the natural gas share of total electric
generation in the United States in 1970 (pre-environmental regulation)
compared to today?
Response. The natural gas share of U.S. electricity generation in
1970 was 24 percent compared to about 18 percent in 2004. This is shown
in Figure 1 (U.S. EIA data).
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Question 2. We heard that the United States has the highest natural
gas prices in the world, but we've also heard a lot about high gas
prices in Europe recently. What are the current prices of natural gas
and LNG in Western Europe? Historically, how have prices in the United
States and Western Europe compared?
Response. Price comparisons are difficult due to the structural
differences in gas markets in different countries. In addition, the
prices can be very volatile and responsive to local conditions. For
example, North American gas prices were higher in 2005 due to the
effects of Hurricanes Rita and Katrina, which did not affect European
prices. U.S. gas prices are currently low due to a mild winter while
the same is not true for Europe. With those caveats, Figure 2 shows
2004/5 data from the EIA and International Energy Agency for gas
delivered to industrial customers in different countries. The U.S.
price includes the high year-end price due to the hurricanes. It also
shows the very low prices in gas producing countries.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
We can also look at the most current price data reported in the
trade press for March 22, 2006. This shows the currently tight gas
supply situation in Europe and the high price for spot LNG deliveries.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
______
Response by Joel Bluestein to an Additional Question from
Senator Voinovich
Question. Please provide your thoughts on how we can increase the
supply of natural gas and reduce natural gas prices today and over the
long term.
Response. The most complete answers to these questions are provided
by the 2003 study on natural gas supply and demand prepared by the
National Petroleum Council at the request of the U.S. Secretary of
Energy.\1\. The NPC study recommends a balanced program of:
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\1\ ``Balancing Natural Gas Policy--Fueling the Demands of a
Growing Economy'', National Petroleum Council, 2003, www.npc.org
---------------------------------------------------------------------------
<bullet> Reducing demand for natural gas through higher end use
efficiency.
<bullet> Maintaining diversity in fuel use.
<bullet> Increasing North American gas supply through
environmentally appropriate development in the lower 48 states,
offshore and Alaska.
<bullet> Increasing imports of LNG.
These are still the appropriate answers.
______
Responses by Joel Bluestein to Additional Questions from
Senator Lieberman
Question 1. Please state in absolute terms the extent to which
coal-fired power plant capacity was increased after November 15, 1990.
Please state in absolute terms to the extent to which natural gas-fired
power plant capacity was increased after November 1, 1990.
Response. According to EIA data, gas generating capacity increased
by 279 GW from 1990 through 2004. Coal generating capacity increased by
13 GW during that same period.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Question 2. Please assess the impact of the following factors on
natural gas demand since 1990: the cost of natural gas, capital costs
for new natural gas plants, opportunities for siting such plants, the
time required to build such plants, and responsiveness to load changes
of gas-fired power plants.
Please compare or contrast the effect of the requirements of the
Clean Air Act and EPA's implementation thereof to or with the factors
enumerated in the previous sentence in terms of their impact on natural
gas demand.
Throughout the 1990's a number of States, as well as the Federal
Energy Regulatory Commission, restructured electricity ratemaking or
deregulated it. Please describe the impact of electricity restructuring
or deregulation on the building of new natural gas power plants and the
demand for natural gas.
Response. These questions address two separate issues that are
often treated as one but in fact are not strongly linked:
<bullet> The growth in natural gas consumption for power
generation.
<bullet> The surge in construction of gas-fired power plants
between 1999 and 2004.
Natural gas demand for power generation has been increasing
steadily since the late 1980s. This growth has occurred for a variety
of reasons. For the most part, it is not associated with the
construction of new gas-fired power plants, which did not happen until
the last 5 years (Figure 4). The growth in gas demand during the 1990's
was largely a response to normal load growth in regions with a large
amount of existing natural gas capacity such as California and Texas.
Natural gas generators were the plants available to meet this load
growth, accounting for most of the increased gas demand. Gas generation
also increased at times during this period to offset periods of low
hydroelectric generation.
[GRAPHICS NOT AVAILABLE IN TIFF FORMAT]
Most of the questions posed here relate to the surge in
construction of gas-fired power plants over the last 5 years. This
surge was the result of several factors:
<bullet> The preparation for and implementation of electric
industry restructuring caused a period of uncertainty in the industry
during the 1990's. One result of this uncertainty was a slowdown in
power plant construction. Construction of new power plants of all types
during the 1990's was lower than at any time since the 1950s.
<bullet> The move to restructuring resulted in a focus on power
plant construction by non-utility developers. These developers were
depending on project financing rather than traditional utility
financing. The lower capital cost of gas-fired plants (approximately
half that of a coal plant) was a huge advantage for these companies,
who had to raise cash from investors to build the plants. The new
market also created a premium for speedy plant construction to reach
the competitive market before other developers. The short construction
time for gas plants was also highly advantageous in this respect. At
the gas prices prevailing during the late 1990's when these plants were
developed, they were highly competitive with the more expensive coal
plants.
<bullet> The small footprint and infrastructure requirements (fuel
delivery, water requirements, land use, etc.) for gas plants allowed
them to be sited close to electric load centers and in locations with
high electricity market prices.
<bullet> Many of the new plants were peaking plants that operate
only a few hundred hours per year and for which coal is not an
economically viable option.
<bullet> The gas plants have much lower emissions than coal plants
but still were required to go through a rigorous permitting process and
faced stiff local opposition in many locations. The new source review
process and other relevant environmental regulations establish more
stringent emission limits for gas plants than for coal plants, so the
gas plants' lower emissions did not substantially simplify the air
emission permitting process relative to a coal-fired plant.
In short, there were a variety of market and institutional factors
that led developers to focus on gas power plants during the late
1990's. Lower emissions were one contributing factor but were less
important than developments in the market and the institutional factors
that created a focus on gas power plant construction.
Finally, the surge of new gas power plants has not, as yet,
resulted in a comparable surge in gas consumption. Whether this occurs
will depend on other market factors that determine the future
utilization of the new gas plants including the disposition of future
environmental regulation including the treatment of CO<INF>2</INF>
emissions.
Statement of Jack N. Gerard, President and CEO, American
Chemistry Council
Good Morning. My name is Jack Gerard. I am President and CEO of the
American Chemistry Council. Thank you for the opportunity to testify on
behalf of the 900,000 men and women who work for the U.S. chemical
industry, an industry that is essential to America's economic and
national security.
I would like to focus my comments today on the consequences of the
high cost of natural gas on the chemical industry and, by extension, on
the entire manufacturing economy.
Chemistry consumes more than 10 percent of the Nation's natural
gas. We use it to run our plants and as the key ingredient in the
products we make. And since our products are found in 96 percent of all
manufactured goods, it's safe to say that natural gas is a key
ingredient to the Nation's manufacturing economy.
Last year, the Nation's natural gas bill topped $200 billion for
the first time in history. In 1999, the last time natural gas prices
traded in its historic price band, the national gas bill was just over
$50 billion. Higher natural gas costs, according to the National
Association of Manufacturers, are a major reason why the Nation has
lost 2.9 million manufacturing jobs since 2000.
My industry's share of the gas bill topped $30 billion last year,
up from $7.5 billion in 1999. In a few short years, the United States
has gone from having the lowest cost natural gas in the industrialized
world to the highest cost market. The impact has been staggering.
In a few short years, the U.S. chemical industry has lost more than
$50 billion in business to overseas operations and more than 100,000
good-paying jobs in our industry have disappeared. Put another way, the
chemical industry went from posting the highest trade surplus in the
Nation's history in the late 1990's to becoming a net importer by 2002.
Other industries include forest and paper, agriculture, aluminum and
steel, carpets, bedding and furniture, have a similar story to tell.
How did it happen? When you look at the data, the answer to us is
clear. Too little supply being chased by rapidly increasing demand. For
example, since the 1990's, there has been a 35 percent spike in natural
gas consumption by the utility sector. That is 1.5 trillion cubic feet
of new demand.
In that same period of time, domestic natural gas production
remained flat. Prices spiked at the end of 2000 and have been on an
upward trajectory ever since. In recent years, supply and demand have
been balanced largely through industrial demand destruction. Simply
put, when natural gas prices climb too high many industrial facilities
simply cut back or shut down.
In the 1990's natural gas became the fuel of choice in the power
sector for several reasons: low prices, lower capital costs, and
burning natural gas helped bring utilities into compliance with new
Clean Air Act requirements. At the time, it made a lot of sense for
utilities to invest in gas-fired power generation.
What nobody seemed to know at the time was that existing sources of
supply were unable to meet new sources of demand. When a supply
response was needed, it didn't come.
To us, the real failure in government policy was that it did not
open up new sources of natural gas supply to meet demand growth.
Government stood by while short supplies of natural gas led to a price
bidding war that drove more than 10 percent of industrial demand out of
the market.
For too many years, U.S. policy has been trying to have it both
ways. It can't continue. It is failing millions of Americans whose
livelihoods depend on reliable supplies of natural gas at affordable
prices.
The high price of natural gas is driving the global chemical
industry out of the United States. For example, today there are more
than 120 world-scale chemical plants--plants costing more than $1
billion--under development around the world. Only one is being built in
the United States. Business Week calls it the ``hollowing out of the
Nation's industrial core.'' By contrast, fifty of those new plants are
being built in China.
It is in the Nation's interest to urgently bring new sources of
natural gas supply in order to bring price relief to the market and to
stop the erosion of the manufacturing economy. That will mean changes
to 25 years of policies that have locked up more than 85 percent of the
Outer Continental Shelf to deep water energy development. The resource
potential is enormous.
That is why it is so frustrating to see proposals in Congress that
would extend the off-limits signs in the OCS out to 150 to 250 miles
off Florida's coast even as Cuba is hiring Chinese energy interests to
explore for energy in waters that are barely 50 miles from Florida.
It is time for a change. It is time to strive for balance and
reason. Here are three things Congress can do:
First, curb demand. Congress should continue to encourage all
natural gas users to become more efficient. Last year's Energy bill has
many good efficiency and conservation measures. Those measures should
be fully funded and implemented.
Next, diversify fuel sources. In the 1990's natural gas fired power
generation emerged as the technology of choice. Today, there are other
good choices, including advanced coal, nuclear and renewables
technologies. They should become the backbone of the power sector.
Finally, increase supply. We can no longer escape the fact that our
Nation's currently available supply of natural gas can no longer meet
the Nation's growing needs. We must increase access to new sources of
supply that are currently off limits to use.
In conclusion, the issue is restoring balance to the U.S. natural
gas policy in a way that helps manufacturers compete in global markets,
permits utilities to branch into leading edge technologies, and ensures
a reliable and affordable supply of natural gas for America's homes and
businesses.
I'd be happy to answer your questions.
______
Responses by Jack N. Gerard to Additional Questions from
Senator Jeffords
Question 1. Your testimony includes a number of recommendations for
Congress. The second recommendation discusses the need to diversify
fuel sources. It mentions renewable energy, technologies I have
supported for my entire career in Congress. I know your industry uses
natural gas to produce your products, but you also use it as an onsite
power source as well.
How do you see renewable energy playing a greater part in the
future of the chemical industry? Or were you mentioning renewable
energy as something that should be used by electric utilities, not the
chemical industry?
Response. ACC advocates for the use of all available energy
resources as the best means of addressing our long-term energy
security. Within the business of chemistry, we pride ourselves for
using energy wisely and efficiently.
Chemicals companies are investing in ways to make chemical
feedstocks from renewable energy sources. DuPont, for instance, is
building a plant to make a building block chemical for one of its fiber
businesses by using industrial biotechnology to ferment corn. The
company has set a goal of producing 25 percent of its chemical
feedstock from renewable energy sources.
Traditional renewable energy such as wind, solar and hydroelectric,
is typically not economically viable and/or available for the size
operations that are typical of the chemical industry. That said, as
these energy sources become more widely used and inexpensive, our
industry, along with all of the U.S. economy, will benefit from
affordable electricity that is generated by a widely diverse and
affordable fuel supply that includes renewable energy.
Question 2. The industrial sector, which includes the chemical
industry, is the largest consumer of natural gas, followed by the
electrical power sector. Would you favor reinstitution of policies that
would prevent or limit the use of natural gas for generating electric
power, so that more natural gas could be available as a feedstock for
the chemical industry?
Response. We do not support blanket prohibitions on natural gas
use. We do believe that electric utilities should use natural gas as
efficiently as possible and that policies should incent utilities to
rely on a broad array of fuel choices.
Congressional action to balance the supply and demand of natural
gas and broad diversification of our other energy sources will ensure
that picking winners and losers in the energy markets is unnecessary.
The use of natural gas as a valuable feedstock for the chemical
industry is critical to our ability to competitively manufacturer a
multitude of products used every day in this country. Continued high
prices for natural gas, driven by increased demand and short supply
across the economy is undermining the ability for our companies to
compete with our global competitors. Increasing the domestic supply of
natural gas is critical to ensuring that enough reasonably priced
natural gas is available for the variety of sources now using this
valued commodity. So is providing economically viable alternative
energy choices for utilities to help offset the rising demand for
natural gas. A diverse energy portfolio coupled with a balanced natural
gas supply/demand is essential to our industry's economic future as
well as to the broader U.S. economy.
______
Responses by Jack N. Gerard to Additional Questions from
Senator Voinovich
Question 1. Please provide your thoughts on how we can increase the
supply of natural gas and reduce natural gas prices today and over the
long term.
Response. Short-term and longer term actions are both critical.
Near term actions to increase efficiency and conservation would ease
demand pressures and Congress needs to fund and encourage the rapid and
full implementation of the 2005 Energy Policy Act. Opening access to
the Nation's natural gas supplies is also an immediate need. The Senate
should immediately pass the Domenici-Bingaman Lease Sale 181 bill. That
would bring enough gas to market to heat 5 million homes for 15 years.
Had Congress acted years ago when we started highlighting these
problems, permits would be in place, pipelines either built or nearing
completion and gas would have been flowing--and these would have been
short-term solutions. We can't wait another decade, or even another
year for Congress to act. Longer term, diversifying our energy
portfolio through use of advance coal technologies, nuclear and
renewable energy should be an activity that we can begin now, and
continue to grow.
Question 2. You mentioned in the hearing that ``Cuba is hiring
Chinese energy interests to explore and drill for energy in waters that
are barely 45 miles off the Florida coast.'' Please provide more
information.
Response. Cuba is already exploring for energy 60 miles from
Florida's coast, where U.S. exploration is prohibited by U.S.
moratoria. [100 miles from Florida], and this exploration is
accelerating. This should be of great interest to all Americans as we
debate our Nation's energy policy.
<bullet> Several foreign oil companies have begun exploration in
waters between Florida and the Cuba coast (north and west of Cuba, some
60 miles from the Florida coast), where U.S. exploration is prohibited.
(Source: media reports, publicly available company Web sites, publicly
available CIA Data Book, NOIA):
<bullet> Spain's Repsol--YPF
<bullet> Canada's Sherritt International
<bullet> Canada's Pebercan
<bullet> China's Sinopec
<bullet> China's CIINOOC
<bullet> China's Petro China
<bullet> India's ONGC Videsh
<bullet> Venezuela's PDVSA
<bullet> Cuba [Cuban National Oil Company--Cuba Petroleo or Cupet]
has signed joint venture exploration agreements with China, Canada,
Spain and Brazil. (Houston Chronicle, 2/4/06)
<bullet> ``Two Canadian energy companies, Pebercan and Sherritt
International, [have] discovered oil in the Gulf of Mexico in an area
under Cuba's control . . . Canadian companies had discovered estimated
reserves of 100 million barrels.'' (New York Times, 1/11/06)
<bullet> Most of Sherritt's Cuban oil production is derived from
oil fields located at [Cuban fields] Yumuri, Varadero, Canasi, and
Puerto Escondido. Average net production in 2004 was over 19,000
barrels per day. (Source: NOIA)
<bullet> ``Canadian oil company Pebercan has made a new discovery
on the Santa Cruz 100 well in the Canasi field of Cuba's block 7, the
company said in a December 24 statement . . . Pebercan is preparing an
appraisal program . . . and two appraisal wells are set to be drilled''
in 2006-2007. (Source: NOIA)
<bullet> ``In 2004, Spanish petrochemicals company Repsol-YPF SA
announced it had found petroleum reservoirs off Cuba's coast . . .
Repsol will join up with China's largest offshore oil producer, CNOOC
Ltd.; Norway's industrial company Norsk Hydro ASA; and India's state-
owned Oil and Natural Gas Corp., ONGC.'' (Miami Herald, 2/2/06).
<bullet> Repsol was the first to conduct deepwater exploration and
found good quality oil, but there was either not enough or it was too
deep to pursue production. Repsol used Norway's Eirick Raude rig for
drilling 18 miles off Cuba's northwest coast beginning in June 2004.
(Source: Publicly available company Web sites, publicly available CIA
Data Book).
<bullet> Canada's Pebercan drilled four exploration wells in the
first quarter of 2005. Two new wells were brought on-stream. Perbercan
currently has 12 oil-producing wells on the Seboruco deposit, compared
with five as of March 31, 2004. (Source: NOIA)
<bullet> Repsol-YPF holds exploration rights to six blocks offshore
northwest Cuba. In June 2004, Norwegian deep-water oil rig Eirik Raude,
under contract with Repsol-YPF, began drilling two wildcat wells of
Cuba's northwest coast. (Source: NOIA)
<bullet> ``In one of the most closely followed wildcatting efforts
in the Gulf of Mexico last year, Repsol YPF of Spain spent more than
$20 million to lease a Norwegian drilling rig to search for oil in
Cuban waters.'' (New York Times, 1/11/06)
<bullet> By longstanding convention the territorial waters boundary
between the United States and Cuba is half the distance between the
Florida Keys and Cuba's coast, less than 100 miles. That means that
drilling for oil and gas is taking place within 50 miles of the U.S.
coast even though under U.S. policy American energy companies are
barred from drilling along most areas of the U.S. coast. (ICIS News, 2/
9/06)
<bullet> About 85 percent of resource-rich U.S. outer continental
shelf (OCS) areas, chiefly along the East and West coasts and in the
eastern U.S. Gulf, are closed to energy exploration and development
under 25-year-old congressional moratoria. (ICIS News, 2/9/06)
Cuba's Exploration Activities Off the Florida Coast are Accelerating.
<bullet> Cuba ``has intensified its search for outsiders to develop
oil fields off its northern and western coasts, not far from the tip of
Florida.'' (Houston Chronicle, 2/4/06)
<bullet> ``Cuban officials . . . announced plans to double their
drilling capacity and explore for oil in the waters off the Caribbean
island. In the 2 years since oil deposits were found off its coast,
Cuba has inked exploration deals with Canadian, Chinese, Indian and
Norwegian firms.'' (Associated Press, 2/5/06)
<bullet> ``Chinese oil drilling equipment has been arriving in Cuba
this year [2006] as state-run Cubapetroleo (Cupet) and its foreign
partners prepare to significantly increase drilling along the northwest
heavy oil belt, an 80-mile stretch of coast in Havana and Matanzas
provinces.'' (Natural Gas Week, 1/2/06).
<bullet> The newest is joint venture between Cuba's state-run oil
company, Cubapetroleo, and Chinese company Sinopec. The venture was
agreed to in 2004, but has yet to occur. The exact location of the
planned drilling is unknown, but it does lie between Cuba and Florida
and most estimates provide a figure of 45 miles from the Florida Keys.
(Source: Publicly available company Web sites, publicly available CIA
Data Book)
<bullet> Production by a Canadian company (Sherritt) is slated to
begin this year 90 miles from Key West. Sherritt's existing production
is concentrated off Cuba's northern coast. In December 2004, Sherritt
announced that drilling at a well in Santa Cruz was promising and will
begin production in 2006. Santa Cruz del Norte oil field is located 33
miles east of Havana and 90 miles south of Key West. (Source: Publicly
available company Web sites, publicly available CIA Data Book)
<bullet> ``Analysts following Cuba's energy industry said they
expected Repsol YPF to continue drilling in Cuban waters later this
year or in early 2006, together with Union Cubapetroleo, an energy
concern controlled by the Havana government.'' (New York Times, 1/11/
06).
<bullet> Sinopec inked an agreement with CUPET to produce oil on
the coast of western Pinar del Rio province. (Source: Publicly
available company Web sites, publicly available CIA Data Book).
<bullet> ``In the 2 years since oil reservoirs were discovered off
Cuba's coast, Canadian, Chinese, Indian and Norwegian companies have
lined up to explore the potentially lucrative Caribbean waters.''
(Miami Herald, 2/2/06)
<bullet> Brazil's Petrobras expressed renewed interest in Cuban
exploration in January 2005 and will likely join forces with Canada's
Sherritt and/or Spain's Repsol for deep water drilling.
(Source: Publicly available company Web sites, publicly available
CIA Data Book)
Meanwhile, Florida Senators are introducing new legislation that would
extend off-limits areas out to 150 to 250 miles off Florida's
Coast.
<bullet> ``[Republican Sen. Mel] Martinez and Democratic Sen. Bill
Nelson are pushing for a buffer of 150 miles from Florida's Panhandle.
Rep. Jim Davis, D-Tampa, is seeking the same in a bill he introduced in
the House on [Feb. 16].'' (Orlando Sentinel, Feb. 17).
<bullet> ``[Senators] Martinez and Nelson have proposed legislation
that would open up a smaller area of the eastern Gulf to drilling [than
the Domenici-Bingaman bill]--but only in return for a permanent, no-
drilling zone that extends at least 150 miles off the rest of the
Florida coast and renews the nationwide drilling moratorium until
2020.'' (Los Angeles Times, 2/17/06).
<bullet> It is frustrating and ironic to see proposals in Congress
that would extend the off-limits signs in the OCS out to 150 to 250
miles off Florida's coast even as Cuba is hiring Chinese energy
interests to explore for energy in waters that are barely 50 miles from
Florida.
<bullet> ``Last month's [oil] discovery already has Cuba watchers
[in the U.S.] and officials [in Cuba] pondering potential changes in
relations with the United States. American companies are currently
prohibited from drilling in waters 100 miles or so from the coast of
Florida . . . A significant oil discovery, one that could turn Cuba
into an oil exporter from an importer, might prompt calls for reviewing
policies that exclude the great majority of American companies from
trading with Cuba.'' (New York Times, 1/11/06)
<bullet> ``The discovery last month by Pebercan of Montreal and
Sherritt of Toronto illustrates how companies from other countries
stand to benefit from the American embargo on most dealings with
Cuba.'' (New York Times, 1/11/06)
<bullet> ``News of the [oil] find by the Canadian companies and the
potential for larger discoveries of oil in the portions of the Gulf of
Mexico controlled by Cuba are fueling speculation about how the
emergence of Cuba as a promising oil exploration area might affect
relations with the United States.'' (New York Times, 1/11/06).
<bullet> ``Drilling of an exploratory well in Cuba's virgin Gulf of
Mexico waters that could make the Communist nation an oil exporter and
undermine the U.S. embargo has been completed, a [Cuban] senior
official said. Work on the well by Spain's Repsol YPF began in June and
captured the attention of the industry and governments due to its
potential economic and political consequences.'' (``Exploratory Oil
Drilling Done Off Cuba,'' Reuters, 7/25/2004).
<bullet> ``A commercially viable find could transform the cash-
strapped island from oil importer to petroleum exporting nation, adding
pressure on the United States to lift its four-decades-old trade
embargo against President Fidel Castro's government.'' (``Exploratory
Oil Drilling Done Off Cuba,'' Reuters, 7/25/2004).
<bullet> ``China is reaching out to acquire the energy it needs.
Last fall for example, China signed an oil and gas agreement with Iran
worth at least $70 billion. Sinopec Group, a Chinese State run energy
company, announced this year that they will be drilling for oil in
Central Asia and Cuba. China has also reached out to Venezuela, South
Africa and Angola.'' (Speech by Gale Norton, U.S. Secretary of the
Interior, before the Independent Petroleum Association of America, June
16, 2005).
<bullet> ``The petroleum reservoirs have fueled the Cuban
government's hopes of increased self-sufficiency amid tightened U.S.
sanctions.'' (Miami Herald, 2/2/06).
<bullet> ``Since 2004, Cuba has pumped $1.7 billion into its energy
sector with help from Canada, Europe and Latin America.'' (Miami
Herald, 2/2/06)
<bullet> ``There is a 45-year-old U.S. embargo designed to
undermine Fidel Castro's communist government . . . The energy sector
is the next cornerstone in ending the embargo. . . . [The U.S.] already
receives] oil from Venezuela, . . . although that is a country that the
United States also hasn't been getting along with.'' (Houston
Chronicle, 2/4/06).
<bullet> ``Greta Lichtenbaum, an attorney for the Washington firm
of O'Melveny & Myers that focuses on regulations governing
international business and trade, didn't see how energy companies could
get permission to do business with Cuba. `Barring regime change in
Cuba, I can't imagine why they would license such activity.' . . . The
U.S. Government approved a 2000 law that allowed food and agricultural
products to be sold to Cuba . . . But Lichtenbaum notes there's a
difference between investing in Cuban oil production and sales of U.S.
agricultural products. `An investment in Cuba would be a lot more
controversial.' '' (Houston Chronicle, 2/4/06)
<bullet> If oil in commercially viable volumes is found, Cuba could
be transformed from an oil importer to an exporter, ending the
country's chronic energy shortages and filling the government's coffers
with much-needed revenue. Repsol-YPF has reported that it plans to
spend more than $40 million on the project, on the basis that up to 1.6
billion barrels could potentially lie under the seabed. (Source: NOIA).
<bullet> ``U.S. corporations, however, have watched the activity
less than 60 miles south of Florida's coastline with their hands tied.
U.S. oil exploration in Cuban waters--along with most U.S. trade--is
prohibited under a 45-year-old U.S. embargo designed to undermine Fidel
Castro's communist government.'' (Miami Herald, 2/2/06)
<bullet> The United States generally has the best deep water
equipment, which are prohibited from being used due to the embargo.
(Source: Publicly available company Web sites, publicly available CIA
Data Book.)
Question 3. You mentioned that Dow Chemical was planning on
building a large facility in Texas, but due to natural gas prices, the
plant is now going to be built in Oman. Please provide more details,
including the advantages of having this plant located in the United
States (such as jobs, etc.) and the factors that contributed to this
decision (such as natural gas prices in the United States versus Oman,
plant siting requirements, etc.).
Response. Andrew Liveris, President and CEO of the Dow Chemical
Company, testified before the Senate Energy and Natural Resources
Committee on October 6, 2005 on the subject of high natural gas prices.
He noted that high U.S. natural gas prices were affecting Dow's
investment decisions. Specifically, he said that the U.S. price of
natural gas, by far the highest in the world, had forced Dow to cancel
plans to build a $4 billion polyethylene complex and move the project
to Oman. When completed, Mr. Liveris said, the project will employ
1,000 people in operations, engineering and research and development
positions. As noted, chemical complexes create a large multiplier
effect on communities. Every chemical industry job creates 5.5
additional jobs in businesses that service and supply the chemical
complex. Locating chemical plants in other parts of the world creates
fewer jobs for engineers and scientists thus weakening America's
technical universities.
Question 4. You mentioned that one of the problems with sending all
of these jobs overseas is the ``brain drain'' that it is causing on our
competitiveness. What is the impact of all of these jobs lost in the
chemical industry in terms of Nation's innovation?
Response. Experts in the field of developing new and innovative
products will obviously follow the jobs, wherever they might be. If the
companies are moving operations overseas and the product growth
opportunities are occurring offshore, then it follows that the R&D
experts will be located accordingly. Short term, this creates the brain
drain and long term, it lessens the attractiveness for U.S. students to
choose these career options as they have fewer job opportunities within
the United States. These factors suggest that more and more of the new
and innovative products will not be domestically developed.
Question 5. You mentioned in your testimony that your industry has
lost over 100,000 jobs as energy prices undermined the global
competitiveness of some chemical operations. What are the types of jobs
that were lost and what can we do to bring them back?
Response. The chemical industry employs on average, the highest
skilled workers in the country and these are high paying jobs. Every
job in the industry adds about 5.5 jobs to the broader U.S. economy
through both supplier and expenditure jobs. Unfortunately, the jobs
lost are unlikely to come back. The intellectual capital also tends to
relocate with the manufacturing facilities--offshore. So we are also
losing the longer term science and technological leadership from this
country as these individuals follow the opportunities elsewhere in the
world. This is why it is so critical for Congress to act and restore
balance and affordability to the natural gas market to stop this
attrition on good paying U.S. jobs.
Question 6. You mentioned that demand destruction through shutdowns
or curtailments by the industrial sector has been the means of
achieving balance for natural gas. What would it take to avoid future
demand destruction?
Response. More access to the Nation's energy supply and full
utilization of the diversity of fuels we have available. A growing
economy needs a growing supply of energy. It's that simple. Congress
needs to free up the domestic supply of natural gas and support
continued growth of nuclear coal and renewable energy sources. Demand
destruction will continue as long as industry's that compete globally
are priced out of the market by domestically driven demands on natural
gas that can be passed along to the consumers. The attached white
paper, prepared by ACC economists, details the cause and effect of
industrial demand destruction.
__________
Statement of the American Forest & Paper Association
introduction
The American Forest & Paper Association (AF&PA) applauds the
Subcommittee for recognizing the nexus between government policies and
energy prices. For many years, Federal policies have encouraged
increased consumption of clean burning natural gas to meet
environmental objectives. At the same time, other Federal policies have
restricted access to supplies of natural gas both on and offshore. This
dichotomy has resulted in a serious supply demand imbalance with
natural gas prices rising to record levels.
AF&PA is the national trade association of the forest, paper and
wood products industry. Our organization represents approximately 250
member companies and related trade associations that grow, harvest, and
process wood and wood fiber; manufacture pulp, paper and paperboard
from both virgin and recycled fiber; and produce solid wood products.
The U.S. forest products industry is vital to the Nation's economy.
We employ more than one million people and rank among the top 10
manufacturing employers in 42 States with an estimated payroll of more
than $60 billion. Sales of the paper and forest products industry top
$230 billion annually in the United States and export markets. We are
the world's largest producer of forest products.
Energy is the third largest manufacturing cost for the forest
products industry, making up 18 percent of total manufacturing costs
for pulp and paper mills--up from 12 percent just 3 years ago.
Annually, forest products companies purchase about 400 billion cubic
feet of natural gas. While today the price of natural gas in the United
States hovers around $8 per million BTUs, in the last 3 months we have
seen prices as high as $15. That is an increase since July and four
times historic averages. This increased price for natural gas has also
put increased pressure on purchased electricity and the price of
chemicals needed for our manufacturing operations. Higher natural gas
prices have the additional effects of increased transportation costs,
as pulp is sourced from around the world.
Meanwhile, prices in the rest of the world are noticeably lower.
For example, the high cost of gas in the United States dwarfs gas
prices in other countries that have seen much lower prices per million
BTUs, such as South America, and Russia, putting our industry at a
significant competitive disadvantage. This disadvantage is on top of
other competitive disadvantages we face. Our taxes are higher than
those of competing nations, and there are unfair trade barriers to the
export of our products. The cost of compliance with our Nation's
environmental laws is directionally higher than the cost for some of
the countries with which we compete, and transportation costs are
greater than anywhere else around the globe. Government restrictions
are also limiting our access to fiber--even though our forestry stock
has increased by 39 percent since 1952. If we cannot successfully
address these challenges, the public demand for forest products will
increasingly be filled by other nations who do not adhere to our high
standards.
The impacts of rising energy prices on the industry have been
dramatic. The forest products industry has closed over 232 mills and
lost 182,000 jobs (12 percent of employment) since 2000 when energy
prices started a steep rise. High energy costs contributed
significantly to these closures/lay offs. Mills also have suffered
supply curtailments.
Ultimately, an adequate supply of energy at a reasonable price is
needed for vibrant economic growth and environmental protection. Long-
term solutions are essential to addressing this critical problem;
however, it is also important that short-term steps be taken to
mitigate the impact currently being felt by manufacturers.
impacts on the u.s. forest products industry
Due to the already tight supply situation, the industry needs
short-term regulatory relief as long as prices stay abnormally high.
Fuel switching is a viable option, as well as ceasing the operation of
non-essential gas-intensive controls at forest products facilities.
However, these options are precluded at many facilities due to permit
and other environmental requirements.
<bullet> Boise-Cascade says natural gas costs were behind a shift
cut of about 70 jobs at its lumber mill in La Grande, Oregon for 2
months last fall. The sawmill uses gas-fired boilers to generate steam
for drying lumber. Boise reported that the cost of natural gas has
nearly doubled at the time, making it infeasible to operate the shift.
Boise-Cascade is Union County's largest employer with 700 workers.
<bullet> A Pasadena Paper mill, the last paper mill in Houston,
closed its mill in early October and blamed high natural gas prices for
the decision. The mill employs 250 workers and has been in operation
for more than 60 years.
Supply Curtailment
AF&PA members around the country report that supply and demand are
delicately balanced, and companies from Wisconsin to Mississippi report
curtailment problems--especially following the recent hurricanes.
Many companies operate with interruptible contracts to save money
and allow natural gas to be diverted for high priority uses in the
winter. The following examples illustrate the recent difficulties
experienced with this type of curtailment.
More Frequent and Longer Shut Downs
<bullet> A Wisconsin company reported experiencing one to two
interruptions during past heating periods, but during the 2004--2005
winter season, interruptions doubled to three to four shut downs. And
the duration of each interruption was much longer--lasting up to seven
or 8 days in some cases. The company is concerned about the coming
winter and actively monitoring the situation.
<bullet> On September 28, a facility in Zachary, Louisiana was
issued an administrative compliance order to cease use of natural gas
because natural gas supplies were not available to the facility. If
natural gas curtailment becomes necessary, it would be large industrial
customers who lose natural gas first. Home heating and other key uses
of natural gas will take precedence over uses by industry even if they
technically have ``non-interruptible contracts.''
Shrinking Supply/Increasing Prices
<bullet> An Alabama wood products facility with interruptible
service was notified after Hurricane Rita that service would be
interrupted for about 1 week. However, the facility was given the
option of purchasing gas at the average daily market price. The price
of gas for the facility rose from an already high value of $10.99/MCF
to a new high of $19.79/MCF. And over the week, the facility spent an
extra $57,000 to meet its energy needs.
Ability to Switch Fuels Limited by Permits
In the face of higher natural gas prices and supply interruptions,
temporarily switching to less expensive fuels is a very viable and
necessary option for mills facing the economic challenge of paying
utility bills and remaining profitable. However, this option is
constrained by permit requirements:
Permits Limit Options
<bullet> Paper and wood products companies from Massachusetts to
Tennessee and Georgia report that permits limit the burning of #6 fuel
oil--the more reasonably priced fuel--to 60 or 90 days per year.
Several companies report that they are nearing their limit for using #6
fuel oil, and if gas prices go higher, their only option is to close
facilities. Clearly, permit waivers while prices are high would avoid
this situation.
Faced with interruptions and exorbitant prices, companies have
unpleasant options for continuing business. They can pay substantially
more for available energy or shut down the facility. Neither solution
is acceptable to the company or to the U.S. economy.
Majority of Gas Used for Emissions Control Units
Members operating wood products facilities report that the control
unit required to remove emissions of volatile organic compounds (VOCs)
consumes by far the majority of gas at the facility. As an industry,
paper and wood products facilities combined use BCF of natural gas--
approximately the amount needed to heat 90,000 homes--to fuel control
units.
And the percentage of natural gas used to fuel control units is
increasing as facilities improve energy efficiency elsewhere in the
plant.
Emissions Control Consumes High Percent of Natural Gas
<bullet> Several companies report that VOC control units can
consume from 50 to 99 percent of all natural gas used at wood products
facilities.
With rising gas prices and interrupted supplies, the cost to remove
emissions of volatile compounds--mostly methanol--is staggering.
Control requirements for these facilities were based on far
different gas-price scenarios. At many facilities, the economic
analysis used gas prices in the range of $2-$3/MCF. With gas prices of
$8-$12/MCF, the results are dramatically different and call into
question whether the controls should be required while prices are so
high. The following two examples illustrate this point.
------------------------------------------------------------------------
Cost of VOC Removal ($/Ton VOC
----------------------------------- Removed)
-------------------------------------
Wood Products Facility Time of
Permitting At $12 gas
------------------------------------------------------------------------
Door Finishing Facility, MS....... $532 $20,000
Average Oriented Strand Board $1,500-12,000 $3,000-36,000
facility.........................
------------------------------------------------------------------------
VOC Control Units Facilitate Foreign Competition
In the south, companies are facing increased competition on some
wood products from South American suppliers. With higher natural gas
prices, companies estimate that it is the cost of operating the VOC
control units that makes it feasible for foreign competitors to enter
the market. The United States is the only country in the world to use
these types of controls on wood product facilities. Skyrocketing gas
prices exacerbate the problem.
VOC Control Costs Burden U.S. Manufacturers
<bullet> One company estimates that on average it costs $1.25-$1.75
million per year to operate a control unit at today's gas prices. For a
facility with three units--which is typical--total costs are on the
order of $3.75 to $5.25 million per year.
i. recommendations for short term relief and associated savings
Manufacturers need immediate action to allow them to operate while
prices stay high whether driven by increasing demand for winter heating
or supply reductions caused by hurricanes. This action should include
the ability: (1) to use other fuels in the face of natural gas
curtailments or prohibitively expensive gas and (2) to temporarily
cease operations of non-essential gas-intensive controls that primarily
control emissions of methanol. Similarly, electric utilities use the
most natural gas in terms of industry sectors and fuel switching could
result in huge natural gas savings. Other short-term recommendations
include more aggressive consumer conservation programs. Each is
discussed below.
(1) Fuel Switching at Forest Products Industry Facilities
Recommendation
<bullet> EPA and States could use enforcement discretion to allow
fuel switching during periods of supply disruptions or exorbitant
prices. EPA should provide short-term waivers, variances, or temporary
compliance orders to facilities during the current emergency
exacerbated by Hurricanes Katrina and Rita.
<bullet> Clean Air Act new source review (NSR) requirements should
not be imposed on facilities that switch fuel especially in emergency
situations. EPA could issue guidance clarifying that NSR would allow
units designed to burn alternative fuels to do so.
<bullet> Monitor and reconsider, where appropriate, pending
regulatory requirements that have significant negative impacts on
natural gas demand or supply.
Potential Savings
AF&PA has surveyed its members to determine the extent to which
they could switch to alternative fuels if permit limits and regulatory
constraints did not limit or prevent switching. In the survey, we
specifically requested respondents to consider physical plant, pricing
and other potential practical issues when answering. Our objective was
to obtain an accurate estimate of the amount of fuel switching that
actually could occur if the permit and regulatory constraints were
removed.
Based on responses to our survey, it is clear that removing
barriers to fuel switching could result in savings of significant
amounts of natural gas and economic relief for industry mills.
Specifically, responding mills producing pulp, paper, paperboard and
paper products indicated potential savings of about 1 billion cubic
feet per month. These savings represent approximately 4 percent of the
monthly natural gas used by the industry. These mills would realize
cost savings of almost $6 million per month by switching to other
fuels. These resources could be better spent on retaining high paying
industry jobs or investing to make the mills more efficient and
competitive.
We should note that these figures are based only on the responses
we have obtained to date from our members. They likely understate the
potential conservation of gas because the responding mills account for
a small portion of the mills that make up the forest products industry.
(2) Operations of Non-Essential Gas-Intensive Controls at Forest
Products Industry Facilities
The forest products industry operates some mandatory pollution
controls that require considerable amounts of natural gas to operate,
while producing questionable environmental benefits especially during
cold weather months. Permit requirements mandating full time operation
of regenerative thermal oxidizers (RTOs) serve as an example. Many of
these RTOs are designed to burn primarily methanol emissions for ozone
abatement, in part, even though methanol is not a major contributor to
smog formation. In addition, ozone is not a pollutant of concern during
the winter months, yet operating permits require year-round operation.
For the forest products industry, RTOs consume about 10 billion cubic
feet of natural gas annually at a cost of over $100 million. Finally,
these controls produce hundreds of tons of nitrogen oxide emissions
that contribute to the ozone problem making the cure cause more harm to
the environment. Therefore, mills should be permitted to cease
operating these nonessential controls as the effect on public health
would be negligible and substantial gas savings would result.
Recommendation
<bullet> EPA should allow amendments to current permits to address
energy emergencies. At current gas prices of $8-12/million BTUs,
emissions controls are not cost effective.
Potential Savings
The wood products segment of the industry has the potential for the
greatest savings from ceasing operation of non-essential gas intensive
controls--approximately 7 billion cubic feet per year. With regard to
the paper segment of the industry, potential savings are lower at
approximately 2 billion cubic feet per year.
(3) Fuel Switching by Industrial Boilers
Recommendation and Savings
Today, only 5-10 percent of other industrial boilers are capable of
fuel switching, down from 25 percent in the past. Nonetheless, due to
the number of such boilers, potential savings could be as much as 0.2
trillion cubic feet per year. Again, this may be an optimistic estimate
because there could be other, non-regulatory impediments to fuel
switching for these boilers, such as the siting of fuel back up tanks.
Nonetheless, due to the magnitude of potential savings, it is worth
additional consideration and analysis.
(4) Continued Aggressive Energy Conservation Campaign
AF&PA supports the Administration's ``Easy Ways to Save Energy''
Campaign recently announced by Energy Secretary Bodman. The campaign
includes actions directed at consumers, businesses and government
agencies. We support the comprehensive nature of this campaign, with
its recognition that all societal sectors must contribute to
conservation efforts.
At least 10 AF&PA member mills have participated in an existing
Department of Energy (DOE) energy saving program, which provided energy
assessments for industrial facilities. On average, implementation of
the assessments' recommendations has resulted in millions of dollars in
savings per mill. DOE should continue and expand these and the other
measures in the campaign.
(5) Better Compliance with Executive Order on Energy Impacts
The four regulations and policies discussed below are just a few
examples of requirements that, depending on how they are implemented,
can increase the demand for natural gas, and therefore increase the
upward pressure on prices. EPA and other Federal agencies should work
with the Office of Management and Budget (OMB) to ensure rigorous
compliance with Executive Order 13211 (Actions Concerning Regulations
that Significantly Affect Energy Supply, Distribution, or Use) to
clearly identify regulations that are significant energy actions and to
require robust, detailed analysis of the effects regulatory actions
will have on natural gas supply, use and price. This will allow
Congress and the Nation to have an informed discussion about policies
increasing natural gas demand.
1. PM fine Implementation rule (final in mid-2006).--A number of
improvements can be made to EPA's proposed rule to increase compliance
flexibility in State Implementation Plans (SIPs) that are due in 2008.
Failure to find cost effective reductions or take credit for the
significant reductions under the Clean Air Interstate Rule (CAIR) will
lead to additional regulatory pressures on manufacturing and utilities
to reduce NOx and SO<INF>2</INF>. On the margin, some facilities may
choose to switch to natural gas rather than fit facilities with
expensive add-on controls. New units especially will be driven to use
natural gas given a lack of sufficient ``emission credits'' to use coal
or other fuels.
2. Ozone implementation proposal (proposal 2006).--EPA should
maximize State flexibility to implement the new 8-hour ozone rule.
Failure to take into account reductions from existing programs could
push States to control Volatile Organic Compounds (VOCs) through gas-
intensive incinerators which also produce hundreds of tons of NOx and
require additional NOx reduction that will occur as a result of CAIR
and other programs.
3. Industrial Boiler review (fall 2006).--Under the Air Quality
Management recommendations, EPA is examining the need for additional
national controls on industrial boilers. We are concerned that tighter
controls on a wide variety of boilers will prompt further fuel
switching to natural gas if controls are expensive or infeasible. EPA
should not set national criteria pollutant standards for boilers since
this approach was recently rejected as part of CAIR and remaining air
quality problems are more localized and not national in scope. Finally,
boilers differ substantially across industries in terms of fuels, size,
uses, and designs so a one-size-fits-all national regulatory approach
is not justified.
4. Trading as a Viable Compliance option under the Clean Air Act
(first half of 2006).--EPA has embraced trading in the Acid Rain and
CAIR programs. However, the opportunities for other sources, especially
in the manufacturing sector to participate in such programs have been
limited to date (i.e., NOx SIP call). EPA should develop a model
trading rule for States to adopt for industrial sources as a viable and
more cost effective option for complying with Best Available Retrofit
Technology (BART) and the regional haze program in general as well as
for implementing the new PM fine and ozone NAAQS. Trading programs
should be integrated with existing programs to the extent possible.
ii. recommendations for long-term balance of supply and demand
An adequate supply of energy at a reasonable price is needed for
vibrant economic growth. Long-term solutions are essential to
addressing this critical problem. Ultimately, we believe that balance
can only be achieved if action is taken in each of the following
critical areas:
(1) Remove Barriers to Supply of Natural Gas
OCS
Remove Federal restrictions currently limiting access to deep-water
offshore natural gas resources in the Pacific, Atlantic, and Eastern
Gulf of Mexico Outer Continental Shelf (OCS). AF&PA supports H.R. 4318
The Outer Continental Shelf Natural Gas Relief Act of 2005, a bill
introduced by Representatives Peterson and Abercrombie that would lift
restriction on natural gas leasing in the OCS.
The National Petroleum Council estimates that there are
approximately 300 TCF of natural gas and more than 50 billion barrels
of oil on the OCS off the continental United States that can be
recovered using existing technology but which have yet to be
discovered. This is enough natural gas to maintain current OCS
production for almost 70 years and enough oil to maintain current U.S.
oil production for more than 80 years.
<bullet> Lease 181.--Lease 181 might represent 20 percent of the
entire Gulf gas production for the next 6 years; it is an immediate
source of supply because the pipeline infrastructure necessary to
transport the gas to market is already built and operational in the
area. Congress and the Administration should take immediate actions to
expedite the sale of the lease 181 area.
<bullet> State Empowerment.--Senator Lamar Alexander's ``Natural
Gas Price Reduction Act of 2005,'' (S. 726) and Subtitle E (Chairman
Richard Pombo's Ocean State Options Act) of the House Resources
Committee's budget reconciliation package, provide a workable framework
for allowing States to pursue deep water energy production off their
shores.
<bullet> Liquefied Natural Gas (LNG).--LNG is becoming more
affordable and practical with recent advances in liquefaction and
transportation technology. However, barriers to LNG in the Natural Gas
Act and FERC regulations and difficulties in siting new or expanded
facilities will make it a challenge for the Nation to realize
significant increased natural gas supply through increased LNG use. The
provisions in the Act to expedite LNG siting and expansion should be
aggressively implemented.
<bullet> Generation Efficiency.--Industrial consumers of natural
gas have improved significantly the efficiency with which they use
natural gas because of the pressures of global competition. Utilities,
however, are not subject to the same competitive forces and have not
updated the efficiency of older power plants, in most cases simply
passing through to their consumers the increased cost of natural gas.
Congress and the Administration should adopt and support policies that
will encourage or require all public utilities to meet a generation
efficiency standard for their natural gas-fired generation units.
<bullet> Alaska Natural Gas Pipelines.--The Alaska Natural Gas
Pipeline will provide 1.5-2.2 TCF per year that could reach the lower
48 States after 2015. Efforts should be undertaken to expedite the
completion of the pipeline.
<bullet> Unconventional Sources of Natural Gas.--Congress and the
Administration should encourage and provide incentives for new
technologies to find and tap supplies of unconventional sources of gas.
The United States already obtains 7 TCF of natural gas a year from
unconventional sources, and the EIA projects that production of
unconventional gas can be increased by 1.2 TCF within the next 10
years.
<bullet> Efficient Permitting.--The oil and gas reserves on Federal
lands should play a critical role in the Nation's energy supply.
Congress recognized the impediments to efficient exploration and
development of these resources (as well as the OCS) in the Act by
directing the Department of the Interior to improve its practices and
conduct various pilot projects on more efficient processing of access
applications. The Administration and the Congress should fully fund the
permitting programs to eliminate the backlog of permitting and expand
the pilot project if it proves to be successful.
(2) Diversify the Nation's Energy Portfolio through R&D and Incentives
<bullet> Renewable Energy.--Biomass energy is renewable, and is
``carbon neutral.'' DOE should strongly support the Agenda 2020
program, a key component of which is the Integrated Forest Products
Biorefinery (IFPB), a technology platform that includes biomass
gasification technologies. The IFPB technologies will give industry the
ability to make greater use of renewable biomass energy in its
processes, while becoming a net producer of renewable electric power,
liquid transportation fuels, and other biobased energy and products. If
fully developed and commercialized, the IFPB technologies could produce
enormous energy and environmental benefits for the industry and the
Nation both, including contributing to a diversified and secure
national energy supply.
<bullet> Coal.--In the United States, coal is the lowest cost and
most abundant domestic energy resource; coal fuels more than 50 percent
of U.S. electricity. AF&PA supports the Administration's FutureGen coal
initiative that will spend $1 billion over 10 years. The initiative
will build the world's first zero-emissions fossil fuel plant combining
several promising technologies to enhance the efficiency and reduce the
environmental impacts and greenhouse gas emissions from coal. The
Administration should also aggressively implement the ``Clean Coal''
provisions in the Act and adopt other policies to encourage deployment
of this technology and use of coal as an energy source for the Nation.
Conservation
Over the long term, energy conservation programs can yield
impressive energy savings and Congress and the Administration should
aggressively fund and continue energy conservation campaigns.
conclusion
We urge the subcommittee to support policies that will address the
fundamental imbalance in natural gas supply for both the short term and
the long term. Our Nation's economic growth and the ability of U.S.
manufacturers to regain their competitiveness can be greatly enhanced
by implementation of a strong and balanced energy policy that will
reduce natural gas costs for all consumers.
<all>