[Senate Hearing 109-362]
[From the U.S. Government Printing Office]
S. Hrg. 109-362
ENERGY OUTLOOK 2006
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED NINTH CONGRESS
DISCUSS THE ENERGY INFORMATION ADMINISTRATION'S 2006 ANNUAL ENERGY
OUTLOOK ON TRENDS AND ISSUES AFFECTING THE UNITED STATES' ENERGY MARKET
FEBRUARY 16, 2006
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Committee on Energy and Natural Resources
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COMMITTEE ON ENERGY AND NATURAL RESOURCES
PETE V. DOMENICI, New Mexico, Chairman
LARRY E. CRAIG, Idaho JEFF BINGAMAN, New Mexico
CRAIG THOMAS, Wyoming DANIEL K. AKAKA, Hawaii
LAMAR ALEXANDER, Tennessee BYRON L. DORGAN, North Dakota
LISA MURKOWSKI, Alaska RON WYDEN, Oregon
RICHARD M. BURR, North Carolina, TIM JOHNSON, South Dakota
MEL MARTINEZ, Florida MARY L. LANDRIEU, Louisiana
JAMES M. TALENT, Missouri DIANNE FEINSTEIN, California
CONRAD BURNS, Montana MARIA CANTWELL, Washington
GEORGE ALLEN, Virginia KEN SALAZAR, Colorado
GORDON SMITH, Oregon ROBERT MENENDEZ, New Jersey
JIM BUNNING, Kentucky
Alex Flint, Staff Director
Judith K. Pensabene, Chief Counsel
Bob Simon, Democratic Staff Director
Sam Fowler, Democratic Chief Counsel
Lisa Epifani, Counsel
Jennifer Michael, Democratic Professional Staff Member
C O N T E N T S
Akaka, Hon. Daniel K., U.S. Senator from Hawaii.................. 15
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................ 3
Caruso, Guy, Administrator, Energy Information Administration,
Department of Energy........................................... 1
Domenici, Hon. Pete V., U.S. Senator from New Mexico............. 1
Murkowski, Hon. Lisa, U.S. Senator from Alaska................... 16
Responses to additional questions................................ 23
ENERGY OUTLOOK 2006
THURSDAY, FEBRUARY 16, 2006
Committee on Energy and Natural Resources,
The committee met, pursuant to notice, at 2:40 p.m. in room
SD-366, Dirksen Senate Office Building, Hon. Pete V. Domenici,
OPENING STATEMENT OF HON. PETE V. DOMENICI,
U.S. SENATOR FROM NEW MEXICO
The Chairman. The hearing will please come to order.
Senator Bingaman is not here at this moment, but he was here. I
was not quite on time, so he had to go somewhere. Now we have
representation on both sides and I assume, Senator Akaka, we
can proceed; is that right?
Senator Akaka. Yes.
The Chairman. All right. First, Mr. Caruso, we are sorry we
had to put this hearing off the other day and we will try to
hear you today.
For the past 3 years I have observed that the level of
concern about energy issues seems to go up as prices have gone
up. It is definitely right that our concern should rise with
the American consumers who are paying more for home energy and
transportation, but I want us all to keep in mind that, in
spite of that, for now the economy is strong. However, we need
to take whatever steps we can to assure that energy prices do
not change that fact if there is anything we can do about it.
So the first step we took in August 2005 was we passed a
rather comprehensive bill. It is having some significant
impact. I will note, and you can confirm later, that even in
your analysis, where it is pretty hard for you to take energy
sources that are not yet in existence and expect them, you do
expect nuclear power to be online and to be part of the mix in
the next 25-year forecast. That is the first time that has
happened in quite a while; right, Mr. Caruso?
STATEMENT OF GUY CARUSO, ADMINISTRATOR, ENERGY INFORMATION
ADMINISTRATION, DEPARTMENT OF ENERGY
Mr. Caruso. That is correct.
The Chairman. We trust you on your estimate on that one,
although I have some very serious concerns about some other
parts of your estimate. I hope you are right, but on some of
them I really wonder.
First, I am proud of the vote that occurred on that bill of
ours, that means that we know how to work together. And it has
a lot of provisions in it so I am just going to insert in the
record, Senator Bingaman. That helps us in terms of the issues
that Mr. Caruso is concerned with.
So given the importance of many of the provisions in the
energy bill and in the national security problems, it is
imperative that we remain vigilant on the implementation of
that act as I see it. Today, as an example, you will tell us
that you expect coal use for electricity generation to go from
50 percent to 57 percent by 2030. Given that prediction, it is
obvious that we must do many of the things in that Energy Act
to ensure cleaner coal and attempt to do better at funding the
activities that would get us that. That is not your policy
decision, but I think that follows like night from day, based
upon your estimates of what we are going to have to use.
It is obvious that much of what we must do, and we have not
done enough yet, is we have to address the use of--reducing the
use of petroleum products in our transportation sector and we
have to look at new places to get crude oil. I have not
mentioned it in any big way yet, but I think we have to
probably begin to look at it if we are going to try to get
where the President suggested on energy dependence, oil
dependence, or further. We are probably going to have to look
at things like oil shale and the like in the not too distant
I am going to skip over the PACE bill, Senator Bingaman,
which we all know has some impact on the future. I want to just
go to your final assessments here. The outlook that you have
here predicts that prices in 2025--you predict that they are
going to be $21 higher--that is oil we are talking about--than
your last year's prediction. That is a major adjustment in the
expected future price of oil and makes me wonder about the
reliability of these predictions.
In other words, you had the price going up much more than
that by 2025; is that not correct?
Mr. Caruso. That is correct, chairman.
The Chairman. What was the number?
Mr. Caruso. The 2025 number is approximately $21 higher in
real terms this year than last year.
The Chairman. So what is that dollar amount? When you add
21, what is the dollar number?
Mr. Caruso. The cents per gallon maybe?
The Chairman. Dollars per barrel.
Mr. Caruso. Dollars per barrel, it is $57 per barrel WTI.
The Chairman. So what I am saying is I think that it is
going to be higher than that. I do not understand how you get
it that low.
Mr. Caruso. For the record, in nominal dollars, that is
The Chairman. Yes.
Mr. Caruso. Sometimes it is hard to think in 2004 dollars.
The Chairman. Now we have got it.
I wanted to make this last one. You also think that the
level of petroleum imports is going to drop from its 2005
forecast of 68 percent to 60 percent by 2025; is that correct?
Mr. Caruso. That is correct, Mr. Chairman.
The Chairman. Now, that is not--those are apples and
apples. You think we are going to have 8 percent less
importation, based upon the starting point and the assessment
that you make every year. You use the same assumptions; it is
going to go down. Are you going to tell us why in the
Mr. Caruso. Sure, I would be happy to.
The Chairman. That is kind of exciting. We do not have to
do anything and we could have had a policy saying we are going
to reduce it 8 percent, Senator Bingaman, and had a bill, an 8
percent reduction, and passed it, like everybody wants us to
be, bold. Then we would have called him up here and said, did
we do it?
Senator Bingaman. Full credit.
The Chairman. Full credit.
Okay, Senator Bingaman.
STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR
FROM NEW MEXICO
Senator Bingaman. Mr. Chairman, knowing the way this place
operates, there will probably be such a bill introduced before
Let me thank you for coming and thank you for your good
work. But I do not really have a series of questions at this
point. Once you give your testimony, I am anxious to understand
the assumptions that are built into it and how any of the
policies that we adopted last year as part of the energy bill
or that we are contemplating adopting here in this second
session of this Congress might impact on your assumptions or on
your projections. That is going to be the focus of my
Again, thanks for being here.
The Chairman. Thank you, Senator Bingaman.
Mr. Caruso. Mr. Chairman, members of the committee, thank
you very much once again for allowing me the opportunity to
present the Energy Information Administration's Annual Energy
Outlook, which this year for the first time goes to 2030. Mr.
Chairman, I also wanted to say that, while I realize this is
not a budget hearing, I would be remiss if I did not mention
our budget for fiscal year 2007 that Secretary Bodman presented
here in this committee last week. It does include an increase
over fiscal year 2006 and I, of course, feel it is fully
justified. I would certainly be glad to discuss that with you
or any other member or staff at another occasion. I just wanted
to say that, while I have the floor.
You are absolutely correct in that this year we have
reassessed our outlook for world oil prices significantly above
what we have been saying in recent outlooks. As you can see
from figure 2* in the written testimony, our expectations are
that world oil prices will decline somewhat from where they are
now over the next decade or so to roughly $47 in 2014 and then
rise to $57 in 2030. That, again, is in real terms, in 2004
*All figures have been retained in committee files.
That represents on average about $21 per barrel higher than
our reference case of last year. I think this reflects two
important things, and they are that investment opportunities on
the global market are tighter than we thought a year ago, and
costs are higher. Therefore, we think that there will be less
increase in productive capacity than we did a year ago, which
would lead to higher prices.
Now, you indicated the uncertainty in global markets, and
we tried to anticipate that uncertainty by having a range of
assumptions. In this case we have a low price case and a higher
price case, which range from $34 per barrel in 2030 to $96 per
barrel in 2004 dollars. So clearly we agree with you that there
is uncertainty, and we have attempted to capture much of that
uncertainty by the high and low price cases in this outlook,
which we have released just this week.
Natural gas prices also are higher this year than last
year, although we do expect them to come down from their
current levels of about $7 per 1,000 cubic feet to about $4.50
in the middle of the next decade, rising to about $6 by 2030 in
Energy demand--with these kinds of prices, we have slightly
slower growth in energy demand, but we still expect an increase
in U.S. energy consumption by about one-third between now and
2030. That is about a 1.1 percent increase annually. The
strongest growth will be for electricity generation and in the
transportation and commercial sectors.
Because of the high prices, total demand is about 6
quadrillion Btus lower than we were saying a year ago. The
lower demand results from higher energy prices, lower growth in
manufacturing output, more penetration of hybrid and diesel
vehicles, and the effect of the Energy Policy Act of 2005, all
of which combine to reduce demand by 2030.
The U.S. economy continues to become more energy efficient.
Energy intensity, measured as the energy used per dollar of
GDP, declines at an average rate of 1.8 percent per year
through 2030, due to improved efficiency and shifts in the
economy to less energy-intensive goods and services. This
combination of higher oil and natural gas prices, technological
change, and the effect of EPAct 2005 has the effect of reducing
the shares of oil and natural gas in the U.S. energy mix and
increasing the shares of coal, nuclear, and renewables in this
outlook. Nevertheless, petroleum is expected to remain the
primary fuel in the United States economy, as shown in figure 5
in the written testimony. That is mainly because of growth in
the transportation sector, which uses more than 70 percent of
all of our petroleum.
Improved efficiency helps, but it cannot offset continued
growth in travel by our consumers. Hybrid and diesel vehicles
will reach 9 and 8 percent, respectively, of new car sales by
2030--a significant increase from where they are this year,
less than 1 percent for hybrids, for example--contributing to
the increase in efficiency improvements.
Natural gas demand will grow through the next decade or so,
but then flatten out. We do think natural gas prices will have
an impact on consumption in the industrial and particularly the
electric power sectors, and therefore, its use actually peaks
and declines during this outlook period.
Coal, as has been mentioned, remains the primary fuel for
electric power generation. Its share increases from 50 percent
currently to 57 percent in 2030 in this outlook. We also
anticipate, with these higher real prices for crude oil, that
there will become a market for coal-to-liquids at the latter
part of this period, and we do anticipate coal production to
increase from 1,100 million short tons this year to about 1,800
million short tons in 2030, with about 190 million tons going
to coal-to-liquids. That would produce about 800,000 barrels a
day of mainly diesel fuel from coal-to-liquids plants that
would contribute to our petroleum demand.
Nuclear generation is expected to increase in this
forecast, going from about 100 gigawatts currently to 109
gigawatts. In the side cases, which allow for advanced
technology and lower costs, the increase in nuclear power
generation would be significantly more than in the reference
U.S. petroleum demand grows from about 21 million barrels a
day this year to 27.6 million barrels a day in the forecast in
2030. Domestic production in the near term will actually
increase as we bring on deepwater projects in the Gulf of
Mexico, but over the long term it will decline again, so that
our imports of petroleum as a share of total consumption will
go from 58 percent in 2004 to about 62 percent in the reference
Now, as I mentioned, we have a low price case and a high
price case. In those cases, the oil import dependence would be
53 percent in the high price case and 68 percent in the low
price case. So price does make a significant difference and it
would make a significant difference in terms of alternative
liquids from coal and natural gas, as I mentioned.
Now, for natural gas production, we do think it will
increase in the near term, but decline between 2020 and 2030,
and therefore there will be a need for significant imports of
natural gas. Net pipeline imports from Canada will decline due
to resource depletion in western Canada and the need for
Canadian domestic consumption. Therefore, LNG will rise
substantially, from .6 trillion cubic feet in 2004 to 4.4
trillion cubic feet in the reference case in this outlook.
We do think new facilities to regasify that LNG, in
addition to the ones under construction now and the expansion
of existing onshore facilities, will be built to serve the gulf
coast, Florida, southern California and New England. We also
anticipate the Alaska Natural Gas Pipeline will be onstream in
2015 in this outlook.
For electricity generation, we have a 50 percent increase
between now and 2030, and coal will supply about 70 percent of
that increase under these assumptions. Nuclear generation, as I
mentioned, will increase and renewable generation will increase
as well, in part due to EPAct 2005 and the various State energy
renewable portfolio standard rules and legislation, but will
still remain at about 9 percent of total generation.
The Clean Air Interstate Rule and the Clean Air Mercury
Rule, issued in March 2005, are expected to substantially
reduce power plant emissions of sulfur dioxide, nitrogen oxide,
and mercury over the next 25 years. But we do think this can be
done without a significant increase in electricity prices.
Mr. Chairman, with this very brief overview of the
comprehensive Annual Energy Outlook, I would be pleased to
attempt to answer any questions that you or any other committee
members may have at this time. Thank you.
[The prepared statement of Mr. Caruso follows:]
Prepared Statement of Guy Caruso, Administrator, Energy Information
Administration, Department of Energy
Mr. Chairman and Members of the Committee: I appreciate the
opportunity to appear before you today to discuss the long-term outlook
for energy markets in the United States.
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. ETA's
baseline projections on energy trends are widely used by government
agencies, the private sector, and academia for their own energy
analyses. 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 Annual Energy Outlook (AEO) provides projections and analysis
of domestic energy consumption, supply, prices, and energy-related
carbon dioxide emissions through 2030. The Annual Energy Outlook 2006
(AEO2006) is based on Federal and State laws and regulations in effect
on October 1, 2005. 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 includes consideration of the impact of the Energy
Policy Act of 2005 (EPACT2005), signed into law August 8, 2005.
Consistent with the general approach adopted in the AEO, the reference
case does not consider those sections of EPACT2005 that require
appropriations for implementation or sections with highly uncertain
impacts on energy markets. For example, EIA does not try to anticipate
the policy response to the many studies required by EPACT2005 or the
impacts of the research and development funding authorizations included
in the law. The AEO2006 reference case only includes those sections of
EPACT2005 that establish specific tax credits, incentives, or
standards--about 30 of the roughly 500 sections in the legislation.
These provisions include the extension and expansion of the Federal tax
credit for renewable generation through 2007 and incentives intended to
stimulate the development of advanced coal and nuclear plants.
EPACT2005 also has important implications for energy consumption in
the residential and commercial sectors. In the residential sector,
EPACT2005 sets efficiency standards for torchiere lamps, dehumidifiers,
and ceiling fans and creates tax credits for energy-efficient furnaces,
water heaters, and air conditioners. It also allows home builders to
claim tax credits for energy-efficient new construction. In the
commercial sector, the legislation creates efficiency standards that
affect energy use in a number of commercial applications. It also
includes investment tax credits for solar technologies, fuel cells, and
microturbines. These policies are expected to help reduce energy use
for space conditioning and lighting in both sectors.
The AEO2006 is not meant to be an exact prediction of the future
but represents a likely energy future, 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 weather, 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 complete AEO2006, which EIA is releasing this week,
includes a large number of alternative cases intended to examine these
uncertainties. The following discussion summarizes the highlights from
the AEO2006 reference case for the major categories of U.S. energy
prices, demand, and supply and also includes the results of some
U.S. ENERGY OUTLOOK
EIA has reassessed its long-term outlook on energy prices for the
AEO2006 reference case (Figure 1*), including much higher world oil
prices than in recent AEOs. World oil markets have been extremely
volatile for the past several years, and the reference case oil price
path in recent AEOs did not fully reflect the causes of that volatility
and their implications for future oil prices. In the AEO2006 reference
case, world oil supplies are assumed to be tighter, as the combined
productive capacity of the members of the Organization of the Petroleum
Exporting Countries (OPEC) does not increase as much as previously
*All figures have been retained in committee files.
In the AEO2006, world crude oil prices, which are now expressed by
EIA in terms of the average price of imported low-sulfur crude oil to
U.S. refiners, are projected to fall from current levels to about $47
per barrel in (2004 dollars) in 2014, then rise to $54 per barrel in
2025 and $57 per barrel in 2030. The projected price in 2025 is about
$21 per barrel higher than projected in last year's reference case
Geopolitical trends, the adequacy of investment and the
availability of crude oil resources and the degree of access to them,
are all inherently uncertain. To evaluate the implications of
uncertainty about world crude oil prices, the AEO2006 includes two
other price cases, a high price case and a low price case, based on
alternative world crude oil price paths. The cases are designed to
address the uncertainty about the market behavior of OPEC. Although the
price cases reflect alternative long term trends, they are not designed
to reflect short-term, year-to-year volatility in world oil markets,
nor are they intended to span the full range of possible outcomes. In
the low price case, world crude oil prices are projected to decline
gradually to $34 per barrel (2004 dollars) through 2020 and then remain
at that level through 2030. In the high price case, oil prices grow
throughout the projection horizon, reaching more than $96 per barrel
(2004 dollars) in 2030.
In the AEO2006 reference case, average wellhead prices for natural
gas in the United States decline from $5.49 per thousand cubic feet
(2004 dollars) in 2004 to $4.46 per thousand cubic feet in 2016 as the
availability of new import sources and increased drilling expand
available supply. After 2016, wellhead prices are projected to increase
gradually, reaching $5.92 per thousand cubic feet in 2030. Growth in
liquefied natural gas (LNG) imports, Alaskan production, and lower-48
production from unconventional sources are not expected to increase
sufficiently to offset the impacts of resource depletion and increased
demand in the lower-48 States. Projections of wellhead prices in the
low and high price cases reflect alternative assumptions about the cost
and availability of natural gas, including imports of LNG. In the low
price case, the average wellhead price is projected to decline more
rapidly through 2015 than in the reference case, then increases more
slowly to 2030, reaching $4.97 per thousand cubic feet (2004 dollars).
In the high price case, the pattern is reversed, and the projected
wellhead price reaches $7.71 per thousand cubic feet in 2030.
In the AEO2006, continued increases in coal production, including
an increase in relatively high-cost eastern coal, result in a gradual
increase in the average minemouth price from $20.07 per ton (2004
dollars) in 2004 to $22.23 per ton in 2010. After 2010, the price
declines gradually to $20.20 in 2020, as the average utilization of
mining capacity and the production share of higher-cost Central
Appalachian coal decline. Between 2020 and 2030, prices are projected
to increase as rising natural gas prices and the need for baseload
generating capacity lead to the construction of many new coal-fired
generating plants. The substantial investment in new mining capacity
during this period, combined with low productivity growth and rising
utilization of mining capacity, lead to a recovery in the average
minemouth coal price to $21.73 per ton (2004 dollars) in 2030, just
under the 2010 average.
Average delivered electricity prices are projected to decline from
7.6 cents per kilowatt-hour (2004 dollars) in 2004 to a low of 7.1
cents per kilowatt-hour in 2015 as a result of an increasingly
competitive generation market and a decline in natural gas prices.
After 2015, average real electricity prices are projected to increase,
reaching 7.5 cents per kilowatt-hour in 2030.
Total energy consumption is projected to grow at about one-third
the rate (1.1 percent per year) of gross domestic product (GDP), with
the strongest growth in energy consumption for electricity generation
and transportation and commercial uses. Transportation energy demand is
expected to increase from 27.8 quadrillion British thermal units (Btu)
in 2004 to 39.7 quadrillion Btu in 2030, an average growth rate of 1.4
percent per year (Figure 3). Most of the growth in demand between 2004
and 2030 occurs in light-duty vehicles (57 percent of total growth),
followed by heavy truck travel (24 percent of growth) and air travel
(11 percent of growth). Delivered commercial energy consumption is
projected to grow at a more rapid average annual rate of 1.6 percent
between 2004 and 2030, reaching 12.4 quadrillion Btu in 2030,
consistent with growth in commercial floorspace. The most rapid
increase in commercial energy demand is projected for electricity used
for office equipment, computers, telecommunications, and miscellaneous
Delivered industrial energy consumption is projected in the AEO2006
to reach 32.2 quadrillion Btu in 2030, growing at an average rate of
0.9 percent per year between 2004 and 2030, as efficiency improvements
in the use of energy only partially offset the impact of growth in
manufacturing output. Delivered residential energy consumption is
projected to grow from 11.4 quadrillion Btu in 2004 to 14.0 quadrillion
Btu in 2030, an average rate of 0.8 percent per year. This growth is
consistent with population growth and household formation. The most
rapid growth in residential energy demand is projected to be in the
demand for electricity used to power computers, electronic equipment,
and small appliances.
The reference case includes the effects of several policies aimed
at increasing energy efficiency in both end-use technologies and supply
technologies, including minimum efficiency standards and voluntary
energy savings programs. However, the impact of efficiency improvement
on energy consumption could differ from what is shown in the reference
case, as illustrated in Figure 4 which compares energy consumption in
three cases. The 2005 technology case assumes no improvement in the
efficiency of available equipment beyond that available in 2005. By
2030, 8 percent more energy (10.3 quadrillion Btu) is required than in
the reference case. The high technology case assumes that the most
energy-efficient technologies are available earlier with lower costs
and higher efficiencies. By 2030, total energy consumption is 8.2
quadrillion Btu, or 6 percent, lower in the high technology case when
compared with the reference case.
Total petroleum demand is projected to grow at an average annual
rate of 1.1 percent in the AEO2006 reference case forecast, from 20.8
million barrels per day in 2004 to 27.6 million barrels per day in 2030
(Figure 5) led by growth in transportation uses, which account for 66
percent of total petroleum demand in 2004, increasing to 72 percent in
2030. Improvements in the efficiency of vehicles, planes, and ships are
more than offset by growth in travel. In the low and high price cases,
petroleum demand in 2030 ranges from 29.6 to 25.2 million barrels per
Total demand for natural gas is projected to increase at an average
annual rate of 1.2 percent from 2004 to 2020, then remain relatively
flat through 2030. With continued growth in natural gas prices in the
latter half of the projection, natural gas is expected to lose market
share to coal in the electric power sector. Natural gas use in the
power sector is projected to decline by 14 percent between 2020 and
Total coal consumption is projected to increase from 1,104 million
short tons in 2004 to 1,784 million short tons in 2030, growing by 1.9
percent per year. About 92 percent of the coal is currently used for
electricity generation. Coal remains the primary fuel for electricity
generation and its share of generation (including end-use sector
generation) is expected to increase from about 50 percent in 2004 to 57
percent in 2030. Total coal consumption in the electric power sector is
projected to increase by an average of 1.5 percent per year, from 1,015
million short tons in 2004 to 1,502 million short tons in 2030. Another
fast growing market for coal is expected in coal-to-liquids (CTL)
plants. These plants convert coal to synthetic gas and create clean
diesel fuel, while producing surplus electricity as a byproduct. In the
reference case, coal use in CTL plants is projected to reach 190
million short tons by 2030, or 11 percent of the total coal use. In the
high price case, coal used in CTL plants is projected to reach 420
million short tons. In the low price case, however, the plants are not
expected to be economical within the 2030 time frame.
Total electricity consumption, including both purchases from
electric power producers and on-site generation, is projected to grow
from 3,729 billion kilowatt-hours in 2004 to 5,619 billion kilowatt-
hours in 2030, increasing at an average rate of 1.6 percent per year.
The most rapid growth (2.2 percent per year) occurs in the commercial
sector, as building floorspace is expanded to accommodate growing
service industries. Growing use of electricity for computers, office
equipment, and small electrical appliances is partially offset in the
AEO2006 forecast by improved efficiency. EPACT2005 sets residential
efficiency standards for torchiere lamps, dehumidifiers, and ceiling
fans and creates tax credits for energy-efficient furnaces, water
heaters, and air conditioners. It also allows home builders to claim
tax credits for energy-efficient new construction. In the commercial
sector, the law creates efficiency standards that affect energy use in
a number of commercial applications.
Total marketed renewable fuel consumption, including ethanol for
gasoline blending, is projected to grow by 2.0 percent per year in the
reference case, from 6.0 quadrillion Btu in 2004 to 10.0 quadrillion
Btu in 2030, largely as a result of State mandates for renewable
electricity generation and the effect of production tax credits. About
60 percent of the projected demand for renewables in 2030 is for grid-
related electricity generation (including combined heat and power), and
the rest is for dispersed heating and cooling, industrial uses, and
Energy intensity, as measured by primary energy use per dollar of
GDP (2000 dollars), is projected to decline at an average annual rate
of 1.8 percent, with efficiency gains and structural shifts in the
economy offsetting growth in demand for energy services (Figure 6). The
projected rate of energy intensity decline in the AEO2006 approximately
matches the decline rate between 1992 and 2004 (1.9 percent per year).
Energy-intensive industries' share in overall industrial output is
projected to fall at an average rate of 0.8 percent per year, a slower
decline rate than the 1.3 percent per year experienced from 1992 to
Historically, energy use per person has varied over time with the
level of economic growth, weather conditions, and energy prices, among
many other factors. During the late 1970s and early 1980s, energy
consumption per capita fell in response to high energy prices and weak
economic growth. Starting in the late 1980s and lasting through the
mid-1990s, energy consumption per capita increased with declining
energy prices and strong economic growth. Per capita energy use is
projected to increase by an average of 0.3 percent per year between
2004 and 2030 in the AEO2006 reference case, with relatively high
energy prices moderating the demand for energy services and promoting
interest in efficiency improvements in buildings, transportation, and
Energy Production and Imports
Total energy consumption is expected to increase more rapidly than
domestic energy supply through 2030. As a result, net imports of energy
are projected to meet a growing share of energy demand.
Petroleum. Projected U.S. crude oil production increases from 5.4
million barrels per day in 2004 to a peak of 5.9 million barrels per
day in 2014 as a result of increased production offshore, predominantly
in the deep waters of the Gulf of Mexico. Beginning in 2015, U.S. crude
oil production is expected to decline, falling to 4.6 million barrels
per day in 2030. Total domestic petroleum supply (crude oil, natural
gas plant liquids, refinery processing gains, and other refinery
inputs), increases from 8.6 million barrels per day in 2004 to a peak
of 10.5 million barrels per day in 2021, then remains at about that
level through 2030. Production from coal liquefaction compensates for a
decline in crude oil production in the latter half of the projection
In 2030, net petroleum imports, including both crude oil and
refined products on the basis of barrels per day, are expected to
account for 62 percent of demand in the reference case, up from 58
percent in 2004 (Figure 7). Under alternative oil price projections,
the 2030 import fraction ranges from 68 in the low price case to 53
percent in the high price case. Figure 8 compares the impact of the
AEO2006 reference, high price, and low price cases on U.S. oil
production, consumption, and imports.
In the U.S. energy markets, the transportation sector consumes
about two-thirds of all petroleum products and the industrial sector
about one-quarter. The remaining 10 percent is divided among the
residential, commercial, and electric power sectors. With limited
opportunities for fuel switching in the transportation and industrial
sectors, large price-induced changes in U.S. petroleum consumption are
unlikely, unless changes in petroleum prices are very large or there
are significant changes in the efficiencies of petroleum-using
Higher crude oil prices spur greater exploration and development of
domestic oil supplies, reduce demand for petroleum, and slow the growth
of oil imports in the high price case compared to the reference case.
Total domestic petroleum supply in 2030 is projected to be 1.5 million
barrels per day (15 percent) higher in the high price case than in the
reference case. Production in the high case includes 1.9 million
barrels per day in 2030 of synthetic petroleum fuel produced from coal
and natural gas, compared to 0.8 million barrels per day in the
reference case (Figure 9). Total net imports in 2030, including crude
oil and refined products, are reduced from 17.2 million barrels per day
in the reference case to 13.3 million barrels per day in the high price
Natural Gas. Domestic dry natural gas production is projected to
increase from 18.5 trillion cubic feet in 2004 to 21.6 trillion cubic
feet in 2019, before declining to 20.8 trillion cubic feet in 2030 in
the AEO2006 reference case (Figure 10). Lower-48 offshore production is
projected to fall slightly from the 2004 level of 4.3 trillion cubic
feet and then grow steadily through 2015, peaking at 5.1 trillion cubic
feet as new resources come on line in the Gulf of Mexico. After 2015,
lower-48 offshore production declines to 4.0 trillion cubic feet in
2030. Unconventional natural gas production is projected to grow from
7.5 trillion cubic feet in 2004 to 9.5 trillion cubic feet in 2030.
With completion of an Alaskan natural gas pipeline in 2015, total
Alaskan production is projected to increase from 0.4 trillion cubic
feet in 2004 to 2.2 trillion cubic feet in 2018 and to remain at about
that level through 2030.
Net pipeline imports are expected to decline from 2004 levels of
2.8 trillion cubic feet to about 1.2 trillion cubic feet by 2030 due to
resource depletion and growing domestic demand in Canada. The AEO2006
reflects an expectation that growth in Canada's unconventional natural
gas production, primarily from coal seams, will not be adequate to
offset a decline in conventional production.
To meet a projected demand increase of 4.5 trillion cubic feet from
2004 to 2030 and to offset an estimated 1.6 trillion cubic feet
reduction in pipeline imports, the United States is expected to depend
increasingly on imports of LNG. LNG imports in the AEO2006 reference
case are projected to increase from 0.6 trillion cubic feet in 2004 to
4.4 trillion cubic feet 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. LNG imports in 2030 in the high price case, where expected
natural gas demand is lower, are projected at 1.9 trillion cubic feet,
less than half of the 4.4 trillion cubic feet projected in the
One area of uncertainty examined through sensitivity cases regards
the rate of technological progress and its affect on future natural gas
supply and prices. Technological progress affects natural gas
production by reducing production costs and expanding the economically
recoverable natural gas resource base. In the slow oil and gas
technology case, advances in exploration and production technologies
are assumed to be 50 percent slower than those assumed in the reference
case, which are based on historical rates. As a result, domestic
natural gas development costs are higher, production is lower, wellhead
prices are higher at $6.36 per thousand cubic feet in 2030 (compared to
$5.92 in the reference case) (2004 dollars), natural gas consumption is
reduced, and LNG imports are higher than in the reference case. In
2030, natural gas production is 18.8 trillion cubic feet (10 percent
lower than in the reference case), net natural gas imports are 6.4
trillion cubic feet (14 percent higher), and domestic natural gas
consumption is 25.6 trillion cubic feet (5 percent lower). Conversely,
the rapid technology case assumes 50 percent faster improvement in
technology. In that case, natural gas production in 2030 is 24.4
trillion cubic feet (17 percent higher than in the reference case), net
natural gas imports are 4.5 trillion cubic feet (20 percent lower),
domestic natural gas consumption is 29.4 trillion cubic feet (9 percent
higher), and the average wellhead price is $5.20 per thousand cubic
Coal. As domestic coal demand grows in the AEO2006 forecast, U.S.
coal production is projected to increase at an average rate of 1.6
percent per year, from 1,125 million short tons in 2004 to 1,703
million short tons in 2030. Production from mines west of the
Mississippi River is expected to provide the largest share of the
incremental coal production. In 2030, nearly two-thirds of coal
production is projected to originate from the western States (Figure
In the AEO2006 reference case, total electricity generation
increases by 50 percent between 2004 and 2030, growing at an average
rate of 1.6 percent per year. Coal is projected to supply about 70
percent of the increase in electricity generation (including generation
in the end-use sectors) from 2004 to 2030. Generation from coal is
projected to grow from about 1,970 billion kilowatt-hours in 2004 to
3,380 billion kilowatt-hours in 2030 in the reference case. In 2030
coal is projected to meet 57 percent of generation, up from 50 percent
in 2004 (Figure 12). Between 2004 and 2030, AEO2006 projects that 174
gigawatts of new coal-fired generating capacity will be constructed,
including 19 gigawatts at coal-to-liquids plants.
Generation from natural gas is projected to increase from about 700
billion kilowatt-hours in 2004 to 1,102 billion kilowatt-hours in 2020,
but decline by 10 percent between 2020 and 2030 in the face of growing
natural gas prices and the availability of a new generation of coal
plants. The natural gas share of electricity generation is projected to
decline from 18 percent in 2004 to 17 percent in 2030.
The use of renewable technologies for electricity generation is
projected to grow, stimulated by improved technology, higher fossil
fuel prices, and extended tax credits in EPACT2005 and in State
renewable energy programs (renewable portfolio standards, mandates, and
goals). The expected impacts of State renewable portfolio standards,
which specify a minimum share of generation or sales from renewable
sources, are included in the projections. The AEO2006 reference case
also includes the extension and expansion of the Federal tax credit for
renewable generation through December 31, 2007, as enacted in
EPACT2005. Total renewable generation in the AEO2006 reference case,
including hydroelectric power and renewables-fueled combined heat and
power generation, is projected to grow by 1.7 percent per year, from
358 billion kilowatt-hours in 2004 to 559 billion kilowatt-hours in
2030. The renewable share of electricity generation is projected to
remain at about 9 percent of total generation from 2004 to 2030.
Nuclear generating capacity in the AEO2006 is projected to increase
from about 100 gigawatts (about 10 percent of total U.S. generating
capacity) in 2004 to 109 gigawatts in 2019 and to remain at that level
through 2030. The total projected increase in nuclear capacity between
2004 and 2030 includes 3 gigawatts expected to come from uprates of
existing plants that continue operating and 6 gigawatts of capacity at
newly constructed power plants, stimulated by the provisions in
EPACT2005. The new nuclear plants are expected to begin operation
between 2014 and 2020. Total nuclear generation is projected to grow
from 789 billion kilowatt-hours in 2004 to 871 billion kilowatt-hours
in 2030 in the AEO2006. The share of electricity generated from nuclear
is projected to decline from 20 percent in 2004 to 15 percent in 2030.
The AEO2006 reference case assumptions for the cost and performance
characteristics of new nuclear technologies are based on cost estimates
by government and industry analysts, allowing for uncertainties about
new, unproven designs. Two advanced nuclear cost cases analyze the
sensitivity of the projections to lower costs for new nuclear power
plants. The advanced nuclear cost case assumes capital and operating
costs 20 percent below the reference case in 2030, reflecting a 31-
percent reduction in overnight capital costs from 2006 to 2030. The
vendor estimate case assumes reductions relative to the reference case
of 18 percent initially and 44 percent by 2030. These costs are
consistent with estimates from British Nuclear Fuels Limited for the
manufacture of its AP 1000 advanced pressurized-water reactor. Cost and
performance characteristics for all other technologies are assumed to
be the same as those in the reference case.
Projected nuclear generating costs in the advanced nuclear cost
cases are competitive with the generating costs projected for new coal-
and natural-gas-fired units toward the end of the projection period. In
the advanced nuclear cost case, 34 gigawatts of new nuclear capacity
are added by 2030, while the greater cost reductions in the vendor
estimates case bring on 77 gigawatts by 2030 (Figure 13). The
additional nuclear capacity displaces primarily new coal capacity.
The Clean Air Interstate Rule and the Clean Air Mercury Rule,
issued by the U.S. Environmental Protection Agency in March 2005, are
expected to result in large reductions of emissions from power plants.
In the AEO2006 reference case, projected emissions of sulfur dioxide
from electric power plants in 2030 are 66 percent lower than the 2004
level, emissions of nitrogen oxide are 42 percent lower, and emissions
of mercury are 71 percent lower.
Energy-Related Carbon Dioxide Emissions
Carbon dioxide emissions from energy use are projected to increase
from 5,900 million metric tons in 2004 to 8,114 million metric tons in
2030 in the AEO2006, an average annual increase of 1.2 percent (Figure
14). The energy-related carbon dioxide emissions intensity of the U.S.
economy is projected to fall from 550 metric tons per million dollars
of GDP in 2004 to 351 metric tons per million dollars of GDP in 2030,
an average decline of 1.5 percent per year. Projected increases in
carbon dioxide emissions primarily result from a continued reliance on
coal for electricity generation and on petroleum fuels in the
Continuing economic growth in the United States is expected to
stimulate more energy demand, with fossil fuels remaining the dominant
source of energy. The U.S. dependence on foreign sources of oil is
expected to continue increasing. Petroleum imports that accounted for
58 percent of total U.S. petroleum demand in 2004 are expected to
account for 62 percent of total demand by 2030 in our reference case,
with most of the increase resulting from increased consumption for
Furthermore, although natural gas production in the United States
is expected to increase, natural gas imports, particularly LNG, are
expected to grow rapidly. Total net LNG imports in the United States
and the Bahamas are projected to increase from 0.6 trillion cubic feet
in 2004 to 4.4 trillion cubic feet in 2030 in our reference case. In
the United States, reliance on domestic natural gas supply to meet
demand is projected to fall from 83 percent in 2004 to 78 percent in
2030. The growing dependence on imports in the United States occurs
despite efficiency improvements in both the consumption and the
production of natural gas.
This concludes my testimony, Mr. Chairman and members of the
Committee. I will be happy to answer any questions you may have.
The Chairman. Thank you very much.
I might say to the Senators, since there are so many here,
I am sure that that indicates a genuine interest in inquiring.
So I want to just be very brief and then, if you do not mind,
Senator Craig, I might even, if you can be here a while--you
Senator Craig. I have to leave here at 3:30.
The Chairman. Okay. Can one of the two Senators here be
here for a while this afternoon?
Senator Murkowski. Yes.
The Chairman. Then I would leave for a little bit and you
can take over, and then Senator Bingaman and the Democrats can
stay as long as they like, and I can return.
I just have two questions I want to be sure that I
understand. In 2005 you predicted the price of oil 25 years
down the line or whatever--what is your number, 25 years?
Mr. Caruso. In 2005 our final year was 2025, and the
outyear price was about $36.
The Chairman. So how far off were you then?
Mr. Caruso. Well, we have reassessed that outlook and we
now think that a more plausible reference case outlook is about
$20 more than what we were saying a year ago. So for 2025 it is
actually about $54 compared with $33 that we were saying last
The Chairman. Tell me again, because I am not
understanding. When you last gave us an assessment, you told us
25 years from now the price of oil is going to be what?
Mr. Caruso. Our reference case was the expectation prices
would go back down to roughly $30, $33 to be precise, in 2025.
The Chairman. Now you are giving us----
Mr. Caruso. Now what we are saying is, having looked at
what investment plans are--not only OPEC, but non-OPEC
countries--and issues with respect to accessibility to the
resource base and higher cost of doing business in the
commodities boom that we have witnessed, we now believe that a
more plausible reference case is on average about $50. But
recognizing the uncertainty that you mentioned, we also have a
low price case of $33 and a high price case of $97. So we hope
that those three cases would encompass the range of most
possibilities over the next 20, 25 years.
The Chairman. Well, I would hope so, too. Because,
obviously, if that is the range, for anybody who has to base
their business judgments on that, it is not very helpful.
In any event, let me boil it down to less years. Do you
give some estimate of what the price might be next year or the
year after, close term?
Mr. Caruso. Sure.
The Chairman. Is the price going up or down in the next 2
or 3 years?
Mr. Caruso. We are looking at, in the next 2 years, $60 to
$65 as a range in our Short-Term Energy Outlook. However, we do
think as you look out 3 to 5 years that the investments that
are now underway will bear fruit, and that the productive
capacity growth in the country, in the world, will allow some
downward pressure on prices over the next, I would say, 3 to 5
The Chairman. So even with the world situation being what
it is, which you must take into consideration, you are not, as
our expert here, predicting a dramatic increase in the price of
oil over the next 2, 3, 4, 5 years? Is that a fair statement?
Mr. Caruso. That is correct, in a non-disrupted market.
The Chairman. Now, let us move to the domestic. You have
something to say about the non-imported oil, both as to--you
talked about how much we are going to produce ourselves; is our
production going up or down short-term and long-term?
Mr. Caruso. In the short term it is going up. We anticipate
the deepwater projects in the Gulf of Mexico between 2006 and
about 2012 will actually see an increase, a small increase, but
nevertheless, not a decline, which we have seen now for the
last 2 decades. However, beginning about the middle of the next
decade it will resume its decline, and therefore we anticipate
that net oil import dependence will increase over the longer
The Chairman. I was not going to take time, but I think I
will go to natural gas and do the same thing. Tell us what is
going to happen with natural gas today, natural gas 25 years
from now, and then natural gas short-term?
Mr. Caruso. On prices, we think natural gas prices will
stay high for the near term, which is probably through 2007 and
possibly into 2008. However, beginning in 2008 we do think a
significant amount of new LNG projects will be onstream, the
regasification projects here, and the liquefaction in Qatar and
elsewhere. So we think that prices will start to come down for
natural gas in the latter part of this decade. We have it
coming down under $5 by 2014, 2015, and then increasing again,
as I mentioned, to about $6 by 2030, in 2004 dollars.
On supply, we do think that there is room for growth in
domestic gas production, but not nearly enough to meet demand
growth. So we have small growth over the next decade or so from
unconventional sources, primarily tight sands in the Rocky
Mountains, shale gas, and coalbed methane, and the expectation
that the Alaska gas line will be onstream beginning in 2015 at
about 4.5 Bcf a day.
All of that we think will contribute to a better supply
situation. In the long run, we will have to rely on LNG. We are
projecting LNG imports to exceed 4 trillion cubic feet in the
2020 to 2030 timeframe, up from only about .6 trillion cubic
feet in 2004.
The Chairman. One last question. You mentioned natural gas
from shale; if you assume that can work, is there anything
different about assuming that it would work for the production
Mr. Caruso. Yes. Oil technology as we know it today--and
there are companies, as you know, that are possibly on the
verge of making some significant breakthroughs, but as we know
it today, shale oil in our model is not competitive, it cannot
be produced at less than about $70 a barrel.
The Chairman. Thank you very much.
Senator Bingaman. Let me ask a couple of basic questions.
You have a chart in here, it is figure 3, energy consumption by
fuel. No, let me go instead to figure 6, total energy
production and consumption. This is in the forward or the
overview at the beginning of your report. Now, the way I read
that chart, between 2004 and 2030 you are expecting the gap
between consumption and production in the country to widen, so
that we will become more dependent on foreign sources.
Mr. Caruso. That is correct.
Senator Bingaman. Now, the President said in his State of
the Union speech that he was setting as a goal that we would
reduce our imports of oil from the Middle East--I believe I am
correct--by 75 percent by 2025. Do you have any chart in here
that talks about what you project to be our imports of oil from
the Middle East or generally by that time?
Mr. Caruso. Not in the main report, but we do have some
supplemental tables, which are released on the website. I am
trying to think. Our expectations of imports from the Persian
Gulf region in 2025 are about 3.3 million barrels a day.
Senator Bingaman. How does that compare to today?
Mr. Caruso. Today they are about 2.3.
Senator Bingaman. So you expect that the imports from the
Middle East will go up fairly significantly between now and
Mr. Caruso. Under these assumptions, yes, that is correct,
Senator Bingaman. Compared with last year's outlook, that is a
significant reduction. We were saying about 6 million barrels a
day from the gulf in 2025 in the outlook that we released 1
Senator Bingaman. And what has caused you to change that
outlook so dramatically as far as imports from the Middle East?
Mr. Caruso. I think two main things. One is that our total
consumption of petroleum projected for 2025 is about a million
and a half barrels a day, maybe even two million barrels a day
lower, and we do have an increase in domestic supply, both
conventional as well as, as I mentioned, coal-to-liquids. The
big picture is that the net import number is lower by about 3
million barrels a day and, by virtue of the fact that the
Middle East is the marginal supplier, with all of non-OPEC
producing at full capacity, almost all of the decline comes out
of our expectations from the Persian Gulf region.
Senator Bingaman. Let me refer you to the chart that you
have up here, the capacity additions by year and fuel. I
understood you to say that you expect the production or the
capacity from nuclear to go from 100, which it is now, 100
gigawatts roughly, up to 109 by 2030?
Mr. Caruso. That is correct, yes.
Senator Bingaman. On that chart, as I understand it, the
yellow is supposed to represent the addition of nuclear
Mr. Caruso. That is correct.
Senator Bingaman. Now, I notice, when I have tried to read
it here, unless my eyesight is failing me, you do not have any
additional nuclear capacity being added after about the year
2017 for the next 12 years or 13 years after that. Why is that
stalling out, in your view?
Senator Domenici has been a big champion of the nuclear
industry and I have certainly supported trying to expand their
capacity. But you are estimating that--this is taking into
account what we did in last year's energy bill. But, regardless
of that, as I see it, you are saying there is going to be a 9
percent increase in the amount of electricity produced from
nuclear power in the next 25 years. That is not a big increase.
Mr. Caruso. Just to clarify, going from 100 gigawatts
capacity to 109 gigawatts capacity is comprised of 6 gigawatts
directly related to the provisions of EPAct 2005 and the
production tax credits, which, as I understand it, expire or
these new nuclear plants have to come onstream by 2019, I
believe. So that is why we have the increases you do see before
Senator Bingaman. So you assume when those expire there is
not going to be any more construction of nuclear capacity?
Mr. Caruso. Under the assumptions we have right now, coal
gets--as you can see from that chart, the blue areas--the
lion's share of the new capacity after 2020.
Senator Bingaman. So you are basically assuming--or your
conclusion is that absent those tax incentives that we put in
last year's bill, coal is a much more economic way to produce
electricity in the future than is nuclear?
Mr. Caruso. Yes, sir.
Senator Bingaman. Is that fair?
Mr. Caruso. That is absolutely correct, and the other 3
gigawatts through the nuclear is through up-rates of the
Now, in our outlook, which we released this week, we run
two alternative cases, advanced nuclear technology and vendor
cost estimates. In those cases, which assume much lower capital
costs for new nuclear plants, that 6 gigawatts of new capacity
goes up to 34 gigawatts in one case and 77 in the case where
the vendors' cost estimates are accurate. Vendors of nuclear
plants have much lower cost estimates than we believe are
plausible, but in order to, I think----
Senator Bingaman. So what you are saying is that there is
another estimate, that you just do not think is a valid
estimate of the cost of doing additional nuclear capacity?
Mr. Caruso. Yes, Senator.
Senator Bingaman. I think my time is up. Thank you very
Senator Murkowski [presiding]. Go ahead, please.
Senator Craig. I think Senator Akaka was here before me.
Senator Murkowski. Senator Akaka.
STATEMENT OF HON. DANIEL K. AKAKA, U.S. SENATOR
Senator Akaka. Thank you very much, Mr. Chairman.
Welcome, Mr. Caruso. Good to have you here, and I want to
thank you for the Energy Information Administration's outlook
report of 2006 and sharing with us your research analysis that
will be useful tools for us in our decisionmaking here.
As you know, Hawaii's energy situation is unique because we
rely almost 100 percent on oil for our generation of
electricity and gasoline, and almost all of our energy needs,
of course, are imported. So we have to face that. Last year you
testified before this committee that ultimately gas hydrates
should be a large supply of natural gas. At the same time, you
expressed some pessimism regarding the development of the
Along with my colleague, Senator Murkowski, I believe that
gas hydrates are a potentially invaluable resource. My question
to you is, did you include gas hydrate reserves in your
calculations regarding domestic supplies of natural gas?
Mr. Caruso. No, Senator Akaka. The gas hydrates technology
remains unproven and too expensive, in our view, to be a
significant supplier of natural gas in the timeframe that we
are looking at here, which is 2030.
Senator Akaka. Just to be specific, this is part of what we
know as methane, methane hydrates.
Mr. Caruso. Yes.
Senator Akaka. And I know the technology is not here and it
is down a few years before we can get to it. Yet, as you said,
we have a huge supply of that.
According to your Annual Energy Outlook, there will be a
growth in the use of coal--and the graph here shows that very
clearly--and coal for electricity production. Particularly,
again, what impact do you think this trend will have on the
cost of electricity in the State of Hawaii, where virtually all
electricity, as I pointed out, comes from oil-fired plants?
Mr. Caruso. I think, as you point out, since I think more
than 80 percent of your electricity is oil-fired steam
turbines, we do not anticipate that the developments of coal
use increasing elsewhere will have much of an impact on Hawaii.
But if, for example, the utilities there were to replace the
oil-fired plants with new coal-fired plants, we think, in our
model, that the average cost of producing that electricity
would go down. However, there is so much investment already in
the oil-fired plants, of course, there would be a huge capital
cost to those utilities.
So the marginal cost of producing the electricity from coal
would be lower, but it would require substantial new
investments to replace those existing plants. So we do not
anticipate in our outlook that that investment decision will be
Senator Akaka. Your calculations, as you said, show that
there would be a savings in using coal. But let me ask you
another part of that, and you alluded to this, that there may
be other costs, like shipping of coal to Hawaii. We will have
to import it. Do you think this might offset any savings?
Mr. Caruso. Yes, in fact I think that is why we are not
assuming any of those investment decisions to be made, because
the infrastructure of providing receiving facilities for the
coal and new electric power generation units, because of the
reasons you just said--the large, up-front, new infrastructure
investment that would be needed.
Senator Akaka. Thank you for your responses. My time has
expired. Thank you, Mr. Chairman.
STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR
Senator Murkowski. Thank you, and I appreciate you, Senator
Akaka, bringing up our gas hydrates bill. I think that that is
important, that we try to keep that out in the forefront so
people do not forget the great potential there.
Mr. Caruso, moving from Hawaii to Alaska and the
discussion, your comments about the significance of Alaska's
North Slope natural gas coming online and the projection that
it will be there by 2015. I want to remain optimistic. The
State remains in negotiations for a contract or an agreement to
move forward with that, but as of yet we do not have an
What happens to your forecast, to your projection, if that
Mr. Caruso. All other things being equal, the price of gas
would be higher without, without that project coming onstream
Senator Murkowski. How much cushion do you have? Say we are
behind by a year, what would that do? Would that markedly
affect the price or would it have to be a significant delay
before we would actually see anything reflected in the market?
Mr. Caruso. I think, for whatever time it is that it is
delayed, those years--let us just say instead of 2015 it is
2016. I think that is 1 year of somewhat higher natural gas
prices, just isolating that one factor. It means that there is
4.5 Bcf a day that we have to import as, let us say, Qatar LNG,
and that will be a bit higher.
Senator Murkowski. Let me ask you, in your report you note
the need to bring on additional natural gas imports and you
make mention of the existing LNG facilities that we have, the
expansions of three or four of them, and the new construction
that is coming on line you are anticipating. Given what we will
need, what you anticipate we will need because of imports, and
given what you know of the existing facilities, do we have
enough either on the drawing board or already in existence that
we would be able to accept the LNG that we will need coming in?
Mr. Caruso. As of now, it does look like we have, when you
combine the expansion of three of the four onshore facilities,
the two that are under construction, and those that FERC or the
Coast Guard have already approved, it does look as though the
regasification side of this equation is moving actually faster
than most analysts thought even 1 year ago and, if anything,
now we are a little bit more worried about whether the
liquefaction facilities in places like Nigeria or Qatar will be
on time to meet the demand.
So I would say on the regas side we are in reasonably good
shape, especially since there are facilities in Baja
California, Mexico, to serve southern California, and in the
Maritimes of Canada, which we now think will be built to serve
Senator Murkowski. You mentioned that if, in fact, the
timeline slips on the Alaska natural gas, we have got to figure
out a way to meet that difference for the year until the gas
comes online. But the reality is these contracts that we are
signing, whether it is with Qatar or whomever, for these
additional gas supplies, these are not typically contracts for
1 year, these are longer-term contracts.
Mr. Caruso. That is correct.
Senator Murkowski. This is one of the concerns that I have
from Alaska's perspective. We do not want to get aced out by
signing onto some long-term contracts in order to meet that
short-term differential because we do not have Alaska's gas
coming on. That is something that we are working on.
Let me move to oil. As part of your alternative forecast
scenarios last year, you looked to ANWR with an alternative
forecast that assumes that ANWR is open. You have done that
again in this year's forecast. Can you talk about what opening
up ANWR with the potential of 10 billion barrels of oil, what
it means in terms of your forecast that we have currently
before us now?
Mr. Caruso. Sure. Yes, we would expect that if ANWR were
approved it would take about 10 years to get it online, so 2015
or so, and it would ramp up to about 800,000 barrels a day
after probably 5 to 7 years of ramp-up. That would reduce the
amount of imports barrel-for-barrel. So we think probably
instead of 62 percent import dependency, it would reduce that
to about 60 percent.
In terms of the price impact, our rough estimate is about a
dollar a barrel for every barrel that we consume, and by then,
as I mentioned, we would be consuming about 27 million barrels
a day. So it is consistent with the reports we have done for
this committee and for the House side as well.
Senator Murkowski. Just one last question. Looking at the
chart, in terms of where we are importing our oil currently and
recognizing that we get about 7.3 percent of our oil demand
from Venezuela and Venezuela accounts for a little over 11
percent of our imports, Venezuela is not exactly a comfortable
place right now. In terms of what a disruption coming out of
Venezuela could mean to your forecast--11 percent of our
Nation's imports coming out of Venezuela now--if that were to
be shut off, what would that mean to us?
Mr. Caruso. Well, in the short run, because there is so
little spare productive capacity in the world, unless we were
to offset that with Strategic Petroleum Reserve or some other--
Senator Murkowski. How could we offset that much?
Mr. Caruso [continuing]. It would be substantial. We could
not offset it in terms of relying on spare capacity in the
world because there is only about 1.5 to 2 million barrels a
day spare capacity, and most of that is in Saudi Arabia, and
that is 45 days away. So clearly there would be an immediate
In terms of the Strategic Petroleum Reserve, we could
release that oil, of course. But there is a limit to how much,
how long we would be able to replace the missing barrels. It
would depend on the duration of the disruption. But
nevertheless, we saw in late 2002 and the early part of 2003
how significant the Venezuelan oil was to our refiners. We had
a sharp price runup and a decline in inventories, which we have
only recently recovered from.
Senator Murkowski. Thank you.
I am sure my time is up, even though there is not a light.
Senator Bingaman. Thank you.
Let me ask you, on this chart that you have in here, it is
figure 7, energy production by fuel. Again, it is in the
overview at the beginning of your report or close to the
beginning. I think it is page 8. Now, as I read that chart, it
shows non-hydro renewables as increasing until 2030, so that we
would continue to be adding capacity in non-hydro renewables
each year essentially from now until 2030.
You are also, though, assuming, or at least I believe you
are, that the tax incentives that we put into the law this last
year expire when we said they would expire, which is the end of
Mr. Caruso. That is correct.
Senator Bingaman. So the production tax credit for wind,
the production tax credit for solar, you are assuming that
those production tax credits all expire at the end of next
year. In spite of that, you believe that there will continue to
be additions to capacity for these renewable energy sources.
That is very different than what you have assumed with regard
to nuclear power. In the case of nuclear power, you have said
once the tax incentives go away, we quit building nuclear
power, but in the case of renewables, we do continue to build
Mr. Caruso. The main reason for that difference is there
are 23 States with renewable portfolio standards and they
continue. We assume that they remain in effect. So in those
States we see continued growth in non-hydro renewables.
Senator Bingaman. I see. Now, the way I read your chart
here--again, this one that you have up here on the easel--you
have much more of the total addition to capacity coming from
renewables in the next couple of years, 2006 and 2007, than you
do after that. That, I assume, relates to the fact that we are
eliminating those tax incentives or they are scheduled to
I guess the question is, have you done any calculation as
to what would be the effect on our addition to capacity of
renewable power if we were to extend those tax credits from now
Mr. Caruso. I would have to check on that. We may have done
something for the NCEP.
Senator Bingaman. The NCEP?
Mr. Caruso. We may have done some analysis which assumed
their continuation as part of the analysis we did for you last
Senator Bingaman. Okay.
Mr. Caruso. But I will check on the record for that.
[The information follows:]
Renewable Electricity. [Note, paraphrased question] Has EIA done an
analysis of what would be the effect on our addition to capacity of
renewable power if we were to extend the renewable electricity
production tax credits from now to 2030?
EIA has not conducted an analysis of the impact on renewable
generation capacity of an extension of the production tax credit (PTC)
through 2030. In January 2006, EIA conducted an analysis of an
extension through 2016 of the renewable energy PTC, on behalf of the
Congressional Joint Committee on Taxation. This analysis used the
Annual Energy Outlook 2006 reference case as the baseline, and assumed
the PTC is structured as currently specified, but with eligibility for
facilities entering service by December 31, 2016.
The analysis concludes that an extension of the renewable energy
portions of Section 45 of the tax code would result in significant
growth in renewable generating capacity and generation.
The biggest growth is seen in wind generation with 244 billion
kilowatt-hours in 2016 in the PTC extension case, compared to 56
billion kilowatt-hours in the reference case. Wind capacity has a
fairly short lead-time and relatively low-cost resources are available
in many parts of the country. Biomass generation also grows
substantially, with 63 billion kilowatt-hours in 2016 in the PTC
extension case, compared to 50 billion kilowatt-hours in the reference
case. Although low-cost biomass fuels are widely available, the
technology has longer construction lead-times than wind capacity, and
it also receives half of the credit value as wind. Geothermal
generation increases to 32 billion kilowatt-hours in 2016 in the PTC
extension case, compared to 24 billion kilowatt-hours in the reference
case. Geothermal resources are limited both by geography and by the
rate of exploitability. Landfill gas and hydroelectric generation also
increase slightly with the PTC extension, but the additional resources
that can be economically developed by these technologies are limited.
Growth in solar generation is not affected by extension of the PTC,
because solar technologies are no longer eligible for this tax credit.
Mr. Caruso. The other comment on the early part of the non-
hydro renewables is that we also have in there the renewable
fuel standard that is part of that, in that production, in
figure 7 on page 8.
Senator Bingaman. I see. Okay.
Let me just ask, since you raised the issue of that study
you did last year, that NCEP report, the National Commission on
Energy Policy, you concluded as part of that study that there
would be, I think the phrase you used was no material effect on
the economy from the adoption of the recommendations of that
NCEP; is there anything in this that would contradict that
conclusion, anything in this new report?
Mr. Caruso. Not that I am aware of.
Senator Bingaman. You stick by that conclusion?
Mr. Caruso. Yes, Senator.
Senator Bingaman. You have a section called issues and
focus, and you talk about energy technologies on the horizon
and advanced technologies for light-duty vehicles. Could you
just take a minute to tell me what your conclusions are? I have
not had a chance to read any of that yet, but I am interested
in knowing if there are some new energy technologies or
advanced technologies available for vehicles that would
significantly impact any of these projections.
Mr. Caruso. The answer is that we see a number of new
technologies for light-duty vehicles that can substantially
increase their efficiency. This outlook already has reasonably
good increases in average vehicle efficiency as a result of the
change in the mix with more hybrids and diesels. In addition to
that, with various new technologies which are enumerated in the
report, we do think that that could be increased by at least 10
percent--we have a high technology case in the report, which I
believe is about a 10 percent improvement in the average
vehicle efficiency from a combination of different technologies
with respect to vehicles, which are described in more detail in
Senator Bingaman. Have you done any modeling or had any
requests to do any modeling related to the increased use of
this plug-in technology everyone is--I am reading articles
these days about how the next great advance in reducing fuel
consumption in the transportation sector may come from adoption
of a plug-in technology, so that you have cars with a
substantial battery capacity that can operate off of electric
power for a significant distance.
Have you looked at that or is that anything that you have
the capacity to look at?
Mr. Caruso. We have not done anything in detail with
respect to plug-in hybrids, but certainly we have that
capacity. We have looked, again in conjunction with the
National Commission on Energy Policy report analysis we did for
you, looked at a 36 percent increase in CAFE standards and what
the impact of that would be. So we have done some things, but
they have not been specifically related to plug-in hybrids.
Senator Bingaman [presiding]. Okay. I think, just looking
around the table here, it looks as though we are out of
Senators. I am informed that the record is going to remain open
until the close of business tomorrow and Senators may want to
submit questions to you in writing. If you would be willing to
answer those, we would appreciate it very much.
Mr. Caruso. We definitely would do that.
Senator Bingaman. Thank you for coming today.
[Whereupon, at 3:35 p.m., the hearing was adjourned.]
Responses to Additional Questions
Department of Energy,
Congressional and Intergovernmental Affairs,
Washington, DC, April 11, 2006.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate,
Dear Mr. Chairman: On February 16, 2006, Guy Caruso, Administrator,
Energy Information Administration, testified regarding EIA's Annual
Enclosed are answers to 25 questions that were submitted by
Senators Craig, Thomas, Talent, Akaka, Salazar, and you to complete the
If we can be of further assistance, please have your staff contact
our Congressional Hearing Coordinator, Lillian Owen, at (202) 586-2031.
Jill L. Sigal,
Responses to Questions From Senator Domenici
Question 1. In the EIA ``High Oil Price Case'', oil prices reach
more than $96 (in 2004 dollars) by 2030. What changes between the
Reference Case, which predicts prices will be around $57 in 2030, and
the High Oil Price Case that accounts for this nearly $40 difference?
Answser. Relative to the Reference Case, the High Price Case
assumes that global oil resources are more costly and less abundant and
that OPEC members choose to produce oil at a slower rate.
In particular, the High Price Case assumes that (1) the costs of
finding and developing the remaining world's oil resources are 15%
higher, and (2) the ultimately recoverable reserves are 15% lower than
in the Reference Case. The High Price Case also projects in 2030 that
OPEC members produce only 31.7 million barrels of oil per day, as
opposed to 45.8 million barrels per day in the Reference Case.
Question 2. We have watched oil prices go up on worries about the
Iran nuclear situation and react to kidnappings in Nigeria. These
events are examples of what analysts often talk about as the ``fear
premium'' on oil. What do you think the fear premium number is today?
Answer. Separating expectations on future events that might affect
oil markets from the so-called fundamentals is difficult and imprecise
at best. Further separating them and quantifying a risk portion is
simply an educated guess.
That said, with the spot price of West Texas Intermediate crude oil
at around $61 per barrel as of February 28, EIA estimates that a
``premium'' of 0 to $5 would seem reasonable, based on EIA's analysis
and modeling that suggests a range from the high $50s (West Texas
Intermediate) to the low $60s can be explained by the fundamentals,
notably tight spare upstream capacity. One way to view the ``premium''
is that as it fluctuates constantly, so, too, does the demand for
inventory shift. Since the end of December, those shifts have occurred
not only with changing perceptions on the risk of Iranian disruptions
or worsening Nigerian oil flows, but shifting assessments of recent
OPEC and non-OPEC volume losses (Russia, North Sea, U.S. Gulf of
Mexico, etc.) and their likely duration, weather impacts on Asian and
European crude oil/product demand and stocks, and, especially,
forthcoming U.S. gasoline tightness as spring approaches.
When WTI rose over $68 per barrel in late January, it would not
have been unreasonable to say the risk premium increased to between $5
and $10 per barrel. But with the surge in U.S. gasoline stocks over the
last 4 to 6 weeks, and to a lesser extent, the absence of even a
seasonal draw in distillate fuel, much of the earlier ``fear'' of
winter pressures compounding an already tight outlook for gasoline has
eroded, undercutting margins and crude prices. To some extent, the
immediacy of Iranian pressures has also eroded, but how much of the
corresponding crude drop can be attributed to Iran, how much to
gasoline, and how much to other factors is impossible to know.
Question 3. The lack of world spare oil capacity has been one of
the prime factors for today's high oil prices. World spare capacity now
is at about 1.5 million barrels a day. What do you think we should
expect world spare capacity to be in the next 5, 10, 20 years? Will
spare capacity continue to be one of the prime factors affecting oil
Answer. We expect spare oil production capacity to increase over
the next few years and to reach a level of 3 to 5 million barrels per
day by 2010. After 2010, on average we expect global spare capacity to
remain between 3 and 5 million barrels per day during the projection
period to 2030. Spare oil production capacity will continue to be one
of the prime factors affecting oil prices in the short term, but over
the longer term other factors such as resources and other energy
alternatives are more important.
Question 1. According to the most recent Summary of Weekly
Petroleum Data, total U.S. motor gasoline imports (including both
finished gasoline and gasoline blending components) averaged nearly 1.2
million barrels per day. Given that domestic refinery capacity is
predicted to grow at about 0.5% annually between 2004 and 2030 and
utilization rates are expected to remain around 93% during that time
period (according to EIA Reference Case Table Answer), will the United
States become increasingly dependent on imports of refined products and
how will this effect prices and domestic refineries?
Answer. The EIA projections have always indicated that the U.S. is
likely to become somewhat more dependent on product imports. In
AEO2006, the demand for petroleum products is projected to grow at over
1 percent per year between 2004 and 2030, about twice the rate at which
refinery capacity is expected to grow for the same period. If U.S.
refinery margins (i.e., the difference between crude oil and petroleum
product prices) widen, domestic refinery capacity will expand faster.
Refinery margins are determined in international markets and depend on
many different variables, including refinery capacity, crude quality,
product specification, transportation costs, and fuel costs.
In AEO2006, a significant portion of the growth in product imports
relative to AEO2005 resulted from a projected increase in imports of
natural gas liquids (NGL). Lower projected total domestic natural gas
production in AEO2006 coupled with an assumed decrease in the NGL
content of unconventional sources have resulted in significantly lower
domestic NGL production. The shortfall is compensated for with an
increase in NGL imports.
Finally, AEO2005 also contained assumptions more favorable to the
expansion of domestic refineries than to importing products, including
the assumption that global petroleum product providers would be
reluctant or unable to supply MTBE-free reformulated gasoline and
ultra-low-sulfur diesel at attractive prices.
Question 1. Current natural gas storage is at about 2.4 trillion
cubic feet. Working gas stocks remain 37.8 percent above the 5-year
average and about 23 percent above last year's level. Why do natural
gas prices remain at record levels if our storage rates are strong and
does the 5 year average storage number reflect the increase in demand
we have experienced in gas over the last 5 years? What is the level of
protection that this level of storage provides compared to other years?
Answer. Natural gas prices spot prices have dropped significantly
as extremely mild weather in January and early February led to an
unusually low draw on gas from storage. For example, Henry Hub spot
prices, which exceeded $15 per million Btu in mid-December, declined to
below $7.00 per million Btu on Monday, February 27. Projected winter
heating costs, while still higher than those experienced last winter,
are significantly below our expectations at the beginning of October.
While natural gas prices have fallen sharply, they remain far above
levels typical of the 1990s. One factor working to prevent a return to
much lower prices is the difficulty of increasing supply in North
America, notwithstanding very high levels of drilling activity.
Competition between natural gas and oil products is another factor that
limits opportunities for a sharp fall in natural gas prices. Lastly,
although natural gas in storage has exceeded the 5-year average
throughout the current heating season, withdrawals since the start of
the heating season on November 1 have been limited. There has been an
apparent reluctance by industry to draw down stocks heavily owing to
the economic incentives to retain gas in storage posed by the unusually
large premium of futures contract prices over the Henry Hub spot price,
the concerns about supply availability throughout the winter while
hurricane-related production shut-ins continue, and the uncertain
demand impacts of winter weather. Absent significant withdrawals from
storage, the presence of large volumes in storage does not have a
direct effect on market prices.
The level of working gas stocks in underground storage on November
1 (the start of the heating season) in 2001-2005 exceeded 3,100 billion
cubic feet (Bcf), after averaging 2,948 Bcf during the period 1995-
2000. This additional gas in storage is equivalent to an average of
more than 1 billion cubic feet per day of additional supplies
throughout the 5-month heating season.
Question 1. The AEO 2006 forecast projects that most of the growth
in demand for transportation energy occurs in light duty vehicles (57
percent of total growth). Can you estimate what amount of the projected
growth in demand for fuel for light duty transportation vehicles will
be met by ethanol or other renewable fuels?
Answer. In the United States, transportation ethanol is currently
consumed as a blending component in reformulated gasoline (between 5.7
percent and 10 percent ethanol content), as gasohol (up to 10 percent
ethanol blended with conventional gasoline), or as E85 (up to 85
percent ethanol and the remainder gasoline). Ethanol is used in the
transportation sector almost exclusively as a blending component in
gasoline (99.7 percent of total demand in 2004) and although total
ethanol demand increases more than 350 percent over the projection
period it continues to be used primarily as a blending component in
gasoline (99.6 percent in 2030). Growth in light duty vehicle (cars,
vans, sport utility vehicles, and pickups with a gross vehicle weight
rating less than 8,500 pounds) energy demand increases 6.77 quadrillion
Btu from 2004 to 2030, accounting for 57 percent of the total increase
in transportation energy demand. Ethanol represents all of the
projected increase in transportation renewable fuel use and increases
by 0.72 quadrillion Btu from 2004 to 2030. Light duty vehicles account
for 97 percent of total gasoline demand in the transportation sector
and, assuming that all the projected consumption of ethanol was used by
light duty vehicles, it would account for 11 percent of the total
increase in light duty vehicle energy demand to 2030.
Question 2. In 2030 what proportion of U.S. CO2
emissions will be produced by the transportation sector?
Answer. Between 2004 and 2030, the Annual Energy Outlook 2006
reference case projects that the share of U.S. carbon dioxide emissions
attributable to the transportation sector will grow from 32.9 percent
to 33.7 percent. Carbon dioxide emissions from transportation grow from
1,945 million metric tons in 2004 to 2,734 million metric tons in 2030.
During the same period, U.S. total carbon dioxide emissions are
projected to increase from 5,919 to 8,115 million metric tons.
Question 1. U.S. coal resources represent about a 250 year supply
at current rates of consumption. The AEO 2006 forecast notes that
``Coal remains the primary fuel for electricity generation and its
share of generation (including end-use sector generation) is expected
to increase from about 50 percent in 2004 to 57 percent in 2030.'' The
AEO 2006 report also notes that a ``fast growing market for coal is
expected in coal-to-liquids (CTL) plants.'' The AEO 2006 High Price
Case projects that Coal to Liquids plants could consume 420 million
short tons of coal in 2030. With the large growth in demand for steam
coal and greater use of coal in coal to liquids applications, how long
can we expect our coal reserves to last?
Answer. Based on the Annual Energy Outlook 2006, coal reserves are
projected to last 150 years beyond 2005.
In the AEO2006 reference case, cumulative coal consumption between
2004 and 2030 is expected to be 37 billion short tons. This consumption
represents about 14 percent of the estimated recoverable coal reserves
(268 billion short tons) as of January 1, 2004. If the projections for
coal consumption in the AEO2006 grow through 2030 and then remain at
that level, currently identified coal reserves would last roughly 150
In the high oil price scenario, coal consumption is projected to be
higher than in the AEO2006 reference case. If the high price scenario
is assumed, our coal reserves will last 130 years, rather than 150
There is uncertainty regarding the total amount of coal resource
available and recoverable. The technologies available to extract coal
in the future may allow a larger portion of the demonstrated reserve
base to be recoverable.
Question 2. The AEO 2006 report estimates that ``Between 2004 and
2030 . . . 174 gigawatts of new coal-fired generating capacity will be
constructed, including 19 gigawatts at coal-to-liquids plants.'' How
many new coal-fired generating stations is this if the average size of
the plant is 600 Megawatts?
Answer. In the AEO2006 reference case, 174 gigawatts of coal-fired
plants are projected by 2030. Assuming a plant size of 600 Megawatts,
this is about 290 plants. Of this 174 gigawatts, 19 gigawatts are coal-
to-liquids plants. Again, if these were all 600 Megawatts, this would
be about 32 plants.
Question 3. The AEO 2006 forecast projects CO2 emissions
from energy use will grow from 5.9 billion metric tons in 2004 to 8.1
billion metric tons in 2030 largely due to a continued reliance on coal
for electricity generation and on petroleum fuels in the transportation
sector. What proportion of the growth results from coal fired
generation? Does the AEO 2006 projection take into consideration the
use of carbon capture and sequestration technologies in new coal fired
Answer. In the AEO2006 reference case, carbon dioxide emissions
from coal-fired power plants are projected to increase by 1,031 million
metric tons between 2004 and 2030, representing 48 percent of the
increase in total carbon dioxide emissions of 2,147 million metric
tons. The projections for increased carbon dioxide emissions from coal-
fired power plants include emissions from plants in both the electric
power and industrial sectors. In the industrial sector, electricity
generation at coal-to liquids plants is projected to produce 150
million metric tons of carbon dioxide emissions by 2030.
The AEO2006 model forecast includes the representation of carbon
capture and sequestration technology for advanced coal and natural gas
generating plants. However, in the reference case these technologies
are not projected to be utilized.
Question 1. In your testimony there is a forecast that 6 gigawatts
of electricity from new constructed nuclear plants will come online
thanks to the Energy Policy Act of 2005. The Annual Energy Outlook for
2006 also highlights that carbon dioxide emissions from energy use are
projected to increase from 5.9 billion metric tons in 2004 to 8.1
billion metric tons in 2030, an average annual increase of 1.2 percent.
If the 6 forecasted nuclear plants are not brought online, how does
this affect the amount of carbon dioxide emissions?
Answer. The 6 gigawatts of new nuclear capacity are expected to
generate approximately 47 billion kilowatt-hours of electricity in
2030. If that generation were to instead come from coal plants, an
additional 42 million metric tons of CO2 would be emitted,
an increase of 1.3 percent in power sector CO2 emissions and
0.5 percent in total energy-related CO2 emissions.
Question 1. How have higher energy prices affected the Gross
Domestic Product (GDP) and what might we expect to happen to our
economy over the next 20 years if the trend of energy price increases
Answer. Over the past two years as the price of oil has gone from
$30 per barrel at the end of 2003 to $60 at the end of 2005, GDP may
have been affected negatively by approximately 1 percentage point below
what $30 oil would have yielded. The Annual Energy Outlook (AEO2006)
provides a high oil price scenario which can provide some insights into
the macroeconomic impacts to be expected over the next 20 years. In
this scenario, real GDP is approximately 1.0% lower in the 2010 to 2015
time frame relative to the reference case. However, the impacts of
higher energy prices are not uniform. Some energy-intensive industries,
such as chemicals, may be more vulnerable to the adverse impacts of
rising energy prices. As the economy adjusts to higher prices after
2015, the difference in GDP between the two cases declines.
LOSSES IN REAL GDP WITH THE AEO HIGH PRICE CASE
Loss in 2000
Dollars Percent Loss
2007............................ $22 billion....... 0.2 percent
2010............................ $108 billion...... 0.8 percent
2015............................ $129 billion...... 0.9 percent
2025............................ $23 billion....... 0.1 percent
Responses to Questions From Senator Craig
Question 1. What percentage of energy will be emission-free (i.e.,
no carbon emissions--e.g., nuclear, hydroelectric, wind, geothermal,
solar, etc.) in EIA's current baseline, and what are the percentages of
each emission-free source. How do these assumptions change when each of
the two more optimistic alternatives for lower-priced nuclear energy
Answer. Emission-free sources currently represent 14 percent of
total energy consumption, and ETA's reference case forecast projects
that share to remain stable throughout 2030. In the two cases with more
optimistic costs for new nuclear power, the emission-free share in 2030
increases to 15 percent and 17 percent, respectively, for the Advanced
Nuclear case and Nuclear Vendor case. Nuclear power has the largest
share of the emission-free sources, followed by biomass and hydro.
PERCENT OF TOTAL ENERGY CONSUMPTION FROM SPECIFIC EMISSION-FREE
AEO Advanced Nuclear
Reference Nuclear Vendor
case case case
Nuclear............................. 6.8% 8.4% 10.9%
Hydro............................... 2.3% 2.3% 2.2%
Geothermal.......................... 1.1% 1.1% 0.9%
Municipal Solid Waste............... 0.3% 0.3% 0.3%
Biomass/Wood........................ 2.5% 2.5% 2.4%
Wind................................ 0.5% 0.5% 0.5%
Alternatively, if only electricity generation in the power sector
is considered, emission-free sources currently represent 29 percent of
total generation, and EIA's reference case forecast projects that share
to drop to 24 percent by 2030. In the two cases with more optimistic
costs for new nuclear power, the emission-free share in 2030 increases
to 28 percent and 33 percent, respectively, for the Advanced Nuclear
case and the Nuclear Vendor case. Again, nuclear power has the largest
share of the emission-free sources, followed by hydro. Biomass is not
as much of a contributor in this case, as it is used primarily in
PERCENT OF TOTAL ELECTRICITY GENERATION FROM SPECIFIC EMISSION-FREE
AEO Advanced Nuclear
Reference Nuclear Vendor
case case case
Nuclear............................. 14.7% 18.3% 23.8%
Hydro............................... 5.1% 5.1% 5.1%
Geothermal.......................... 0.9% 0.9% 0.8%
Municipal Solid Waste............... 0.5% 0.5% 0.5%
Biomass/Wood........................ 1.7% 1.6% 1.5%
Wind................................ 1.1% 1.1% 1.1%
Responses to Questions From Senator Thomas
Question 1. In 2005, you did not include any coal to liquid numbers
in your projections. I noted that in this year's outlook, you are
projecting that by 2030, over 10% of future coal production will be
used to generate liquid from coal. What caused you to make this
adjustment in your calculations?
Answer. In the Annual Energy Outlook 2005 (AEO2005) reference case
projections, the production of coal liquids was not competitive because
the world oil price was approximately $21 per barrel less than the
Annual Energy Outlook 2006 (AEO2006) reference case projections. In the
AEO2005 High B case, crude oil prices were roughly comparable to the
crude oil prices in the AEO2006 reference case. In 2025, CTL production
was projected to be about 980,000 barrels per day by in the AEO2005
High B case, which is more than the projected 580,000 barrels per day
in the AEO2006 reference case. The lower estimate in the AEO2006
reference case, compared to the AEO2005 High B case, reflects a
reassessment, raising the capital costs associated with the coal-to-
liquids production process.
Question 2. You stated in your written testimony that under your
``likely energy future'' analysis, energy consumption is expected to
increase more rapidly than domestic energy supply through 2030. This
will make us more energy dependent, not less. That's a troubling
As a nation, what do we do to change that projection? Under any of
the scenarios you use in your Outlook, is there any way for the United
States to achieve energy independence?
Answer. There is little that the Nation can do practically to
achieve complete energy independence in the foreseeable future short of
drastic social and structural changes. There are no scenarios completed
as part of the AEO that achieve total energy independence.
In the AEO2006 reference case, net imports are expected to
constitute 33 percent of total U.S. energy consumption in 2030, up from
29 percent in 2004. hi the AEO2006 high price case, with almost 70
percent-higher prices by 2030, net imports are projected to still
account for 26 percent of U.S. energy consumption in 2030.
While supply, conversion, and demand technologies available today
can decrease U.S. dependence on energy imports, a number of factors are
substantial obstacles to complete oil independence. On the supply side,
many technology options are expensive compared to imports even at
current prices, the investments for the construction of adequate
capacity require long lead times and huge investments, and the
environmental and water consequences of certain supply options can be
significant. On the demand side, a growing number of drivers and
continued economic prosperity contribute to an expected increase in
vehicle-miles traveled, while many consumers continue to favor vehicles
that apply most advances in technology to improved performance rather
than fuel efficiency.
Question 3. You mention that by 2030, nearly 59 percent of coal
production will originate from the western United States. You also warn
that a stable transportation system will be needed to achieve that
I agree and believe our energy transportation system is inadequate
to meet future demands. Whether you are talking railroads, pipelines or
electric transmission lines, there are some serious weaknesses. Do you
have any concerns about the current condition of our system?
Answer. The increase in coal production projected in the AEO2006
could potentially cause short-term bottlenecks and would require
additional capacity from transportation infrastructure, in particular
the railroads. Railroads are a capital-intensive industry requiring
investment in infrastructure to keep up with normal wear-and-tear on
railcars, tracks, etc. The projected increase in coal demand in the
AEO2006 will necessitate investment in capacity that extends beyond
normal maintenance. While predicting the exact magnitude of railroad
investments needed is beyond the scope of the AEO2006 forecast, the
projected large increases in coal volume indicate that some portions of
the railroad network may be more vulnerable to congestion than others.
Possible areas of congestion include the Joint Line, a section of
railroad required to move coal out of the Wyoming Powder River Basin.
An increase of 275 million short tons is projected for the Wyoming
Powder River Basin between 2004 and 2030. Of that quantity, about 100
million tons is projected to be shipped to the Midwest. The AEO2006
also projects over 100 million additional tons from the Interior region
for generation plants in Kentucky and Tennessee. Some changes in
transportation patterns for coal produced in Northern Appalachia are
Although the magnitude of increases in coal shipment between 2004
and 2030 is large, the total projected increase is spread over 26
years. For instance, the largest single-year increase for Wyoming
Powder River Basin coal is projected to be an incremental 27 million
The coal-to-liquids facilities projected in the AEO2006 are assumed
to be built near existing refining capacity. Therefore, new pipeline
capacity is not assumed. Many of the coal-fired generation plants are
projected to be built in regions serving neighboring areas and may
require the construction or expansion of transmission capacity.
Question 4. In your testimony you point out that energy consumption
per capita fell in the 1970s in response to high energy prices and weak
economic demand. Which had the greatest impact on consumption: high
prices or a weak economy?
Answer. The statement in the testimony referred to a period from
the late 1970s through the early-to-mid 1980s, when significant energy
price and economic disruptions both affected energy use. Despite the
first oil price shock in 1973/1974 and the subsequent 1974/1975
recession, energy use per capita rebounded in the second half of the
decade to achieve its all-time high, about 360 million Btu per capita,
in 1978 and 1979. After the 1979/1980 price shock, per-capita energy
use fell to 332 million Btu in 1981, and then fell further, to 316
million in 1982 and 312 million in 1983, the time of the country's last
relatively severe recession. How much of this additional 20 million Btu
per capita drop was the continuing effect of high energy prices and how
much was due to overall economic slowdown is difficult to say. However,
in the next three years, when the U.S. emerged from the recession but
energy prices were still relatively high, energy use rebounded only
slightly, to the 320-325 million Btu per capita range.
It was only after the oil price collapse of 1986 that energy use
once again moved ahead significantly, to 338.1 million Btu per capita
in 1988. However, it should be noted that despite the relatively low
(in real terms) energy prices that prevailed from the mid-1980s to the
beginning of the 21st century, energy use per capita never again
reached the level of the late 1970's. It reached as high as about 350
million Btu in the year 2000, before the next round of energy price
increases began and per capita use fell again, to about 338 million Btu
Responses to Questions From Senator Talent
NATURAL GAS PRODUCTION
Question 1. The graph at Figure 10 seems to show that domestic
production of natural gas ceased to track consumption sometime around
1987 and is today about 15 percent less than consumption. You project
that this rift will grow to about 21% by 2030. Can you tell me what
initially caused this shortfall in domestic production and what has
prevented us from closing that gap?
How much of a role do governmental restrictions on exploring for
natural gas play in this continuing domestic production shortfall? Is
the price of imported natural gas or LNG a critical factor (i.e., is it
a matter of imports being cheaper or a lack of domestic supply)?
Answer. Imported natural gas and liquefied natural gas (LNG) have
been priced competitively with domestic supplies, which has promoted
growth in the volume of net imports. Larger volumes of net imports to
the United States, however, have not prevented growth in domestic
production. Natural gas volumes from domestic and foreign sources both
have expanded from the 1986 level, as is shown in Figure 10.
The United States has been a net importer of natural gas since
1958, with the bulk of the volumes coming from Canada. After peaking at
1,198 billion cubic feet (Bcf) in 1979, net imports averaged only 843
Bcf in 1980-1986. However, regulatory initiatives during the mid-1980s
promoted a more market-based system for trade between the two
countries. In 1988 the creation of the U.S.-Canadian Free Trade
Agreement prohibited most import or export restrictions on energy
The Energy Information Administration (EIA) has not recently
assessed the impact of Government regulations or legislation on
domestic production. However, there are estimates for the amount of
natural gas resources subject to Governmental restrictions. According
to the Minerals Management Service, 86 trillion cubic feet of natural
gas is located in offshore areas under Federal leasing moratoria in the
Atlantic and Pacific oceans, the Eastern Gulf of Mexico, and the North
Aleutian Basin. The United States Geological Survey (USGS) estimates
that 9 trillion cubic feet of natural gas resources are located in the
Arctic National Wildlife Refuge (ANWR), which is also under a Federal
leasing moratorium. Another 5 trillion cubic feet of natural gas,
according to the USGS, is located in state waters where oil and gas
drilling is prohibited by statute or administrative decree. A study
conducted for EIA by a private consulting company estimates that 21
trillion cubic feet of natural gas resources are officially
inaccessible in lower-48 onshore areas where leasing and/or surface
occupancy are prohibited by Federal statutes or administrative decrees,
and an additional 101 trillion cubic feet of lower-48 onshore natural
gas resources are de facto inaccessible due to the prohibitive effect
of compliance with various environmental and pipeline regulations.
EIA estimates that as of January 1, 2004, there were 1,273 trillion
cubic feet of technically recoverable natural gas resources in the
lower-48 states, including proved reserves but excluding volumes
thought to be located in areas that are officially inaccessible.
CLIMATE CHANGE--IMPACT ON COAL
Question 2. I am looking at Figure 14, which shows U.S. carbon
dioxide emissions by sector and fuel. I want to focus on the portion
showing emissions by fuel source, the bars on the right. If I
understand this graph correctly and assuming we were to try and cut
overall CO2 emissions focusing solely on coal, it appears we
would have to cut our emissions from coal, meaning our use of coal,
roughly in half in order to get overall emissions down to approximately
current levels. Is that correct? And we'd have to virtually eliminate
the use of coal, using today's technology, to get back to 1990
emissions levels. Assuming that's correct, what would be the economic
impact of eliminating coal as a fuel source? What would we replace it
Answer. Based on the AEO2006 reference case, and focusing solely on
emissions from coal-fired plants, U.S. coal consumption in 2030 would
have to be reduced by 68 percent to reduce carbon dioxide emissions
back to the 2004 level of 5.9 billion metric tons, and by 97 percent to
return emissions to the 1990 level of 5.0 billion metric tons.
While carbon reduction forecast scenarios were not modeled for the
AEO2006, a past report completed by EIA for Senators Inhofe, McCain and
Lieberman in June 2003 (analysis of S. 139, the Climate Stewardship Act
of 2003) included several restricted greenhouse gas emission scenarios.
The primary case in this report, the S. 139 case, projected a reduction
in energy-related carbon dioxide emissions to 5.4 billion tons in 2025.
In this scenario, substantial reductions in carbon dioxide emissions in
the electric power sector were achieved through a switch from coal to
natural gas, nuclear and renewable fuels. In addition, some advanced
coal-and natural gas-fired generating capacity equipped with carbon
capture and sequestration equipment was projected to be built. U.S.
coal production in 2025 was projected to be 72 percent below the 2004
level and 69 percent below the 1990 level in this case.
Question 3. Looking at Figure 6, what effect has recent energy
prices had on the ratio of energy use per capita? How about on energy
use per dollar of gross domestic product? Doesn't this indicate that we
as a nation have become more efficient in our energy use?.
Answer. The figure below* shows the ratios you ask about for the
last three years (indexed to 2002, the last year before energy prices
began to rise rapidly). In 2005, energy use per capita declined
approximately 2 percent below its level during the 2002 through 2004
*The figure has been retained in committee files.
One can think about how much energy we use per capita by observing
two trends: what is the intensity of energy use in the production of
output (the energy to GDP ratio) and how much GDP are we producing per
capita (the GDP per capita ratio). During this period, the average
refiner acquisition price for crude oil rose by over 100 percent. The
higher energy prices caused energy use per GDP to decline at a
significantly higher rate (3.1 percent per year) than in the 1990s (1.7
percent), in part due to changes in how energy is used (efficiency) and
in part because some energy-intensive industries, such as chemicals,
experienced lower growth than might otherwise have occurred (structural
change). At the same time, the aggregate economy still grew on a per
capita basis. Productivity remained high in spite of the high energy
prices and per capita GDP grew by 2.5 percent per year, which acts to
increase energy demand. Weather factors affecting energy use for
heating and air conditioning also influenced energy consumption trends
since 2002. On balance, energy consumption per capita declined by an
average of 0.6 percent per year over the last three years.
Responses to Questions From Senator Akaka
Question 1. Mr. Caruso, last year you testified before this
committee that ultimately gas hydrates could be a large supplier of
natural gas. At the same time, you expressed some pessimism regarding
the development of the necessary technology. Along with my colleague,
Senator Murkowski, I believe that gas hydrates are a potentially
invaluable resource. Did you include gas hydrate reserves in your
calculations regarding domestic supplies of natural gas?
Answer. Natural gas hydrates may become an invaluable resource in
our future. Natural gas hydrates are not included in the domestic
supplies of natural gas in the AEO2006 projections because gas hydrate
production is not considered technically and economically feasible
prior to 2030. Arctic gas hydrates are not projected to be produced
because there are ample, lower-cost conventional natural gas resources
to serve the Alaska and MacKenzie gas pipelines well beyond the 2030
time frame of the AEO2006. Deep-water ocean gas hydrate deposits will
not be produced until considerable technological progress is achieved.
Question 2. According to the Annual Energy Outlook, there will be a
growth in the use of coal for electricity production. What impact do
you think this trend will have on the cost of electricity in the state
of Hawaii, where virtually all of the electricity comes from oil-fired
plants? If so, do you foresee that the high cost of shipping coal to
Hawaii might off-set any savings?
Answer. As indicated, most of Hawaii's electricity generation comes
from petroleum-fired power plants. These plants accounted for roughly
80 percent of Hawaii's generation in 2005. Hawaii's two coal-fired
power plants, AES Hawaii and Puunene Factory, accounted for less than
15 percent of Hawaii's electricity supply in 2005. Unless new coal
plants are built in Hawaii to meet demand growth or replace existing
petroleum-fired plants; we do not believe that coal will have an impact
on the cost of electricity generation in Hawaii.
However, it may be possible for Hawaii to increase its reliance on
coal. Other countries, with shipping distances similar to Hawaii's,
currently rely more heavily on coal. For example, Japan, which is
located a similar distance from the large coal export ports in eastern
Australia, relied on coal-fired plants for 28 percent of its total
electricity supply in 2004, while oil-fired plants accounted for only
10 percent. This would suggest that shipping distance alone should not
make increased coal use in Hawaii uneconomic.
Question 3. According to a recent BBC News article, Brazilian Flex-
fuel cars, which run on a combination ethanol made from sugar cane and
gasoline, took 53.6% of the Brazilian market in 2005. Would similar use
of ethanol-fueled vehicles in the United States produce a sizable
decline in oil imports?
Answer. The use of ethanol flexible-fueled vehicles such as those
in Brazil would only produce a decline in oil imports if the ethanol
supply in the U.S. was priced competitively with gasoline and an
infrastructure existed to produce and distribute the ethanol.
There are currently about 5 million flexible-fuel vehicles in use
the U.S. that are capable of running on either gasoline or E-85, and
auto manufacturers sell about 800,000 new flexible-fuel-capable
vehicles per year. While having these vehicles in the market place
provides the potential to displace demand for gasoline, ultimately the
cost and availability of E-85 will determine demand. Currently, there
are approximately 500 fueling stations that offer E-85 out of about
180,000 stations nationwide. The majority of these stations are located
in Minnesota and Illinois, where the price of E-85 is relatively
competitive to gasoline. Until E-85 can be supplied across the country
at competitive prices, the availability of flexible-fuel-capable
vehicles will have little impact on oil imports.
Responses to Questions From Senator Salazar
REGARDING NATURAL GAS SUPPLIES AND PRICES
Question 1. Mr. Caruso, I'd like to take this opportunity to thank
you for the good work your offices do that rarely gets brought up at
these hearings--all the data collections and analysis that are used by
the Congress and by businesses alike every day.
I see from your projections that the price of natural gas is
expected to fall significantly over the course of this year. When I
read your testimony, you say that these prices are expected to fall
because of increased imports and increased drilling. Now, it isn't
clear to me how increased drilling is going to cause natural gas prices
to go down. When I look at your own EIA website, here is the trend I
find: from 1999 to 2004, the United States of America increased the
number of gas wells from about 300 thousand to a little more than 400
thousand. That is a huge increase: 33%. And yet after those huge
increases in the number of wells, the overall production of natural gas
production was up only 1%. So what does that mean? It means we are
drilling faster and faster just to keep up. Are we going to bring
another 100,000 wells online in the next 5 years? Possibly. But as the
average production per domestic well keeps declining, as it has ever
since 1971, it is hard to understand how more drilling will lower
prices in the near term. Can you please comment on how these facts
correlate to the dramatic decrease in price your Figure 1 shows for
natural gas over the next couple of years?
Answer. Drilling has increased significantly the last few years
with little increase in production, as indicated, primarily because the
focus of the drilling has been in unconventional gas formations (i.e.,
tight gas, gas shales, and coalbed methane). Between 1999 and 2004,
beginning-of-year unconventional natural gas reserves increased 69
percent (from 52.1 trillion cubic feet to 88.0 trillion cubic feet).
Unconventional gas has a lower production-to-reserves ratio and a
production profile that is flatter and longer than onshore conventional
gas. So even though supply from traditional sources (conventional
lower-48 and pipeline imports) is projected to continue to decline,
production from unconventional sources is projected to slowly increase,
putting downward pressure on prices in the mid-to long-term.
The short-term decline in the average wellhead price of natural gas
is driven mostly by the projected significant increase in liquefied
natural gas (LNG) imports. Net LNG imports are projected to increase
more than 250 percent (or 0.96 trillion cubic feet) between 2005 and
2008, increasing from 0.59 trillion cubic feet in 2005 to 1.55 trillion
cubic feet by 2008. During this same time period, U.S. natural gas
consumption only increases 3 percent, or 0.66 trillion cubic feet.
REGARDING THE USE OF COAL
Question 2. I find your projections for the use of coal very
interesting. Regardless of the scenario modeled, your projections show
an increased reliance on coal and increased domestic production of coal
here in America. In some cases this even includes coal to liquids,
which interests me very much. Would you confirm that coal use in
America is projected to increase regardless of what our energy future
Answer. In general, in all cases in the Annual Energy Outlook 2006,
we project that U.S. coal consumption will increase over our 2004 to
2030 forecast horizon. The estimated costs of reducing criteria
pollutants that include sulfur dioxide, nitrogen oxides and mercury at
coal-fired power plants are not expected to be prohibitive. However, in
other analyses where we have examined the impacts of policies to reduce
greenhouse gas emissions, we have projected much lower, and, in some
cases, declining, coal production.