[Senate Hearing 109-362]
[From the U.S. Government Printing Office]

                                                        S. Hrg. 109-362
                          ENERGY OUTLOOK 2006



                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                       ONE HUNDRED NINTH CONGRESS

                             SECOND SESSION




                           FEBRUARY 16, 2006

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


27-065                      WASHINGTON : 2006
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                 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

                       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

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 2:40 p.m. in room 
SD-366, Dirksen Senate Office Building, Hon. Pete V. Domenici, 
chairman, presiding.

                  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?


    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.

                        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. 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 
2004 dollars.
    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 Administration.
    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 
alternative cases.

                          U.S. ENERGY OUTLOOK

Energy Prices
    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 
(Figure 2).
    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.

Energy Consumption
    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 
small appliances.
    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 
day, respectively.
    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 
fuel blending.

Energy Intensity
    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 
electricity generation.

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 
reference case.
    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 

Electricity Generation
    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 
transportation sector.


    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 
of oil?
    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.
    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 
year ago.
    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 
existing plants.
    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.

                          FROM HAWAII

    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 
necessary technology.
    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.

                          FROM ALASKA

    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 
project slips?
    Mr. Caruso. All other things being equal, the price of gas 
would be higher without, without that project coming onstream 
in 2015.
    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 
New England.
    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 
price response.
    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.
    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 
next year.
    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 
those capacities.
    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 
to 2030?
    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 
the report.
    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, 
        Washington, DC.
    Dear Mr. Chairman: On February 16, 2006, Guy Caruso, Administrator, 
Energy Information Administration, testified regarding EIA's Annual 
Energy Outlook.
    Enclosed are answers to 25 questions that were submitted by 
Senators Craig, Thomas, Talent, Akaka, Salazar, and you to complete the 
hearing record.
    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,
                                               Assistant Secretary.
              Responses to Questions From Senator Domenici
                               oil prices
    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.

                              NATURAL GAS

    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.

                                     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 
are assumed?
    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.

                              SOURCES, 2030
                                          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 
industrial applications.

                              SOURCES, 2030
                                          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 
also projected.
    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 
in 2003.

               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.

                           ENERGY EFFICIENCY

    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


    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.