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27–065 PDF 2006

S. HRG. 109–362

ENERGY OUTLOOK 2006

HEARING

BEFORE THE

COMMITTEE ON 

ENERGY AND NATURAL RESOURCES 

UNITED STATES SENATE

ONE HUNDRED NINTH CONGRESS

SECOND SESSION

TO

DISCUSS THE ENERGY INFORMATION ADMINISTRATION’S 2006 ANNUAL 

ENERGY OUTLOOK ON TRENDS AND ISSUES AFFECTING THE UNITED 

STATES’ ENERGY MARKET

FEBRUARY 16, 2006

(

Printed for the use of the 

Committee on Energy and Natural Resources 

(II)

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

PETE V. DOMENICI, New Mexico, Chairman 

LARRY E. CRAIG, Idaho 

CRAIG THOMAS, Wyoming 

LAMAR ALEXANDER, Tennessee 

LISA MURKOWSKI, Alaska 

RICHARD M. BURR, North Carolina, 

MEL MARTINEZ, Florida 

JAMES M. TALENT, Missouri 

CONRAD BURNS, Montana 

GEORGE ALLEN, Virginia 

GORDON SMITH, Oregon 

JIM BUNNING, Kentucky 

JEFF BINGAMAN, New Mexico 

DANIEL K. AKAKA, Hawaii 

BYRON L. DORGAN, North Dakota 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

DIANNE FEINSTEIN, California 

MARIA CANTWELL, Washington 

KEN SALAZAR, Colorado 

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 

(III)

C O N T E N T S 

STATEMENTS 

Page

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

APPENDIX 

Responses to additional questions .......................................................................... 23

(1)

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. 

OPENING STATEMENT OF HON. PETE V. DOMENICI,

U.S. SENATOR FROM NEW MEXICO 

The CHAIRMAN. The hearing will please come to order. Senator 

Bingaman is not here at this moment, but he was here. I was not 

quite on time, so he had to go somewhere. Now we have representation on both sides and I assume, Senator Akaka, we can proceed; 

is that right? 

Senator AKAKA. Yes. 

The CHAIRMAN. All right. First, Mr. Caruso, we are sorry we had 

to put this hearing off the other day and we will try to hear you 

today. 

For the past 3 years I have observed that the level of concern 

about energy issues seems to go up as prices have gone up. It is 

definitely right that our concern should rise with the American consumers who are paying more for home energy and transportation, 

but I want us all to keep in mind that, in spite of that, for now 

the economy is strong. However, we need to take whatever steps 

we can to assure that energy prices do not change that fact if there 

is anything we can do about it. 

So the first step we took in August 2005 was we passed a rather 

comprehensive bill. It is having some significant impact. I will note, 

and you can confirm later, that even in your analysis, where it is 

pretty hard for you to take energy sources that are not yet in existence and expect them, you do expect nuclear power to be online 

and to be part of the mix in the next 25-year forecast. That is the 

first time that has happened in quite a while; right, Mr. Caruso? 

STATEMENT OF GUY CARUSO, ADMINISTRATOR, ENERGY 

INFORMATION ADMINISTRATION, DEPARTMENT OF ENERGY 

Mr. CARUSO. That is correct. 

The CHAIRMAN. We trust you on your estimate on that one, although I have some very serious concerns about some other parts 

of your estimate. I hope you are right, but on some of them I really 

wonder. 

2

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 future. 

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 $107. 

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 

3

*All figures have been retained in committee files. 

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 statement? 

Mr. CARUSO. Sure, I would be happy to. 

The CHAIRMAN. That is kind of exciting. We do not have to do 

anything and we could have had a policy saying we are going to 

reduce it 8 percent, Senator Bingaman, and had a bill, an 8 percent 

reduction, and passed it, like everybody wants us to be, bold. Then 

we would have called him up here and said, did we do it? 

Senator BINGAMAN. Full credit. 

The CHAIRMAN. Full credit. 

Okay, Senator Bingaman. 

STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR

FROM NEW MEXICO 

Senator BINGAMAN. Mr. Chairman, knowing the way this place 

operates, there will probably be such a bill introduced before sunset. 

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 questions. 

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 dollars. 

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 producVerDate 0ct 09 2002 12:24 Apr 24, 2006 Jkt 109362 PO 27065 Frm 00007 Fmt 6633 Sfmt 6633 P:\DOCS\27065.TXT SENERGY2 PsN: PAULM
4

tive 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 

5

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 case. 

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 case. 

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:]

6

*All figures have been retained in committee files. 

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 

7

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 projected. 

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. 

8

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 

2030. 

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 gridrelated electricity generation (including combined heat and power), and the rest is 

for dispersed heating and cooling, industrial uses, and fuel blending. 

9

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 2004. 

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 period. 

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 equipment. 

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 case. 

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). Lower48 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. 

10

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 feet. 

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 11). 

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 

11

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 kilowatthours 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. 

CONCLUSIONS

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 transportation. 

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. 

12

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 cannot? 

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 year. 

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 years. 

The CHAIRMAN. So even with the world situation being what it 

is, which you must take into consideration, you are not, as our exVerDate 0ct 09 2002 12:24 Apr 24, 2006 Jkt 109362 PO 27065 Frm 00016 Fmt 6633 Sfmt 6602 P:\DOCS\27065.TXT SENERGY2 PsN: PAULM
13

pert 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 term. 

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 

14

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 2025? 

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 capacity? 

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. 

15

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 2018. 

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 much. 

Senator MURKOWSKI [presiding]. Go ahead, please. 

Senator CRAIG. I think Senator Akaka was here before me. 

Senator MURKOWSKI. Senator Akaka. 

STATEMENT OF HON. DANIEL K. AKAKA, U.S. SENATOR

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 

16

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 coalfired 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 made. 

Senator AKAKA. Your calculations, as you said, show that there 

would be a savings in using coal. But let me ask you another part 

of that, and you alluded to this, that there may be other costs, like 

shipping of coal to Hawaii. We will have to import it. Do you think 

this might offset any savings? 

Mr. CARUSO. Yes, in fact I think that is why we are not assuming 

any of those investment decisions to be made, because the infrastructure of providing receiving facilities for the coal and new electric power generation units, because of the reasons you just said—

the large, up-front, new infrastructure investment that would be 

needed. 

Senator AKAKA. Thank you for your responses. My time has expired. Thank you, Mr. Chairman. 

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

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 

17

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 agreement. 

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 poVerDate 0ct 09 2002 12:24 Apr 24, 2006 Jkt 109362 PO 27065 Frm 00021 Fmt 6633 Sfmt 6602 P:\DOCS\27065.TXT SENERGY2 PsN: PAULM
18

tential 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. 

19

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 expire. 

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 year. 

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.

20

Mr. CARUSO. The other comment on the early part of the nonhydro 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 plugin 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 

21

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.] 

(23)

APPENDIX 

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. 

Sincerely, 

JILL L. SIGAL, 

Assistant Secretary. 

[Enclosures.] 

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. 

24

When WTI rose over $68 per barrel in late January, it would not have been un- reasonable 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 prices? 

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. 

REFINERY

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 

25

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 hurricanerelated 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. 

TRANSPORTATION

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. 

COAL

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 years. 

26

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 years. 

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 generation? 

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. 

NUCLEAR

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. 

ECONOMY

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 continues? 

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.

27

LOSSES IN REAL GDP WITH THE AEO HIGH PRICE CASE 

Loss in 2000 Dollars Percent Loss 

2007 ................................... $22 billion .......................... 0.2 percent 

2010 ................................... $108 billion ........................ 0.8 percent 

2015 ................................... $129 billion ........................ 0.9 percent 

2025 ................................... $23 billion .......................... 0.1 percent 

RESPONSES TO QUESTIONS FROM SENATOR CRAIG

Question 1. What percentage of energy will be emission-free (i.e., no carbon emissions—e.g., nuclear, hydroelectric, wind, geothermal, solar, etc.) in EIA’s current 

baseline, and what are the percentages of each emission-free source. How do these 

assumptions change when each of the two more optimistic alternatives for lowerpriced 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.

PERCENT OF TOTAL ENERGY CONSUMPTION FROM SPECIFIC

EMISSION-FREE SOURCES, 2030

AEO

Reference case 

Advanced

Nuclear

case 

Nuclear

Vendor

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.

PERCENT OF TOTAL ELECTRICITY GENERATION FROM SPECIFIC

EMISSION-FREE SOURCES, 2030

AEO

Reference

case 

Advanced

Nuclear

case 

Nuclear

Vendor

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? 

28

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 projection. 

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 figure. 

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 tons. 

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. 

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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 products. 

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 

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*The figure has been retained in committee files. 

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 with? 

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 period. 

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 

31

the AEO2006 projections because gas hydrate production is not considered technically and economically feasible prior to 2030. Arctic gas hydrates are not projected 

to be produced because there are ample, lower-cost conventional natural gas resources to serve the Alaska and MacKenzie gas pipelines well beyond the 2030 time 

frame of the AEO2006. Deep-water ocean gas hydrate deposits will not be produced 

until considerable technological progress is achieved. 

Question 2. According to the Annual Energy Outlook, there will be a growth in 

the use of coal for electricity production. What impact do you think this trend will 

have on the cost of electricity in the state of Hawaii, where virtually all of the electricity comes from oil-fired plants? If so, do you foresee that the high cost of shipping coal to Hawaii might off-set any savings? 

Answer. As indicated, most of Hawaii’s electricity generation comes from petroleum-fired power plants. These plants accounted for roughly 80 percent of Hawaii’s 

generation in 2005. Hawaii’s two coal-fired power plants, AES Hawaii and Puunene 

Factory, accounted for less than 15 percent of Hawaii’s electricity supply in 2005. 

Unless new coal plants are built in Hawaii to meet demand growth or replace existing petroleum-fired plants; we do not believe that coal will have an impact on the 

cost of electricity generation in Hawaii. 

However, it may be possible for Hawaii to increase its reliance on coal. Other 

countries, with shipping distances similar to Hawaii’s, currently rely more heavily 

on coal. For example, Japan, which is located a similar distance from the large coal 

export ports in eastern Australia, relied on coal-fired plants for 28 percent of its 

total electricity supply in 2004, while oil-fired plants accounted for only 10 percent. 

This would suggest that shipping distance alone should not make increased coal use 

in Hawaii uneconomic. 

Question 3. According to a recent BBC News article, Brazilian Flex-fuel cars, 

which run on a combination ethanol made from sugar cane and gasoline, took 53.6% 

of the Brazilian market in 2005. Would similar use of ethanol-fueled vehicles in the 

United States produce a sizable decline in oil imports? 

Answer. The use of ethanol flexible-fueled vehicles such as those in Brazil would 

only produce a decline in oil imports if the ethanol supply in the U.S. was priced 

competitively with gasoline and an infrastructure existed to produce and distribute 

the ethanol. 

There are currently about 5 million flexible-fuel vehicles in use the U.S. that are 

capable of running on either gasoline or E-85, and auto manufacturers sell about 

800,000 new flexible-fuel-capable vehicles per year. While having these vehicles in 

the market place provides the potential to displace demand for gasoline, ultimately 

the cost and availability of E-85 will determine demand. Currently, there are approximately 500 fueling stations that offer E-85 out of about 180,000 stations nationwide. The majority of these stations are located in Minnesota and Illinois, where 

the price of E-85 is relatively competitive to gasoline. Until E-85 can be supplied 

across the country at competitive prices, the availability of flexible-fuel-capable vehicles will have little impact on oil imports. 

RESPONSES TO QUESTIONS FROM SENATOR SALAZAR

REGARDING NATURAL GAS SUPPLIES AND PRICES

Question 1. Mr. Caruso, I’d like to take this opportunity to thank you for the good 

work your offices do that rarely gets brought up at these hearings—all the data collections and analysis that are used by the Congress and by businesses alike every 

day. 

I see from your projections that the price of natural gas is expected to fall significantly over the course of this year. When I read your testimony, you say that these 

prices are expected to fall because of increased imports and increased drilling. Now, 

it isn’t clear to me how increased drilling is going to cause natural gas prices to 

go down. When I look at your own EIA website, here is the trend I find: from 1999 

to 2004, the United States of America increased the number of gas wells from about 

300 thousand to a little more than 400 thousand. That is a huge increase: 33%. And 

yet after those huge increases in the number of wells, the overall production of natural gas production was up only 1%. So what does that mean? It means we are drilling faster and faster just to keep up. Are we going to bring another 100,000 wells 

online in the next 5 years? Possibly. But as the average production per domestic 

well keeps declining, as it has ever since 1971, it is hard to understand how more 

drilling will lower prices in the near term. Can you please comment on how these 

facts correlate to the dramatic decrease in price your Figure 1 shows for natural gas 

over the next couple of years? 

32

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 holds? 

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.

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