[Senate Hearing 108-511]
[From the U.S. Government Publishing Office]



                                                        S. Hrg. 108-511

                          ENERGY OUTLOOK 2004

=======================================================================

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                      ONE HUNDRED EIGHTH CONGRESS

                             SECOND SESSION

  TO REVIEW THE ENERGY INFORMATION ADMINISTRATION (EIA) ANNUAL ENERGY 
OUTLOOK 2004 REPORT REGARDING THE SUPPLY, DEMAND, AND PRICE PROJECTIONS 
FOR OIL, NATURAL GAS, NUCLEAR, COAL, AND RENEWABLE RESOURCES, FOCUSING 
     ON OIL AND NATURAL GAS, AND TO CONSIDER COMMERCIAL AND MARKET 
        PERSPECTIVES ON THE STATE OF OIL AND NATURAL GAS MARKETS

                               __________

                             MARCH 4, 2004


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


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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                 PETE V. DOMENICI, New Mexico, Chairman
DON NICKLES, Oklahoma                JEFF BINGAMAN, New Mexico
LARRY E. CRAIG, Idaho                DANIEL K. AKAKA, Hawaii
BEN NIGHTHORSE CAMPBELL, Colorado    BYRON L. DORGAN, North Dakota
CRAIG THOMAS, Wyoming                BOB GRAHAM, Florida
LAMAR ALEXANDER, Tennessee           RON WYDEN, Oregon
LISA MURKOWSKI, Alaska               TIM JOHNSON, South Dakota
JAMES M. TALENT, Missouri            MARY L. LANDRIEU, Louisiana
CONRAD BURNS, Montana                EVAN BAYH, Indiana
GORDON SMITH, Oregon                 DIANNE FEINSTEIN, California
JIM BUNNING, Kentucky                CHARLES E. SCHUMER, New York
JON KYL, Arizona                     MARIA CANTWELL, Washington

                       Alex Flint, Staff Director
                   Judith K. Pensabene, Chief Counsel
               Robert M. Simon, Democratic Staff Director
                Sam E. Fowler, Democratic Chief Counsel
                         Lisa Epifani, Counsel
         Jennifer Michael, Democratic Professional Staff Member


                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Bingaman, Hon. Jeff, U.S. Senator from New Mexico................     2
Caruso, Guy F., Administrator, Energy Information Administration, 
  Department of Energy...........................................     6
Domenici, Hon. Pete V., U.S. Senator from New Mexico.............     1
Landrieu, Hon. mary L., U.S. Senator from Louisiana..............    42
Koonce, Paul, CEO, Dominion Energy, Inc..........................    16
Saunders, Jay, Energy Analyst, Deutsche Bank AG..................    26
Sharples, Richard J., Senior Vice President, Strategic Planning 
  and Marketing, Anadarko Petroleum Corporation..................    12
Thomas, Hon. Craig, U.S. Senator from Wyoming....................     6
Wyden, Hon. Ron, U.S. Senator from Oregon........................     3

                                APPENDIX

Responses to additional questions................................    57

 
                          ENERGY OUTLOOK 2004

                              ----------                              


                        THURSDAY, MARCH 4, 2004

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 10:08 a.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. I apologize for being late. Good morning to 
my good friend from Wyoming.
    We all had conflicts, so we want to say to the panelists we 
are going to do our best, if you help us. We cannot have 
extremely long statements, even from those of you who are very 
expert. We are going to have to read your statements with our 
staff and move along.
    We are here to take stock of our energy situation and what 
our expectations are for the near and the long term. We hope 
this hearing will provide a little bit of an overview of the 
core issues, particularly on oil and natural gas, and that it 
will stimulate further hearings by the committee on more 
specific issues such as the future of liquified natural gas, 
LNG, and the status of international oil and natural gas 
development.
    Oil and gas are the lifeblood of this economy. If they were 
not supposed to be, we have made them that for sure. They 
account for more than 60 percent of the energy consumed in this 
country.
    On March 3, oil prices were $35.80 a barrel. Natural gas 
prices were, Senator Bingaman, $5.37 per Btu. These numbers 
reflect a continued trend of high prices. I am sure I am not 
alone in worrying about them hurting our economy as well as the 
economy of the globe which we participate in so dramatically.
    It is clear that these prices are a reflection of an 
imbalance in supply and demand. Our national security and 
prosperity require that, if we can, we develop policies that 
encourage balance, balance in production, consumption, and 
price.
    The energy bill, whether each and every one of us agree on 
all of it or not--I hope that we believe we can pass something 
before the year is out that will do a few things that are 
important. It will have some production incentives, permit 
streamlining, incentives for critical infrastructure like the 
Alaska natural gas pipeline, hydrogen initiatives, et cetera.
    Yesterday there were a number of reports stressing the need 
to pass the bill after debate in the Senate, however that is. 
The distinguished minority leader indicated that there were 
sufficient votes, but I think the missing question in his 
statement was how many amendments will there be before that 
event occurs. We will get with him and ask him what that means. 
Maybe he can get with Senator Bingaman and ask Senator Bingaman 
what that means. I do not want to ask you here because that is 
not fair.
    [Laughter.]
    But obviously, sooner or later, we have got to know whether 
it is 5, 10, or 30. Maybe we will find a way to let anybody 
decide how many they want and figure out that the rules of the 
Senate will still let us get a bill.
    I am worried, Senators and anybody else, that people are 
not going to wait around too much longer for this bill. They 
are going to start picking the good pieces. One of the great 
pieces in it is wind. Clearly the pressure is on because all 
wind production stopped. New projects I should say, and so the 
pressure is on to ask the committee to pass a 1-year extension 
or the like, Senator Bingaman. I do not know if you have heard 
that, but that is the latest. Take it out of the bill, pass a 
1-year extension. I think as soon as that happens, the question 
is how far does it go. What happens to Alaska? What happens to 
the other provisions?
    Now, having said that, I am going to move quickly now to 
Senator Bingaman and any other Senators. Senator Bingaman is 
welcome to have an opening statement. If the rest of you could 
do without and go right to questions, I would appreciate it. If 
not, we will go to----
    Senator Wyden. Mr. Chairman?
    The Chairman. Yes.
    Senator Wyden. Just your thoughtfulness is always so 
helpful because, like you, I have the Budget Committee. If I 
could just take no more than 5 minutes, even for an opener to 
outline----
    The Chairman. Senator Bingaman, is that all right with you?
    Senator Bingaman. Fine.
    The Chairman. Proceed.
    Senator Wyden. No. I will wait my turn. I am fine now.
    The Chairman. Senator Bingaman.
    Senator Wyden. Thank you, Mr. Chairman. I appreciate it.

         STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR 
                        FROM NEW MEXICO

    Senator Bingaman. Mr. Chairman, I appreciate your having 
the hearing. I think this is a very useful hearing. I look 
forward to hearing the Administrator of EIA explain to us their 
view as to not only future supply but future price for these 
various energy sources that we depend so much on. I think it is 
absolutely crucial to our economy that we have an adequate 
supply at a reasonable price. Obviously, we need all the wisdom 
we can gain from the Administrator and the other witnesses on 
what we can expect. So thank you for having the hearing.
    The Chairman. Senator Wyden, would you like to take your 5 
minutes and we will understand your having to be absent. I am 
supposed to be there too, but I am not going for a while.

           STATEMENT OF HON. RON WYDEN, U.S. SENATOR 
                          FROM OREGON

    Senator Wyden. Mr. Chairman, thank you. Again, you have 
always been so gracious and I really appreciate it.
    Mr. Chairman and colleagues, we have never had gasoline 
prices this high at this time of year before. Now, the oil 
companies say that it is not their fault, but I have released 
evidence indicating that the companies have deliberately 
curtailed refining capacity and increased their refinery 
margins, actions that boost gasoline prices higher.
    In 2001, I revealed internal oil company documents showing 
that major oil companies pursued efforts to curtail refinery 
capacity as a strategy for stifling competition and boosting 
their profits. One oil company document revealed efforts to 
prevent the restart of the Powerine refinery in southern 
California because they feared its restart would reduce gas 
prices and refinery profits by 2 to 3 cents per gallon.
    Now Shell Oil has announced that it is permanently shutting 
down its 70,000 barrels per day Bakersfield, California 
refinery which is critical to the entire west coast gasoline 
market, including my home State. As Yogi Berra said, ``It's 
deja vu all over again.''
    Now, Shell claimed that there was simply not enough crude 
oil supply to keep the refinery operating, but recent news 
article have reported that both Chevron, Texaco, and State of 
California officials estimate that there is at least a 20- to 
25-year supply of crude oil remaining in the area where the 
Bakersfield refinery is located. What makes Shell's decision to 
close the Bakersfield refinery especially curious is that the 
company never even tried to find a buyer. The California 
Attorney General is investigating Shell's action for potential 
antitrust violations.
    But Mr. Chairman and colleagues, for the life of me, I 
cannot figure out why the Federal Trade Commission will do 
absolutely nothing to even investigate the Bakersfield refinery 
closure because this goes right to the heart of making sure 
that gasoline prices are affordable on the west coast of the 
United States.
    Mr. Chairman, I would ask unanimous consent that the letter 
that I sent to the Federal Trade Commission on February 18, 
2004, asking the Federal Trade Commission to investigate the 
implications for the west coast gasoline market of the 
Bakersfield refinery closure, would be made a part of the 
record.
    The Chairman. That will be done.
    [The letter of Senator Wyden follows:]

                                               U.S. Senate,
                                 Washington, DC, February 18, 2004.
Hon. Timothy J. Muris,
Chairman, Federal Trade Commission, Washington, DC.
    Dear Chairman Muris: I am writing to request that the Federal Trade 
Commission (FTC) use its continuing authority to re-examine recent 
mergers in the gasoline industry in order to investigate Shell Oil's 
plans to close its 70,000 barrel-per-day Bakersfield, California 
refinery on October 1, 2004. I urge the FTC to use this authority to 
determine whether this refinery closure will cause further 
anticompetitive problems in West Coast gasoline markets and to take 
appropriate action avoid any such problems.
    As you know, the FTC has allowed two major oil industry mergers and 
acquisitions to proceed that involved Shell Oil's Bakersfield 
refinery--the merger of Chevron and Texaco and Shell's acquisition of 
Pennzoil-Quaker State. Prior to the merger of Chevron and Texaco, the 
Bakersfield refinery was operated by Equilon Enterprises LLC, a joint 
venture between Shell and Texaco. However, Shell acquired full 
ownership of the Bakersfield refinery when Texaco was required by the 
FTC to sell its Equilon holdings as a condition of the Chevron Texaco 
merger in 2001. Subsequently, in 2002, the FTC allowed Shell to acquire 
Pennzoil-Quaker State.
    Although Shell's announcement of its decision to close the 
Bakersfield refinery maintained ``there was simply not enough crude 
supply to ensure the viability of the refinery in the long-term,'' 
recent news articles have reported that both Chevron Texaco and State 
of California officials estimate that the San Joaquin Valley where the 
Bakersfield refinery is located has a 20-25 year supply of crude oil 
remaining. In fact, The Bakersfield Californian reported on January 8, 
2004, that Chevron Texaco plans on drilling more than 800 new wells in 
the San Joaquin Valley this year which is ``300 more new wells than 
last year.'' The fact that Shell's former joint venture partner is 
increasing its drilling in the area calls into question Shell's claim 
that a lack of available oil supply is the reason for closing its 
Bakersfield refinery.
    It is also curious that Shell appears to have made no attempt to 
sell the Bakersfield refinery before deciding it had to be closed. The 
attached Shell Bakersfield Refinery Closure FAQ's included the 
following question and answer put out by the company:

        ``10. Instead of closing the refinery, has Shell considered 
        selling it?

        Any new owner would face the same issues Shell is facing; there 
        is simply a lack of crude supply to operate this refinery.''

    Shell's position seems at odds with the rest of the oil industry 
which typically points to a lack of refinery capacity, rather than 
availability of crude oil to refine, as a persistent problem. For 
example, according to the American Petroleum Institute, current 
refinery utilization rates exceed 91 percent and these high utilization 
rates leave little excess refining capacity to respond to supply 
problems or disruptions. Given the lack of spare refining capacity in 
the oil industry and the impacts this can have on supply and prices, it 
is interesting that Shell would shut down a major refinery without even 
attempting to find a buyer.
    In 2001, I revealed internal oil company documents showing that 
major oil companies pursued efforts to curtail refinery capacity as a 
strategy for stifling competition and boosting their profits. These 
efforts included working to prevent the restart of the closed Powerine 
refinery in Southern California. One company document revealed that if 
the Powerine refinery was restarted, the additional gasoline supply on 
the market could bring down gas prices and refinery profits by two to 
three cents per gallon and called for a ``full court press'' to keep 
the refinery down. The Powerine refinery's capacity was 20,000 barrels 
per day. Because of the much larger capacity of the 70,000 barrels-per-
day Bakersfield refinery, the FTC should investigate the impacts 
closure of the Bakersfield refinery could have on both gasoline supply 
and prices at the pump.
    Finally, the FTC should also look into Shell's plans to close its 
Bakersfield refinery as part of a troubling trend of refinery closures 
that is further concentrating the oil industry. According to 
information compiled by the Senate Permanent Investigations 
Subcommittee, mergers in the oil industry over the last few years and 
the closing of refineries have dramatically increased the concentration 
in the oil refining industry. Under one commonly used test for 
concentration, 28 states would now be considered tight oligopolies. In 
fact, the number of states which have high levels of concentration 
doubled from 14 to 28 between 1994 and 2000. And since then, the FTC 
has allowed additional oil company mergers to occur. The closure of 
Shell's Bakersfield refinery, the 12th largest in California, would 
further contribute to this already troubling trend, with potential 
adverse impacts on competition, production and prices for consumers.
    For these reasons, I am requesting that the FTC use its authority 
to re-examine recent oil mergers to investigate whether the planned 
closure of Shell's Bakersfield refinery will create further 
anticompetitive problems in West Coast gasoline markets, such as 
raising prices or restricting supply. I would also urge that you 
undertake this investigation expeditiously to ensure there is 
sufficient time to take appropriate action before the refinery closure 
takes place.
    Thank you for your attention and I took forward to your response.
            Sincerely,
                                                 Ron Wyden,
                                                      U.S. Senator.

    Senator Wyden. Mr. Chairman, the only other point that I 
wanted to make is the Consumer Federation of America has, I 
think, done some very good work to look at these questions of 
refinery margins. They have done an analysis saying that the 
refinery margins are taking three times as big a bite about of 
consumers' pockets, for example, as the actions of the OPEC 
cartel, which are continually highlighted by many in the oil 
industry. And I would ask unanimous consent that a Consumer 
Federation of America letter dated March 4, 2004 be made a part 
of the record as well.
    The Chairman. That will be done.
    [The letter from the Consumer Federation of America 
follows:]

                            Consumer Federation of America,
                                     Washington, DC, March 4, 2004.
Hon. Pete Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Chairman Domenici: It has come to my attention that the Senate 
Energy Committee is holding another hearing into the ongoing crisis in 
domestic energy markets without inviting a witness to present a 
consumer view. The failure of the Congress and the Bush Administration 
to look beyond the supply-side of the market and craft a balanced 
approach has frustrated energy policy in this country for the past four 
years.
    The National Energy Policy Task Force headed up by Vice President 
Cheney, which framed the energy policy agenda, remains embroiled in a 
controversy over the excessive influence that producers and industry 
had in the deliberations. For the Senate to repeat the mistake of the 
task force-would be a grave mistake, The ``supply-side only'' approach 
will not solve the problem and attempting to shut out demand-side 
voices will only make it more difficult to reach a consensus.
    The Consumer Federation of America has been the leading consumer 
group dealing with energy problems in the past two decades. Attached is 
an op-ed piece outlining the Weaknesses of energy policy that excludes 
the demand side of the equation.
    Also attached is a report published five months ago, which 
demonstrates that approximately $30 billion of increased gasoline 
costs--about three quarters of the total increase of the past three 
years--are domestic in origin. Domestic refining and marketing 
operations of the oil companies are imposing record costs on consumers. 
Public opinion polls show that American consumers reject the argument 
that foreign producers are the sole cause of high energy prices and our 
research shows that they are right.
    These facts must be taken into account if a genuine solution to the 
energy problem is to be found. I urge you to ensure that this 
perspective--the ``other side of the story''--is presented to the 
Committee at the earliest possible moment.
            Sincerely,
                                            Mark N. Cooper,
                                              Director of Research.

    Senator Wyden. The last point I would make, Mr. Chairman, I 
just think it sure looks like the oil companies are using 
higher oil prices as an excuse to increase their refinery 
margins and pad the bottom line. A prime example is Exxon Mobil 
which last year announced an all-time record profit of $4.4 
billion, the highest profit by any company in history, and here 
again the Federal Government is sitting on its hands with 
respect to stopping oil companies from exploiting the tight 
supply market by padding refinery margins and profits.
    So the chairman has been very gracious to give me a few 
minutes to outline these concerns. Like the chairman, I will be 
in and out through the course of the morning because of the 
Budget Committee, but I intend to come back and ask some 
questions with respect to these issues.
    This Bakersfield closure does not smell right. It does not 
add up and it has great implications for the entire west coast 
market. In California they are paying over $2 per gallon. That 
is the case in Hawaii as well. My State is not far behind at 
nearly $1.80 per gallon. I have to tell you, this Bakersfield 
closure smells and we are going to stay at it until we get to 
the bottom of it.
    Mr. Chairman, I thank you very much for your thoughtfulness 
this morning.
    The Chairman. Thank you very much, Senator.
    How about on my side? Do either of you want to make some 
remarks?
    Senator Smith. Mr. Chairman, in the interest of time, I may 
include a statement in the record.
    The Chairman. Whatever you would like, Senator.
    Senator Thomas.

         STATEMENT OF HON. CRAIG THOMAS, U.S. SENATOR 
                          FROM WYOMING

    Senator Thomas. I will be very brief also.
    I certainly appreciate having this meeting. We have been 
reading the balance of gas policy, the annual outlook report 
here. Clearly, we have a problem and we need to talk about 
conservation. We need to talk about research. We need to talk 
about alternatives. We need to talk about domestic production. 
We have been trying to do that, so we need to make it more 
clear that we are in a situation where we have to make some 
moves.
    Thank you, sir.
    The Chairman. Thank you.
    Can we proceed now? You got my admonition. We are going to 
start with panel one, Guy Caruso, Administrator of the EIA, 
Department of Energy. Would you start? And your statement will 
be made a part of the record right now, and you give us your 
testimony as quickly as you can. We will not ask questions 
unless the Senators need to. We will go to the other witnesses 
and then come back. Proceed, please.

 STATEMENT OF GUY F. CARUSO, ADMINISTRATOR, ENERGY INFORMATION 
              ADMINISTRATION, DEPARTMENT OF ENERGY

    Mr. Caruso. Thank you, Mr. Chairman and members of the 
committee. The Energy Information Administration is pleased to 
be represented here at this hearing and to present our outlook.
    As we end the winter of 2003-2004, market fundamentals are 
extremely tight in both the oil and gas markets. On a global 
basis, we are producing about 80 million barrels a day of oil 
in 2004, and the unused productive capacity is only about 2 
million barrels a day and most of that is in Saudi Arabia. So 
we are operating a global oil industry with only about 2.5 
percent of unused capacity which, of course, means there is 
little flexibility in the system.
    Similarly in North American natural gas, we are stretched 
very thin, particularly on the production side, as has already 
been mentioned. These fundamentals of supply and demand have 
led to a very tightly balanced supply/demand situation. 
Therefore, the market is vulnerable to surprises. Any demand or 
supply changes or unexpected events such as industrial 
accidents, weather, all lead to spikes in prices.
    The combination of rising world oil demand growth, fairly 
low inventories, and production restraint by OPEC has kept oil 
supplies tight globally and we expect prices to remain 
relatively high.
    U.S. inventories are low both for crude oil and for major 
products. Gasoline, as was mentioned, is in very tight supply, 
and this is true as we look around our OECD partners in the 
EIA.
    EIA expects the average price of West Texas Intermediate, 
the benchmark crude, to stay in the $29 to $35 per barrel range 
over the next 2 years in our short-term forecast. Of course, as 
was mentioned, the current price is almost $36, and we are in 
the process of preparing our March outlook and we will be 
looking again at our price projections. The gasoline market is 
extremely tight, and it is led by the fact that it is a very 
inflexible system that has to meet demands of a large number of 
different specifications, including the most recent MTBE bans 
in New York and Connecticut.
    OPEC production decisions, of course, also affect the crude 
price and have been influencing price trends. In 47 out of the 
last 52 months, the OPEC benchmark price for its basket of 
crudes has been within or above their targeted range of $22 to 
$28 and, in the last several months, has been above $30. OPEC, 
on March 31, announced a further restraint on production with a 
quota cut that begins on April 1.
    As this chart shows, the natural gas composite spot prices 
have also been very high, averaging $5.50 per 1,000 cubic feet 
last year. That is a 70 percent increase over 2002. And 
consumers are paying about $10 per 1,000 cubic feet which, of 
course, has added to the cost to the households across this 
country. We expect that price of roughly $5.50 per 1,000 cubic 
feet to be sustained over the next 2 years, given the supply/
demand situation.
    In the longer run, we do not think the $5 price is 
sustainable and we do see it coming down toward the end of this 
decade as alternative supplies in the form of Liquified Natural 
Gas (LNG) put some competitive pressure on that price, and 
prices may come down to below $4 per 1,000 cubic feet by 2010. 
But we will be, of course, watching that market very closely as 
we approach that period.
    We then see prices rising after 2010 in our long-term 
outlook, shown in this chart, depending very much on the 
success rate in the drilling in this country and the ability to 
bring in the Alaskan gas and LNG at the cost that we now 
foresee.
    So clearly we are in a situation in this country where our 
traditional sources of gas are declining and we will need to 
rely on nonconventional sources, coalbed methane, tight sands, 
and shale gas, as well as Alaskan gas in order to achieve the 
31 tcf supply that we think we need by 2025.
    My final chart, Mr. Chairman and members of the committee, 
is the oil outlook for the period through 2025, and we do 
expect oil prices to stay in real terms in that $25 to $27 per 
barrel range. But we know the volatility that has been 
witnessed in recent decades, and we certainly expect that 
volatility will continue. Therefore, we need to be prepared to 
deal with what I would label as an asymmetrical risk toward the 
higher end of our price forecast.
    Therefore, Mr. Chairman, I will conclude by saying we are 
facing high and volatile oil and gas prices in the short run, 
and, although we expect some tempering of that in the long run, 
it will mean continued and increasing import dependence for 
both oil and natural gas.
    Thank you once again for this opportunity.
    [The prepared statement of Mr. Caruso follows:]

Prepared Statement of Guy F. 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 outlook for 
energy markets in the United States and recent developments in world 
oil markets.
    The Energy Information Administration (EIA) is the 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 Department of Energy, other 
government agencies, the U.S. Congress, and the public. We do not take 
positions on policy issues, but we do produce data and analysis reports 
that are meant to help policymakers determine energy policy. Because 
the Department of Energy Organization Act gives EIA an element of 
independence with respect to the analyses that we publish, our views 
are strictly those of EIA. They should not be construed as representing 
those of the Department of Energy or the Administration.
    Each month, EIA updates its Short-Term Energy Outlook (STEO), which 
contains monthly projections through the next two calendar years, 
taking into account the latest developments in energy markets. Once 
each year, EIA updates its longer-term outlook in the Annual Energy 
Outlook, which currently provides annual projections for U.S. energy 
supply and demand through 2025. My testimony today is based on 
projections from the February 2004 Short-Term Energy Outlook and the 
Annual Energy Outlook 2004 (AEO2004).
    These projections are not meant to be exact predictions of the 
future but represent 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, subject to many random events that cannot 
be foreseen, such as weather, political disruptions, strikes, etc. Many 
of these uncertainties are explored through the generation of 
alternative cases.
    The projections are not statements of what will happen but of what 
might happen, given certain assumptions. Because EIA does not propose, 
advocate, or speculate on changes in laws and regulations, one of our 
key assumptions is that all current laws and regulations remain as 
enacted. For AEO2004, that means, for example, that provisions in the 
current House and Senate energy bills, such as an Alaska gas pipeline 
tax credit, are not included in this forecast.

                               Oil Prices

    A combination of rising world oil demand growth and restraint by 
the Organization of Petroleum Exporting Countries (OPEC) has kept oil 
supplies tight and oil prices relatively high. EIA expects the average 
price of the benchmark West Texas Intermediate (WTI) crude oil to 
remain in the $28-$30 range through 2005, as shown in Chart 1.* price 
projections are based on our February 2004 STEO. We are currently 
reevaluating these projections for our March STEO, and we are likely to 
revise these projections upward due to the continued tightness in the 
market.
---------------------------------------------------------------------------
    * The charts have been retained in the committee files.
---------------------------------------------------------------------------
    This crude oil price projection from February would translate into 
an average regular gasoline price of about $1.57 per gallon in 2004. 
Last year, gasoline prices peaked twice in March and again in August. 
This year, the average retail price for regular gasoline is up 24 cents 
per gallon since December 29, 2003, with an increase of 3 cents per 
gallon last week alone. While the largest increase has been seen in 
California (up 51.4 cents per gallon over this period, with a jump of 
8.0 cents per gallon last week), there have been significant increases 
across the country. While it is still too early to know with any 
certainty how high prices will go this year, many signs are pointing to 
a tight gasoline market this driving season.
    A typical household has two personal vehicles, each typically is 
driven about 11,000 miles per year, with an average on-the-road 
efficiency of about 20 miles per gallon. Such a household would spend 
about $1,700 for gasoline in 2004--similar to last year's costs but 
about $200 above expenditures in 2002. Because there is a wide range of 
variation across households in the number of vehicles owned, vehicle 
efficiency, number of miles driven, and the local price of gasoline, 
the impacts of higher gasoline prices for specific households can vary 
widely from this average value.

                     Announced Cuts in OPEC Quotas

    On February 10, 2004, OPEC (excluding Iraq) announced that it would 
cut its production quotas, trimming 1 million barrels per day from its 
current quota beginning April 1. In addition, OPEC asked its members 
for a strong commitment ``to comply with the agreed production 
levels''. Recently, OPEC production has been more than 1.5 million 
barrels per day above existing quota levels. If OPEC production were 
actually reduced to the new quota levels, OPEC production would fall by 
2.5 million barrels per day--a decline of 10 percent. World oil prices 
increased by $2 per barrel in the first week following the OPEC 
announcement.
    ETA's February STEO, developed prior to OPEC's February 10th 
announcement, projects that actual OPEC production will decline during 
the second quarter of 2004 by 1.5 million barrels per day from February 
levels. Under this projection, OPEC would still be producing 1 million 
barrels per day above the new April 1 quotas, a plausible outcome given 
recent experience. EIA believes that this production is consistent with 
WTI prices staying in the high $20s to low $30s in 2004.
    There is always considerable uncertainty regarding OPEC's quota 
adherence and the size of any cutbacks that will actually be made. For 
example, OPEC announced on September 24 of last year that it would cut 
its quota by 900,000 barrels per day effective November 1, 2003. OPEC 
also emphasized the need for strict quota adherence, much as it did in 
its February 10, 2004, announcement. Despite these public statements, 
actual OPEC production rose, not fell, and OPEC production is higher 
now than it was during September. Even with this higher production 
level, WTI spot prices increased from an average of $28 per barrel in 
September to a current monthly average of nearly $35 per barrel, 
largely because of rising demand and low inventory levels.
    OPEC has been successful during the past 5 years in adjusting 
production to keep prices from falling (Chart 2). As a result, the 
average price of a basket of OPEC oils has been within or above its 
stated target range of $22-$28 per barrel for 47 out of the past 52 
months.

                              Natural Gas

    Market factors are also keeping natural gas prices high. In 2003, 
the average natural gas spot price was about $5.51 per thousand cubic 
feet, about $2.30 per thousand cubic feet more than the 2002 average, 
for an increase of more than 70 percent. This increase was driven, in 
part, by the extraordinarily high level of storage refill requirements. 
We expect natural gas spot prices to retain most of that increase 
through at least 2005 as shown in Chart 3.
    Residential natural gas prices, which respond to spot prices with a 
lag, are expected to show an average increase of about $2.10 per 
thousand cubic feet between 2002 and 2004. The average household having 
a gas hookup in the United States uses about 82 thousand cubic feet per 
year. The expected 2-year increase means that households will pay about 
$815 in 2004, roughly $170 more than in 2002.

                          Winter Heating Costs

    With a significant part of the heating season now past, the 
estimated winter 2003-2004 household heating bills, compared to last 
winter, are as follows:

   Natural gas-heated homes: up by 11 percent. Despite some 
        decline in demand, residential prices this winter have 
        reflected increased gas acquisition costs accumulated since the 
        previous winter, as well as high near-term prices for spot 
        natural gas.
   Heating oil users: down by 1 percent. High crude oil costs 
        and strong heating oil prices in the Northeast have been 
        keeping bills for oil-heated homes high, but probably a bit 
        below last winter as overall demand this season is expected to 
        be slightly below the level seen in the 2002-2003 winter.
   Propane-heated households: up by 7 percent. In this case, 
        the average price increase is likely to offset the overall 
        decline in demand.
   Homes with electric heat: up by about 2 percent. Retail 
        electric rates are expected to be several percent higher this 
        winter, due in part to higher fuel costs. This offsets a modest 
        decline in demand due to weather comparisons.

    Households have generally seen relatively high costs for heating 
fuels since 2000. EIA estimates that for the three winters between 2000 
and 2003, a typical household (in areas where significant winter 
heating is required) probably paid an average of more than 40 percent 
more to heat the house than the average paid during the three prior 
heating seasons (Chart 4). It is worth noting that for homes heating 
with natural gas, heating oil, or propane, heating expenditures for 
this winter are shaping up to be more than 30 percent above the 
previous 6-year average.

                                  Coal

    Coal consumed by the electric power sector accounted for 92 percent 
of all coal consumed in the United States in 2002. For the first 9 
months of 2003, coal consumed to generate electricity was 2.9 percent 
higher than for the same period in 2002. Coal and nuclear generation 
are typically used to meet base load (the minimum amount of electric 
power required at a steady rate) demand. Year-to-date nuclear 
generation was down 2.3 percent. Coal-fired generation, up 2 percent, 
took up the slack in base load demand and was also used, whenever 
possible, to replace expensive gas-fired generation. Strong projected 
growth in electricity demand in 2004 and 2005, 2.5 percent in both 
years, will be the impetus for continued electric sector coal 
consumption. Electric sector coal demand is expected to increase by 1 
percent in 2004 and by an additional 3.4 percent in 2005.
    Despite demand growth of 1.9 percent in 2003, we estimate that the 
full-year data for total U.S. coal production will show a decline of 
about 1.7 percent in 2003. Increases in imported coal and stock 
withdrawals (from producer and secondary sources) helped meet the 
demand growth in 2003. Coal production is expected to rise in 2004 and 
2005 to meet the projected demand growth. Western region coal 
production is expected to continue its strong recent growth, while 
Appalachian and Interior production is expected to decline.

                           Natural Gas Prices

    In ETA's AEO2004 reference case, average lower 48 wellhead gas 
prices are projected to decline from 2003 levels to $3.40 per thousand 
cubic feet (2002 dollars) in 2010, and then increase to $4.40 per 
thousand cubic feet in 2025 (Chart 5).
    Wellhead gas prices rise over the long-term, because gas 
exploration and production costs are projected to increase as deeper 
and smaller gas reservoirs are brought into production to meet 
increasing demand. The rate at which gas exploration and production 
costs increase largely depends upon the future rate of technological 
progress. In the reference case, the future rate of technological 
progress has been set at the historic rate.
    Future rates of technological progress, however, could be higher or 
lower than what has been observed historically, resulting in gas prices 
that are lower or higher, respectively, than what is projected in the 
reference case. The two other scenarios shown in this chart, the rapid 
and slow technology cases, illustrate the impact of technological 
progress on wellhead gas prices.

                           Natural Gas Supply

    Total natural gas supply, from both domestic and foreign sources, 
is projected to increase at an average annual rate of 1.4 percent per 
year between 2002 and 2025, reaching 31.3 trillion cubic feet in 2025 
(Chart 6).
    Traditional sources of supply, associated and non-associated 
conventional production in the onshore and offshore, will remain 
important, meeting 39 percent of U.S. supply requirements in 2025, 
compared to 56 percent in 2002. However, U.S. natural gas supplies will 
become increasingly dependent on unconventional production from tight 
sands formations, shale, and coalbed methane, natural gas from Alaska, 
and liquefied natural gas (LNG) imports.
    Total non-associated unconventional natural gas production is 
projected to grow from 5.9 to 9.2 trillion cubic feet between 2002 and 
2025. With completion of an Alaskan natural gas pipeline in 2018 
(capacity of 3.9 billion cubic feet per day) and its expansion in 2023 
(incremental capacity of 0.9 billion cubic feet per day), total Alaskan 
production is projected to increase from 0.4 trillion cubic feet in 
2002 to 2.7 trillion cubic feet in 2025.
    Nearly all of the increase in U.S. net imports is expected to come 
from LNG. AEO2004 projects expansion at the four existing U.S. LNG 
terminals (Everett, Massachusetts; Cove Point, Maryland; Elba Island, 
Georgia; and Lake Charles, Louisiana) and, starting in 2007, the 
construction of additional facilities in the lower 48 States. EIA 
projects that between 9 and 12 new facilities will be constructed by 
2025. Total net LNG imports are projected to increase from 0.2 trillion 
cubic feet in 2002 to 4.8 trillion cubic feet in 2025.

                               Oil Prices

    The historical record shows substantial variability in world oil 
prices, and there is similar uncertainty about future prices. The level 
of oil production by countries in OPEC is a key factor influencing the 
world oil price projections incorporated into AEO2004. Three price 
cases allow an assessment of alternative views on the course of future 
oil prices (Chart 7).
    In the reference case, projected prices increase by an average rate 
of 0.6 percent per year from 2002, reaching $27 per barrel in 2025, in 
2002 dollars. In nominal dollars, the reference case price is expected 
to reach almost $52 per barrel in 2025. In the low price case, prices 
are projected to decline from their high last year, reaching $16.86 per 
barrel this year and remaining at that level to 2025. The high price 
case projects a price rise of 1.7 percent per year from 2002 to 2025, 
with prices reaching about $35 per barrel in 2025. The projected 
leveling off in the high price case is due to the market penetration of 
alternative energy supplies that could become economically viable at 
that price.

                       Oil Reserve Recalculations

    During the past two months, several prominent oil and gas companies 
announced that they had made large downward recalculations of their oil 
reserves at a time when there has been increased attention to oil and 
gas reserve estimates. The Securities and Exchange Commission has been 
reviewing its reserve reporting requirements for more than a year. In 
addition, the Enron failure and the Sarbanes-Oxley Act of 2002 have 
brought about generally increased attention to and scrutiny of 
corporate financial reporting of all types. Finally, there has been 
some concern that these downward supply revisions came at a time when 
world oil demand has been growing rapidly and oil prices have been 
rising. EIA believes that while these oil and gas reserve write-downs 
may be noteworthy and may be one of the variables affecting current oil 
market dynamics, they are not large enough on a world scale to support 
the argument that world oil supplies are in short supply or to 
influence world oil prices significantly.
    The reserve recalculations made by Shell and El Paso need to be put 
in perspective. These recalculations are notably large; however, 
companies revise reserve estimates from time to time. Revisions occur 
due to the inherent difficulty of precisely defining the concept of 
proved reserves and to the methodological difficulty of estimating 
proved reserves, because this estimation is subject to uncertainty even 
with improvements in technology.
    In 2003, proved oil reserves on a global basis are continuing to 
increases, and there were no comparable dramatic revisions in any 
country's oil reserve estimates. Global proved reserves increased by 4 
percent, or by 53 billion barrels, from the 1,213 billion barrels 
estimated in 2002, reflecting new discoveries in locations such as 
Africa. This upward revision dwarfs the comparatively small downward 
revisions made by Shell and El Paso. While these company revisions may 
represent a substantial portion of the companies' booked reserves, they 
account for only a small fraction of the world's proven oil reserve 
base of well over 1 trillion barrels. As a result, the reserve 
recalculations have not made much of an impact on world oil prices. 
Other factors, such as OPEC actions and tight world oil inventory 
levels, have been much more influential in influencing world oil price 
levels.
    The downward revisions in oil reserves by some companies never 
questioned the amount of the petroleum present but merely reflected the 
timing of its development. Several billion barrels of oil equivalent 
were moved from the proved category to the probable category. Proved 
reserves refer to discovered oil or gas whose amount is known and is 
considered recoverable in both the technical and economic sense. 
Probable reserves are those which are believed to exist but are not 
developed for production or shown to exist through drilling. Although 
these revisions sent a shock to these companies' stocks and to a lesser 
extent selected other energy companies' stocks, it was only an exercise 
in adhering to the correct reporting conventions and not a harbinger of 
the world running out of oil.

                                  Coal

    Total U.S. coal production is projected to increase from 1,105 
million short tons in 2002 to 1,543 million short tons in 2025 (Chart 
8) to meet increasing demand for coal in the electricity sector. 
Continuing the historical trend, Western coal production is projected 
to continue increasing over the forecast horizon, while production from 
Eastern coal mines remains relatively constant. With virtually no 
growth in coal consumption projected over the AEO2004 forecast horizon 
in the non-electricity sectors, the electricity sector share of total 
U.S. coal consumption is projected to increase from 92 percent in 2002 
to 94 percent in 2025.

    The Chairman. Thank you very much.
    The second panel: Richard Sharples, senior vice president 
of Strategic Planning and Marketing, Anadarko Petroleum. Would 
you proceed?

   STATEMENT OF RICHARD J. SHARPLES, SENIOR VICE PRESIDENT, 
     STRATEGIC PLANNING AND MARKETING, ANADARKO PETROLEUM 
                          CORPORATION

    Mr. Sharples. Yes, Mr. Chairman. Thank you very much for 
the opportunity to be here. We appreciate your leadership on 
energy challenges facing America, and I appreciate the 
opportunity to discuss particularly the EIA's forecast this 
morning.
    For frame of reference, Anadarko is the Nation's seventh 
largest producer of natural gas and most active explorer. We 
operate across the United States on and off shore in Alaska and 
have a significant presence in the Rockies. One point I would 
like to make is our only business, Mr. Chairman, is to explore 
for, find, and produce energy. We are not in the downstream oil 
and gas business.
    We commend EIA on its 2004 annual energy outlook report and 
we believe it does recognize many of the challenges facing oil 
and gas production and it realistically attempts to estimate 
our future potential.
    Given our limited time, I would like to focus my remarks on 
natural gas where our experience suggests that EIA projections 
may be overly optimistic. As you are probably aware, we are 
still several months away from having a full picture of what 
our 2003 natural gas production actually was.
    But early indications are that a production decrease, 
rather than the increase predicted by EIA, actually occurred. 
The initial reports from public companies, which account for 
about 70 percent of gas produced in the United States, actually 
reveal a decrease of 2 to 30 percent from 2002 production. 
Moving the starting point would obviously have a very 
significant impact on the expectations going forward.
    Additionally we are observing continuously deteriorating 
well performance, as mature basins are increasingly exhausted 
and this will further constrain future production growth.
    Based on our own analysis and experience in the field, we 
see three primary reasons why the EIA may err on the high side 
when it comes to supply forecasting. We believe the agency has 
overestimated the productivity for new wells, under-estimated 
the rate of decline of new wells, and under-estimated the unit 
costs. Additionally and significantly, the agency may have 
under-appreciated the significant time lags inherent in 
developing new resources. I address these points in much 
greater detail in my statement for the record.
    Natural gas is clearly destined to play an increasingly 
important role in America's energy future. Unfortunately, this 
rising demand will exceed our ability to produce gas 
domestically, forcing America to rely on imports, including 
LNG, to bridge the gap and relieve upward pressure on price.
    But the irony, Mr. Chairman, is that America is rich in 
natural gas resources. We do not have to become overly 
dependent on imports. We could and should produce much more 
here at home. When new areas are open for exploration, the 
industry will search for and likely will find new gas. The 
eastern Gulf of Mexico is an excellent success story where the 
MMS has expeditiously leased new acreage that will soon produce 
gas. We asked for access. You granted it in part and we acted 
on it.
    Last year Anadarko discovered substantial quantities of gas 
in four successful exploratory wells in the eastern Gulf, and 
these wells are expected to begin producing by 2007. I would 
point out Mr. Koonce's company is a partner in one of those 
discoveries.
    Unfortunately, many of the most promising natural gas 
prospects in this country, however, is still off limits to 
exploration because of moratoria or regulatory complexity. We 
commend Congress for resisting further restrictions. Even in 
the eastern gulf, most of the potentially 40 trillion cubic 
feet of natural gas is under moratoria, as are virtually the 
entire east and west coasts.
    In fact, the National Petroleum Council, in their 
comprehensive 2003 report on balancing natural gas policy, 
estimates that as much as 200 trillion cubic feet of America's 
technically recoverable undiscovered natural gas lies under 
Federal lands where access is either denied or restrictions 
cause projects to be uneconomic. Working through this 
regulatory maze frequently raises the cost of doing business to 
the point where it becomes more cost effective to invest scarce 
capital abroad. In these cases delay is effectively the same as 
denial.
    Let me be clear, though. We are not asking for permission 
to explore everywhere. For example, we do not want access to 
our precious protected wilderness areas or national parks. What 
we are asking for is more reasonable access to new resources, 
and we are committed to finding innovative ways to develop 
them. Environmentally responsible development is possible, 
especially when government and local groups and industry 
collaborate.
    But I point out there are no quick fixes or easy answers 
when it comes to energy policy for America. There are, however, 
important steps we can take to relieve our growing dependence 
on imported energy and lower the price paid by the American 
consumers. Many of them are contained in the comprehensive 
energy legislation pending before Congress, which we see as a 
good and necessary start toward American energy independence. I 
will not go through the details, but we think they are very 
significant points and you brought most of them up earlier, Mr. 
Chairman.
    Passing this energy legislation is an important first step 
to begin to address the issues and concerns raised by both EIA 
in their energy outlook and the National Petroleum Council in 
their 2000 report on balancing natural gas policy.
    Thank you, Mr. Chairman. I would be glad to address 
questions at the appropriate time.
    [The prepared statement of Mr. Sharples follows:]

   Prepared Statement of Richard J. Sharples, Senior Vice President, 
    Strategic Planning and Marketing, Anadarko Petroleum Corporation

    Mr. Chairman, I am Dick Sharples, Senior Vice President of Anadarko 
Petroleum Corporation. I thank you for your leadership on the energy 
challenges facing America and I appreciate the opportunity to 
participate in the Committee's consideration of the Energy Information 
Administration's (EIA) 2004 Forecast.
    Anadarko is the nation's seventh largest producer of natural gas 
and most active explorer. We are an environmentally responsible 
producer onshore and offshore, including pioneer deepwater leases in 
the Eastern and Western Gulf of Mexico. We have a major presence in 
Alaska and in the Rockies; we also have significant international 
energy investments. Our only business, Mr. Chairman, is finding and 
producing the energy America needs to prosper and grow.
    Anadarko commends the EIA on its Annual Energy Outlook 2004 report, 
which recognizes many of the challenges facing oil and gas production 
and realistically seeks to estimate future potential. We are generally 
comfortable with the Agency's outlook for domestic crude oil 
production.
    We do, however, have some concerns in the key area of natural gas 
where our experience and data suggest the EIA projections--especially 
in regard to domestic production--may be overly optimistic. In its 
estimates for 2003, EIA assumptions include a modest increase in 
domestic natural gas production. We believe that there has actually 
been a production decrease. I hasten to emphasize that we still lack 
some of the key production data for 2003, but initial reports from 
public companies--which account for 70% of the gas produced in the 
United States--suggest a 2-3% decrease in natural gas production from 
2002\1\. The difference between the EIA projection of a 1% increase and 
the potential 2-3% decrease we are sensing presents quite a divergent 
base upon which the forecast depends and could have important 
implications for the American economy and future energy policy.
---------------------------------------------------------------------------
    \1\ Based on surveys conducted by Jefferies and Co.
---------------------------------------------------------------------------
    Two of the fundamental factors bearing on our ability to respond to 
increasing demand for natural gas in this country are the facts that we 
are chasing an increasingly scarce resource and paying an increasingly 
high price to develop it. Over the decades we have found almost all the 
easy gas; we have developed the giant fields. Today, with demand 
increasing and with an environmental premium on natural gas, we must 
spend more to find less. We are seeing deteriorating well performance 
as mature basins are increasingly exhausted, further constraining 
future production growth. And--as a final irony--many of the most 
attractive prospects still out there are either under moratoria or 
encumbered by other access issues or regulations.
    Based on our own analysis and experience in the field, we see three 
primary reasons why the EIA may have erred on the high side when it 
comes to natural gas supply. We believe the Agency may have 
overestimated productivity per new well, underestimated the rate of 
decline of new wells, and underestimated unit costs.

               Productivity per New Well/Basin Exhaustion

    As noted above, we have been producing natural gas for generations 
in America, and we have found and produced from the most abundant and 
productive sources of gas. Today we are dealing with the concept of 
``basin exhaustion,'' which is a fancy way of saying that each 
incremental well we drill will bring on less natural gas than the 
previous well produced.
    For example, as you can see in Exhibit 1*, the first 1,000 
discoveries made on the Gulf of Mexico Continental Shelf added 40 
billion barrels of oil equivalent (boe), most of it natural gas. But 
the next 1,000 discoveries are expected to generate just 6 billion boe 
because the basin is so mature. In other words, the next 1,000 wells 
are 85% less productive than the first 1,000.
---------------------------------------------------------------------------
    * The exhibits have been retained in committee files.
---------------------------------------------------------------------------
    The National Petroleum Council (NPC) published similar findings in 
its September 2003 report, ``Balancing Natural Gas Policy.'' The NPC 
found that in 1990, wells drilled in the Lower 48 recovered 1.4 billion 
cubic feet of gas per connection; by 2001, the recovery rate had 
dropped to 1 billion--a 30% decrease over the decade.
    The maturation, or exhaustion, of our basins leads to progressively 
less total gas and less daily deliverability from each new well. 
Exhibit 2 illustrates the deterioration in well productivity in terms 
of daily production per well. Well performance was at its best in 1996, 
with the average well achieving peak production of 1,300 Mcf/d. By 
2002, the peak had steadily decreased to slightly over 800 Mcf/d, or 
nearly a 40% deterioration in productivity per well. Changes in well 
productivity must be accounted for when looking to future production 
potential.
    The EIA 2004 forecast discusses the challenges of maturing basins 
and declining well productivity, and assumes that reserve additions 
from onshore conventional natural gas wells, both exploratory and 
developmental, will add less than 1 billion cubic feet (bcf) per well 
to total reserves in each year of the forecast period. Much of the 
EIA's supply growth instead relies on unconventional reservoirs, many 
of which will have higher costs and higher decline rates. Although it 
is unclear what the AEO 2004 forecast assumes for costs and decline 
rates, Anadarko's experience in the field suggests that the EIA may 
still be underestimating decline rates and unit costs for new wells.

                             Decline Rates

    Production decline rates for both old and new wells are fundamental 
factors in determining prospects for future growth because they 
determine how much new gas we must bring into production each year 
simply to stay even. For example, today we must bring a minimum of 13 
BCF/day on stream just to replace the underlying decline. A decade ago 
the replacement figure was only 9 BCF/day.
    Steeper decline rates of new wells increase the threshold for 
maintaining flat production and impair our ability to grow supply. We 
simply cannot use historical decline averages to estimate future 
supply. Over the last decade, decline rates for new wells have 
steepened continually and significantly. Today, production from the 
average well in the U.S. declines 55% in the first 12 months; a decade 
ago the decrease was only about 35%.
    The type of wells we drill also has a profound impact on the 
decline rate. Tight sands formations, for example, have incredibly 
steep rates of decline. Exhibit 3 shows a production profile from 
Anadarko's tight gas production in Freestone County, Texas. These wells 
decline 75% from their peak in just two months! We would also note that 
much of the production increase posited by EIA relies on growth in 
tight gas. What we know about decline rates in these types of 
reservoirs suggests to us that it will be very difficult to grow tight 
gas production while we are on the treadmill of decline.

                    Unit Costs and Corporate Returns

    Not only does well productivity impact the challenges to supply 
growth, but it also makes rising unit costs a reality. If the well 
Anadarko drills today produces less gas than the well we drilled three 
years ago, then--on a unit of production basis, or a unit of reserves 
basis--our effective cost has increased. In addition, as we explore for 
new and increasingly scarce resources, we are forced to drill into 
deeper formations, move out further into deeper water, farther from 
existing infrastructure; all of these factors add significantly to unit 
costs.
    Tight gas represents a good example of higher cost development. 
Tight reservoirs require stimulation and the use of fracturing 
technology. Developing the tight formations requires well spacing at 40 
acres--compared to conventional 640 acre spacing. That means many more 
wells must be drilled. In our opinion, the wellhead prices indicated in 
EIA's forecast are therefore not likely to stimulate the volume of 
additional tight gas production to support their growth conclusions.
    Exhibit 4 demonstrates that companies operating in North America 
have seen production costs increase by about 30% over the past five 
years while finding and development costs have increased by 175% during 
the same period.
    Cost increases inevitably impact company returns. Even in a 
relatively high price environment, company returns have been eroding. 
Exhibit 5 below shows the decrease in returns on equity since 2000. We 
must have access to new areas that will deliver the returns needed to 
meet investor expectations.

           Comparison to National Petroleum Council Findings

    Our sense that increasing domestic production of natural gas will 
be a great challenge is also consistent with many of the key findings 
of a recent, comprehensive study of gas markets conducted by the 
National Petroleum Council. In its September, 2003 report, ``Balancing 
Natural Gas Policy'' the NPC concluded that natural gas production from 
the Lower 48 states could grow by less than one half of one percent 
annually through 2020 if moderate changes in policy were enacted to 
streamline permitting processes and allow increased drilling and 
development activity in the Rocky Mountains. The 1% growth rate which 
serves as the basis for the EIA forecasts could only be achieved 
through a dramatic improvement in opening new areas to production and 
reducing regulatory delays.

            First Steps: Improved Access and the Energy Bill

    Natural gas is clearly destined to play an increasingly important 
role in America's energy future. Unfortunately, this rising demand will 
exceed our current ability to produce gas domestically, forcing America 
to rely on imports, including LNG, to bridge the gap and relieve upward 
pressure on price.
    The irony is that America is rich in natural gas resources. We do 
not have to become overly dependent on imports. We could--and should--
produce much more here at home.
    When new areas are opened for exploration, we will find new gas. 
The Eastern Gulf of Mexico is an excellent success story, where the 
Minerals Management Service has expeditiously leased new acreage that 
will soon produce gas. We asked for access, you granted it in part, and 
we acted on it. Last year Anadarko discovered substantial quantities of 
gas in 4 successful exploratory wells in the Eastern Gulf, which we 
expect to begin producing in 2007. Unfortunately, many of the most 
promising natural gas prospects in this country are off-limits to 
exploration because of moratoria or regulatory complexity. We commend 
Congress for resisting further restrictions. Even in the Eastern Gulf 
most of the potentially 40 Tcf of natural gas is under moratorium, as 
are virtually the entire East and West Coasts.
    In fact, the National Petroleum Council, in their 2003 report 
(``Balancing Natural Gas Policy''), estimates that as much as 200 Tcf 
of America's undiscovered natural gas lies under federal lands where 
access is tightly controlled or where restrictions cause projects to be 
uneconomic. Working through this regulatory maze frequently raises the 
cost of doing business to the point it becomes more cost-effective to 
invest scarce capital abroad. In these cases, delay is effectively the 
same as denial.
    The same NPC study concluded that removing the Outer Continental 
Shelf moratoria and reducing the impact of conditions of approval on 
the Rocky Mountain areas by 10% per year for five years would add 3 
billion cubic feet per day to domestic production in 2020 and would 
reduce the average price of natural gas by as much as $0.60 in nominal 
terms--which translates into a $300 billion savings to consumers over 
20 years. That is compelling evidence of the extent to which we have 
constrained our ability to respond--here at home--to the energy 
challenge facing America.
    Let me be clear, we are not asking for permission to explore 
everywhere. For example, we don't want access to protected wilderness 
areas or National Parks. What we are asking for is more reasonable 
access to new resources and we are committed to finding innovative ways 
to develop them. Environmentally responsible development is possible, 
especially when government, local groups, and industry collaborate.
    There are no quick fixes or easy answers when it comes to an energy 
policy for America. There are, however, important steps we can take 
together to improve the situation and relieve our growing dependence on 
imported energy.
    Many of them are contained in the comprehensive energy legislation 
pending before the Congress which we see as a good and necessary start 
toward greater American energy independence. Specifically, it--

   Streamlines permitting processes for exploration and 
        development programs.
   Renews certain incentives like Section 29 tax credits, which 
        have historically proven effective in increasing U.S. supply.
   Reduces barriers to gas pipeline permitting and 
        construction.
   Imposes deadlines on appeals delaying offshore exploration 
        and development.
   Authorizes the Alaska Natural Gas Pipeline which can bring 
        35 Tcf of currently stranded natural gas to the Lower 48 
        states.

    Passing this energy legislation is an important first step to begin 
to address the issues and concerns raised by both the EIA in their 
Energy Outlook 2004 and the National Petroleum Council in their 2003 
report on Balancing Natural Gas Policy.
    Thank you again, Mr. Chairman, for the opportunity to address these 
important issues. I would be pleased to take your questions.

    The Chairman. Are you finished, sir?
    Mr. Sharples. Yes, sir.
    The Chairman. We are going to now ask--Mr. Koonce, were you 
going to testify?
    Mr. Koonce. Yes, sir.
    The Chairman. All right. You proceed and then we will go to 
Mr. Saunders.

      STATEMENT OF PAUL KOONCE, CEO, DOMINION ENERGY, INC.

    Mr. Koonce. Yes. Thank you, Mr. Chairman. My name is Paul 
Koonce, and I am the chief executive officer of Dominion 
Energy, which is a subsidiary of Dominion Resources, the 
Nation's third largest utility in North America, with a market 
capitalization in excess of $20 billion. We own and operate 
electric generation facilities, electric transmission lines, 
natural gas facilities, and natural gas pipelines throughout 
the Midwest, Northeast, and Mid-Atlantic regions.
    I also serve as second vice chairman of the Interstate 
Natural Gas Association of America and am here testifying today 
on their behalf. INGAA represents the interstate and 
interprovincial pipelines throughout North America and 
transports almost 90 percent of the natural gas consumed in 
America today through its 180,000 mile interstate pipeline 
network.
    My message to you today is clear. Congress can and should 
play a critical role in promoting a stable energy marketplace. 
It can do so by empowering the appropriate agencies with clear 
and undeniable authority to authorize the build-out of our 
natural gas infrastructure. As we speak, there are specific 
examples where market forces are calling for it, the private 
sector is willing to invest, and the greater national good 
would be served. Yet, the need is not being met.
    It is widely recognized that North America is experiencing 
a fundamental shift in the supply and demand for natural gas. 
Abundant natural gas resources exist in North America and 
worldwide and can supply the market at reasonable prices, but 
this desirable outcome can only come about with public policies 
that promote the development of resources and infrastructure 
needed to link national buyers and sellers across the Nation.
    Increasingly local, State, and Federal permitting conflicts 
leave projects designed to build those important links in 
limbo. As a result, consumers and project developers cannot 
achieve the benefits so important to a healthy economy. For 
example, just this past winter, New York City prices soared to 
more than $40 per million Btu. This occurred while gas prices 
in neighboring States remained relatively stable as compared to 
Gulf Coast prices. The principal cause for this disparity has 
been inadequate pipeline infrastructure.
    Let us be clear. Interstate pipelines and LNG terminals are 
important both to the interstate commerce and, in the case of 
LNG, foreign commerce. The Constitution clearly places the 
regulation of interstate and foreign commerce into the hands of 
Congress, and yet some individual States are developing 
arguments that usurp the authority of the Congress and the 
agencies that have been designated by Congress to improve such 
facilities, namely the FERC. When one State is given the power 
to veto multi-State projects, be it pipelines or LNG, then all 
States will eventually suffer the consequences.
    This is one of the reasons Congress passed the Natural Gas 
Act of 1938. The NGA empowers the FERC to determine whether a 
proposed interstate pipeline is in the public interest and, if 
so, where and how it should be constructed.
    The FERC has similar powers with respect to the siting of 
LNG terminals. Prior to the enactment of NGA, pipelines were 
approved on an individual State-by-State basis which led to a 
``beggar thy neighbor'' dynamic. The result: inadequate 
pipeline infrastructure prevailed for everyone. This is why 
Congress took action in 1938 and why Congress needs to, once 
again, assert itself in the interest of the greater public 
good. Legislation pending here in Washington can move the 
Nation forward with predictable, positive results.
    FERC's authority for siting natural gas pipelines must be 
respected by all Federal and State agencies. This has not been 
the case of late. For example, States have been delegated 
authority by the Congress to manage and implement the Coastal 
Zone Management Act, but some States are using the CZMA to veto 
interstate pipeline projects, to the detriment of entire 
regions. This is occurring despite the fact that FERC has 
already determined that these pipeline projects are in the 
public interest, that they meet the public convenience and 
necessity, which is a very high standard.
    I urge you to clarify Federal authority and approve and 
site interstate pipelines once and for all. While I will not go 
into all the details here, several key provisions of S. 2095 
would address these emerging impediments to interstate pipeline 
construction. This is why INGAA strongly supports passage of 
the comprehensive energy legislation.
    I also want to talk about another important segment of the 
natural gas industry, that is, liquified natural gas. While 
INGAA is predominantly an interstate pipeline group, INGAA's 
members include owners of the four operational LNG terminals in 
the United States and they are also among those companies 
proposing new terminals at various sites.
    The company I represent, Dominion, successfully reactivated 
the Cove Point terminal located on the Chesapeake Bay about 60 
miles southeast of here. Fortunately, FERC and the U.S. Coast 
Guard have streamlined the approval of onshore and offshore LNG 
facilities, but the need to obtain final approvals from other 
Federal, State, and local agencies, also acting pursuant to 
Federal and State law, will likely be a significant factor 
affecting how quickly LNG developers can respond to the demands 
of the market. In other words, the conflicts that now exist for 
interstate pipeline approvals are likely to also manifest 
themselves in LNG siting.
    We believe that codifying the Hackberry doctrine for LNG 
terminal construction and/or expansion, as proposed in S. 2095, 
is a positive first step. I would urge the Congress to continue 
monitoring the development of these terminals with an eye 
toward further clarification of FERC's authority to be the 
exclusive agency for determining whether these facilities 
should be built.
    Mr. Chairman, the provisions of the energy legislation 
dealing with pipeline and LNG terminal construction are not 
those winning big headlines, but they represent areas where 
changes in the statutory framework for U.S. energy policy can 
help ensure that there is adequate pipeline and LNG import 
infrastructure to serve the energy needs of the Nation's 
economy.
    Without an adequate natural gas delivery system, 
bottlenecks and higher cost for consumers and the economy will 
most certainly result.
    Mr. Chairman, thank you for the time to be here this 
morning, and I look forward to answering any questions.
    [The prepared statement of Mr. Koonce follows:]

Prepared Statement of Paul Koonce, CEO, Dominion Energy Inc., on behalf 
          of the Interstate Natural Gas Association of America

    Good morning. My name is Paul Koonce and I am CEO of Dominion 
Energy Incorporated, a subsidiary of Dominion Resources. I am 
testifying on behalf of the Interstate Natural Gas Association of 
America (INGAA). INGAA represents the interstate and interprovincial 
natural gas pipeline industry in North America. INGAA's members 
transport over 90 percent of the natural gas consumed in the U.S., 
through a 180,000 mile pipeline network.
    Dominion, headquartered in Richmond, VA, is one of the nation's 
largest producers of energy. Dominion's portfolio consists of nearly 
24,000 megawatts of electric power transmitted over more than 6,000 
miles of transmission lines, 6.3 trillion cubic feet equivalent of 
natural gas reserves, 7,900 miles of natural gas pipeline and the 
nation's largest natural gas storage system with more than 960 billion 
cubic feet of storage capacity. Dominion also serves 5 million electric 
and natural gas retail customers in nine states.
    The North American pipeline network provides the indispensable link 
between natural gas production and the local distribution companies 
that serve retail consumers. Natural gas represents 25 percent of the 
primary energy consumed annually in the United States, a contribution 
second only to petroleum and exceeding that of coal. Consequently, the 
natural gas pipeline delivery network is a critical part of the 
nation's infrastructure.
    It now is widely recognized that North America is experiencing a 
fundamental shift in the supply and demand equation for natural gas. 
INGAA agrees with the assessment that we are not running out of natural 
gas; rather we are running out of places where we are permitted to 
explore and produce it. Abundant natural gas resources exist in North 
America and worldwide and can supply the market with natural gas at 
reasonable prices, provided that public policies do not unreasonably 
limit resource and infrastructure development.
    An important corollary to this answer is the important role of 
pipeline and storage infrastructure in ensuring that natural gas supply 
can satisfy market demand. Two examples, one from a producing region 
and another from a consuming region, illustrate this point:
    The first example concerns how expanding the Kern River Gas 
Transmission Company interstate pipeline benefited both Wyoming 
producers and Nevada and California consumers. A year ago the prices 
received by Wyoming natural gas producers were sharply lower than those 
received by producers elsewhere in the West. The root cause of this 
disparity was that natural gas production in Wyoming exceeded the 
pipeline capacity available to export Wyoming gas to consuming markets. 
Wellhead prices in Wyoming fell to as low as 58 cents per million Btus 
(mmBtu) while wellhead prices in New Mexico--where pipeline capacity 
was much more prevalent--averaged about $1.60 per mmBtu.
    This situation changed dramatically last spring when the Kern River 
expansion entered service. Kern River doubled the capacity of its 
pipeline from Wyoming to Nevada and California. As a result, producer 
prices in New Mexico and Wyoming are nearly identical now. Downstream 
consumers in Nevada and California have benefited as well from the 
increased competition between sources of gas supply. Other proposed new 
pipelines will provide additional outlets for Wyoming production. For 
example, El Paso Corporation is working on a new pipeline, called the 
Cheyenne Plains Pipeline, that will move Wyoming gas to markets in the 
Midwest. I would note that Rocky Mountain production is projected to 
continue increasing in the future. Therefore, unless pipeline 
infrastructure can keep pace, there is the prospect that gas supply 
again will outstrip the take away capacity for moving it to consuming 
markets.
    The New York City market offers an example from the other end of 
the natural gas delivery chain. This winter, prices in New York City at 
times have exceeded $40 per mmBtu compared with average prices of $6 
per mmBtu at the benchmark Henry Hub in Louisiana. The blame for this 
``basis blowout'' has been laid squarely on the inadequacy of pipeline 
capacity for delivering gas into the New York City market. Pipeline 
capacity serving this market has remained the same for the past four 
years, despite steadily increasing demand. Because of this bottleneck, 
New York City residents and businesses pay much higher prices for 
natural gas than do consumers in other regions and even consumers in 
other cities in the Northeast. A recent study by the economic 
consultant Energy and Environmental Analysis concluded that consumers 
in the Northeast--and particularly in New York City--will continue 
having to pay unusually high natural gas prices until the bottleneck is 
relieved by the construction of new pipeline capacity entering the 
region.
    This begs the question: Why hasn't the New York City bottleneck 
been relieved already? Numerous projects have been proposed, but few 
have been built. The already daunting task of constructing interstate 
pipeline infrastructure in developed areas has been made even more 
challenging by concerted local opposition that is focused increasingly 
on the state and local permitting process. The irony is that such 
dilatory tactics are contributing to the significantly higher natural 
gas prices being paid by consumers who, in many cases, live within the 
same jurisdictions that these permitting agencies represent.
    The short-sighted focus of such opposition becomes apparent when 
one considers the consumer value that pipeline and storage capacity 
create by ensuring adequate energy supply and dampening price 
volatility. A perspective on this can be gained by comparing the cost 
of such infrastructure with the total cost of delivered natural gas. 
According to the Energy Information Administration (EIA), over the 
three-year span between 2000 and 2003, the cost of pipeline 
transmission and storage represented at most 15 percent of the average 
winter heating season price of natural gas paid by consumers in the 
United States. A bar graph illustrating EIA's analysis is appended to 
this testimony. Investing in adequate pipeline and storage 
infrastructure is a prudent insurance policy against the risks to 
consumers and the economy from the price shocks that can be caused by 
capacity constraints.
    What solutions are there to the natural gas supply and 
infrastructure dilemma now facing us? As the Committee is no doubt 
aware, liquefied natural gas, or LNG, has captured the attention of 
both energy policymakers and the energy industry after years of being 
only a miniscule part of total U.S. gas supply. LNG clearly is part of 
the answer to the natural gas supply and demand question. It is not, 
however, a ``silver bullet'' that single-handedly will solve the 
problem.
    While INGAA is predominantly a pipeline group. INGAA's members 
include the owners of the four operational LNG terminals in the United 
States. Dominion, in 2002 purchased, and last summer successfully 
reactivated, the Cove Point LNG terminal located on the Chesapeake Bay 
in Southern Maryland. Since that time we have received 38 ships and 
moved 105 Bcf of natural gas through the facility and into the mid-
Atlantic market. In addition, INGAA's members are among the developers 
of proposed LNG terminals. Consequently, we have some perspective on 
the issues associated with operating and developing LNG import 
terminals
    Federal regulators at the Federal Energy Regulatory Commission 
(FERC) and the U.S. Coast Guard have streamlined the approval of 
onshore and offshore LNG terminals. Still, just as with interstate 
pipeline projects, the need for final approvals issued by other 
federal, state and local agencies acting pursuant to federal and state 
law likely will be a significant factor affecting how quickly LNG 
developers can respond to demands of the market. Furthermore, if the 
hurdles are too high or if the approval process takes too long, LNG 
import facility development will be discouraged and project sponsors 
will deploy their capital elsewhere. On a related issue pertaining to 
LNG, I would like to commend the FERC for initiating a process to allow 
market participants to develop a consensus approach to handling the 
issues of gas quality and interchangeability. I am confidant that 
importers, pipelines, producers, and end-users will reach common ground 
on the issue.
    There also must be adequate pipeline take away capacity for getting 
LNG supplies to consuming markets. Richard Grant, the President and CEO 
of Tractebel LNG North America, which operates an LNG receiving 
terminal in Everett, Massachusetts, stated at a conference recently 
that unless something is done, ``[t]here will be 10 to 15 times more 
LNG capacity than (pipeline) takeaway capacity.'' This would be 
analogous to the situation in Wyoming that I addressed earlier; that 
is, too much natural gas supply trapped behind to little pipeline 
capacity. I can offer a specific project that clearly demonstrates the 
point: Dominion's recent announcement of plans to increase throughput 
capacity at Cove Point from 1 Bcf/day to 1.8 Bcf/day is dependent upon 
FERC approval of two associated pipelines to move that increased that 
capacity away from the terminal and into the market.
    An important natural gas supply option in North America is Alaska 
natural gas. The members of the Committee are very familiar with the 
proposal to construct a pipeline that would deliver natural gas from 
Alaska to the Lower 48. Current estimates suggest a natural gas reserve 
of approximately 35 trillion cubic feet on the Alaskan North Slope, and 
possibly even more. In just the last several weeks, two different 
groups have proposed constructing an Alaskan Natural Gas Pipeline. It 
is encouraging that two competing sponsor groups have come forward. 
This healthy competition promises to result in a project that is more 
innovative and less costly than many previously thought.
    These developments highlight the very real price that will be paid 
if the Congress fails to enact a comprehensive energy bill. Both the 
loan guarantees and the permitting process that would be authorized by 
H.R. 6 and S. 2095 are essential to making either of the competing 
proposals a reality. If we as a nation want natural gas from Alaska to 
begin flowing to the Lower 48 within the next decade, the legislation 
must pass soon.
    While LNG and Alaskan natural gas are promising sources of gas 
supply, they alone are not sufficient answers to the nation's natural 
gas supply dilemma. If the United States wants adequate supplies of 
natural gas at reasonable prices, it must pursue all available supply 
that can be developed in an environmentally responsible manner. This 
means that we must expand supply from the Rocky Mountain region, the 
deepwater Gulf of Mexico, and Arctic Canada, as well as from Alaska and 
LNG. Failure to do so will cost consumers, the economy and the 
environment.
    Let me now briefly review the public policies that affect natural 
gas pipeline construction and operation. Interstate pipelines are 
subject to economic regulation by FERC and safety regulation by the 
Department of Transportation Office of Pipeline Safety (OPS). Both 
agencies are widely recognized for their excellent work on natural gas 
pipeline siting and safety issues. FERC's leadership has emphasized 
prompt and thorough processing of pipeline construction applications 
and the agency's Office of Energy Projects has been very responsive to 
a wide variety of stakeholders in its review of pipeline applications. 
The OPS also deserves praise. The agency recently issued a wide-
ranging, balanced final rule governing pipeline integrity, pursuant to 
the Pipeline Safety Improvement Act of 2002. The pipeline industry also 
appreciates the role played by the White House Task Force on Energy 
Project Streamlining. The White House Task Force took the lead in 
executing a Memorandum of Understanding to coordinate decision making 
among the various federal agencies whose authorizing statutes give them 
a jurisdictional stake in some aspect of the pipeline permitting 
process.
    Yet, the pipeline industry has serious and growing concerns about 
the ability of federal, state and local regulators to erect impediments 
to efficient, timely pipeline construction. In particular, while the 
Natural Gas Act (NGA) provides FERC with the exclusive authority for 
determining whether proposed pipeline projects are in the public 
convenience and necessity, other agencies increasingly are using the 
jurisdictional hook provided by other laws to second guess the 
decisions made by FERC after a thorough review as part of the NGA 
certificate process.
    The prime example of this has been some state agencies' use of 
delegated authority under the Coastal Zone Management Act to question 
pipeline routes that already have been reviewed and approved by FERC. 
This is now occurring in at least three instances. The problem has been 
compounded by the procedures followed by the National Oceanic and 
Atmospheric Administration (NOAA) of the Department of Commerce in 
reviewing appeals from state decisions finding a proposal to be 
inconsistent with its coastal zone management plan. In the one appeal 
that has been fully litigated at the administrative level, NOAA spent 
18 months compiling its own record from scratch after the same issues 
had been thoroughly vetted as part of the FERC review process. This 
administrative delay created great uncertainty for the pipeline sponsor 
and penalized consumers by yet again postponing relief from the costs 
of the New York City pipeline bottleneck. These events also have cast a 
cloud over other pipeline projects in coastal states, including another 
proposal to serve the New York City area, as well as proposed LNG 
import projects that must run the same regulatory gauntlet.
    In order to realize the widely recognized energy security and 
environmental benefits that can result from abundant and affordable 
natural gas supplies, the nation must take steps that facilitate the 
development of natural gas supply and infrastructure. Several important 
provisions in H.R. 6, the comprehensive energy bill, and now S. 2095, 
would remove impediments to building pipeline and LNG infrastructure. 
These provisions include the following:

   The bills would amend section 7 of the Natural Gas Act to 
        authorize an appeal to the U.S. Court of Appeals for the D.C. 
        Circuit if an action by a federal or state agency unreasonably 
        delays or conditions the construction of a pipeline project 
        authorized by FERC.
   The bills also would specify that the extensive record 
        developed by FERC in its certificate proceeding must be used by 
        other agencies in any administrative appeals concerning a 
        project that has been reviewed by FERC.
   Reforming the Public Utility Holding Company Act will 
        encourage the capital formation necessary for building energy 
        infrastructure.
   As already mentioned, the Alaska Natural Gas Pipeline 
        authorization is critical to constructing the infrastructure 
        needed to bring this resource to consumers.
   The bills improve access to pipeline right-of-way corridors 
        across federal lands and eliminate uncertainties surrounding 
        the methodology used by the federal government in setting fees 
        for using such rights-of-way.
   The bills would codify FERC's ``Hackberry'' decision to 
        remove the open access requirement on new and expanded LNG 
        terminals.

    Congress may also need to further clarify federal supremacy in the 
approval and siting of pipeline and LNG terminals to be used in 
interstate and foreign commerce.
    In sum, while these are not the provisions in the energy bill that 
garnered the headlines, they represent areas where changes in the 
statutory framework for U.S. energy policy can make a real contribution 
to ensuring that there is adequate pipeline and LNG import 
infrastructure to serve the energy needs of the nation's consumers and 
its economy.
    Before concluding, I would like to highlight two additional issues 
for the Committee. The first deals with security and pipeline service 
surety. Because natural gas pipelines are a part of the nation's 
critical infrastructure, INGAA and its members have been working with 
numerous federal and state agencies in developing heightened security 
procedures. The Department of Homeland Security is now verifying these 
procedures through audits. A key part of this exercise is contingency 
planning for response and recovery should an incident occur. Along with 
the Department of Energy, we are modeling the effect and response to 
possible attacks/outages on key pipeline systems. We also are 
encouraging participation by the operators of other parts of the 
infrastructure so that we can appreciate better the interdependencies 
within of our national infrastructure and plan for how best to restore 
service in the event of an emergency.
    The second issue is the implementation of the pipeline integrity 
rule that I mentioned previously. The mandate that natural gas systems 
in populated areas perform ``integrity assessments'' is one of the most 
important provisions in the Pipeline Safety Improvement Act of 2002. 
The new law establishes strict timeframes for baseline integrity 
assessments and reassessment intervals. Beginning this year and 
continuing throughout the decade, significant pipeline segments will be 
removed from service in order to perform assessments and any resulting 
repairs. This unprecedented integrity program will almost certainly 
affect natural gas deliverability and delivered natural gas prices. The 
effect could be compounded because, coincidentally, the integrity 
assessments will happen during what could be a protracted period of 
tight natural gas supplies. We urge Congress to pay close attention to 
the implementation of this rule, particularly if significant service 
disruptions begin occurring.
    In closing, let me emphasize the importance of public policies that 
foster a positive environment for natural gas pipeline construction and 
investment. The interstate pipeline business model is not ``build it 
and they will come''. Rather, given the capital intensity of the 
pipeline business and its status as a regulated industry, pipelines are 
built only when a sufficient number of credit worthy shippers have 
committed to long-term contracts for firm service. Therefore, the 
overall health of the energy industry and policies that encourage 
shippers to make responsible choices in contracting for natural gas 
supply and pipeline capacity are important to maintaining sufficient 
natural gas infrastructure. The alternative is not desirable, because 
inadequate pipeline capacity creates supply bottlenecks that result in 
higher costs for consumers and the economy. Consequently, as it 
examines policies to increase natural gas supplies, the Congress also 
should promote policies that encourage a robust natural gas pipeline 
infrastructure.

    The Chairman. Thank you very much. Mr. Saunders, let's see 
if we can work you in with some answers to questions, and if we 
do not get in what you wanted to say, we will come right back 
to you. Let me proceed for a few minutes and yield to Senator 
Bingaman.
    We did not ask the Senator from Louisiana at the outset if 
she had anything. All right.
    Mr. Caruso, can you describe the general fuel switching 
abilities in the United States market between oil and natural 
gas and what barriers exist to fuel switching?
    Mr. Caruso. Well, there are several hundred thousand 
barrels a day of fuel switching capability. The actual number 
is a bit elusive, but nevertheless, we have seen in the last 
two winters, as a result of high natural gas prices, increased 
demand for residual fuel oil and, in some cases, distillate 
fuel oil for electric power generation, particularly for 
interruptible customers. And as I mentioned, on average it has 
been between 300,000 and 400,000 barrels a day, as best as we 
can discern that, because this data is not reported on----
    The Chairman. That is a percent of the oil consumption. 
What would the percent be?
    Mr. Caruso. It is about 300,000 to 400,000 barrels a day 
out of a 2 million barrel a day demand.
    In terms of inhibitions or things that may--there are a 
number of State and local regulations which limit the number of 
hours that a utility, in particular, can burn an alternative 
fuel, in particular, oil. That certainly does put a significant 
limitation on the ability to switch fuels.
    And the second thing is that in the last 10 or 12 years, 
the technology of choice for electric power generation has been 
combined cycle gas turbines, and most of those new plants have 
been built with limited or no fuel switching capability. So we 
are becoming less flexible as a Nation.
    The Chairman. And that is the marketplace. There are no 
rules or regulations regarding it. That is the way they are 
building them.
    Mr. Caruso. That is correct.
    The Chairman. Again you, Mr. Caruso. Oil reserve 
calculations have been in the news a lot lately. In January, 
Shell announced a 20 percent cut in energy reserves. El Paso 
slashed reserves by 40 percent. Give us a brief explanation of 
what these cuts actually mean and whether they have made much 
of an impact on world prices.
    Mr. Saunders, when he is finished, would you give us your 
observations on his answers to these questions?
    Mr. Caruso. I think the reserve recalculations by Shell and 
El Paso were certainly notable and important for those 
companies, and certainly their stocks reflect that and Mr. 
Saunders may go into that more. In terms of the big picture, it 
is a relatively small change in terms of global reserves. For 
example, the Shell revision was 4 billion barrels and world 
proved reserves are 1.2 trillion barrels. So we do not see that 
as any general trend, as a writing down of the ultimately 
recoverable reserves.
    And the second thing is I do not think that has much of an 
impact on the current oil market or the current oil price.
    Finally, we certainly do not see this as some harbinger of 
the running out of oil.
    The Chairman. Mr. Saunders.
    Mr. Saunders. Mr. Chairman, thanks. By way of introduction, 
I am Jay Saunders. I am an equity analyst at Deutsche Bank, so 
I am concerned with these issues from a company perspective.
    We have checked this out with Shell and we, of course, have 
been worried about this spreading to other companies and have 
not found much evidence within the integrated space at least, 
and I think the EMP's as well, that this is an issue that is 
going to be widespread in the industry. However, I think there 
is a big problem with transparency, and SEC is concerned about 
this in the reporting requirements.
    I would reiterate what Guy just said in that I do not think 
this should imply that there is any less oil, say, or natural 
gas left in the world. Part of Shell's downgrade, for instance, 
had to do with the reclassification of reserves which hinged on 
not whether the oil was in place or the gas was in place, but 
whether they could get that oil or gas to market, whether it 
was commercial. So I think this is more of a timing situation 
in Shell's case, and in fact, there was a portion of that 20 
percent reserve booking that is going to be rebooked, I think, 
here, very soon because one of these fields became commercial 
with government sanction.
    So I do not think there is reason to be too alarmist here, 
but from an SEC perspective and a reporting perspective, I 
think it could be pretty beneficial to transparency in the 
equity markets.
    The Chairman. Let me follow with you, Mr. Saunders. We have 
been experiencing a period of sustained high oil prices. Do you 
think that the investment community now believes that these 
high prices are a new reality? Has the industry accepted the 
high prices to the point that investment behavior and 
expectations have changed?
    Mr. Saunders. It is a really good question because my piece 
of the business tries to value these companies on what we call 
mid-cycle prices, your long-range prices. Right now, for 
various reasons, there is an increasing thought that, well, our 
mid-cycle range is several dollars higher on oil and probably a 
dollar or two higher on natural gas.
    Personally I think we are in for 2 years of pretty high 
prices. My forecast is not too different from what Guy and his 
team have come up with at EIA. Longer term, I think we are an 
opportunity-rich world for oil and natural gas with high 
returns on our projections for internal rates of return.
    I do not think we are in a situation where we are going to 
have $30 oil forever, but I just think it is going to take 2 
years to bring these back down.
    But to get to the crux of your question, we are seeing that 
the psychology is definitely turning and there are theories out 
there that we are going to have relatively high prices forever. 
And you can see this actually in the futures curve of the oil 
markets. I mean, a year ago this time, you had prices that were 
at similar levels. Yet, your price 5 years out, say, on the 
NYMEX futures curve was about a dollar or two lower than it is 
now. Typically that price is an anchor far out and it does not 
move very much. Now we have a much higher price further out, 
which suggests, as you suggested, there was a change in 
psychology here.
    The Chairman. Mr. Caruso, I have a general question and I 
guess I should have had the answer many months ago, but I 
somehow did not. You have explained that waiting out there in 
the wings for new production of electricity from various 
sources of supply, that it has all moved in the direction of 
natural gas. You described that as not being very flexible 
because of what they are building.
    Do we know how many plants remain to be built where the 
companies have agreed that they are going to build natural gas 
burning power plants? Are there 5, 15? What is the number?
    Mr. Caruso. In our long-term outlook to 2025, we believe 
there will be 356 gigawatts of new electric power generation 
needed in this country and about 60 percent of that is 
estimated to be natural gas combined cycle units. So at least 
60 percent we believe will be new natural gas combined cycle 
units and about 30 percent coal-fired power plants, the 
remaining 10 being renewables, mainly wind. I see this trend 
continuing.
    The Chairman. Thank you very much. In just a moment, I am 
going to turn it over to Senator Bingaman or Senator Craig, and 
then we will proceed in a normal manner. We want to make sure 
that Mr. Saunders gets a chance to state what he would like. I 
have to go to a markup of the budget.
    But I want ask you, Mr. Sharples. I am getting very tired 
of hearing witnesses that I have a lot of confidence in, 
because they seem to know what they are doing, talk about the 
American production of natural gas. And they all seem to say, 
well, we still have a lot of natural gas in America, and I feel 
very happy and say is that not nice. We are going to get a lot 
of natural gas. And then comes the word ``but''. And the word 
``but'' is always followed by a sentence or two saying we do 
not know how to get it produced. There are too many obstacles. 
Then you follow on with statements like, ``but there is a lot 
of it there.''
    Other than Alaska, I am beginning to wonder what this is 
all about. I mean, is there really a net positive in terms of 
natural gas that is available in continental America that we 
are not getting because of rules, regulations, or something, or 
are we just kidding ourselves?
    Mr. Sharples. I think the first thing I would say, Mr. 
Chairman, is to call attention to the very comprehensive work 
in the National Petroleum Council, work which goes into area by 
area, basin by basin, and tight gas by tight gas, to answer 
your question in great detail.
    But in summary, I would say that we feel that we are going 
to struggle to grow as an industry our domestic resource. The 
question is how fast do we decline. In fact, if you layer onto 
that the LNG issue, it becomes a race between how fast do we 
decline the domestic resource and how fast can we bring in 
alternative energy. So we frankly get to the relatively almost 
arbitrary discussions, are we going to decline at a half a 
percent a year, 2 percent a year, or grow at 1 percent a year. 
I do not think there is a magic bullet within the domestic 
resource base that will solve the problem.
    The Chairman. Well, before I yield to Senator Bingaman, let 
me just state for the record, as far as my views are concerned, 
a few years ago I would have looked at this and said there is a 
chance we will catch up. But then I found out what was 
happening to the electricity generation plants of America, 
electric utilities. Everything was going to natural gas-
producing power plants. At one point there were 15 waiting to 
come on line. There were as small as 750, but most of them were 
1,000 megawatts. When I saw that and saw what was happening, I 
came to the conclusion that so long as we were going to have 
that as America's future instead of some other mix, be it clean 
coal, be it nuclear, whatever, that I never thought we would 
catch up, especially since so many other people are using it, 
the fertilizer industry, houses, all kinds of appliances. It is 
such a fantastic fuel.
    I remain now as the chairman of this committee very, very 
perplexed. Unless something happens out of Alaska that is a 
barn-burner, I think we are going to be getting further and 
further behind in terms of demand versus supply.
    You have implied today for the first time that I have heard 
that the solution may very well be LNG, whichever one of you 
said that. Did you say that, Mr. Koonce, or who said that?
    Mr. Koonce. I think we both said it.
    Mr. Sharples. We both alluded to it.
    The Chairman. That sounds neat, but to me, let me say it 
sounds very much like we just got out of one problem and we are 
jumping right back into another. The first problem was we let 
ourselves get into a mess where we cannot produce enough crude 
oil so we are stuck buying it from all over the world, friend 
and foe. We thought we were going to be great. We were never 
going to do that with natural gas. And it would seem to me, 
Senator, that we are right back there because, to the extent 
that we substitute LNG, it is going to be from someplace else 
in the world, not us. That may be a great plan.
    But I would hope that we would try first to produce some 
flexibility in terms of American production, but I am not sure 
we will get there. This bill sought to do that, but it has got 
some hang-ups right now. It would have tried to produce three 
other kinds in due course, plus a nice little shot of wind 
coming in.
    With that, I am going to yield to you, Senator Bingaman, 
and thanks to all of you for coming.
    Senator Bingaman. Thank you very much.
    I thought maybe before we ask any more questions, should we 
just ask Mr. Saunders to summarize his testimony so we have the 
benefit of that? I think that would be a useful thing. Why 
don't you go right ahead?

  STATEMENT OF JAY SAUNDERS, ENERGY ANALYST, DEUTSCHE BANK AG

    Mr. Saunders. Thank you, Senator Bingaman. I will just keep 
this short. I appreciate the opportunity to comment on what 
looks like to me another 2 years of high crude oil, natural 
gas, and petroleum product prices. I am coming at this from 
Deutsche Bank from an equity perspective. I am concerned about 
these prices for these commodities because there is a pretty 
strong correlation between those and equity performance.
    While I do not think that there is a permanently higher 
price level, as I mentioned earlier, for these commodities, I 
do believe it is going to take some time. It is going to take 2 
years to get us back to what has traditionally been a normal 
level for these prices.
    In the interest of time, I will just summarize with some 
bullet points here and request, of course, that this is entered 
into the record.
    World oil markets are caught in a vicious cycle of rampant 
demand, a cohesive OPEC, the weak U.S. dollar, a consequent 
increase in speculative froth on oil futures markets, 
production instability in Iraq and Venezuela and global 
terrorism. I do not think it is any mistake or any 
manipulation, say, that the west Texas intermediate crude price 
has approached the $38 per barrel that we saw this time last 
year in advance of the invasion of Iraq, which itself was the 
highest level since the Persian Gulf War.
    The largest influence on the oil markets are OPEC, which 
has been tweaking supply to keep prices high, and demand as the 
economy recovers, particularly in China. Together, both of 
these forces are keeping global oil inventories low.
    Low threats to OPEC's market share leads me to expect that 
the cartel can maintain prices at relatively high levels for 
the next 2 years.
    More close to home for the American consumer, these tight 
market fundamentals are making for what in my view will be 
another year of high gasoline prices. This summer when 
Americans hit the roads, gasoline inventories will be at least 
as low as last year when consumers paid $1.57 per gallon at the 
pump, and that is the same level that the EIA is forecasting 
for 2004 in full.
    There are some caveats to this. I think you could see 
gasoline's current price fade as you see refineries in the gulf 
coast and the east coast, as well as the Midwest, come up from 
annual maintenance. That should be happening early this month 
and then by the end of the month in the Midwest.
    You could also see a little bit lower demand. This time 
last year we were faced with very high gasoline prices and a 
similar outlook, as your demand really did not materialize, for 
several reasons, until the late part of the summer and we saw 
prices come off very quickly.
    Finally, you could see imports rise very strongly here 
relative to where they have been over the past several months.
    These high oil prices I think will aggravate the 
fundamental in other areas. We have talked about natural gas. 
Growth in liquified natural gas, LNG, I do not think is going 
to happen in any significant way until around 2007. Low U.S. 
domestic production and the declining rates that we have talked 
about until then are going to keep prices, I think, pretty 
high.
    Further, to gasoline. Just a few quick comments. I think 
what we need to look at here is the premium to crude, which is 
at a similar level right now as it was this time last year. The 
question I have is, are we going to see this price come off 
very quickly like we did last year when imports came and just 
pushed the price down, or are we going to see it actually rise 
further, or are we going to see it rise and then stay at that 
level for several months here?
    The answer to me lies, number one, in crude prices which I 
think are going to come down, but they are going to remain 
high. Our forecast this year is about $31 for west Texas 
intermediate, which is about $3.50, to get at the psychology 
question earlier, higher than what Wall Street analysts are 
estimating this year. If those crude prices come down to $31 
even, that is going to take gasoline with it, but because of 
these what we call boutique fuels in the industry--this is low 
sulfur gasoline that is starting this year and low sulfur 
diesel in 2006--I think this is going to put a relatively high 
floor on your product prices in addition to the elimination of 
MTBE not only in California but also in New York and 
Connecticut.
    So to me, to summarize all this up, I think you are looking 
at a pretty high crude price here relative to the $22 that we 
have seen over the long term, and to get out of this cycle of 
rampant demand and what has been relatively low non-OPEC 
production growth, as these companies try to move out of mature 
areas like the North Sea and the United States and into growth 
areas like the Caspian and West Africa and Russia that are more 
politically sensitive, I think as they enter this growth phase, 
it is going to take some time and it is going to keep this 
cycle of very strong demand relative to supply from OPEC 
constraint--I think that is going to keep the cycle going for a 
couple years. And it is only going to take a shock to get us 
out of this situation, maybe not as dramatic as we saw on 9/11. 
Of course, that took prices down for a brief period of time, 
but I think we need some kind of supply and demand shock near 
term to get us out of this cycle.
    Thank you.
    [The prepared statement of Mr. Saunders follows:]

  Prepared Statement of Jay Saunders, Energy Analyst, Deutsche Bank AG

    Mr. Chairman, I appreciate the opportunity to comment on what looks 
to me like another two years of high crude oil, gasoline and natural 
gas prices that will be prone to spikes along the way. As an energy 
equity analyst at Deutsche Bank my concern with the outlook for these 
commodities stems from the relationship of oil prices to equity 
performance. While I do not think that we face a permanently high price 
level for these commodities, I do believe we will not see a correction 
closer to historical averages until 2006 at the earliest.
    I'll highlight several points to summarize the current strength in 
oil prices, which in turn has led to high gasoline prices and fears of 
$3/gallon by the summer, and request that my full testimony be entered 
into the record.

   World oil markets are caught in a vicious cycle of rampant 
        demand, a cohesive OPEC, the weak U.S. dollar, a consequent 
        increase in speculative froth on oil futures markets, 
        production instability in Iraq and Venezuela, and global 
        terrorism. It's no mistake that WTI oil prices have neared the 
        $38/bbl level of a year ago, in advance of the Iraq invasion, 
        which itself was the highest level since the Persian Gulf War.
   The largest influences on the oil markets are OPEC, which 
        has been tweaking supply to keep prices at a higher level than 
        in the past, and demand as the economy recovers. Together these 
        have kept global oil inventories low and prices high.
   Low threats to OPEC's market share leads me to expect that 
        it can maintain prices at a relatively high level through next 
        year.
   More closely to home for the American consumer, these tight 
        market fundamentals are making for what in my view will be 
        another year of high gasoline prices.
   This summer, when Americans hit the roads, gasoline 
        inventories will be at least as low as last year, when 
        consumers paid $1.57/gallon at the pump, the same level the 
        Energy Information Administration (EIA) expects for 2004 in 
        full.
   There are some caveats that could allow gasoline's current 
        price strength to fade. Production could rise strongly after a 
        brisk maintenance period completes at refineries on the Gulf 
        and West Coasts, where operating rates were extremely low, and 
        the U.S. Midwest. Demand growth could slow. Imports may rise as 
        supply chases currently high prices.
   High oil prices will aggravate fundamental tightness in 
        other petroleum-based areas as well. U.S. natural gas markets 
        need more supply, but liquefied natural gas (LNG) will not come 
        until at least 2007. Low U.S. domestic production and rising 
        demand will keep prices high until then.

    Further to gasoline, which is particularly important to this 
discussion at this time of year, several questions need answering. Will 
prices come off current peaks into the spring, as happened last year? 
Will gasoline prices continue rising, as in 2001, before falling just 
as fast under the weight of an import rush? Will prices rise and stay 
high as imports fail to sate demand? On balance, I expect product 
prices to fall--U.S. product inventories are 4% higher than last year, 
and overall OECD inventories are not as tight either--but settle at 
relatively high levels, and maybe spike further in between.
    While the extent to which gasoline prices fall is uncertain, the 
pattern will likely be volatile due to a lack of surplus supply. 
Gasoline imports have dropped in volume due to demand diversion 
elsewhere. At the same time, the higher-quality nature of U.S. gasoline 
lessens the amount and complexion of these imports, which are more 
often coming from a wider variety of less stable countries and in a 
form that requires further treatment to make finished gasoline. 
Domestically, what have become specialty gasoline grades will be more 
difficult to make as summer emissions requirements constrict production 
capability. The production difficulties from these new fuels will only 
increase with new requirements through 2006 as the ingredients require 
more intensive manufacturing processes.
    A year ago, this committee faced a similar gasoline market only to 
have weak demand in the spring on wet weather and high imports ease 
prices. This year, we may not be so lucky as a stronger economy and 
declining automotive fuel efficiency with greater penetration of sport-
utility vehicles in the passenger car fleet drives demand. At the same 
time, gasoline production capacity remains constrained as cleaner 
product specifications usher in capacity closures and investment that 
has not translated, unlike in the past, into capacity growth. All these 
dynamics, in addition to a shaky Venezuela, which normally supplies 10% 
of U.S. gasoline imports, have the U.S. shaping up for another high-
priced driving season. Gasoline's price premium to crude has reached 
last year's peak, which occurred both a year ago and in August, and 
stand higher than at any time in 2002.
    The price outlook for crude oil, part and parcel of gasoline's 
prospects, looks similar. Non-OPEC production is growing only slowly as 
companies struggle to move from declining production in mature areas, 
like the U.S. and North Sea, to more politically-sensitive regions, 
like West Africa and the Caspian. Further, Iraq's problems are taking 
longer-and-longer to fix, and the risks of renewed civil unrest are 
rising into the summer's power transition. Finally, Venezuela 
production has recovered somewhat from the strikes of a little over a 
year ago but remains sensitive politically throughout the effort to re-
call President Chavez.
    The outcome of these dynamics, at a minimum, is another year of 
high prices--just yesterday Deutsche Bank moved from what originally 
was a bull view of $25.50/barrel for WTI in 2004 to $31, or about the 
level of 2003, against the Energy Information Administration's (EIA) 
$30.40 expectation. The trends into 2005 say that Iraq and Venezuela 
will still be struggling, Russian output growth could slow, and that as 
long as demand stays robust, OPEC can support prices again. We expect 
WTI to average $27 in 2005, or lower than the EIA's $28.38.
    Longer-term, I continue to believe the post-1999 price rally has 
taken oil markets to unsustainable levels, and the combined impact of 
higher non-OPEC investment and lower demand growth will cause a price 
reversion closer to OPEC's baseline revenue requirement of around $23/
barrel WTI. This shakeout could take two years. While product prices 
should flatten with the energy complex in general, the introduction of 
low sulfur diesel and gasoline, and the consequent complexities these 
introduce to the supply system, could support relative product prices 
into 2006. At the pump gasoline prices will fall with crude oil, and 
refinery run rates should rise following investment by more efficient 
companies. Finally, demand growth could slow with higher fuel economy 
standards, as the EIA assumes in the Annual Energy Outlook 2004 
(AE02004).
    U.S. natural gas prices, which seem more closely linked to oil, see 
similar upside pressure. While here again I do think prices will drop, 
with the LNG cavalry charge not coming until 2007 it will also take 
time and a demand downturn that may only come at the expense of the 
ongoing economic recovery.
    Only shock treatment may provide a near-term escape from the energy 
complex's vicious cycle, but a cohesive and comprehensive energy policy 
could soften the landing and help us avoid the cycle again.
    Further details from the Deutsche Bank Energy Team follow on all 
the topics I've mentioned.
    Easy OPEC discipline. OPEC's oil production remains hard to gauge, 
but there is a strong body of evidence arguing spare capacity is 
increasingly concentrated in Saudi Arabia. At the same time, structural 
decline in the non-OPEC regions is gathering pace, heightening the 
impression of supply tightness.
    In Venezuela, conventional oil production has been steadily 
declining since early 2001, even setting aside the collapse in 
production in January 2003. Venezuela conventional oil may well have 
reached a `Hubert's peak'. The government has already prioritized heavy 
oil projects ahead of conventional crude. These plays have the dual 
advantage of off-quota production, and international oil company (ICC) 
funding, and we suspect that setting aside the politics of the massive 
restructuring of state oil company PDVSA, that there are fundamental 
decline rate and conventional reserves replacement issues in Venezuela 
conventional crude.
    Nigeria's onshore and shallow water production--its conventional 
heartland--has clearly been impacted by civil unrest and under-
investment. Royal Dutch/Shell's recent reserves downgrade there was a 
reflection of the slow pace of infrastructure development, and, we 
suspect, the increasing complexity of onshore oil developments, 
combined with companies' reluctance to invest in marginal fields with 
heightened operating (read political) risk. Deepwater oil growth should 
halt the slide, but new delays are creeping into an already-long queue 
of potential developments. Nigeria seems to be running close to full 
capacity, and hardly looks a threat to OPEC discipline this year.
    The pre-war concept that Iraq's oil production would grow swiftly 
to 2.8 mmb/d and beyond, once the Saddam regime had been changed, is in 
tatters. Today, Iraq is pumping a mere 2.0 mmb/d. The Kirkuk fields and 
the `northern' pipeline that links them to Ceyhan are shut in due to 
security problems. The southern oil fields, in the Shiite areas, are 
exporting some 1.6 mmb/d via Basra, with potential for a further 0.5 
mmb/d in spring from the re-vamped Khor al-Amaya port. Behind that 
stark reality, there seems to be strong evidence that Iraq's oil 
facilities were systematically mismanaged and under-invested, and that 
oil-for-food vintage reports of dire declines from Saybolt, for much of 
the 1990's, were real, rather than politicized. Most troubling, armed 
militias seem to be guarding oil facilities, a tactic likely to 
degenerate into infighting, once Iraqi leadership is installed as early 
as June. For now, the Shiite regions in the south are producing oil 
from fields relatively untouched by sabotage. That situation could 
change quickly: the Shiite leadership wants elections quickly, against 
the wishes of the Coalition. The risks to Iraqi oil production from 
infighting are real. We expect Iraqi production to trickle up to 2.5 
mmb/d by year-end, again presenting no threat to the oil market in 
2004.
    Aiding OPEC's cause, non-OPEC production decline rates remain a key 
oil industry challenge. Larger publicly-traded IOCs are slowing 
investments in mature basins and shifting into replacement 
infrastructure-led plays. That shift takes time, and is leading to 
downward pressure on estimates for non-OPEC supply. West Africa deep 
water and Russia remain the core non-OPEC growth regions, and these 
plays, combined with base declines elsewhere, take us to a total non-
OPEC growth estimate of 1.1 mmb/d in 2004 (less aggressive than the 
ETA's 1.4 mmb/d). That rate of non-OPEC growth is 400 kb/d below our 
expectations for oil demand growth in 2004. That, combined with limited 
growth potential this year from Iraq, plays firmly into the hands of 
OPEC's price hawks, and points to strong oil prices in 2004.
    Robust oil demand. Estimated global oil demand growth of nearly 
2.0% in 2003 looks relatively healthy after three years of sub-par 
performance averaging only 0.7% per year 2000-2002. Oil use in 2003 was 
artificially boosted by at least 500 kb/d more than it would have grown 
without cold northern hemisphere weather, Japanese nuclear outages, 
high natural gas prices and low hydro levels in Europe, all of which 
led to fuel switching into oil. Nevertheless, even without these 
unusual events, oil demand would have been up a relatively healthy 1.0 
mmb/d. We look for demand to grow 1.5 mmb/d in 2004 and 1.6 mmb/d in 
2005, driven mainly by higher global GOP growth.
    The consensus estimate for global GOP growth in 2004 is 4.2% (and 
4.5% for Deutsche Bank), following a 3.3% rise in 2003. The current 
consensus for 2005 is 3.8% (DB). The average rate of global GOP growth 
calculated using IMF data over 1998-2003 was about 3.2% per year. In 
view of the above-average growth, and the potential for some of the 
``unusual'' factors of 2003 to persist into 2004, we see upside risk to 
our 2004 oil demand projection, especially given that China and the 
U.S. are both expanding at the same time.
    The U.S. accounts for about one quarter of the world's oil use, and 
despite the occasional impacts from fuel switching and weather, growth 
in oil is still largely determined by GDP. A year ago, the consensus 
forecast for 2004 GDP growth in the U.S. was 3.6% and now stands at 
4.6%, and 5.2% from DB. If achieved, this GDP would exceed the robust 
4.3% rate achieved in 1997-1999 when oil demand growths averaged 400 
kb/d annually. In 2004, we expect U.S. oil demand to climb to 20.4 mmb/
d, or a similar 370 kb/d (EIA 440 kb/d), and we expect at least 360 kb/
d growth in 2005, or less than the EIA's 480 kb/d on rising 
transportation and industrial use.
    As in 2001, China has had a major influence on high crude prices. 
Apart from the sheer volume of import increase to satisfy rising 
demand, China's relatively simple refineries require a higher-quality 
crude barrel, often from West Africa. These long-haul imports not only 
deprive the U.S. and Europe of incremental supply but also buoy freight 
rates, which in turn get passed through to crude prices. The signs of 
demand maturation evident in China in 1998-2001, when demand growth 
averaged 4.3% annually, have faded. In 2002 demand grew by over 6% and 
preliminary figures for 2003 suggest a rise over 10%. In 2003 China 
(5.48 mmb/d) surpassed Japan (5.43 mmb/d) as the second largest global 
oil consumer after the United States. The consensus on China's long-
term yearly economic growth is in the area of 7.5%, and the 2004-05 
estimates are above that. Economic restructuring could eventually lead 
to lower oil/GDP ratios, or a banking/currency crisis could unhinge GDP 
growth, however, near term expectations for strong economic growth 
could keep oil demand rising by 6-7% annually in 2004-05.
    Positive demand surprises elsewhere? An economic recovery is 
underway in Japan, where economists estimate GOP grew by 2.3% in 2003 
and expect it to grow at that rate again in 2004. This reversal comes 
after two years of stagnation. Furthermore, the nuclear crisis there 
that boosted oil demand in 2003 has not yet been completely resolved. 
GDP revivals are likely boosting oil demand in Argentina and Brazil, 
enhancing the prospects for the entire Latin American region outside of 
Venezuela. With rising cash flows from oil sales, oil consumption in 
the Middle East seems to also be growing robustly. In our view, the 
potential for demand upgrades in the non-OECD countries looks good.
    Downgrades to these forecasts could come from lower GDP, higher 
average oil prices, or the potential for atypical events (like a warm 
winter) to lower demand rather than increase it. The economic recovery 
in the U.S. seems well entrenched for 2004 and with interest rates 
still low at this point in the cycle, good growth in 2005 seems likely. 
Should China stumble, all of Asia could suffer, but the timing of such 
an event seems impossible to predict. Strength in Asia (including 
China) is probably encouraged by the nascent GDP recovery underway in 
Japan.
    OPEC and prices. Currency impacts suggest higher OPEC-driven dollar 
denominated prices as U.S. dollar weakness presents good justification 
for OPEC holding oil prices at the upper edge of its price band. OPEC 
ministers have been complaining loudly about the impact of the weak 
U.S. dollar on purchasing power. In January 2000 the U.S. dollar and 
the Euro were trading at about parity. It now takes about U.S.$1.25 to 
buy one Euro. Currencies fluctuate, and over the entire period since 
the start of 2000 when OPEC announced its $22-28 desired range for the 
OPEC basket price, the currency translation has been more often in 
OPEC's favor. Nevertheless, the North African and Gulf OPEC members who 
have significant trade with Europe are justifiably unhappy about the 
decline in the value of the dollar.
    As long as the U.S. dollar is weak, we suspect that OPEC will try 
hard to keep the Euro value of its crude from going much below $22, and 
this implies that the dollar price will hover near the $28 top (and not 
the $25 middle) of the OPEC band. We do believe that the Euro is likely 
to gain advocates for pricing oil in certain markets (Russian sales to 
Europe, for example), but the complications in switching the long-
standing international payment system suggest that this is unlikely to 
be a sudden move.
    One of the few bear cases for oil prices stems from speculative 
hedging against the weak U.S. dollar in U.S. dollar-denominated oil. 
Along with the popularity of commodities in general, speculative 
interest in crude oil has skyrocketed over the past few years. A 
strengthening of the U.S. dollar could spark a dramatic sell-off in 
crude futures markets. Further, a major psychological deterioration in 
perceived market fundamentals could do the same. Cognizant of this 
risk, OPEC has chosen to at least voice an intent to maintain 
currently-high crude prices, reflected in two consecutive surprises in 
quota reductions last September and early February.
    OPEC quota pressures low. Most of the OPEC countries have plans for 
capacity expansion, but the general trend for upstream capital spending 
within OPEC seems to have mirrored the ``modest'' pattern set by the 
international oil companies. Last September we estimated that OPEC's 
capacity to produce would total some 37 mmb/d in 2006. Our current 
estimate for 2006, following on Iraq's slow recovery, is more than 3 
mmb/d lower. Development of Iraq's reserves is almost certain to take 
longer than we anticipated last year, and although we still think Saudi 
Arabia can increase its capacity, we now see that rising at a slower 
rate.
    The ``success'' stories in OPEC capacity growth are almost 
exclusively found where international oil company (IOC) expertise and 
access to capital are employed. Algeria, for example, grew its capacity 
by 0.4 mmb/d between 1998 and 2003. With the removal of UN sanctions 
and the likely end of unilateral U.S. sanctions coming soon, Libya may 
be the next OPEC member to implement such a strategy. The good news for 
OPEC is that rising IOC production in many countries appears to have 
been accommodated via a dramatic decline in national oil company (NOC) 
production. The NOCs have effectively made room--or far more room than 
might have been expected--for the IOC output. This may turn out to be 
especially crucial as deepwater Nigerian production starts to flow. In 
the critical 2004-2005 period, we expect the likely inability of Iraq 
and Venezuela to make much progress in boosting capacity to be 
instrumental in maintaining cohesion within the cartel.
    Although we still see OPEC maximum capacity expanding by 2 mmb/d 
over the next two years (from 29.8 mmb/d in 2003 to 31.8 mmb/d in 
2005), almost 75% of this growth is in Nigeria and Iraq where plans 
could easily go awry. In Saudi Arabia, having, but not necessarily 
using, spare capacity is a policy.
    Longer-term reversion, but it will take time. We caution against a 
bullish, `$25 oil prices forever' view. Major oil companies have 
stepped back from mature basins spending and are investing in new 
production provinces. We judge that this will be a successful reserves 
replacement and volume growth strategy, but it will take time. U.S. 
foreign policy is clearly linked to generating oil growth from outside 
the Gulf region. That policy is closely aligned with company 
aspirations, and basically improves access rates to non-OPEC countries. 
Major oil company growth projects are being planned and/or built from 
the Caspian, Russia (proposals for the Murmansk and East Siberia 
pipelines), deep-water West Africa, and Canada oil sands. Deepwater 
Angola alone should be pumping 1.7 mmb/d by 2010 (from nothing in 
1998). In aggregate, we see non-OPEC growth adding 5.4 mmb/d for 2003-
08E, compared to demand growth of 4.4 mbd over the same period.
    That said, we see an interesting oil price `window' opening for 
OPEC in 2005. Russia's Major Oils are under intense political pressure 
and scrutiny from the tax authorities, after the Khordokovsky-Yukos 
affair. The impending divorce of Yukos and Sibneft leaves those 
companies at a strategic crossroads. At the same time, the government 
is mulling a tax increase, and dithering on routes, ownership and 
timing of the various new oil pipelines. Russia's growth credentials 
are intact, but delays are creeping in, and we suspect that 2005-
directed discretionary spend is slipping.
    We question the view that Saudi Arabia is suffering from 
accelerating decline rates. After all, the Saudis did ramp up 
production from 800 kb/d in December 2002 to 9.4 mmb/d in April 2003, 
to make up for oil shortfalls across Gulf War 2. However, OPEC has been 
ex-growth since 1998, and has had little incentive to invest for new 
production capacity since then. The OPEC oil system looks ill-prepared 
to fuel a sustained rally in OPEC oil demand, putting oil prices under 
upwards pressure when major supply regions wobble (for example last 
spring), or when consumption accelerates (for example this winter's 
weather and GOP combination).
    Mexico's oil industry is also at an interesting stage. Oil reserves 
have fallen 20%, lining up Pemex with SEC booking rules; giant oil 
producer Cantarell may have peaked; and capital spending needs to rise 
substantially from here. Mexico, not an OPEC player but a key element 
of previous OPEC/non-OPEC alliances, has little incentive to chase a 
growth strategy, or play for U.S. market share. The real decision rests 
in whether or not to bring in the Ions.
    The seeds of OPEC capacity growth are there. Deep-water Nigeria 
exploration could add 1.0 mmb/d by 2010. Kuwait continues to mull IOC 
involvement in its 900 kb/d Northern fields. Venezuela is poised to 
develop new conventional reserves (Tomoporo), and sanction heavy oil 
upgrades. Iraq increased its oil reserves by 33 billion barrels in 
2003, with a clear implication that growth investment is coming. OPEC's 
problem, and hence its reluctance to invest, is that most of these 
projects would be IOC funded. Approving these investments would create 
growth rates that could be hard to stop (witness Algeria in recent 
years). It may be far easier to delay the go-ahead for replacement 
projects, and play the upside in oil prices.
    Political events in 2005 also look supportive. Next year will see 
Venezuela's President Chavez fighting for his political life again. A 
recall vote might emerge this year, and with elections not scheduled 
until 2006, he can hardly afford an oil price crisis, and isn't 
investing enough now anyway for any meaningful growth next year.
    With no elections planned for Iraq until after the 2004 
presidential campaign, we question if there will be an administration 
in either of these countries that would dare allocate oil development 
contracts in Iraq to the IOCs. This year or next year could see the 
northern pipeline opening again--we are projecting 2.8 mmb/d by end 
2005--but equally, fractional infighting could continue to put downward 
pressure on production estimates, as is the case today.
    The Caspian and Angola look set to be the main supply growth 
regions next year. BP's BTC should be complete in the first half of 
2005, and beginning to fill in the second. However, the fields that 
will fill that pipe won't build up to 1 mmb/d until 2008, and the delay 
to Kashagan early oil to 2007-08 limits the potential to fill the pipe 
next year. We expect the FSU to add another 0.7 mmb/d, although that 
number could disappoint, given current political trends. All told, we 
see a similarly strong 2005 as the EIA, with our outlook for non-OPEC 
growth of 1.1 mmb/d (EIA also at 1.1 mmb/d) and demand growth at 1.6 
(EIA 1.5). With little momentum from Iraq, the OPEC players can hold 
their production flat again into 2005, whereas the EIA has 0.5 mmb/d 
for OPEC in 2005. We recently increased our oil price forecasts for 
2005 to $27 WTI on these supportive supply/demand trends and the 
outlook for a weak dollar.
    Downside oil market risks are real, but not until 2006. The oil 
markets are currently locked in a perpetual loop of low inventories and 
high prices. OPEC and unusual political events have kept production in 
check and demand has recovered from the setbacks earlier in the decade. 
Backwardation in the futures market provides a strong disincentive for 
the building of commercial inventories and that in turn keeps 
inventories low. The only way out of this circle is through the 
application of a demand or supply shock: an economic downturn, a very 
warm winter, surging Russian or Caspian production, a reversal of decay 
in Venezuela, or a flood of Iraqi oil. These are certainly worth 
discussion, but the general evidence on these topics points to 
incremental and not colossal shifts.
    The relationship between oil demand and changes in global economic 
growth is clear: GDP drives oil demand. The GDP crashes in 1974 and 
1980 unmistakably drove oil demand down and it is possible that these 
circumstances could be repeated. A simultaneous downturn in China and 
the U.S. might be enough to trigger a serious GDP shortfall, and this 
in turn could pressure oil prices. However, it is possible to argue 
that crashes in oil prices tend to be preceded by very sharp increases 
in real prices. The oil price extremes since the early 1970s typically 
have been associated with war. A number of economic studies have shown 
that consumer unease in the face of war reduces spending and it is the 
combination of higher oil prices and dramatically reduced consumer 
expenditures that causes GDP to plummet. It might take $35-40 real oil 
prices ($40-45 Brent) to cause a repeat of the big downturns.
    In China, leading indicators (money supply, bank loans) continue to 
decelerate. Among the G7 nations, a number of recent forecasts suggest 
industrial demand may peak this summer. In the developing countries, 
concerns are rising that industrial output is peaking now and could 
sharply drop into Q2-Q3 2004. The political rhetoric on high oil prices 
is increasing. Politicians in the U.S., France, Germany, and Japan have 
recently expressed rising concern over the level of oil prices and the 
potential negative impact that high oil prices could have on consumers.
    FSU production also presents downside. There is no question that 
Russia, Azerbaijan and Kazakhstan are likely to be the source of much 
of the non-OPEC supply growth over the next few years. The Former 
Soviet Union accounts for more than half of the entire non-OPEC growth 
in 2004 and 2005. Russian production is expected to grow by about 540 
kb/d in 2004, and 700 kb/d for the FSU (EIA 700 kb/d also), but this 
rise is about 50 kb/d lower than our prior assumption because of a 
downgrade to Yukos' production profile. The CPC pipeline in Kazakhstan 
should operate at a higher rate during 2004, allowing a rise of about 
100 kb/d. In Azerbaijan, the next big jump is expected to come from the 
01/2005 start-up of the Baku-Ceyhan (BTC) pipeline. In all of these 
countries, the potential for significantly higher output than our 
forecast is low and the possibility of timing downgrades is real.
    Status quo reversal in Venezuela? Venezuelan production appears to 
have stabilized at 2.7 mmb/d, including heavy oil. PDVSA has maintained 
close to normal production levels in Eastern Venezuela where fields are 
younger and the oil is lighter. Production in Western Venezuelan has 
leveled out after a sharp decline (over 500 kb/d) due to inexperience 
in maintaining old infrastructure and complex ``huff and puff' lifting 
methods. It seems plausible that the lost 500 kb/d could be recaptured, 
but serious problems involve the long-term loss of reserves due to 
reservoir damage and unbalanced water/gas injection. Outside estimates 
of the costs to restore overall capacity to 3.1-3.2 mmb/d by 2005 
suggest that it would take $11 bn. With neither the government nor 
PDVSA having the required investment, on top of tough fiscal terms and 
political uncertainties, it seems highly unlikely that foreign 
companies could make much of a difference in the short term.
    A flood of Iraqi oil? Iraq's main northern oil artery, the Kirkuk-
Ceyhan pipeline, is not operating. The poor state of the facilities 
appears to be at least as much of a problem as sabotage. It is possible 
that a restart could occur soon, but even if disruptions could be 
contained, flows above 250-50 kb/d would be unlikely. In the south, 
work on rebuilding Gulf port loading facilities at Khor al-Amaya has 
been underway for several months. Some 350-500 kb/d of exports could be 
flowing with immediate effect.
    Simply adding up the possible incremental exports (0.6-1.0 mmb/d) 
and assuming this amount of oil is available may not be sound. First, 
Iraq's oil fields are in dire need of reservoir management. Ultimate 
recovery has been reduced with field abuse, particularly at Kirkuk in 
the north. Until wells have been rehabilitated and new investment takes 
place, it may be unwise to project output growth that may not be 
sustainable. Second, the Shia population in south Iraq is supportive of 
the coalition, but there are indications recently that insurgents are 
trying to move south. If the protection of the Shia population becomes 
questionable, their support for the coalition could wane and southern 
oil facilities might then be vulnerable to interruption.
    U.S. SPR to the rescue? Another possible source of significant and 
easily accessible incremental barrels is the U.S. Strategic Petroleum 
Reserve. It is possible that oil could be sold or swapped out of the 
SPR and, in fact, this was done in the fall of 2000 by the Clinton 
administration just before the November 2000 U.S. presidential 
elections. The Bush administration has generally been opposed to the 
use of the SPR under almost any circumstances. Bush did not use it 
during the combined outages in early 2003 caused by the strike in 
Venezuela, the Iraq war and unrest in Nigeria. It seems difficult to 
believe that he would use it now. The U.S. Secretary of Energy has 
reiterated his support for the current fill program that has been 
adding almost 150 kb/d to global demand for oil, claiming that it was 
an ``insignificant'' part of 80 mmb/d of global demand.
    Crude oil tightness feeds into U.S. downstream. The year has begun 
with strong headline refining margins on low product inventories, in 
part driven by strong demand and an unusual amount of U.S. refinery 
downtime in Q1. With MTBE phase-out in H1 2004 further complicating the 
picture, we have increased our global refining margin forecasts from 
$3.12/bbl to $3.90, with much of that upgrade coming in Asia.
    U.S. gasoline remains the dominant force. U.S. gasoline demand 
continues to rise seemingly inexorably on a surging economy and 
declining fuel efficiency with greater penetration of sport-utility 
vehicles in the passenger automobile fleet. At the same time, refining 
capacity remains constrained on several levels. New product 
specifications, unlike in the past, do not seem to be adding capacity. 
In addition, imports have fallen in volume due to demand diversion 
elsewhere (China). Further, the import complexion has changed, with a 
greater percentage of imports being blending components, as opposed to 
finished gasoline, from a wider variety of countries. These dynamics 
have the U.S. shaping up for another high-priced driving season.
    Assuming gasoline demand continues to grow at 1.5% y-o-y and 
imports stay on trend for a 10% y-o-y decline, U.S. gasoline 
inventories would still enter the summer lower than last year's 206 
million barrels even with a relatively high capacity utilization rate 
and yield. Last summer, U.S. conventional-grade retail pump prices 
averaged $1.57/gallon, the same level EIA expects for 2004 in full. 
However, last summer was helped by a late demand surge and high 
imports. We expect strong demand, continued low imports and high crude 
prices to lend upside to $1.60/gallon retail pump prices.
    U.S. and Asian gasoline strength has contributed to a wide WTI 
price premium that also comes from depressed heavy grade values from 
conversion unit downtime. WTI's inflation plays into the hands of not 
only complex refiners but the East Coast, with also those with exposure 
to Brent-based crude. Brent's discount to WTI has averaged $3.80 so far 
in Q1, against a normal $1.50. The phase-in this year of low sulfur 
(Tier 2) gasoline, in addition to low U.S. crude inventories relative 
to Europe, have bid up light, sweet WTI, to East Coast refiners' 
advantage. At the same time MTBE phase-outs in California, New York and 
Connecticut, as well as tighter sulfur levels, are limiting finished 
gasoline imports. U.S. gasoline imports fell from 860 kb/d during Q3 
2003 to 720 kb/d over the four months through January, a month in which 
imports fell 15% below January 2003. Modest European refinery 
maintenance in Q2--900 kb/d vs 1.3 mmb/d during the previous three 
years--may help a bit during the critical spring build to the summer if 
Asia doesn't continue to divert that surplus away from the U.S. In the 
U.S., Q1 downtime is most prevalent in Marathon, Premcor, Valero, Shell 
and ConocoPhillips. This high rate of downtime points to firm headline 
refining margins, but erratic, and disappointing earnings in Q1.
    Apart from support from demand growth and capacity constraint, 
following on capital starvation from the Majors, fuel specification 
changes in Europe (2005) and the U.S. (2006) girds a longer-term 
downstream outlook. We expect a final Auto Oil 2 shift for remaining 
European countries in 2005, to low sulfur (10ppm) diesel. In the U.S., 
2004 began the sulfur reduction in gasoline to what will be 30ppm by 
January 2006, from 120ppm this year. More onerously, refiners have to 
have 80% of their on-highway diesel pool at a lower 15ppm sulfur level 
by mid-2006. Japan meets a less stringent 50ppm level in diesel at end-
2004. The larger companies have begun to upgrade for these changes, but 
the second tier players will leave the needed investments to the last 
minute (witness the maintenance scramble now for MTBE), tightening 
margins and raising product prices. Asia supply-demand could finally 
balance in 2006-07, after years of pain, although the history of this 
segment says that over-investment or a demand problem will stop that 
happening.
    China's role. China's growth has been meteoric, and looks to be 
constrained only by infrastructure--crude import capacity--rather than 
actual need. Last year new car sales rose by some 30% to 345,180 and 
crude imports increased by at the same rate (450 kb/d). Not only does 
China's gasoline-powered fleet look set to grow, but the government has 
also reversed a previous tack in support of diesel car construction. 
Refining capacity, even with the large numbers of small `teakettle' 
plants, seems stretched, reflected in the rise in Singapore refinery 
utilization from 61% in 2002 to 72% in 2003, or fully 170 kb/d. We see 
upside to our 350 kb/d Chinese growth forecast, and continued fuel oil 
imports (being used by the teakettles instead of crude oil) could 
maintain support at the bottom of Singapore's product barrel.
    Japan's role has also been significant. While China has claimed the 
headlines for Asia's downstream turnaround, Japan's role has been just 
as large. Reversing what had been three years of 2% declines, demand 
rose 120 kb/d (2.2%) in 2003 mostly on residual fuel from switching out 
of nuclear energy into oil due to downed reactors. Returning nukes and 
high inventories argue for a decline this year, but 7% y-o-y GDP growth 
in Q4 2003, and a consequent rise in estimates for 2004 to 2.4% from 
1.9% previously, bode well for demand. Further, refinery shutdowns have 
tightened the market. Although over-capacity still has some way to go, 
the seeds for a recovery seem sown.
    U.S. gas, as well, is troublingly tight. Coming out of what looks 
to be a historically (at least near-term) cold winter, strong weather-
adjusted withdrawals have shaped an inventory curve that looks to end 
the winter below 1,000bcf, rather than the 1,100 bcf end-winter level 
expected only a month ago. With the industrial side of the U.S. economy 
booming, and domestic dry gas production struggling, gas price strength 
is likely to remain a fixture. Although we expect 10 or so of the 35 
proposals for new LNG terminals in the U.S. will get built this decade, 
they cannot be completed in time to make much of a difference before 
2007. Until then, the only way to balance supply and demand (absent a 
really warm winter) is to have a high enough price to choke off demand, 
while trusting that the existing four terminal expansions are completed 
on time in 2005. We recently raised our U.S. gas price forecast for 
2004 from $4.20/mmBtu NYMEX to $5.00/mmBtu ($5.24 EIA NYMEX 
equivalent), and increasing our 2005 estimate from $3.50 to $4.25/mmBtu 
(EIA $5.31). Furthermore, we are now estimating a ``settling-in'' price 
in 2006 of $4.00/mmBtu.
    A strong U.S. industrial production recovery is underway. 
Reflecting a relatively more efficient demand base and deterioration in 
fuel switching capability, industrial natural gas demand seems to be 
recovering quickly. Of the larger sub-sectors, chemicals, petroleum 
(refineries), non-metallic minerals and primary metals categories are 
all experiencing growth, providing support for high gas prices. While 
high oil prices have inhibited switching, declining heat rates from 
electricity producers keeps natural gas competitive at $6/mmBtu in the 
winter when WTI oil is around $35/bbl.
    Preliminary data for 2003 suggest that U.S. gas production has been 
weak. While we were expecting good year-over-year comparisons for North 
American natural gas production for the independent producers (given a 
steady climb in the rig count over the last 12 months), we have not 
seen much growth so far, and the majors do not seem to be fairing any 
better. Some of the declines are due to shifts in corporate strategy as 
capital spending has shifted overseas. Texas Railroad Commission data 
(admittedly subject to upward revision) through October shows 
production down 1.3%, but is in contrast to the EIA's estimate for a 
2.2% rise for the same period. In view of what appears to be a 
deceleration in the gas production growth rate evident in the DOE's 
data, we are inclined to believe that our estimate of a 1% increase is 
reasonable.
    LNG deliveries have increased over last year from Trinidad train 
III, more than offsetting a temporary outage from Algeria. A decline of 
nearly 3% from Canada, partially offset by what seems to be weaker 
Mexican demand, should mitigate the downward impact of higher LNG 
volumes and flattish U.S. production. Deep-water Gulf of Mexico output 
continues to rise, and rig counts are up generally even if drilling 
remains suppressed in Wyoming's Powder River Basin. Overall we expect a 
1% gas production increase to be more than offset by demand to keep gas 
storage in the ``normal'' range and gas prices relatively high.
    Low storage could cause spikes. The difference in our model-
predicted storage withdrawals this winter against last is about 1.5bcf 
higher/day. The model does attempt to adjust for demand response to gas 
prices and oil prices, as well as production response to the rig count. 
Thus, the underlying demand against production `shortfall' to the above 
suggests that if the higher withdrawal persists, there would be a 
strong potential for a gas price spike to balance the market, unless 
the market is willing to go into winter 2004-05 with much lower storage 
than last year. Fixing this problem would be helped along by the 
addition of an incremental 30-50 gas rigs.

    Senator Bingaman. Thank you very much. Mr. Chairman, I 
would defer my own questions and allow Senator Wyden to go 
ahead and ask. He has to run off to the Budget Committee, so he 
can go ahead.
    Senator Craig [presiding]. All right. Please proceed.
    Senator Wyden. I thank my friend from New Mexico very much. 
I know everybody's schedule is busy.
    Mr. Caruso, a couple of questions for you because I am very 
concerned that there are administration policies being pursued 
now that are going to push gasoline prices up even higher, and 
I want to walk you through a couple of concerns just for a few 
minutes.
    You said in your testimony that oil supply is very tight 
right now and that that is a factor in pushing gasoline prices 
up. Given that, would you not say that it is a bad time for the 
Federal Government to adopt policies that would further reduce 
oil supply?
    Mr. Caruso. I would agree.
    Senator Wyden. But the administration is pursuing a policy 
that is doing just that, that would, in effect, compound what 
you think is a bad idea, and what the administration is doing 
is making the current supply situation worse by taking oil from 
this very tight market to fill the Strategic Petroleum Reserve. 
I guess my question is how do you justify going out and filling 
the Strategic Petroleum Reserve when experts are issuing all 
these warnings about gasoline supply shortages? It just strikes 
me as incoherent, but I want to give you a chance to respond.
    Mr. Caruso. The Secretary of Energy has asked me to analyze 
that very point. And our view is it does not reduce oil supply.
    Senator Wyden. It does not reduce?
    Mr. Caruso. It does not reduce oil supply.
    Senator Wyden. By taking it from the private sector and 
moving it into the Strategic Petroleum Reserve, it does not 
take it from the supply?
    Mr. Caruso. That is correct. We believe the world oil 
supply has not been affected by the addition last year of the 
120,000 barrels a day of oil, royalty in kind oil into the 
Strategic Petroleum Reserve. And the reason is that OPEC 
producers watch very carefully what is going on in the global 
supply/demand situation and they adapt to, in this case, that 
120,000 barrels a day of oil being put into the reserve instead 
of being on the market. That additional oil is being produced 
by OPEC. It is not a net loss in our view. It is a net zero.
    Senator Wyden. Well, why do you not supply us for the 
record that analysis because I think the idea of awarding long-
term contracts, as prices were actually spiking up, awarding 
contracts that are going to run through the summer at a time 
when prices go up just leaves me baffled. So I would love to 
see your analysis and take a look at it.
    Mr. Caruso. I would be happy to supply it.
    [The information follows:]

    This is in response to your request that the Energy Information 
Administration (EIA) provide you with its assessment of the impact of 
additions to the U.S. Strategic Petroleum Reserve (SPR) from April 2002 
to date on U.S. and global crude oil markets. The average SPR fill rate 
since April 2002 was 120 thousand barrels per day, with a monthly peak 
rate of 210 thousand barrels per day. Our overall assessment of how 
these additions may have affected oil markets can be summarized as 
follows:

   Given OPEC members' recent demonstrated ability to alter 
        production to influence prices, the actual impact of SPR 
        additions on oil prices could be close to zero. Had SPR 
        additions not been made, OPEC members who operate at variable 
        production levels may well have responded with offsetting 
        output adjustments, maintaining a price and inventory profile 
        identical to that which actually occurred. In this case, price 
        impacts at or near zero are entirely plausible.
   EIA has also developed a standard ``rule of thumb'' for 
        assessing the effect of unexpected disruptions to commercial 
        oil supply--that 1 million barrels per day removed from the 
        world market has a price impact of $3 to $5 per barrel. 
        Applying this rule, SPR additions, even at 200 thousand barrels 
        per day, would have a price impact of about 60 cents to $1 per 
        barrel. However, because SPR additions were announced and 
        anticipated by the markets, the standard rule may overstate 
        actual impacts.

    EIA is aware that some market analysts have recently suggested that 
the SPR additions have had a much larger impact on oil prices. For 
example, a representative of the Air Transport Association, was 
recently quoted in press reports as saying that SPR additions ``were 
adding enough demand to the world marketplace to drive up the price by 
more than $6 per barrel.'' In EIA's view, however, impact estimates 
this high (or even higher) use reasoning that does not withstand 
scrutiny.

   One claim made is that SPR additions, especially during a 
        time of rising crude oil prices, push prices higher by 
        exacerbating the tightness of the global oil supply/demand 
        balance. However, additions to the SPR at the average SPR fill 
        rate since April 2002, amount to only 0.15 percent of global 
        demand--hardly enough to drive a 25% to 33% price increases in 
        the global market. A variant of the same approach focuses on 
        the share of SPR additions in the overall change in oil demand. 
        However, as Paul Horsnell of Barclays Capital Research puts it, 
        ``The world consumed 29.2 billion barrels of oil in 2003, while 
        the SPR grew by less than 0.04 billion [barrels]. At the 
        margin, barrels of incremental global demand outnumbered the 
        SPR fill by about fifteen to one.'' [Note: EIA's figures are 
        slightly different, showing a ratio of 13.4 to 1.]
   Another line of argument focuses on the level of commercial 
        oil inventories, making the assumption that all of the oil that 
        has been added to the SPR would, but for those additions, have 
        flowed into commercial storage, resulting in much higher 
        commercial stocks than the current estimate (as of January 16, 
        2004) of 265.2 million barrels, the lowest level since 1975. 
        This reasoning, however, relies on key assumptions regarding 
        the operation of world oil markets that are both implausible 
        and mutually inconsistent:

     First, it assumes no supply response on the part of oil 
            exporters to a change in the level of SPR additions. Given 
            the pre-announced and steady pattern of the SPR additions, 
            it could reasonably be expected that major oil exporters, 
            which have increasingly in recent years sought to reassert 
            control over oil prices by managing output, would in fact 
            produce less if these purchases were not taking place, 
            rather than allowing an equivalent amount of crude oil to 
            flow into commercial inventories.
     Second, even in the unlikely event that supply remained at 
            an unchanged level in a scenario with no additions to the 
            SPR, the significant lowering of oil prices that the ``high 
            impact'' analysts claim in such a scenario should have 
            raised world oil demand above the levels that actually 
            occurred. Even with no supply adjustments (unlikely) there 
            would also have to have been no demand response to 
            significantly lower prices (also unlikely) for all of the 
            SPR additions made over this period to have shown up in 
            current commercial inventories.
     Third, oil companies are unlikely to have to have added to 
            commercial inventories if the SPR oil had been made 
            available. Company inventory positions are at current 
            levels because of cost cutting measures, better inventory 
            management techniques and fiscal incentives. Crude oil has 
            been available on the international market and the 
            companies have chosen to operate with leaner inventories.

 What Factors Does EIA Believe Have Significantly Impacted Oil Markets?

    Although you did not specifically request it, we thought you might 
also be interested in our assessment of key factors currently driving 
oil markets. Since early 2002, a number of important fundamental 
factors have contributed to high crude oil prices, including rising 
demand; OPEC production cuts; supply disruptions in Venezuela, Nigeria, 
and Iraq; and low inventories.

   The rise in crude oil prices to the $27-28-per-barrel range 
        in late summer 2002 only represented a recovery to the levels 
        seen prior to the terrorist attacks of September 11, 2001, 
        which depressed oil demand. By the second quarter of 2003, U.S. 
        economic recovery began to accelerate. Coupled with surging 
        Chinese growth and modest recovery elsewhere, strong economic 
        activity has boosted U.S. and global oil demand significantly. 
        Cold weather and fuel switching from natural gas to oil, both 
        last winter and since mid-December 2003, have added to demand 
        pressures.
   OPEC cut its output quotas sharply at the beginning of 2002, 
        in response to the sharp decline in prices after September 11, 
        2001. This fourth cut, in a series of reductions that began in 
        February 2001, sharply curtailed oil supplies just as oil 
        demand began its recovery. In less than a year, OPEC reduced 
        its ceiling level (for the 10 members excluding Iraq) by 5 
        million barrels per day, and actual production by up to 4 
        million barrels per day. This reduction in supply tightened the 
        global oil balance significantly, resulting in declining 
        inventories relative to normal throughout the second half of 
        2002. The roots of current oil price volatility trace to these 
        actions, since OECD stocks had already reached the near-record 
        lows seen in 2000 by November 2002, just ahead of Venezuela's 
        oil disruption.
   In December 2002, a strike by petroleum workers in Venezuela 
        drastically reduced global crude oil supplies. The impact was 
        felt most in the United States, the largest consumer of 
        Venezuelan crude oil. Nigerian production was also curtailed in 
        early 2003 due to unrest.
   Crude supply disruptions in Venezuela, Nigeria and Iraq in 
        late 2002 and early 2003 were not fully offset by increased 
        supply from other sources. While there can be no doubt that 
        Saudi Arabia and the OPEC 10 dramatically boosted production 
        following the Venezuelan outage, as well as prior to and 
        following the Iraq war, the initial increases were slow in 
        coming, with December 2002 and January 2003 aggregate 
        production levels down sharply from already-tight November 2002 
        supply levels. When the surge in OPEC supply did occur, the 
        bulk of the increase (excluding Venezuela) appears to have gone 
        to China and other Asian refiners, at least through the first 
        half of 2003.
   OPEC cut quotas twice during 2003, reducing global supplies. 
        The first was effective June 1, and they later agreed to cut 
        quotas again effective November l. While OPEC members continued 
        to produce more than their agreed-upon quotas, production 
        remained low enough to sustain WTI prices above $30 per barrel 
        for most of 2003.
   By the end of 2003, there was some recovery in product 
        inventories, but U.S. crude oil inventories reached their 
        lowest levels since the mid-1970s. While OPEC appears to have 
        sustained high production levels over the second half of 2003, 
        OECD stocks in November 2003 dipped back below November 2000 
        levels. Some recovery in either crude oil or product stocks 
        relative to normal has occurred over the last 6 months both in 
        the U.S. and worldwide, but supply has generally been 
        inadequate to meet improving oil demand and at the same time 
        rebuild both crude oil and product stocks. As such, the last 
        year has been characterized by a ``cycling'' of this shortfall 
        from region to region and product to product.

    Obviously, it is impossible to address in full detail all of the 
important factors affecting oil markets in a brief memorandum. Please 
feel free to contact us if you have any additional questions.

    Senator Wyden. To me it is not rocket science. Supply is 
really short. You all are taking it out of the private sector, 
moving it into the Strategic Petroleum Reserve. And if you are 
a consumer getting clobbered in Oregon and California and on 
the west coast, I think you are just sort of incredulous at 
this.
    Given the current west coast market situation with these 
huge price hikes in California and Oregon, could the closing of 
that Bakersfield refinery that I have been talking about this 
morning not cause west coast gasoline and diesel prices to 
increase even more?
    Mr. Caruso. Well, as I have said, it is a very tight market 
not only globally, particularly for gasoline in this country. 
The Shell refinery supplies about 2 percent of California's 
gasoline and about 6 percent of diesel. Clearly any reduction 
in refinery capacity does reduce the flexibility to meet a very 
tight market.
    Senator Wyden. So you think it could be a problem. Do you 
think the Federal Trade Commission should agree with my 
suggestion to look at this? Because I cannot find where you are 
going to make up that supply. As you know, on the west coast, 
it is unbelievably tight in California, Oregon, and Washington. 
And you have got these California officials saying they do not 
understand the case for it. Do you think the Federal Trade 
Commission should agree with my request and look into this, 
given the answer you have just given that this could bump up 
prices even higher?
    Mr. Caruso. The issue of whether the Federal Trade 
Commission should look into it is a separate matter.
    I am just giving you my assessment of what the impact on 
the oil market would be. Now, whether it is an FTC or 
Department of Justice or other issue, I could not really 
comment on that.
    Senator Wyden. At least you have given me an argument to go 
back to the Federal Trade Commission to use in terms of making 
the inquiry because to me, again, this is pretty obvious. There 
is no evidence other refineries are going to come forward and 
increase supply. You have told us that the supply shortage can 
bump up prices. So I am not going to quote from the movie, but 
something has got to give.
    Senator Craig. Senator, your time----
    Senator Wyden. Thank you, Mr. Chairman. I want to thank 
Senator Bingaman again for his thoughtfulness.
    Senator Craig. Senator.
    Senator Thomas. Thank you. Mr. Caruso, most consultants and 
industry sources reporting natural gas production--it will 
decline. Your proposal here or your study indicates a different 
view, an increase in production. How do you explain the 
difference?
    Mr. Caruso. I think both myself and Mr. Sharples agree that 
the resource base is quite large and the potential for adding 
to productive capacity is there.
    I think the big issue is will technological improvements 
and cost reductions allow us to exploit, in particular, the 
unconventional sources of natural gas, particularly in your 
part of the country, with tight sands in Wyoming, Colorado and 
Utah and shale gas and coalbed methane.
    We are very optimistic that given the resource base and 
given the improvements in technology production will increase. 
However, there is uncertainty about the infrastructure that was 
mentioned by both Mr. Sharples and Mr. Koonce and uncertainty 
about the access. Even when it is not on Federal lands, there 
are other issues that come up in the legal system. So I think 
that is the difference.
    Senator Thomas. The permitting and so on, which you all 
have something to do with, plays a role.
    Mr. Caruso. Yes.
    Senator Thomas. Mr. Sharples, much of the gas demand is 
electric generation and all the generators in the last 15 years 
perhaps or almost all have been gas. You do not mention 
anything about alternative fuels. Maybe we ought to be talking 
a little bit more about our largest resource of fossil fuel, 
which is not gas.
    Mr. Sharples. You are right. Senator, we do not have a lot 
of particular expertise in the arena of coal, but certainly to 
the extent that clean coal technology can be proven and we can 
meet the dual goals of protecting the environment and producing 
economical energy, I personally believe they should be part of 
the mix.
    Senator Thomas. Well, it seems that we have to make a 
decision that gas is much more flexible for many other uses, 
and in terms of a policy it looks like--let me read you a 
couple things.
    There has been a fundamental shift in natural gas supply 
and demand balance that has resulted in higher prices and 
volatility. This situation is expected to continue but can be 
moderated. Greater energy efficiency and conservation are vital 
near-term and long-term mechanisms for moderating the price. 
Power generators and industrial consumers are more dependent on 
gas-fired and less able to respond to utilizing alternative 
sources of energy. This is the recommendations or the ideas of 
the summary by the National Petroleum Council.
    Now, none of you have mentioned any of those things, more 
efficiency, conservation. Production is very important, but 
production is not the only factor here. Is that not right?
    Mr. Sharples. Absolutely. If I may comment. My purpose in 
referring several times to that study is that I believe that 
all the findings are significant and need to be considered in 
terms of--just using the title of that paper--Balancing Natural 
Gas Policy. I think there are approximately 10 findings in that 
study. I think all of them are significant and many deal with 
demand issues, energy efficiency, alternative fuels. My 
comments were directed to the one specific area that we know 
best which is gas supply.
    Senator Thomas. Yes, I understand.
    Mr. Koonce, I know I am about through here, but you talked 
about pipelines and the ability to do things. What about RTO's? 
You said the Feds have to have all the responsibility on 
interstate. If we could get effective RTO's, would that not be 
an opportunity for the States to be involved in what you do 
with transportation?
    Mr. Koonce. Yes, Senator. I am glad you asked the question. 
Our company operates 25,000 megawatts of generation and it is 
coal, oil, natural gas, and nuclear. And we are also the 
operator of the Cove Point LNG terminal and we are a producer 
of natural gas with about 6.3 tcf approved reserves.
    When we look at the full measure of the legislation that 
has been drafted, we are very encouraged by a number of things. 
One, we do not view that any one element of the package is 
really the magic bullet, but we do like the idea that there are 
deep gas incentives. There are deep water incentives. There are 
pilot projects to deal with permitting out in the Rocky 
Mountain basin. So combined with initiatives to improve access 
to natural gas supply, we also look at the electric side and we 
look at RTO formation and voluntary participation in that as a 
means to address some of the demand issues created by gas-fired 
generation.
    In our own region of the country in the last 3 years, we 
have developed about 6,000 megawatts of gas-fired generation to 
meet our on-peak demand. The energy bill that is drafted really 
incents all generators to try to achieve the most economic 
dispatch of generation, and added with that the time- of-day 
pricing element of this legislation so that people will be 
incented to use energy in on-peak versus off-peak hours 
efficiently.
    So when you take the combined dispatch of a large region, 
can you get a higher efficiency rate out of a coal plant to 
cause a gas-fired plant to not have to run on peak? Can you get 
those type of efficiencies? Can you change the consuming 
behavior through time-of-day pricing so that you get better 
utilization out of the existing infrastructure? That, combined 
with the LNG initiatives and combined with the production 
initiatives, we think serve to provide enough balance to allow 
all these measures to help solve the problem.
    Senator Thomas. Thank you.
    Senator Craig. Thank you, Senator.
    Senator Bingaman.
    Senator Bingaman. Thank you very much.
    Mr. Caruso, let me ask you about your view as to what can 
be achieved through a more aggressive approach to energy 
efficiency with regard to use of natural gas. My understanding 
is that this National Petroleum Council report that Mr. 
Sharples and others have referred to has in it--one of the 
approaches that they have in there, which is a more aggressive 
approach to energy efficiency, predicts that we can decrease 
overall gas demand to 26 or 27 tcf rather than 31 to 32 tcf by 
2025. Now, your predictions and your charts that you gave us, 
as I understand them, assume we are going to need 21 to 22 tcf 
by 2025.
    Mr. Caruso. 31 to 32.
    Senator Bingaman. 31. That is what I meant to say, yes, 31 
to 32.
    In reaching that conclusion, you evidently are discounting 
the prospect that we might actually reduce that number by any 
of these energy efficiency efforts that the National Petroleum 
Council refers to. Can you explain why you think that is not 
going to happen?
    Mr. Caruso. Yes. I think it is a little bit difficult to 
compare the NPC study with EIA's outlook because I am not sure 
what they are assuming for the actual price to get to that 
lower demand number. I have a feeling that a considerable 
amount of the reduction in demand is price-induced, which, of 
course, does lead to improved efficiencies.
    But I can say we have taken into account considerable 
improvement in energy efficiency even at the 31 tcf level. For 
example, the average new gas-fired combined cycle plant by 2025 
will be consuming 27 percent less natural gas than the existing 
fleet of natural gas-fired electric power plants.
    So as I understand the methodology of the NPC study, it 
sees a lot of the industrial demand for gas being ``destroyed'' 
by the high price, getting you down to the numbers you quoted, 
26 or 27 tcf compared with 31. We are certainly going to be 
looking in more detail at the NPC analysis. In our view most of 
that demand will actually continue to reside in this country as 
opposed to being moved offshore, for example.
    Senator Bingaman. Let me ask Mr. Sharples to comment on 
that. Do you think this NPC prediction that we could get gas 
demand down to 26 or 27 tcf by 2025 is just wishful thinking?
    Mr. Sharples. I do not believe it is wishful thinking. I 
think, though, it is a bit like the answer Mr. Caruso gave in 
terms of gas technology. We look at the tremendous improvements 
in energy efficiency that have been evidenced in the past, and 
if you try the very difficult role of predicting future 
technology improvements, there is an element of that embedded 
into this. But certainly at these prices, there will be 
tremendous incentives to use less. There will be tremendous 
incentives to institute, for example, time-of-day pricing so 
that we can balance the load a little bit. As capital stock is 
replaced, the tremendous incentive to purchase more energy 
efficient appliances. The NPC study assumes that you will see 
continued effect in that regard, not just moving demand 
overseas but influencing the decisions of both the industrial 
power generation, even the residential consumer to purchase 
more energy efficient appliances.
    Senator Bingaman. Let me ask Mr. Koonce about this Alaska 
pipeline, or any of the rest of you. I gather a lot of you 
build into your projections here--and Mr. Caruso, you do--a 
very substantial increase in natural gas production in Alaska, 
and that is assuming we will have a pipeline that will be built 
by 2017, 2018, and that is when you think it will come on line.
    We have this proposal that Mid-America has come up with to 
construct a pipeline, an alternative proposal. Would that 
substantially shorten the time period for getting that gas down 
here and dramatically increase the amount of gas we could see 
from Alaska in the near term? Do any of you have thoughts on 
that? Mr. Sharples, do you have any thoughts or Mr. Koonce?
    Mr. Koonce. We certainly are excited about the prospects 
and we are pleased that Mid-America has stepped forward and is 
attempting to take a lead in trying to bring about the 
development of this pipeline. Estimates say as much as 4 bcf a 
day could flow into the domestic infrastructure from this.
    Again, I think whether it is the Alaska natural gas 
pipeline or whether it is LNG infrastructure, whatever it may 
be, I think the most important thing we can do is to make the 
siting and the authority clear so that project proponents like 
Mid-America or Dominion or whoever else can know once and for 
all where they go and how they get the authority to put the 
infrastructure in place that they want to see happen. I think 
that is one step.
    I think more generally clear Federal authority in terms of 
siting will help the Alaskan pipeline development, but will 
also help LNG development and city development, be it New York 
City or elsewhere.
    Senator Bingaman. Thank you.
    Senator Craig. Senator, thank you.
    Now let me turn to the Senator from Louisiana.
    Senator Landrieu. Thank you, Mr. Chairman. I do have an 
opening statement I will submit to the record.
    Senator Craig. Without objection.
    [The prepared statement of Senator Landrieu follows:]

       Prepared Statement of Hon. Mary L. Landrieu, U.S. Senator 
                             From Louisiana

    Over the last few years our Committee has held a number of hearings 
on the volatility of energy prices in this country and their impact on 
the economy both for consumers as well as industrial end users. Much of 
our time has been spent focusing on oil and natural gas which account 
for about 65% of annual energy use. Today provides us with the 
opportunity to discuss the Energy Information Administration's (EIA) 
Annual Energy Outlook for 2004 on supply, demand and prices for oil and 
natural gas as well as coal, nuclear and renewable energy sources.
    As a Senator from Louisiana I am particularly interested in the 
analysis and testimony on the subject of natural gas. Not only does my 
State produce a considerable amount of natural gas for use by the rest 
of the country, ranking second among states in production, but we are 
also a significant consumer of natural gas. Louisiana is a hub of 
production for the chemical industry which uses natural gas as a fuel 
and as a raw material.

                                PROBLEM

    For almost 4 years, natural gas prices have remained at levels 
substantially higher than those of the 1990s. In fact, U.S. natural gas 
is the most expensive in the industrialized world.
    Industrial end users of natural gas like the chemical industry are 
facing a sustained period of high natural gas prices unlike in any 
period since the late 1970s and early 1980s. Key industries that rely 
on natural gas have responded over the past few years with curtailments 
in production, idling of plants, and in some cases permanent plant 
closures. While U.S. chemical makers have lost an estimated 78,000 jobs 
since natural gas prices began to rise in 2000, Louisiana alone has 
lost 4,400 chemical related jobs over the same span or about 15% of 
that work force.

                          HOW DID WE GET HERE?

    There has been a growing gap between demand and supply of natural 
gas on the horizon for some time. EIA in their Annual Energy Outlook 
for 2004 now projects that total U.S. natural gas consumption will 
increase from 22.78 tcf (trillion cubic feet) in 2002 to 31.41 tcf by 
2025. However, total U.S. domestic natural gas production is only 
expected to increase by less than half of that amount over the same 
period.
    The most dramatic growth in demand for natural gas is expected to 
be for electricity generation. Of the new electric generating power 
either recently constructed or about to placed in operation over the 
next few years, over 90% will be fueled by natural gas. Still, it is 
quite clear from EIA's analysis that the production necessary to match 
this demand is not there.
    The supply imbalance we face has been years in the making. Quite 
simply, we have pursued a policy that is in conflict with itself. On 
the one hand we encourage the use of natural gas in this country to 
meet our energy needs and environmental goals. Natural gas is viewed as 
a clean burning fuel to improve air quality and a low carbon-dioxide 
fuel to meet climate change targets. However, we have ignored the 
supply side of the equation. We promote the use of natural gas but 
restrict its production. As is indicated in some of testimony today, 
the increasingly mature basins we have produced over the decades are 
``exhausted'' and new prospects are either difficult to get to or off 
limits.

                           WHAT CAN BE DONE?

    I believe there are a number of options available to us, none of 
which will single-handedly solve the dilemma we face but all of which 
can contribute to improve the picture. Some of the ideas on the table 
should include:

   supporting efforts to incentivize the production of natural 
        gas such as those in the Energy Conference Report like Section 
        29 tax credits that will tap ``unconventional'' gas reserves 
        such as coalbed natural gas and issuing royalty relief for 
        ultra deep wells drilled on existing leases in shallow waters. 
        According to the Minerals Management Service (MMS), since much 
        of the infrastructure in these areas is already in place, the 
        new gas reserves could be brought into the market quite 
        quickly. In fact MMS anticipates that deep well incentives 
        could provide as much 55 tcf.
   taking advantage of the diversity of supply available in 
        this country--Presently, over 70% of our electricity generation 
        in this country comes from nuclear power and coal. While EIA 
        anticipates in their 2004 report that coal use will increase, 
        they do not appear as optimistic for nuclear energy. That fact 
        is no nuclear plants have been built in this country in 25 
        years. We should take advantage of this power source that 
        provides emission free electricity. To the credit of the 
        Chairman of the Committee there are provisions in the Energy 
        Conference Report that will encourage the production of a new 
        generation of nuclear reactors which can help our country meet 
        its energy needs and environmental goals for years to come;
   establishing a national renewable portfolio standard (RPS) 
        for electric utilities to encourage the production of renewable 
        sources of energy (wind, solar, et al.) and lessen dependence 
        on natural gas for electricity;
   OCS--Most of the Pacific Coast and Eastern Gulf of Mexico as 
        well as the entire Atlantic Coast are off limits to exploration 
        and production. Since this frontier was officially opened to 
        significant oil and gas exploration in 1953, no single region 
        has contributed as much to the nation's energy production as 
        the OCS. The OCS accounts for more than 25% of our nation's 
        natural gas and oil production. With annual returns to the 
        federal government averaging between $4 to $5 billion annually, 
        no single area has contributed as much to the federal treasury 
        as the OCS. In fact, since 1953, the OCS has contributed $140 
        billion to the U.S. Treasury. In light of these tremendous 
        contributions, it is particularly interesting to realize that 
        almost all of our OCS production comes from a very concentrated 
        area of the OCS, the western half, which really means offshore 
        Louisiana and Texas. 98% of the nation's offshore production 
        comes from this half of the Gulf of Mexico. In FY 2001, 
        offshore Louisiana alone accounted for almost 80% of total OCS 
        gas production. While it appears that the deeper and even 
        ultra-deep waters of the Western and Central Gulf hold some 
        promise we should establish what potential reserves may be in 
        those areas under moratoria.
   LNG--Presently, LNG provides about 1% of U.S. gas demand but 
        EIA estimates by 2025 LNG imports could increase to 15% of our 
        consumption. There four operational LNG terminals in the 
        continental U.S. right now including one in Lake Charles, 
        Louisiana. As of December, 2003 there were 32 active proposals 
        for new terminals. While I think everybody would concede that 
        LNG will be a significant part of the natural gas equation in 
        the future, there are some questions that need to be addressed. 
        Do we want our gas market to follow in the steps of our oil 
        market in 1970s where we rely increasingly on imports? Would we 
        be setting ourselves up for exposure to possible insecure 
        sources of foreign supply? Are world natural gas reserves 
        sufficiently dispersed compared to those for oil (Middle East). 
        According to Steve Brown, the Federal Reserve Bank of Dallas' 
        lead energy economist, ``LNG terminals are only attractive at 
        very high prices.'' So, what happens to the investment in LNG 
        if the price of gas drops. Presumably, the interest in building 
        these facilities is in response to the rise in prices. What 
        impact would a drop in price have on interest in LNG?

    Senator Landrieu. Thank you.
    I would like to focus my questions on, of course, the Gulf 
of Mexico, which is where Louisiana is squarely a leader. While 
I have supported, obviously, opening up other areas, Alaska, 
for natural gas, as well as I have supported the policies that 
would bring in liquified natural gas, I do have concerns about 
getting out of the fire into the frying pan with the same 
dependency outside our State. I would like to focus and just 
ask, a few questions about trying to clarify the amount of 
reserves in the Gulf of Mexico. There are three sections, 
eastern, central, and west.
    Could you all just either restate for the record, because 
some of you touched on parts of this, or jump in and help us 
try to understand what the universe of reserves may, in fact, 
be based on your best estimates and guesses, either articles or 
studies that have been published or your professional judgment, 
to try to give us a more accurate sense of what may be 
recoverable in the different sections of the gulf that we have 
not tapped? Because to me the expertise is in the gulf. The 
political stability of the gulf, the trained work force that is 
in the gulf all lead to trying to promote production in the 
Gulf of Mexico.
    Now, I understand about the Florida dilemma, but I do not 
want to get into that debate right now. I am just trying to 
understand. The Gulf is a big place. We have been drilling 
there now for almost 60 years successfully. Anadarko has 
several new--so breaking it down just as quickly as possible, 
eastern, central, and western, now that we can go almost 20,000 
feet deep, not quite yet, but we are going 15,000 feet deep, 
which may open up most of the gulf all the way to Cancun and 
beyond, tell us what we found and what you think is still 
there. I do not know, Mr. Sharples, if you want to go. Just 
gas.
    Mr. Sharples. I do not have numbers in front of me. We will 
research it and we will be happy to provide for the record, if 
we have internal estimates. I am not sure that we do.
    But I will say that there are still interesting things to 
do in the Gulf of Mexico. I discussed the eastern gulf. It is 
at the very early stages of development. History tells us there 
will be more big discoveries there. You tend to find the 
biggest fields first.
    Most recently the Eastern Fold Belt around our Marco Polo 
K2/K2 discovery, but a number of other discoveries by others is 
probably the most active area in the deep part of the Gulf of 
Mexico, very exciting discoveries. And some very interesting 
teasing, if you will, at very deep fusing levels where we are 
seeing people drill actually 30,000 feet, not 30,000 feet of 
water, but 30,000 foot total depth, water and well bore, with 
some potentially interesting discoveries. Very expensive 
initial dry hole cost to the tune of $50 million plus to drill 
an exploratory well. So it is still at the very early stages. 
It may or may not work economically.
    All that said, history says that deep water development has 
not been able to overcome the declines in the shallow water 
shelves, and I do not think they will. But I think that there 
are tremendous to do.
    Guy, do you have----
    Senator Landrieu. Before you leave that point--and I would 
like Mr. Caruso--but are there new technologies that will help 
us to explore more fully on the shallow shelf, or is it just 
drilled out?
    Mr. Sharples. As an explorationist, I would say that the 
jury is still out, in our opinion, on what is known as the deep 
shelf, drilling deeper wells in shallow water. There have been 
some very interesting discoveries and a lot of disappointment. 
That is an area that is receiving a lot of interest. I do not 
think it is a panacea, but I think we will make some 
interesting discoveries in the deep shelf.
    Senator Landrieu. Mr. Caruso, could you give us any more 
specific numbers just to sort of lay it out for the committee? 
Because it is something that we are very interested in. There 
are sections of the gulf that we realize are under moratoria, 
but there are sections that are not. If in this bill we have 
some incentives for deep drilling, some incentives that are 
being discussed for additional research and development, given 
that we know we have to increase supply and it only is going to 
come from Alaska, the Rocky Mountains, or the Gulf of Mexico. 
If we want it to come domestically, I think we need to get 
clear about what the real potential is in the Gulf and act 
accordingly based on what is politically possible, 
scientifically sound, and environmentally responsible. So can 
you add any more of maybe particularly the central and western 
gulf, since that is not under moratoria?
    Mr. Caruso. We would be able to provide those numbers for 
the record.
    [The information follows:]

          POTENTIAL NATURAL GAS SUPPLY FROM THE GULF OF MEXICO

    There are several indicators of the future potential for production 
from the Gulf of Mexico.
    Production was over 4 Tcf and Proved Reserves were 25 Tcf for both 
the Western and Central Planning Areas combined in 2002. The Proved 
Reserves are reasonably certain to be produced in the future.


                                               Production     Reserves
                                                  (Tcf)         (Tcf)

Central Planning Area.......................        3            19
Western Planning Area.......................       11            16
                                             ---------------------------
    Combined................................       14            25
                                             ---------------------------
        U.S. Total..........................       19           187
                                             ===========================


    Future potential also includes natural gas resources that have yet 
to be discovered.
    According to the MMS 2000 National Assessment, the mean estimate of 
``Undiscovered Conventionally Recoverable Resources'' for the Western 
Planning Area is 74.7 Tcf. For the Central Planning Area, the mean 
estimate is 105.5 Tcf. The Total is 180.2 Tcf.
    These 180 Tcf of technical recoverable resources represent a 
potential future supply roughly equivalent to the 187 Tcf of U.S. 
Proved Reserves of Dry Natural Gas in 2002. It will be decades before 
the majority of this estimated undiscovered resource is discovered and 
developed.

    Mr. Caruso. To the general point, we would agree we are 
resource optimists when it comes to the availability of 
additional resources and reserves to be added to our supply 
system from the gulf. And our forecast does have increases in 
the deep water gas, although it has been a little bit less 
optimistic as the drilling results come in, but still it is 
growing.
    The other area is shallow water deep gas that the MMS has 
recently revised upward its resource estimates for that 
component of the gulf.
    So we think there is considerably more gas to be developed 
although we are running harder just to keep up with the decline 
rate particularly in that region.
    Senator Landrieu. I know my time is short, but I would like 
just the courtesy of just one more question particularly to 
Anadarko.
    Senator Craig. One more, Senator, and then we will do 
another round if you wish.
    Senator Landrieu. OK.
    We not only want to try to help you get gas out of the 
shelf and off the coast--and we do it, we think, almost better 
than anybody, Texas and Louisiana, Alabama, Mississippi to a 
certain degree. But Louisiana and Texas have developed quite an 
expertise and we are proud of the expertise we have developed. 
We would like to help the country get a greater supply.
    One of the issues that has been brought to my attention 
that recently some of our yards--I know this is a little off 
the subject, but they have been unable to either compete to 
build the construction and the platforms necessary because of a 
number of things, the price of steel based on some decisions 
that have been recently made, and the lack of depth in some of 
our ports because the equipment now and the platforms are so 
large and so huge, that some of this is actually being 
constructed over seas and floated in.
    Can you comment just briefly? Because, Mr. Chairman, talk 
about adding salt to the wound. We are trying to help get gas 
out of the gulf, one of the few places in the country that is 
not just promoting it but welcoming it and urging it. And now 
we see, in some instances, some of the actual jobs being sent 
overseas and we do not even get the benefit of the tax dollars. 
So we are just in a place where we are just not sure what next 
step to take.
    I do not want to put the company on the spot. I know you 
all make these decisions based on your bottom line. But is that 
what you see happening?
    Mr. Sharples. To some extent, it certainly is. There are 
some things we cannot get around, like the depth of the water 
in the port to physically float the facility out.
    I think a best example is we had recently launched and 
installed a deep water facility. The hull, the underwater part 
was actually constructed in South Korea, but the entire top 
sides, all the work, all of the pipe fitting, all of the 
equipment was actually constructed in Texas and built in Texas, 
and they were brought offshore and put together.
    We need, as an industry, to utilize all the available 
capacity, and we just need to make sure that we do that.
    Senator Landrieu. But I want to know what Mr. Sharples said 
in conclusion to this committee, because the Senator from 
Tennessee and Alaska and Idaho have been so sympathetic and 
supportive, I want to make this point. The gentleman said the 
company is not responsible for the depths of the channels, and 
he is correct. But the Government of the United States is 
responsible for the depths of the channels. We have a policy 
where we are taking oil and gas off the shore of a State, but 
the people of that State cannot work on the facility because 
this Government refuses to take a few pennies--pennies--
generated by the taxes and keep those channels dredged so that 
American workers can do the work.
    So this is an issue, I just want to tell you, I am going to 
bring to this committee. It is not the companies' fault, but it 
most certainly does not seem like good policy when we are 
looking for jobs, looking for gas. We have got people who can 
do the work and have the gas and cannot keep it in Louisiana, 
Texas, and Mississippi, or Alabama.
    So that is all I will say. Thank you.
    Senator Craig. Thank you, Senator. Dredging is a problem. 
It took an environmental statement 5 years to clear in the 
lower Columbia River because of environmental law and concerns 
as to where you put the tailings. So there are a lot of 
complications out there that embroil us.
    Senator Landrieu. This was not environmental. It was 
funding. It was not environmental.
    Senator Craig. It was funding only. Well, I know there is a 
balancing there of combination. I agree with you. Resources are 
clearly necessary for that dredging purpose.
    Let me ask a question. I will move to our other colleagues.
    Mr. Caruso, let me read this first. Canadian Gas Production 
Outlook Week. This is yesterday. Exports of natural gas from 
Canada to the United States fell 1.5 bcfd through the first 10 
months of 2003, according to data from the National Energy 
Board, and was down to 8.999 billion cubic feet a day in 
October. The outlook for Canada's supplies is continually 
decreasing in 2004 and 2005 according to Consult Global 
Insight. Trans-Canada Corporation expects a .5 bcfd lower 
western Canadian production next year while the National Energy 
Board also expects decreases so quoted.
    Now, the reason I put that up probably becomes quickly 
obvious to you. I am aware that EIA, prior to last November, 
projected gas from imports from Canada increasing over the next 
several years, and since November, of course, they projected a 
flattening of gas exports to the United States.
    This, at least to me, was a surprise. Was that large 
decrease a surprise to EIA and do these figures change your 
confidence in EIA's projections made last year about Canada's 
ability to sustain the export volume that Americans have become 
accustomed to?
    Mr. Caruso. Yes, sir. In fact, that was one of the major 
changes we made in the Annual Energy Outlook this year, to 
reassess the Canadian resource base and their ability to 
continue to increase production.
    Senator Craig. How did you miss it? Or what happened?
    Mr. Caruso. We were much more optimistic about their 
ability to produce gas from coalbed methane and tight sands. 
Results have been much more pessimistic than we had thought. So 
we have revised downward our assessment of what Canada can 
produce and particularly what they can export. We now have an 
actual decline in Canadian natural gas exports to the United 
States over the next 2 decades.
    Senator Craig. I had the Energy Minister from Canada in my 
office yesterday. We were visiting, and I am looking at all 
their new figures of ebb and flow, not just in gas and oil but 
also in electricity.
    I know that creating an integrated North American energy 
market was a key recommendation of the President's National 
Energy Policy, and I am familiar with the efforts of Secretary 
Abraham to form the North American Energy Working Group. But I 
worry about our ability to accurately project exports from our 
neighbors. We rely quite heavily on Canada for natural gas and 
electricity.
    Has the working group developed a process by which EIA can 
assure that Canadian projections and U.S. projections are in 
sync given our rather heavy dependence on our resource-rich 
neighbor to the north? I am especially interested in EIA's 
understanding of the Canadian demand, supply, and delivery 
dynamics so that I can have a more complete picture. I think 
that all of us can have a more complete picture on these 
critical issues. They impact us.
    Mr. Caruso. Yes, sir. EIA is participating in the North 
American Energy Working Group. It is chaired on the U.S. side 
by the Assistant Secretary for Policy and International Affairs 
in DOE. But we are, in effect, their analytical arm in 
supporting this group and we work closely with the National 
Energy Board and the appropriate ministries within both Canada 
and Mexico.
    Certainly the National Energy Board report of July of last 
year was instrumental in changing our view of Canada's ability 
to deliver in terms of productive capacity.
    Senator Craig. Since we are talking about reducing gas 
demand, is it correct that a recent tax analysis by EIA found a 
3 percent reduction in gas demand and price with the addition 
of the 6,000 megawatts of nuclear power potentially projected 
in the energy policy?
    Mr. Caruso. Yes, in the Service Report we did for Senator 
Sununu of the Conference Energy Bill, which has now changed.
    Senator Craig. That was a product I think of Senator Sununu 
requesting an analysis.
    Mr. Caruso. Exactly. There was a tax credit for advanced 
nuclear capacity. It would have added 6 gigawatts of additional 
nuclear capacity, as well as some additional integrated 
gasification combined cycle for coal, adding 22 gigawatts over 
the next 20 years. And that would reduce the amount of gas if 
those tax credits were to become law.
    So, yes, there would be a reduction. I will supply for the 
record the actual percentage.
    [The information follows:]

    A recent Energy Information Administration analysis found a 
3 percent reduction in natural gas wellhead prices and natural 
gas consumption by power generators in 2020 due to the nuclear 
production tax credit (NPTC) provision in the Conference Energy 
Bill. Total natural gas consumption in 2020 was reduced by 1 
percent. However, by 2025, natural gas use in the power sector 
is only 2 percent lower than in the reference case because the 
NPTC is not expected to induce additional new nuclear capacity 
beyond the 6,000 megawatts for which it is provided, while 
electricity demand continues to grow. Impacts on natural gas 
prices also vary over time. For example, natural gas wellhead 
prices in 2025 are projected to be slightly higher than in the 
reference case because lower natural gas prices in prior years 
are projected to delay the second phase of the Alaska natural 
gas pipeline to beyond 2025.

    Senator Craig. That would be appreciated. Thank you very 
much.
    Let me turn now to my colleague from Alaska, Senator 
Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    Welcome, gentlemen. I am sorry that I was not able to hear 
your presentation this morning. I have had the opportunity to 
read through all of the testimony that was presented prior to 
the hearing this morning.
    I appreciate the fact that Alaska is recognized and 
contained within the solution when we are talking about meeting 
this country's demand for natural gas. We recognize that in 
Alaska we have got what the country needs. We just need to 
figure out how to get it to you.
    I always like to listen to my colleague from Louisiana. She 
and I share a great deal in common when it comes to energy 
issues. To hear her frustration over government policies 
inhibiting our activities or our ability to get the much-needed 
energy to Americans, it is a subject that we can entirely 
relate on.
    I do note, Mr. Caruso, in your statement that the 
assumption is that the Alaska natural gas pipeline will come on 
in the year 2018 or thereabouts. We in Alaska want to do all 
that we can to see that happen earlier. As you know, there have 
been several applications submitted to the State, one from the 
three major producers, one from Mid-America that was referenced 
by the Senator earlier, and there was a third application that 
was just submitted last week that relates to what we call the 
All Alaska LNG Line, which would be a spur line running down 
through the State of Alaska--liquified natural gas for 
transport to the west coast.
    This is something that has not been included in anybody's 
analysis, so far as I can see. It is something that we have 
been focused on in Alaska for some time. We want to make sure 
that not only do we get our natural gas to the markets in the 
Lower 48, but we also want to make sure that Alaskans have 
access to our own gas as well. So this is a project that we are 
following very, very closely.
    So a question to probably you, Mr. Koonce, because you 
mention in your testimony the two applications that are pending 
and recognize that with these applications, there is a promise 
to result in a project that is more innovative and less costly 
than many previously thought. We hope that you are right, that 
there will be that competition, there will be that incentive to 
move something along.
    First, a question to you as it relates to the possibility 
of an All Alaska Line or a spur and then how that might affect 
your analysis of getting gas to market through the pipeline 
across Canada or possibly LNG imports from Alaska. Have you 
looked at this project at all and would you like to share any 
comments?
    Mr. Koonce. Senator, I apologize. I have not. I am not 
acquainted with the LNG alternative that you speak of. But as 
an industry and as a company that participates in pipeline 
development, we are very anxious to see if we can move along 
the development of this pipeline and the resource base more 
quickly than 2018. It is our belief that it is needed more 
quickly than that when you look at the domestic decline.
    In my discussions with individuals from Trans-Canada, as 
well as Mid-America, and as a company that is in the local 
distribution business--we serve retail customers in Ohio and 
Pennsylvania and West Virginia--it is very important that the 
infrastructure be in place. But what is more important is there 
be supply contracts to back-stop the capacity.
    In my discussions with Trans-Canada and others about the 
likelihood of that project moving forward, what I tell them, 
sitting in the eastern half of the United States, what is most 
important is the project developers bring with them 
representatives of the producing companies who can make 
representations to fill that capacity with production. That 
really is what we are anxious to try to bring about because I 
think once local distribution companies sign up for capacity, 
they also want to know that there is supply that they can count 
on. They do not want to make one without the other. I think 
that is the area where probably the most work needs to be done, 
now that we have two competing proposals attempting to get this 
gas out of Alaska.
    Senator Murkowski. I want to make sure that we state 
clearly for the record--I have said it repeatedly to my 
colleagues, but it bears repeating here--that in order to 
facilitate an Alaska natural gas pipeline, we have got to get 
the energy bill through or certainly those components that 
allow for a natural gas pipeline, whether it is the permitting 
and streamlined regulatory review, certainly the financial 
incentives. All of these will be key. If we fail to do that, I 
am concerned that when we look at this chart that shows the 
growth in Alaska production, that that is pushed out even 
further.
    Based on all of the analyses that I have seen, we as a 
country cannot afford to push that curve out further because 
what happens is we increase our reliance on foreign imported 
LNG. Quite honestly, looking at the figures, recognizing that 
right now we import 1 percent of our LNG, but by the year--what 
is it--2025 we will be at a point where we are importing 15 
percent LNG, that is a dramatic increase in a relatively short 
period of time.
    Of course, the concern that I think we all share is that we 
get to that point with our natural gas that we currently are at 
with our oil where we are close to 60 percent dependent on 
foreign sources of oil. We do not want to go there with our 
natural gas when we have the reserves in this country. We might 
not be able to do 100 percent of it, but shame on us if we get 
to the point with natural gas that we are with oil.
    So I appreciate again the focus on Alaska, and I would ask 
all of you to help us educate the rest of the country on the 
need to bring Alaska's gas to market.
    Thank you, Mr. Chairman.
    Senator Craig. Thank you, Senator.
    Senator Alexander, questions?
    Senator Alexander. Thanks, Mr. Chairman. I agree with what 
Senator Murkowski had to say. The natural gas pipeline is not 
just an Alaskan concern, it is an American concern so far as I 
believe.
    I just have a single question. I am trying to understand 
LNG and what the cost of it will be, how reliable it will be if 
we are looking ahead 10, 20 years, what it will do to the cost 
structure of natural gas in this country.
    This afternoon I am chairing a hearing in the Energy 
Subcommittee on the future of nuclear power, and that reminded 
me that 90 percent of our new power plants have been natural 
gas. Given the skyrocketing price of that and the uncertainty 
of LNG, I just wonder what we can expect. I hear from some 
quarters that there is plenty of gas around the world. It can 
be put in LNG. It can come here. It can bring our price back 
down to $2 to $3. Everything is going to be fine for 10 or 20 
years. I hear concerns on the other side. It makes a difference 
in this country in terms of jobs. It makes a difference in 
terms of clean air whether these projections are right.
    So what about LNG? What will be its cost delivered? What 
will it do to our long-range cost structure and what is the 
reliability of it as a source of supply?
    Mr. Koonce. Senator, I would be happy to start the answer. 
I am sure others have more to add.
    We are very encouraged by what we see taking place on the 
natural gas/LNG front. The FERC about a year and a half ago 
adopted what is now called the Hackberry doctrine, which is a 
policy that we would like to see become law. The brunt of that 
policy is one where two parties can negotiate for the capacity 
of a gas import facility. Right now, Federal regulations 
require that under open access everybody have an opportunity to 
participate in a project. What that has the effect of doing is 
frustrating upstream development of infrastructure. And our 
company just announced a major expansion of our----
    Senator Alexander. Are you talking about a terminal?
    Mr. Koonce. Yes, sir. What it does with the Hackberry 
doctrine, it allows an upstream developer to know with 
certainty that they have a place that they can make redelivery 
of their LNG import capacity. So with the Hackberry doctrine 
now hopefully becoming law, those companies that have reserves 
around the world can now reliably negotiate for re-gas 
facilities in the United States with certainty so that they can 
make the upstream investments in order to bring natural gas 
supply on line and make the investment in ships.
    Right now the landed cost of natural gas in the United 
States is competitive down to $3 for existing facilities and 
maybe even lower. New facilities going forward with the 
technology improvements, with the scale that can come with the 
upstream liquefaction, with 200,000 cubic meter ships, we 
believe that new sources of LNG will continue to be competitive 
at or below $5.
    So what we hope to see is that on the U.S. side we adopt 
policy that allows clear negotiating authority for two 
companies to agree to work exclusively with each other to 
develop the re-gas facilities which will allow them then to 
make the commitment upstream.
    Senator Alexander. Just so I understand you, if I am a 
businessman and I am planning ahead and I am planning to use a 
lot of LNG, I better plan on a $5 price?
    Mr. Koonce. We think new sources of LNG can be competitive 
below $5. We think that it will serve to be a----
    Senator Alexander. You mean an LNG company can make money 
at $5?
    Mr. Koonce. At below $5.
    Senator Alexander. Anything below $5.
    Mr. Koonce. Yes, sir.
    Senator Alexander. What if I am on other end of it? I am a 
consumer. What would you recommend I put in my plans for the 
next 10 years? What range?
    Mr. Koonce. Well, again, I would say that the EIA range of 
prices being plus or minus $5, trending down as more facilities 
come on stream, I think is a good way to think about that 
question so long as we get clear siting authority and we can 
get the new facilities in place without delay.
    Senator Alexander. Thank you.
    Mr. Sharples. If I may add just a couple of points. I do 
not disagree with the estimate of price.
    But I think that a lot of the analysis that you read, which 
is essentially a cost-based analysis that says, well, ships 
cost this much and re-gas costs this much, and therefore, gas 
ought to cost this much, really miss some very significant 
points, the first of which is LNG is a world market. The United 
States is not the only market for LNG. It is not ``build it and 
they will come.'' During some of our highest price levels in 
the last 3 years, we have had existing import facilities that 
sat unused because other markets in the world demanded that gas 
and were willing to pay a higher price. Point number one.
    Point number two is that the upstream LNG projects need to 
compete for capital with other opportunities for the oil and 
gas companies around the world. Right now we are riding a wave 
of some gas that needs to find a home. It was found in 
association with oil in places like offshore West Africa. It 
needs to come somewhere. When that is used up, and we have to 
incent brand new LNG projects around the world, LNG gas supply 
projects to feed all of these terminals, the price that is 
received has to be high enough to incent the huge capital 
projects.
    So it is not a panacea I guess is my only point. I think 
the ranges that, Senator, you mentioned where we grow to about 
15 percent of total supply is probably doable. I would not say 
that you could go significantly above that or that we could do 
it at prices significantly below the ranges that Mr. Koonce 
just mentioned.
    Senator Alexander. Thank you. Thank you, Mr. Chairman.
    Senator Craig. In the context of the dialog that you have 
carried on with Senator Alexander, and especially to you, Mr. 
Koonce, in your testimony you state that Congress may need to 
further clarify Federal supremacy in the approval and siting of 
pipeline and LNG terminals to be used in interstate and foreign 
commerce.
    What is your assessment of the situation regarding the LNG 
proposal by Mitsubishi in Long Beach, California and the 
jurisdiction turf war taking place between California PUC and 
the FERC?
    Mr. Koonce. Yes, Senator. I am very troubled by it. I see 
it heading down a path that could delay the import of LNG into 
critical markets almost indefinitely. We need to make clear--
and I really think it is important for all the constituents 
that participate in this process, be it consumer advocates, be 
it landowners, be it environmentalists, or project developers. 
What is lacking today and what we must do is create a clear 
pathway for these alternatives to be debated, and we need to 
create one platform where all those constituencies can know to 
go to make the record so that the agency charged with that 
responsibility can discharge its responsibilities even if that 
means a no-siting decision so that the industry can move to the 
alternate sites that may be next in the queue.
    So when we look at whether it is the Coastal Zone 
Management, one Federal set of regulations versus another a 
Federal set of regulations, or whether we look at State versus 
Federal, what is troubling is the level of continued 
prosecution of these projects that do not seem to ever get to 
an end. And for a company that is using shareholder capital to 
develop those projects, we now get much more careful about 
which projects we attempt to pursue because of the potential do 
loop you can get into.
    Again, I think it is just as important for all the 
constituents who have limited resources, in terms of financing, 
to tell them once and for all where they need to go to make 
that case. I think it is very troubling.
    Senator Craig. Thank you very much.
    Before I turn to Senator Schumer, one last observation, Mr. 
Sharples. I agree. I do not think LNG is a panacea and I say 
that because we are not the only ones after it and you have 
said that. I was in Europe recently during the climate change 
conference in Milan and visited with Italian producers and 
distributors, and it is true of Germans and all of Europe is 
looking at gas. Their projections of use of gas are almost 
straight up. Of course, obviously, for the same reason it is 
happening here in part. And they are looking at a lot of 
potential and pipeline development coming out of the Caspian 
and all that, but it is out there in the future.
    They also know that the likelihood of maybe less disturbed 
and more reliable could be LNG in some instances versus the 
political consequences of a Caspian basin development or even 
something more coming out of Russia.
    So it is potentially a very competitive market. Depending 
on its rate of development, its rate of capitalization, I think 
I agree with those observations. Do you disagree with that?
    Mr. Sharples. Not at all, Senator.
    Senator Craig. Let me turn to the Senator from New York, 
Senator Schumer.
    Senator Schumer. Thank you, Mr. Chairman. I appreciate the 
panel.
    My first question, first, I would like Mr. Caruso to talk 
about it and anybody else. This relates to the oxygenate 
requirement that is currently forcing California, New York, and 
other States to use ethanol in the gasoline. As the summer 
blend requirements come on line and base gasoline will need to 
be blended to have a lower RBOB, does EIA still believe, as you 
stated in the October report, that supply mismatches could 
result in extreme price spikes? Has the oxygenate requirement 
created a situation in which New York is an unattractive niche 
market for external gasoline suppliers?
    Mr. Caruso. Thank you, Senator. We have been watching the 
MTBE ban development, of course, in California last year, and 
New York and Connecticut as of 1 January this year.
    The results so far have been relatively smooth in the 
winter, as you mentioned.
    Our concern, as we mentioned in October and continue to be 
concerned about as we go into this summer, is whether or not 
opportunistic suppliers of RBOB will be available to meet the 
full demands. And we still do not know the answer to that 
question. So the potential for price volatility continues to 
exist, and I think we will have some early hints even beginning 
this month.
    Senator Schumer. As you know, I have been pushing the 
administration. Governor Pataki has asked for an elimination or 
a waiver of the oxygenate requirement. They gave one to New 
Hampshire, a little different than New York. But what you are 
saying is the possibility of significant price spikes like we 
saw in California is very real. You are not sure it will 
happen, but it could?
    Mr. Caruso. Is it possible? Yes, sir.
    Senator Schumer. A broader question on gasoline. First, Mr. 
Caruso and then anyone else can answer it. Given the fact that 
the severe cold experienced by much of the country this winter 
has led to a longer period of heating oil production than 
normal, the fact that winter gasoline demand has been above 
average, and crude oil stocks are at their lowest since 1975, 
will U.S. refiners be able to physically meet the demand for 
gasoline heading into the summer months? It is a more general 
national question.
    Mr. Caruso. Our short-term outlook answer to that question 
is that we will need substantial imports, particularly from 
Europe, to meet the summer gasoline demand, but I think there 
are a few things that make it a little less certain this summer 
than previously, and that is, Europe itself is operating at 
fairly high rates of utilization and freight rates are up which 
tend to cause them to keep the product home.
    Senator Schumer. Are you saying it is possible that the 
national average which is now what? Getting close to $1.80, is 
it?
    Mr. Caruso. It is $1.72 this week.
    Senator Schumer. Could it get as high as $2 or no?
    Mr. Caruso. I do not know the answer to that for sure.
    Senator Schumer. It is above $2 in, I think, California 
right now.
    Mr. Caruso. Yes. It is $2.10 in California this week. But 
we will be looking at that more closely when we do our next 
outlook. I think we will be raising our previous expectation 
which was then a peak of $1.69. We have already exceeded that.
    Senator Schumer. That is a pretty good bet you will raise 
it.
    [Laughter.]
    Mr. Caruso. A key factor is where we think crude markets 
are going, and earlier we discussed the current price of WTI at 
about $36. But we do think that will, on average, come down. 
Depending on the exact timing of that, it will make a big 
difference in whether we will get much above the $1.72. 
Certainly the risk is there. I think, as I mentioned earlier, 
there is an asymmetrical risk of a higher price and a higher 
volatility this summer given the tightness in gasoline.
    Senator Schumer. Does anyone else want to comment on that?
    Mr. Saunders. If I could add real quickly on that, if you 
do not mind, Senator.
    Senator Craig. Mr. Saunders has made comment on that. If 
you would respond.
    Mr. Saunders. Just to reiterate what Mr. Caruso said on the 
imports, we are already seeing very low levels come out 
Venezuela, which supplies about 10 percent of U.S. gasoline 
imports, as well as the rest of South America on this low 
sulfur spec. So if you run some rudimentary numbers and if you 
put a 10 percent, say, decline in imports relative to last year 
and if you get a percent and a half of demand growth and if 
your yields are a normal level for this time of year, you are 
still about 5 million barrels or so in inventory lower than you 
were last year. Remember, the prices spiked at this time last 
year, and the only reason they came down was that demand was--
it took a relatively long time in coming through because we had 
a lot of wet weather in the spring last year.
    Senator Schumer. So where does that lead the price in terms 
of the practical question that I get asked all the time?
    Mr. Saunders. It is largely a question of the crude price, 
which I think is going to come down, but I think it is going to 
be a very high gasoline price season.
    Senator Schumer. Would you want to take a stab at what you 
think the average will be?
    Mr. Saunders. These guys are much more familiar on the 
retail side than I am. But if you say crude is going to stay up 
at $34 or $35, I see no reason to think east of California that 
you will not be above $1.75 or $1.80.
    Senator Schumer. Thank you.
    Does anyone else want to comment on that?
    [No response.]
    Senator Schumer. All right. The final question, because I 
know my time has expired.
    Senator Craig. Yes, if you could do that. We need to be out 
of here by 12, and I am sitting here contemplating Chuck 
Schumer on a bicycle all summer.
    [Laughter.]
    Senator Schumer. I ride a bicycle when I am in New York.
    Senator Craig. A fascinating idea, especially right down 
through the middle of New York City. Anyway, excuse me. Go 
right ahead.
    Senator Schumer. Mr. Chairman, in deference to that, I will 
submit written questions. Thank you.
    Senator Craig. I did not mean to scare you off.
    Senator Schumer. No, no, no. You sometimes do, but this was 
not one of those times.
    [Laughter.]
    Senator Craig. No loaded guns.
    Anyway, gentlemen, thank you very much for your presence 
here this morning, your testimony, and your timeliness to our 
concerns. As you know, as we try to seek out the future of 
energy supply in this country and the process by which we get 
there, accuracy in reporting and projecting, while I know it is 
not an exact science, the closer we can get to it, the better 
we will all be in the shaping of policy. I appreciate it.
    The committee will stand adjourned.
    [Whereupon, at 11:58 a.m., the hearing was adjourned.]


                                APPENDIX

                   Responses to Additional Questions

                              ----------                              

                              Department of Energy,
               Congressional and Intergovernmental Affairs,
                                    Washington, DC, April 20, 2004.

Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Mr. Chairman: On March 4, 2004, Guy F. Caruso, Administrator, 
Energy Information Administration, testified regarding energy supply 
forecasts.
    Enclosed are the answers to 18 questions submitted by Senators 
Campbell, Bingaman, Feinstein and You. The remaining answers are being 
prepared and will be forwarded to you as soon as possible.
    If we can be of further assistance, please have your staff contact 
our Congressional Hearing Coordinator, Lillian Owen, at (202) 586-2031.
            Sincerely,
                                          Rick A. Dearborn,
                                               Assistant Secretary.
[Enclosures.]

                    Questions From Senator Domenici

    Question 1. Some have called for the elimination of all dependence 
on foreign oil by 2020. Is that economically feasible? What resources 
could the U.S. realistically rely on to fulfill our energy needs if 
such an agenda was undertaken?
    Answer. Reducing the estimated 17.5 million barrels a day of crude 
and product imports projected in 2020 to zero would not be achievable 
under any plausible scenario. Additional access to the Alaska National 
Wildlife Refuge could reduce imports by an average of 900,000 barrels a 
day\1\ Alternative transportation fuels cannot be expected to 
completely displace foreign oil by 2020 because many of the resources 
that could be realistically relied upon are already facing increasing 
demand pressures, which will limit their availability to provide 
significant volumes of fuel. These include most of the technologies 
used to create synthetic petroleum from coal, natural gas, or 
agricultural products (ethanol/biodiesel).
---------------------------------------------------------------------------
    \1\ Energy Information Administration, ``Accelerated Depletion: 
Assessing Its Impacts on Domestic Oil and Natural Gas Prices and 
Production,'' EIA-SR/OIAF/2000-04, (Washington DC, July 2000)
---------------------------------------------------------------------------
    Natural gas and coal-based synthetic gas face increasing use by 
electricity generators and the cost to produce these fuels is not 
competitive with projected long-term world oil prices. Fuels based on 
agricultural products are also not cost competitive with oil now and 
face increasing upward price pressure from the entry of China and India 
into U.S. grain markets. Coal to methanol, while economically 
practical, has air toxics issues and groundwater pollution problems 
similar to methyl tertiary butyl ether. It is unlikely that hydrogen 
could make any meaningful entry as a transportation fuel before 2020 
due to the current extremely high cost of the vehicles and the cost to 
distribute the fuel. Transportation technologies that burn petroleum 
more efficiently (hybrids/light duty diesels/high MPG engine designs) 
will provide some reductions in import demand but are unlikely to 
provide any major reductions without significant regulatory changes.
    Question 2. Can you describe the general fuel switching abilities 
in the U.S. market between oil and natural gas? What barriers exist to 
fuel switching?
    Answer. Fuel demand includes a portion with some fuel-switching 
ability. Focusing on natural gas, there is no single figure for the 
consuming potential attributable to fuel switching, because it differs 
among the alternate fuels. Estimates of switching capacity by fuel can 
range widely. One recent study provided an estimate of switching 
capacity between natural gas and residual fuel by the industrial sector 
of about 0.2 billion cubic feet per day (Bcf/d), which is the 
equivalent of roughly 30,000 barrels per day of residual fuel (``Facing 
the Music: U.S. Industrial Gas Demand in an Era of High Gas Prices,'' 
CERA Advisory Service). An EIA publication, U.S. Natural Gas Markets. 
Recent Trends and Prospects for the Future (May 2001), provided an 
estimate for switching between natural gas and distillate fuel of 
roughly 0.58 Bcf/d for commercial and industrial consumers. This is the 
energy equivalent of 102,000 barrels per day of distillate fuel oil.
    There are a number of factors that can limit the ability of 
consumers to switch between fuels.

   The dominant factor is the size of the dual-fired capacity, 
        which itself may not be fully available for switching at any 
        given point.
   For any estimate of actual capacity, the amount of effective 
        capacity will be lessened by its current utilization rate--
        i.e., if dual-fired capacity already has been directed to a 
        lower-cost fuel, that portion of capacity cannot respond to 
        further price movement.
   The ability to switch also depends on the availability of 
        the alternate fuel. This may depend on inventories of the other 
        fuel either on-site or with regional suppliers. Additionally, 
        delivery capacity of the other fuel may be limited--e.g., 
        transmission capacity may not be available to deliver natural 
        gas for potential customers willing to switch from fuel oil.
   Environmental restrictions may limit or disallow the use of 
        certain fuels. This may be more relevant at certain times of 
        the year, for example, toward the end of the calendar year when 
        a company may not have any remaining emissions credits to use 
        and must burn natural gas.
   For any company, the willingness to switch will be mitigated 
        by the switchover costs including any downtime of the 
        equipment, and the expectation for relative prices.

    Question 3. Oil reserve calculations have been in the news lately. 
In January, Shell announced a 20% cut in its energy reserves and El 
Paso slashed reserves by 40%. Please give us a brief explanation of 
what these cuts actually mean and whether they have made much of an 
impact on world oil prices.
    Answer. EIA does not think that the Shell and El Paso reserve cuts 
made much of an impact on world oil prices, although it had a big 
impact on the stock prices of those companies. The cuts represent only 
a small fraction of the world's proved oil reserves. Proved reserves 
have to meet specific technical, economic and regulatory criteria. The 
Shell actions represent changing the classification of several fields 
proved reserves to a different category that has a lower probability of 
being produced. However, the oil and gas resources involved are still 
there and are technically and economically recoverable. Shell had not 
and has not made the financial commitment to build the necessary 
infrastructure to produce these resources. They should have made such 
financial commitments before they booked the resources as proved 
reserves. The negative revisions in El Paso's proved reserves were in 
much larger part, do to poorer than expected performance of producing 
wells in some of their larger fields. This is not uncommon for any one 
company. However, for all U.S. oil fields the annual sum of positive 
and negative revisions to proved reserves is usually positive.
    Question 4. The EIA estimates project that net petroleum imports 
are expected to account for 70 percent of demand, up from 50 percent in 
2002. Further, your studies show that OPEC provides about a quarter of 
our domestic petroleum needs. OPEC recently announced production cuts 
that seem to be holding prices at the high end, if not above, their own 
stated preferred price band of $22-28 per barrel target. In fact, the 
International Energy Agency Chief Claude Mandil [pronounced Mahn-deel] 
just stated on Monday, March 1, that, ``it is clear that the price band 
is over.''
    Question 4a. Do you agree that the $22-28 OPEC price band is over?
    Answer. The Organization of Petroleum Exporting Countries (OPEC) 
basket price was above the price band for almost half of 2003, and has 
been above it every day but two (when it fell to $27.98 per barrel and 
$27.92 per barrel, just pennies below the upper end of the price band) 
since November 6, 2003. And yet, both times OPEC has met since November 
6, 2003, on December 4 and February 10, OPEC surprised market analysts 
with their actions that supported higher prices. First, on December 4, 
2003, when most analysts expected an increase in production quotas, 
OPEC stated their intention to keep production quotas unchanged. Then, 
when they met on February 10, 2004, OPEC once again surprised the 
market by announcing a production quota cut of 1 million barrels per 
day effective April 1. OPEC met again on March 31, 2003 and reaffirmed 
that decision. Looking at these two most recent cuts as evidence, a 
case can certainly be made that OPEC is interested in prices remaining 
above their price band, making it essentially moot. OPEC production 
routinely exceeds its quotas, and when quota cuts are made, actual 
output often drops by a lesser amount.
    Question 4b. Do you think that the root of current oil price 
volatility can be traced to OPEC cuts?
    Answer. With most, if not all, of the world's excess production 
capacity, OPEC has the ability to lower crude oil prices by making more 
crude oil available at lower prices. OPEC has often stated that oil 
companies are not asking for more crude oil, but that is because the 
price at which OPEC is offering the oil is too high to make it 
economical for oil companies to purchase, unless they plan on refining 
it almost immediately. With oil prices at very high levels (Petroleum 
Argus, in their Global Markets publication dated March 29, 2004, stated 
that this is the first time prices for West Texas intermediate (WTI) 
crude oil have been continuously over $30 per barrel for four 
consecutive months since 1983), oil companies are not inclined to 
purchase excess crude oil to be placed in storage, fearing that prices 
are bound to come down from these high prices. However, by doing so, 
inventories remain at very low levels, especially if looked at from a 
days supply basis, leaving the oil market with little, if any, 
flexibility to respond to supply problems or demand surges. If, 
instead, OPEC was to make more oil available at prices low enough to 
create an economic incentive for companies to purchase it, oil prices 
would likely drop and remain below current levels. Therefore, whether 
or not OPEC is the root cause of high oil prices, OPEC does have the 
ability to lower prices.
    Question 5. In his testimony in July 2003, Chairman Greenspan noted 
that ``perceived tightening of long-term demand supply balances is 
beginning to price some industrial demand out of the market.'' How much 
demand destruction caused by high natural gas prices is permanent?
    Answer. Current data do not provide a precise figure on the amount 
of natural gas demand lost on a permanent basis. However, industrial 
consumption, which is the largest consuming sector for natural gas, is 
dominated by a few industries, such as chemicals including ammonia for 
nitrogenous fertilizers, and pulp and paper. Information regarding 
these key industries can provide a rough estimate of the impact of 
higher natural gas prices.
    Altogether, chemicals production accounts for roughly 7.2 billion 
cubic feet per day (Bcf/d) of natural gas consumption. Ammonia 
production requires an estimated 1.1 Bcf/d of the total consumption for 
chemicals. The Fertilizer Institute estimates that high natural gas 
prices have led to the permanent closure of 20 percent of U.S. nitrogen 
fertilizer capacity and the idling of an additional 25 percent of the 
remaining capacity. Absent economic relief, roughly 40 percent of U.S. 
capacity present in the 1999-2000 crop year is in danger of being shut 
down permanently. Regarding petrochemicals, the Washington Post 
reported on March 17, 2004, that one in every ten chemical-related jobs 
has been lost in the past five years. The Petrochemical and Refiners 
Association (NPRA) states that the U.S. balance of payments for 
chemicals went from an $8 billion surplus in 1999 to an estimated $9 
billion deficit for 2003. Natural gas is used as a feedstock in both 
fertilizer and petrochemical production, which makes fuel costs a 
significant portion of total costs and does not allow for switching to 
other fuels.
    Pulp and paper production accounted for an estimated 1.6 Bcf/d of 
natural gas consumption in 1998 (latest year for detailed data). Over 
the years, this industry has reduced its energy intensity in production 
and instituted other enhancements such as use of wood wastes and by-
products to meet over half their energy needs. Nonetheless, 40 mills 
were permanently closed in 2001 and 2002. There is anecdotal evidence 
of further curtailments and shutdowns in 2003. It is not clear how much 
pulp and paper capacity or the chemicals capacity would be bought back 
on line if natural gas prices were to drop significantly and for an 
extended period of time.
    Question 6. What are the inflation-adjusted prices for crude oil 
and natural gas compared to prices 20 years ago?
    Answer. The inflation adjusted price for crude oil (West Texas 
Intermediate--WTI) was higher 20 years ago than the price today. (Here 
we use the Producer Price Index to deflate nominal prices.) Expressed 
in 2004 dollars, the price of WTI averaged nearly $48 per barrel in 
1982, $43 in 1983, $40 in 1984, and $38.50 in 1986. During the period 
from 1986 through 2003, the inflation adjusted price for WTI was as low 
as $16.50 per barrel (1998) and as high as $32 per barrel (2000 and 
2003). The WTI spot price on April 1, 2004 was $34.50 per barrel.
    Unlike crude oil prices, natural gas wellhead prices are at their 
highest inflation-adjusted level in over 20 years. From 1982 through 
1985 the average annual wellhead price for natural gas (expressed in 
2004 dollars), was about $3.50 per thousand cubic feet. During the 
period from 1986 through 2003, the inflation-adjusted wellhead price, 
on an annual basis, was as low as $1.76 per thousand cubic feet in 1995 
and as high as $4.25 in 2001. In 2003, the annual average wellhead 
price for gas averaged $5.10 per thousand cubic feet. The most current 
spot price for natural gas (Henry Hub on April 1, 2004) was $5.99 per 
thousand cubic feet.
    The chart below illustrates the paths for real oil and gas prices 
on a consistent ($/million Btu) basis:



    Question 7. Are natural gas prices more volatile than oil prices 
and why?
    Answer. Price volatility generates significant uncertainties in 
energy markets. Annual price volatility is calculated from daily spot 
prices using the formula, (var [ln(P2/P,)]  number of 
observation) \1/2\. Figure 1 shows that over at least the last seven 
years the spot price of natural gas has been more volatile than that of 
crude oil.



    There are a number of causes of price volatility in energy markets 
such as daily price responses to market news, short-term supply 
disruptions or demand shocks, longer-term business cycles that exhibit 
alternating trends between market oversupply and undersupply, and so 
on.
    There is one source of price volatility that differs between the 
gas and oil markets. Prices may exhibit seasonal patterns that are 
expected by the market. There is more price seasonality in the natural 
gas market than the crude oil market. Subtracting the volatility for 
expected seasonal price changes still leaves natural gas more volatile 
than crude oil but the differences are less.
    The natural gas price spikes in December 2000 and February 2003 far 
exceed (in percentage terms) any price spikes seen in the crude oil 
market. This likely reflects structural differences in the ability of 
the two markets to respond to unexpected supply disruptions or demand 
surges. Market structural differences, such as the greater diversity of 
crude oil supply sources and ability to store crude oil closer to end 
users, could account for differences in price volatility (between 
natural gas and crude oil) beyond those related simply to the inherent 
differences in seasonality between the two markets.

                    Questions From Senator Campbell

    Question 1. The EIA analysis of the tax provisions in the Energy 
Conference Report of 2003 shows that domestic gas production from 
unconventional gas sources (Section 29 tax credit encourages production 
of oil and natural gas from ``non-conventional'' sources--like Devonian 
shale, tight rock formations, and coalbeds--that are usually expensive 
and technologically challenging to produce) is expected to increase 
during the next 10 years. Is this the only provision in the tax section 
of the energy conference bill that will increase natural gas production 
in the near term?
    Answer. Renewal of Section 29 tax credits is not the only provision 
of the Conference Energy Bill that could increase natural gas 
production in the near term, but it was the only provision that EIA 
could readily analyze with its National Energy Modeling System.
    Question 2. Short-term natural gas supply constraints can be partly 
addressed by dispatching the most fuel-efficient gas fired-units first-
either before or in place of older less efficient units. New units use 
about one-third less natural gas to produce the same amount of 
electricity. Has the EIA done any type of studies that looks into how 
much natural gas could be saved by using new combined cycle natural gas 
generation?
    Answer. The EIA has estimated that approximately 47 percent of gas 
consumption by electric generators in 2002 (6.03 billion cubic feet per 
day) is attributable to relatively old generating units (units which 
entered operation in 1985 or earlier). If the power demand served by 
these older plants could be met by more-efficient modern plants, only 
4.61 billion cubic feet per day would be required for the same 
generation, a savings of 1.42 billion cubic feet per day (24 percent of 
the 2002 consumption by electric generators). In fact, many new 
generating units are operating at relatively low utilization rates due 
to the overbuilt electric generating capacity market. The potential 
therefore exists to displace some generation from older and less-
efficient units with output from new units. This displacement is 
occurring and is evidenced, for example, by the retirement or 
mothballing of some older plants.
    There are, however, factors which may force the continued operation 
of some older units. First, transmission constraints may limit the 
ability of generators to ship power from new units to locations where 
that power could displace the output from older units. Note that many 
new generating units were built to serve local load, and the ability to 
sell electricity, if necessary, to remote demand was a primary 
consideration. In addition, many developers expected continued growth 
in the price of electricity. However, in many cases the expected local 
demand and/or price growth did not materialize, reducing the 
utilization of the new capacity. Consequently, many new units have 
become ``distressed assets'' that are candidates for sale or even 
mothballing, in part because they cannot sell power to remote markets 
where the plants might be more competitive.
    Second, older units located near demand centers (especially urban 
areas) may be designated as ``reliability must-run'' plants that must 
operate at times to maintain the stability of the transmission system. 
These factors may force the continued operation of a considerable 
amount of older generating capacity for quite some time, reducing the 
overall demand for the newer, more efficient capacity.

                    Questions From Senator Bingaman

    Question 1. Effect of increased speculation on oil markets.
    The current trend of high oil prices has been suggested by some to 
be a result of increased speculation in crude oil markets.
    Question 1a. Do you see speculators taking on a greater role in 
these markets, and if so, what has the effect been?
    Answer. EIA feels that supply and demand fundamentals support 
prices for West Texas Intermediate (WTI) crude oil at $32-33 per 
barrel, or perhaps even a little higher. However, with current prices 
reaching as high as $38 per barrel in recent days, there does seem to 
be some price impact from the large net long position seen recently for 
the non-commercial participants in the New York Mercantile Exchange 
(NYMEX) contract (see chart below). While it is impossible to separate 
out the nonfundamental factors (i.e., speculators, fear of supply 
losses in the future, etc.), the net long position of speculators 
appears to have had some measurable impact.



    Question 1b. Is volatility increasing as a result of their actions 
in the market? Are we seeing markedly higher prices overall as a result 
of this?
    Answer. Even if volatility has increased recently (and it is not 
clear that it has), it would be difficult to attribute it to any one 
factor. But as stated in the answer immediately above, WTI prices are 
higher than current supply and demand fundamentals would dictate, 
albeit the impact is not as large as some analyst have stated recently.
    Question 1c. Given your analysis, do you think that the data 
gathered by CFTC on net positions is accurate? Are there ways in which 
it could be improved?
    Answer. Nothing in our analysis has led us to believe that the 
Commodity Futures Trading Commission (CFTC) data is not accurate. In 
fact, our relationship with CFTC leads us to believe that they exert 
great effort to make their data as accurate as possible. If there were 
any room for improvement, it would be more in terms of how people 
interpret their data. In defining ``speculators,'' does this neatly 
correspond to the ``non-commercial'' category, or are there some large 
hedge funds included in the ``commercial'' category that more readily 
fit the ``speculator'' label? Or, in determining the net position, 
should one look at ``futures'' positions only or combine ``futures'' 
and ``options'' positions? It would be helpful if CFTC could take some 
steps to help users of their data become more knowledgeable about the 
definitions and categories, so answers to the questions asked above can 
be more consistently answered by different analysts.
    Question 3. The past few weeks we have seen significant increases 
in gasoline prices. Several factors have been noted by our witnesses in 
an attempt to explain the reasons for the rapid increase. What is the 
current rate of refinery utilization? Is it realistic to think that we 
can continue to operate at this rate? Are there specific regional 
issues that we should be looking into in more detail to help dissolve 
any bottlenecks in the system?
    Answer. The 4-week average utilization for the week ending March 
19, 2004 was 88.3 percent. The 5-year average utilization for the month 
of February is 88.3 percent, and for March is 89.7 percent. February 
and early March are typically times when refineries undergo maintenance 
and turnarounds to move from winter products to summer products. As a 
result, utilization is generally lower than during the summer months, 
which have averaged closer to 95 percent. During these periods of 
maintenance, 88 percent can be close to maximum utilization, given the 
capacity temporarily out of service. There is no way to determine 
``excess available capacity'' during these times. This year, high 
crude-oil prices and strong backwardation (i.e., futures market prices 
being lower in the out months than the current month) provided strong 
incentives for refiners to run only as much as needed to meet immediate 
demand. During the summer when refiners have most of their capacity 
available to run, utilizations of 95 percent leave little excess 
capacity available to respond to unexpected imbalances in the supply 
system.
    Demand has grown to fill excess capacity that was the prevalent in 
the 1980's. (Utilization in 1981 was 69%.) Since 1995, U.S. capacity 
has increased in existing refineries from 15.7 million barrels per day 
to 16.8 (1.1 million-barrel-per-day increase) in spite of continued 
shutdowns of small, less efficient refineries. Net imports of petroleum 
products have also increased to help meet rising demand. Net product 
imports in 1995 were 750 thousand barrels per day and averaged 1,603 
thousand barrels per day in 2003. The tighter markets and higher prices 
seen since the year 2000 are increasing incentives for refiners to do 
more expansion, but this may be limited as capital budgets are being 
used to make the necessary changes for the new low-sulfur gasoline and 
ultra-low sulfur diesel programs. Product imports, particularly 
gasoline, are being used to help meet growing demand.
    EIA's outlook for the short term is for continued tightness in 
gasoline and petroleum markets in general. While underlying tight world 
petroleum markets set the stage for tight U.S. markets, the growing 
loss of flexibility of the U.S. system (both production and 
distribution) increases the time needed to respond to regional 
imbalances. Regions like California, Chicago-Milwaukee, and now New 
York and Connecticut are particularly exposed to the possibility of 
price surges in that they are using gasoline that is hard to produce 
(limiting the number of suppliers that provide products to those 
regions), and any extra supplies that may be needed must usually travel 
some distance (1-3 weeks away), which delays resolution of any supply/
demand imbalances. We know of no ready solutions to easing the 
bottlenecks that have evolved. Any actions that provide additional 
flexibility rather than limiting flexibility work in the right 
direction from a supply perspective.

                    Questions From Senator Feinstein

    Question 1. The Energy Information Administration recently issued a 
report analyzing the Energy Bill, particularly as it related to natural 
gas and gasoline production, consumption, and prices. My reading of the 
analysis is that the energy bill does nothing to decrease petroleum or 
natural gas consumption, does nothing to reduce petroleum imports, nor 
does it reduce the price of natural gas by 2010.
    Can any of the witnesses explain to me why the federal government 
should spend at least $14 billion on a bill that purports to alleviate 
our natural gas problems or reduce our dependence on foreign oil when 
in fact EIA's numbers show that neither of these goals will be 
accomplished?
    Answer. The Department of Energy Organization Act provides the 
Energy Information Administration (EIA) with an element of statutory 
independence and EIA does not advocate, recommend, nor promote 
policies. In EIA's report, Summary Impacts of Modeled Provisions of the 
2003 Conference Energy Bill, natural gas consumption in 2010 is reduced 
by 210 billion cubic feet for the year and petroleum consumption is 
reduced by 27,000 barrels per day. Imports as a share of petroleum 
product supplied are reduced from 58.0 percent in the reference case to 
57.6 percent in the Bill case in 2010. Lower 48 natural gas wellhead 
prices are about the same in the Conference Energy Bill as in the 
reference case in 2010.
    Question 2. Natural gas is the fuel of choice in California. The 
benefits of natural gas are well known. However, natural gas supplies 
are tight and the costs of gas have risen. The renewable fuels standard 
that is in the Energy Bill will increase ethanol production by 
approximately 2 billion gallons over the next 10 years.
    In order to get those ethanol plants sited, they will have to be 
powered by natural gas. How much natural gas will be used by these 
plants? What will the price impact be on natural gas?
    Answer. A 2 billion gallon increase in annual ethanol production 
will require an additional 89.8 billion cubic feet of natural gas each 
year. This assumes that the incremental output is from dry mills 
operating at 2004 efficiency levels, that all process energy is from 
natural gas, and that the electricity required to operate the ethanol 
plants is generated from natural gas. While EIA has not directly 
modeled the price impact of this additional consumption, interpolation 
of changes in existing analyses shows that a 2 billion gallon increase 
in ethanol production would increase the price of natural gas at the 
wellhead in 2014 and thereafter by about $0.02 in 2002 dollars per 
thousand cubic feet, or by no more than 0.5 percent.

              Additional Questions From Senator Feinstein

    Question 1. On Monday, March 1, the Energy Information 
Administration released its weekly retail gasoline prices report. 
Across the country, gas prices have risen an average of 16 cents since 
mid January. In California, the numbers are even more startling. The 
overall average of California's reformulated gasoline rose from $1.71 
on January 12 to $2.16 on March 1. At the same time, California's 
refineries are switching from winter blends to summer blends and all of 
our reformulated gasoline must have ethanol in it since the state 
banned MTBE as of January 1, 2004.
    Questioon 1a. Why are gasoline supplies so limited in California?
    Answer. The supply limitations can be summarized as stemming from 
three factors: 1) The California refinery system runs near its capacity 
limits, which means there is little excess capability in the region to 
respond to unexpected shortfalls; 2) California is isolated and lies a 
great distance from other supply sources (e.g., 14 days travel by 
tanker from the Gulf Coast), which prevents a quick resolution to any 
supply/demand imbalances; and 3) the region uses a unique gasoline that 
is difficult and expensive to make, and as a result, the number of 
other suppliers that can provide product to the State is limited. This 
year, freight rates for tankers that transport gasoline were 
exceptionally high, requiring a very high California gasoline price to 
overcome the transportation cost and make it profitable to send product 
to California.
    Question 1b. What will the effect of the closure of the Shell 
Bakersfield facility be on California's gasoline supply?
    Answer. The simple answer is that losing capacity in an already 
tight market will just tighten it more. The product that is being lost 
will likely be made up by moving increased volumes from areas outside 
of the California refineries. The California Energy Commission (CEC) is 
looking into this problem.
    Shell has indicated that the 66,000 barrel per day refinery 
provides 2% of California's gasoline (about 20,000 barrels per day) and 
6% of the State's diesel. While this is considered a small refinery, 
the volumes it produces are still important to the State. It also 
produces other products such as lube oils and asphalt. Currently the 
refinery serves gasoline and diesel markets in Bakersfield, and it 
moves product north to a terminal in Fresno. That Fresno terminal is 
also served by suppliers in northern California. That means, if 
Bakersfield closes, the northern California suppliers must provide more 
product into Fresno and potentially Bakersfield. There are pipeline 
constraints that will require product to be moved by truck and railroad 
car in the short term.
    Tightening the California market means tightening the Western 
market because these markets are linked. For example, CEC indicated the 
northern California suppliers that will be replacing the Bakersfield 
refinery product now send about 30,000 barrels per day of gasoline to 
Oregon (as of 2002). In addition, refineries in the Pacific Northwest 
supply product to California. While the market is operating smoothly, 
the equilibrium price effect is likely to be small, but the chances for 
price surges increase in a tighter market even more dependent on long 
supply chains.
    Question 1c. What can be done to increase supply to California?
    Answer. Increases in supply and increases in supply flexibility 
would both help the California market. Further clean gasoline 
requirements (e.g., California Air Resources Board (GARB) IV) may 
further reduce refinery flexibility and even the capability of existing 
capacity to produce gasoline. Meanwhile demand keeps growing, and new 
supply must come from outside the State or from expansion of refineries 
within the State. There is room for some refineries in California and 
Washington State to increase capacity, but such expansions take time 
and involve many regulatory and environmental issues that must be 
addressed. Assuring that a process exists to identify regulatory and 
environmental hurdles to determine if quick solutions can be found 
would be helpful. As more product volumes come from outside the State, 
it would be helpful to assure infrastructure can be developed in a 
timely fashion to accommodate the necessary tankers and flows without 
jeopardizing environmental quality. For example, expansion of tank 
capacity at or near ports would help to accommodate more volumes. It 
should be noted that completion of the Longhorn Pipeline may allow 
California refiners to provide less product volume into neighboring 
States and more for California. Regarding flexibility, distribution 
infrastructure is key. To the extent that expansion of delivery 
infrastructure (pipelines, terminal tanks) is needed to meet growing 
demand, it would be helpful for government and industry to work 
together to try to derive solutions that will ease supply delivery 
while maintaining environmental quality.
    Question 1d. What is the impact of the 2% ethanol requirement on 
California's gasoline?
    Answer. The Federal 2 percent by weight oxygen requirement in 
reformulated gasoline, in combination with California's MTBE ban, 
requires refiners to add ethanol to RFG. Because ethanol raises the 
Reid vapor pressure (RVP) of gasoline, the base gasoline blend must be 
manufactured to a very low RVP, reducing refiners' flexibility in 
gasoline blending. Also, ethanol-blended gasoline cannot be commingled 
with other gasoline types, mainly due to the possibility of the ethanol 
increasing the Volatile Organic Compounds (VOCs) emissions in other 
gasolines.
    Question 1e. What is the long-term outlook for California's 
gasoline supply and prices?
    Answer. While EIA does not forecast regional supply and prices, we 
would expect the supply/demand balance to remain tight for some time. 
California is considering a yet cleaner and still more difficult to 
produce gasoline (CARB IV) before the first year of supplying GARB III 
is complete, which indicates continued tight markets for some time. Two 
factors are working to relieve this situation. Demand will eventually 
grow to the point where companies will find it beneficial to establish 
large firm contracts with refiners outside the State. Currently 
existing refiners can provide adequate product to meet demand most of 
the time, which limits incentives to commit to regular firm contracts 
from elsewhere. The third-party trading market has also been limited, 
since refiners within the State can handle most of the demand. This 
potentially growing third-party market could increase liquidity and 
volumes available in the short-term markets. Second, the projected 
opening of the Longhorn Pipeline this summer should help to allow 
California refiners to provide more California gasoline as more product 
from Texas flows into the Southwest.
    Question 2. What will the impact of the renewable fuels standard, 
should it pass, be on the state of the refineries? It is my 
understanding that refineries are currently operating at 93%. It is 
also my understanding that reformulated gasoline, when blended with 
ethanol with summer blends, has to be extremely clean. As a result, 
California's refiners lose about 10% of gasoline volume eight months of 
the year when they have to blend summer blends with ethanol.
    Answer. The major volume impact of using ethanol in gasoline 
pertains to reformulated gasoline, but the use of ethanol in 
reformulated gasoline is being driven by methyl tertiary butyl ether 
(MTBE) bans, rather than the renewable fuels standard. If MTBE were 
still being used, reformulated-gasoline-producing refiners in many 
areas likely would find it more economic to meet the renewable fuels 
standard by buying credits from refiners who are adding ethanol to 
conventional gasoline in other areas of the country such as the 
Midwest. But concerns over MTBE are causing many States and companies 
to back away from MTBE. Ethanol is being used to replace MTBE for 3 
major reasons: 1) In reformulated gasoline (RFG), ethanol helps to meet 
the Federal oxygen requirement, since ethanol contains oxygen as did 
MTBE; 2) Ethanol helps to replace the octane lost when MTBE was 
removed; and 3) Ethanol helps to dilute emission characteristics in the 
remaining gasoline blending components. For example, ethanol contains 
no aromatics (which increase emissions), so ethanol dilutes the 
aromatic content of the gasoline blending components to which it is 
added.
    Question 3. If the renewable fuels standard is enacted, and 
refiners choose to use ethanol in reformulated gasoline, should we 
expect further shortfalls in gasoline throughout the country?
    Answer. Refiners would generally be using ethanol in reformulated 
gasoline (RFG) as a result of MTBE bans rather than from a renewable 
fuel standard. Had MTBE not become a water quality concern, RFG-
producing refiners in many areas likely would find it more economic to 
meet the renewable fuels standard by buying credits from refiners that 
are adding ethanol to conventional gasoline. But concerns over MTBE are 
causing many States and companies to back away from MTBE. This leaves 
ethanol as one of the only alternatives to meet the RFG oxygen 
requirement. Furthermore, ethanol helps some refiners replace lost MTBE 
volumes and associated lost octane.
    Increased ethanol use in the next 5-10 years or so would likely be 
supplied mainly from the Midwest. As a result, another separate supply 
chain is being used to meet gasoline demand. That supply chain would be 
most critical for RFG, since the base RFG gasoline stock to which 
ethanol is added is not a finished gasoline and does not meet 
driveability or emission requirements. Thus, any interruption in either 
the gasoline base stock or the ethanol supply could result in temporary 
shortages. If the ethanol-blended conventional market grows to the 
extent that sub-octane conventional gasoline blendstocks are being used 
to blend with ethanol, it could also see a dependence on the separate 
ethanol supply chain. However, conventional gasoline is generally 
easier to adjust to produce a finished product than is RFG.
    Question 4. What would the impact of the seasonal variations 
section of the renewable fuels standard be on refiners and gasoline 
supply, particularly if it is used in reformulated gasoline areas?
    Answer. EIA is not convinced that the seasonal requirements will 
have a large impact, at least in earlier years of the mandate. Ethanol 
use in RFG would not be affected by the seasonal requirement if the 
oxygen requirement remains in place, since ethanol is providing the 
needed oxygen content. Even if the oxygen requirement for RFG were to 
be removed, ethanol likely would be used by many refiners to replace 
the octane lost from MTBE and to dilute other gasoline components that 
contribute to emissions. This would cause them to use ethanol in the 
summer as well as the winter. Generally it is easier to use ethanol in 
conventional gasoline than in RFG, but some suppliers might find it 
less attractive in the summer due to its tendency to increase the rate 
of evaporation of gasoline (i.e., raise Reid vapor pressure or RVP). 
Still, suppliers in the Midwest currently use ethanol all year round, 
and this region would be expected to use ethanol beyond the mandated 
amounts, thereby producing credits for others to purchase.
    Question 5. Would it be smarter to mandate ethanol use only in 
conventional gasoline?
    Answer. In some States with MTBE bans, ethanol is helping to 
replace the MTBE that is lost in RFG. While there is a net volume loss 
in the summer months, some refineries would find it more difficult to 
produce an oxygenate-free RFG that meets both driveability and 
environmental specifications than to use ethanol. A restriction on 
where ethanol may be used only serves to place further restraints on an 
already constrained supply system. Also, if the ethanol mandate allows 
for and is able to accomplish a liquid credit trading market, refiners 
producing RFG would theoretically be able to buy credits if necessary 
to meet the mandate without using ethanol.

                                 ______
                                 
                              Department of Energy,
               Congressional and Intergovernmental Affairs,
                                      Washington, DC, May 18, 2004.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Mr. Chairman: On March 4, 2004, Guy F. Caruso, Administrator, 
Energy Information Administration, testified regarding energy supply 
forecasts. On April 20, 2004, we sent you the answers to 18 questions 
for the hearing record.
    Enclosed are the remaining answers to seven questions submitted by 
Senators Bingaman and Schumer.
    Enclosed also is the edited transcript, and three inserts that were 
requested by Senators Wyden, Landrieu and Craig 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,
                                          Rick A. Dearborn,
                                               Assistant Secretary.
[Enclosures.]

                     Question From Senator Bingaman

                   STRATEGIC PETROLEUM RESERVE (SPR)

    Question 2. The Strategic Petroleum Reserve was established in 1975 
in an attempt to protect the United States from a severe energy supply 
disruption. This action was taken in an environment that enjoyed 
significant excess refining capacity and voluntary actions by companies 
to hold discretionary stocks. Since 1975, energy markets have further 
evolved both globally and domestically. On the domestic front, we've 
seen companies move away from holding discretionary stocks and move 
into just-in-time style management of their inventories of crude and 
products. This has meant that the `cushion' which we used to depend on 
is in fact disappearing. An in this environment, we are exposed to 
increasingly frequent momentary disruptions that do clearly cause 
economic damage. Given the significant shifts in the commercial 
environment of petroleum and petroleum product markets, it would seem 
that a comprehensive review of our approach to the SPR may in fact be 
necessary. What does this mean for our approach to the SPR? What 
changes may be necessary?
    Answer. The Energy Policy and Conservation Act (EPCA) envisions 
that the free market will balance the supply and demand of oil, and oil 
from the SPR will be withdrawn and sold only in extraordinary 
circumstances, and then only upon a decision by the President, or as a 
limited test sale or exchange.
    The Act also provides for our membership in the International 
Energy Agency. This membership allows us to leverage the concept of 
strategic petroleum stockpiling, increasing deterrence value, and 
sharing costs and benefits with other countries.
    Despite evolutionary changes in the petroleum industry, and the 
geographical sources of the world's oil supplies, the basic concepts of 
the Act still serve us well. We should allow free markets to operate 
with minimal intervention by the Government. When the Government is 
required to intervene it should augment supplies and use the mechanisms 
of the free market to distribute the Government supplies of petroleum.
    The reduction of private inventories over time definitely increases 
the value of strategic reserves. That is a contributing justification 
for filling the Reserve to its capacity. That is also one reason the 
President's National Energy Policy provides for the Government to 
encourage other nations to build and maintain strategic petroleum 
reserves.

                     Questions From Senator Schumer

    Question 1. What is the potential for a gasoline shortage to be 
created or exacerbated this summer as a result of the loss of gasoline 
volume in states forced to use ethanol by the oxygenate requirement? 
Are there reliable sources of marginal supply from Canada, South 
America, or other markets that could alleviate any such shortage?
    Answer. The primary change in the gasoline supply picture this 
summer stems not from the oxygenate requirement in reformulated 
gasoline (RFG), which has been in place since the program began in 
1995, but the ban on the use of methyl tertiary butyl ether (MTBE) in 
New York and Connecticut, following a similar ban in California. Since 
MTBE had previously been the primary oxygenate used in those areas to 
satisfy the oxygen requirement, suppliers in those areas have no 
practical choice but to replace the banned MTBE with ethanol.
    Analysis by the Energy Information Administration (EIA) in advance 
of the MTBE ban in New York and Connecticut found that the ban would 
force changes in supply patterns and some logistical challenges that 
could produce some transitional problems. The major supply uncertainty 
found in EIA's analysis was the continued availability of gasoline from 
traditional import supply sources to the area, given that some foreign 
refiners might be unable or unwilling to produce the base gasoline, 
called reformulated gasoline for oxygenate blending (RBOB), to which 
the ethanol would be added. However, EIA found that U.S. refiners 
should be capable of making up any shortfall of RBOB, with import 
sources presumably shifting to supply MTBE RFG or conventional gasoline 
to areas outside of New York and Connecticut.
    Question 2. Have you been made aware of any automotive performance 
issues associated with the use of ethanol in gasoline in states 
required to do so by the oxygen mandate? If so, what steps can be taken 
to alleviate the problem in the face of a tight market?
    Answer. EIA is not aware of any significant automotive performance 
issues associated with the use of ethanol as compared to MTBE in 
gasoline. While both of these oxygenates have a lower energy content 
than the base gasoline they replace, and thus theoretically result in 
somewhat higher gasoline demand in areas where they are used, no 
significant difference in performance has been reported between the two 
blends. Ethanol blended in gasoline, at levels up to 10 percent by 
volume, has been in widespread use in many parts of the United States 
for more than a decade.
    Question 3. We're currently experiencing record supply lows and 
gasoline price highs nationwide, and facing the possibility of supply 
disruptions from several foreign providers. If we have these supply 
disruptions, what would the price impact be? At what point would DOE 
acknowledge that we have a severe economic disruption in the energy 
sector meeting the threshold for releasing oil from the SPR?
    Answer. The price impact of a given supply disruption will depend 
on the size of the disruption, its duration, and a number of other 
factors at work in the market at any given point of time, such as the 
existence of spare production capacity, the size of commercial 
inventories of crude oil and petroleum products, weather, and the 
nature of the disruption itself. As a general rule of thumb, the EIA 
expects that an oil supply disruption that results in one million 
barrels per day of current supply being withheld from the market, and 
the disruption lasts for a period of six months, that could raise world 
oil prices on average by $3-$5 per barrel. The average increase cited 
in this rule of thumb can mask significant short-term price spikes.
    The statutory requirements for an emergency drawdown and sale of 
oil from the SPR are set out in the Energy Policy and Conservation Act. 
These requirements include the existence or imminent threat of a severe 
energy supply interruption; a severe increase or expected increase in 
the price of petroleum; and anticipation that the disruption will have 
an adverse impact on the economy. There are no specific thresholds for 
determining when or if these statutory requirements have been met. DOE 
monitors market developments closely, and in the event of a supply 
disruption or imminent threat of a supply disruption, DOE will conduct 
an analysis of the specific situation and make a recommendation 
regarding the use of the SPR based on the facts at that time.

                    STRATEFIC PETROLEUM RESERVE USE

    Question 4. At the time the SPR was created, the structure of the 
nation's oil market was different and industry was more willing to hold 
on to supply inventories and a number of other factors existed. Given 
that oil markets now function differently, is there a need to 
reevaluate the philosophy on how to use the SPR?
    Answer. SPR use, under the Energy Policy and Conservation Act 
(EPCA), enacted in 1975, and the authorities granted and objectives 
stated therein have proven resilient over the past 29 years. They 
provide appropriate standards for use of the SPR, and flexibility for 
changing conditions. Importantly, they allow for consideration of 
international conditions and the state of our energy security. There is 
no need, at this time, to either increase or decrease the authority for 
selling oil from the reserve, nor is there any need at this time for 
more or less guidance concerning acquisition of oil for the SPR.
    Question 5. Russia is currently not included in the list of top 
suppliers of U.S. oil imports, even though it has risen to the top of 
the global production list with an output of around 9 million barrels 
per day. Is there any hope that the United States could look to 
increased Russian supply in an effort to hedge against OPEC dominance 
and instability in our other suppliers?
    Answer. The U.S. is steadfast in working with Russia to increase 
its shipments of oil to the U.S. Russia currently supplies about 1.5 
percent of U.S. crude oil imports or about 149,000 barrels per day to 
the U.S. We also import about 104,000 barrels per day of refined 
petroleum products from Russia. Russia wants to increase its exports to 
the U.S. but is hampered by an inadequate infrastructure. President 
Putin and Russian companies have stated their desire to provide oil to 
the U.S. and estimate that Russia could provide up to one million 
barrels per day or 10 percent of U.S. imports. In July 2002, the 
Russian oil company Yukos began direct exports of two million barrels 
of oil monthly for six months on a trial basis to the Gulf of Mexico.
    Our two governments have been working closely together over the 
last three years to enhance trade and investment in Russia's energy 
sector and expand Russia's markets. Among the many undertakings, we 
have held two Commercial Energy Summits to catalyze partnerships 
between our energy companies. We have reinvigorated the Energy Working 
Group that on an ongoing basis cooperates on, among other issues, 
investment and facilitating trade. Under the Camp David initiatives, 
agreed to in October 2003, President Bush and President Putin support 
efforts to advance the development of the Murmansk pipeline and port 
system. Murmansk is an ice-free deepwater port that could economically 
expand Russia's oil markets including Russia's exports to the U.S. 
Shipments from Murmansk to the U.S. are actually a shorter distance 
than exports from the Persian Gulf. We are working with the Russian 
government as it addresses energy tax issues and its regulatory regime 
for licensing oil and gas fields by sharing the U.S. experience and the 
need to provide incentives and stability for investment.
    Both governments have a shared goal of more Russian oil to the U.S. 
and will continue to work on creating an environment to foster 
commercial energy cooperation that will expand markets for Russian 
energy.
    Question 6. Could you comment on the impact that China's continuing 
industrialization and growing energy demand is going to have on the 
world markets, particularly in oil and natural gas? What steps can be 
taken to anticipate and mitigate any severe economic impacts that may 
result from a surge in Chinese energy demand?
    Answer. In accordance with its pace of industrialization, Chinese 
demand for oil has been growing steadily. China became a net overall 
oil importer in 1993. In 2003, China's demand for oil surpassed that of 
Japan and it became the second largest oil consumer in the world, after 
the United States. Imports, 60 percent of which come from the Middle 
East, now account for one-third of China's oil demand. The 
International Energy Agency estimates that China's imports may account 
for 60 percent of consumption by 2010, and 80 percent by 2030. Rapid 
growth of energy demand in China could put upward pressure on world 
energy prices.
    Such strong growth in energy demand, in conjunction with its 
potential impact on sustainable economic growth, has been recognized by 
the highest levels of Chinese leadership. Their key responses have been 
a commitment to construct a State Petroleum Reserve (SPR), greater 
participation in foreign exploration and production activities by 
Chinese oil and gas companies, and supply diversification away from the 
Middle East.

                CONSTRUCTION OF STATE PETROLEUM RESERVE

    After a decade of consideration, China included in its 10th five-
year plan (2000-2005) the task of building strategic oil reserves. In 
summer 2003, Beijing reportedly selected the following sites for a 
strategic oil reserve: the northeast port of Dalian, Huangdao in 
eastern province of Shandong, and Aoshan and Ningbo in East China's 
Zhejiang province. Chinese plans for SPR construction reportedly come 
in two phases, leading to approximately 30 days of consumption coverage 
by 2010.

               FOREIGN FOREIGN EXPLORATION AND PRODUCTION

    China has been acquiring interests in exploration and production 
abroad. Chinese majors have acquired oil concessions in Kazakhstan, 
Venezuela, Sudan, Iraq, Iran, Peru, and Azerbaijan. The most 
significant deal thus far is the acquisition of a 60 percent stake in 
the Kazakh oil firm Aktobemunaigaz, which came with a pledge to invest 
significantly in the company's future development. Also, China has 
gained shareholdings in Australian and Indonesian gas fields and is 
reportedly looking to take a further stake in the Gorgon gas field 
offshore northwest Australia.

            SUPPLY DIVERSIFICATION AWAY FROM THE MIDDLE EAST

    Russia's Far East is increasingly seen as a potential source of 
Chinese crude oil imports. The most notable proposed initiative is to 
build a $2.5 billion pipeline between Anagarsk and Daqing that would 
carry 600,000 bbl/d of crude oil. While a memorandum of understanding 
was signed between China's state-owned China National Petroleum Corp. 
and Yukos Oil of Russia in June 2003, it remains unclear whether the 
deal would materialize in light of political uncertainties in Moscow 
and a competing one million bbl/d pipeline proposal by Russian pipeline 
operator Transneft that would export Russian gas to an export terminal 
at the Pacific coast port of Nakhodka. China is also stepping up 
activity in Kazakhstan, reflecting a synergy between Chinese efforts to 
diversify supply and Kazakh interest in Chinese market, as the Central 
Asian country plans to boost output to up to 3.5 million bbl/d in 2015 
from around one million bbl/d in 2003.
                                 ______
                                 
                            Anadarko Petroleum Corporation,
                                        Houston, TX, April 6, 2004.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Senator Domenici: Thank you for the opportunity to appear 
before the Senate Committee on Energy and Natural Resources on March 4, 
2004. 1 appreciated the chance to give testimony regarding energy 
supply forecasts.
    Enclosed please find the list of questions and my responses to be 
included in the record.
            Sincerely,
                                       Richard J. Sharples,
                     Senior Vice President, Marketing and Minerals.
[Enclosures.]

                    Questions From Senator Domenici

    Question 1. I believe that producing the energy this Nation depends 
on AND maintaining a healthy environment are NOT mutually exclusive 
goals. Can industry explore and produce oil and gas on public lands in 
a manner that takes care of the environment, maintains wildlife habitat 
and accommodates other users?
    Answer. Absolutely. Through technology that is advancing daily, 
industry can explore and develop America's gas resources without 
harming the environment. Anadarko has successfully demonstrated care 
for the environment in sensitive habitats where we work--from the Gulf 
of Mexico to Alaska. We've proved that we can co-exist with nature, 
exploring for and producing natural resources with minimal physical 
impact to the surroundings.
    It's also important to note that when we talk about access, we're 
talking about access to non-park federal lands--such as off the West 
and East coasts, the Eastern Gulf of Mexico, parts of Alaska and other 
onshore areas particularly in the West--that are currently off limits. 
These resource rich areas can help provide vital sources of energy for 
American consumers.
    Question 2. How important is the role of production from public 
lands in increasing domestic production?
    Answer. Production from public lands is extremely important. 
Without increased access, I don't believe U.S. natural gas production 
can grow at a price level that the market can bear.
    The NPC 2003 study concluded that removing the OCS moratoria and 
reducing the impact of conditions of approval on the Rocky Mountain 
areas by 10% per year for 5 years would add 3 Bcf per day to domestic 
production in 2020 and would reduce the average price of natural gas by 
as much as 60 cents in nominal terms--which translates into a $300 
billion savings to consumers over 20 years.
    Question 3. In your testimony you spoke to the impact of the 
conditions of approval for oil and gas operations in the Rocky Mountain 
areas. I assume you're speaking largely of the Department of the 
Interior and its leasing and permit process.
    Did I understand correctly that these impacts have resulted in a 
production decrease?
    Answer. While there has been increased production from the Rockies, 
the region's growth potential is impaired by the restrictions and 
delays in the permitting process. In order to compensate for the steep 
declines in mature basins, we need to generate greater growth from the 
Rockies and other unexplored areas.
    We think that had it not been for these delays, we could have 
produced more.
    Question 3a. Has the Department been able to improve its processing 
time or its predictability and consistency for issuing drilling 
permits?
    Answer. Overall the answer is no. Across most of Wyoming, it 
currently takes 9 to 12 months to get a permit processed (where it used 
to take 3 months for permits), and the situation seems to be getting 
worse.
    But the Bureau of Land Management (BLM) is attempting to make 
improvements. A positive example is the Buffalo (Wyoming) Field Office 
where they've put policies in place to enact a 46-day turn-around for 
permits and they've increased their staffing to better handle the 
volume of activity. The 46-day policy just went into effect in January 
and we haven't seen the results yet, but we're hopeful. We commend that 
office for a step in the right direction.
    Question 3b. What seems to be the difficulty in fixing this 
problem?
    Answer. It's largely a manpower deployment issue combined with the 
experience level of staff. The activity has increased in the Western 
States, but there's simply not enough people to handle the workload.
    We estimate that the impact of delay on net present value (NPV) is 
costing the Federal Government approximately $12 million in royalty 
value for a single project when an environmental impact statement (EIS) 
takes 60 months instead of 18 months. Likewise, if the BLM could 
improve permit processing time by 6 months, it would increase the 
present value of royalty paid to the Federal Government by 
approximately $500,000 to $750,000 per year for a typical project.
                     Question From Senator Campbell
    Question. The EIA recently analyzed three restricted-supply 
scenarios by 2025 and compared each with the EIA energy forecast. The 
three scenarios were:

   No new Alaska gas pipeline;
   New LNG terminals limited to 3 totaling 2.5 Bcf;
   Future conventional gas production remaining stagnant.

    If these scenarios held true, lower-48 state wellhead price impact 
in 2025 would range from 20 cents/Mcf higher in the no-Alaska pipeline 
case to $1.21/Mcf higher if all three scenarios were combined. Do you 
believe that these price assumptions are realistic or do you believe 
that they will be better or worse?
    Answer. The Alaska sensitivity seems realistic, but the impact 
could be as much as $0.50.
    Based on internal modeling at Anadarko, and assuming current public 
policies are the same, we would expect the impact of no new Alaska 
pipeline plus constrained LNG import capacity to 2.5 Bcf/d to have at 
least a $2.00 impact on the price in 2025. Furthermore, we expect that 
the impact of no new Alaska pipeline plus constrained LNG will mean 
that 20% of gas demand from EIA's reference case will be forced out of 
the market. Under current policies and basin maturities, North American 
gas production has little opportunity for growth, even the 1% per year 
growth assumed by the EIA reference case. Therefore, any disruption to 
anticipated supply must be matched by a corresponding disruption in 
demand. We anticipate that natural gas pricing information will be used 
to ration demand, but will have little impact on the ability of the 
nation to supply more gas (under current policies). The EIA assumes 
that Alaskan supply will equal 2.7 Tcf in 2025 and that LNG imports 
will equal 4.8 Tcf. Constraining LNG import capacity to 2.5 Bcf/d will 
result in LNG supplies equal to only 0.1 Tcf in 2025. Therefore, the 
supply from this sensitivity will effectively be reduced by 6.6 Tcf, or 
20% of the 32.21 Tcf of gas consumption expected. Therefore, we 
conclude that the only way for the market to grow if LNG capacity is 
restrained and Alaska is not approved is to make changes to public 
policy in other arenas particularly access to new exploration acreage.
    An assumption that future production from conventional reservoirs 
could remain stagnant, or flat, we view as optimistic. To the contrary, 
we expect that production from conventional reservoirs will decline 
over the next 20 years by about 1% per year (This is consistent with 
the NPC).

                    Questions From Senator Feinstein

    Question 1. The Energy Information Administration recently issued a 
report analyzing the Energy Bill, particularly as it relates to natural 
gas and gasoline production, consumption, and prices. My reading of the 
analysis is that the energy bill does nothing to decrease petroleum or 
natural gas consumption, does nothing to reduce petroleum imports, nor 
does it reduce the price of natural gas by 2010.
    Can any of the witnesses explain to me why the federal government 
should spend at least $14 billion on a bill that purports to alleviate 
our natural gas problems and reduce our dependence on foreign oil when 
in fact EIA's numbers show that neither of these goals will be 
accomplished?
    Answer. There are no quick fixes or easy answers when it comes to 
an energy policy for America. There are, however, important steps we 
can take together to improve the situation and relieve our growing 
dependence on imported energy. Many of them are contained in the 
comprehensive energy legislation pending before the Congress which we 
see as a good and necessary start toward greater American energy 
independence. Specifically, it--

   Streamlines permitting processes for exploration and 
        development programs.
   Renews certain incentives like Section 29 tax credits, which 
        have historically proven effective in increasing U.S. supply.
   Reduces barriers to gas pipeline permitting and 
        construction.
   Imposes deadlines on appeals delaying offshore exploration 
        and development.
   Authorizes the Alaska Natural Gas Pipeline which can bring 
        35 Tcf of currently stranded natural gas to the Lower 48 
        states.

    Passing this energy legislation is an important first step to begin 
to address the issues and concerns raised by both the EIA in their 
Energy Outlook and the National Petroleum Council in their 2003 report 
on Balancing Natural Gas Policy.
    In addition to the Energy Bill, there are several things--mostly 
administrative--that don't require an act of Congress:

   Add more BLM staff, both to speed up the revision of the 
        RMPs and to speed up well permit reviews.
   Streamline the project approval process.
   Eliminate duplicative or conflicting requirements among 
        state and federal agencies.
   Set time limits for staff decisions.
   Write clear and binding procedures for project approval, 
        from the environmental impact statement stage through well 
        permitting, and make it clear up front what steps operators 
        will have to satisfy to get approval for their projects.

    Longer term, we need more frequent and regular leasing in areas 
that are not under moratoria--Alaska and the Eastern Gulf are examples.
    And we need the moratoria to be lifted in those areas where the 
resource potential is greatest, and where the technology and the 
infrastructure exist today to cost-effectively find, develop and 
produce that gas.
    Question 2. Natural gas is the fuel of choice in California. The 
benefits of natural gas are well known. However, natural gas supplies 
are tight and costs of the gas have risen. The renewable fuels standard 
that is in the Energy Bill will increase ethanol production by 
approximately 2 billion gallons over the next 10 years.
    In order to get those ethanol plants sited, they will have to be 
powered by natural gas. How much natural gas will be used by these 
plants? What will the price impact be on natural gas?
    Answer. Anadarko does not process ethanol and is not the most 
appropriate company to respond to this question.

                            GASOLINE PRICES

    Regarding your questions about gasoline prices--Anadarko does not 
refine or market gasoline, and we believe these questions would be 
better directed at one of the integrated companies.
    1) On Monday, March 1, the Energy Information Agency released its 
weekly retail gasoline prices report. Across the country, gas prices 
have risen an average of 16 cents since mid-January. In California, the 
numbers are even more startling. The overall average of California's 
reformulated gasoline rose from $1.71 on January 12 to $2.16 on March 
1.
    At the same time, California's refineries are switching from winter 
blends to summer blends. And all of our reformulated gasoline must have 
ethanol in it since the state banned MTBE as of January 1, 2004.

   Why are gas supplies so limited in California?
   What will the effect of the closure of the Shell Bakersfield 
        facility be on California's gasoline supply?
   What can be done to increase supply to California?
   What is the impact of the 2% ethanol requirement on 
        California's gasoline supply?
   What is the long-term outlook for California's gasoline 
        supply and prices?

    2) What will the impact of the renewable fuels standard, should it 
pass, be on the state of the refineries? It is my understanding that 
refineries are currently operating at 93%. It is also my understanding 
that reformulated gasoline, when blended with ethanol with summer 
blends, has to be extremely clean. As a result, California's refiners 
lose about 10% of gasoline volume eight months of the year when they 
have to blend summer blends with ethanol.
    3) If the renewable fuels standard is enacted, and refiners choose 
to use ethanol in reformulated gasoline, should we expect further 
shortfalls in gasoline throughout the country?
    4) What would the impact of the seasonal variations section of the 
renewable fuels standard be on refiners and gasoline supply, 
particularly if it is used in reformulated gasoline areas?
    5) Would it be smarter to mandate ethanol use only in conventional 
gasoline?
                                 ______
                                 
      Responses of Paul Koonce to Questions From Senator Domenici

    Question 1. What are the greatest challenges you see facing 
proposed LNG facilities in the U.S.? And, do you think that there will 
be adequate take-away capacity to deal with anticipated LNG imports?
    Answer. Perhaps the greatest challenge LNG faces is the perception 
by some that it is not safe, or presents an inherently significant 
security risk. This perception is incorrect, but it is proof that 
policymakers and the public must be better informed about LNG, its 
importance to our energy supply diversity, its safety and security 
characteristics, and the steps that have been taken in recent years to 
increase safety and security at LNG facilities.
    Even with such an education effort, however, nothing will fully 
eliminate the ``Not in My Backyard'' opposition that now is frustrating 
all sorts of energy infrastructure development. Many state and local 
groups will oppose LNG projects regardless of the benefits the benefits 
to consumers and the economy, simply out of a desire to maintain the 
status quo. These groups will often use safety and security concerns to 
oppose projects when their real objections lie with concerns about 
property values, opposition to any future development, and the 
perceived impact on their ``quality of life.'' It is incumbent upon 
elected officials, opinion leaders and the industry to explain why the 
status quo is not an acceptable alternative. High natural gas prices 
are a real ``quality of life'' issue, and have a real effect on jobs, 
the economy and environmental quality. This is why is it important to 
have an LNG facility approval process that weighs the larger public 
good against narrower, parochial interests.
    Such a consolidated process now exists at the Federal Energy 
Regulatory Commission (FERC); but as you know, it is being challenged. 
I'll save further comment on this problem until Question 5, but suffice 
it to say that a national focus on these problems is crucial.
    Your question about pipeline take-away capacity is also important 
to the debate over increased LNG supplies. As stated in my written 
testimony, LNG import capacity expansions must also happen in 
conjunction with pipeline take-away capacity upgrades. For example, 
Dominion has announced plans to increase throughput capacity at our 
Cove Point LNG facility from 1 Bcf/day to 1.8 Bcf/day, but this is 
dependent upon FERC approval of two associated pipelines to move that 
increased that capacity away from the terminal and into the market.
    Question 2. EIA projects nine to twelve LNG facilities to serve the 
United States will be constructed by 2025. Do you agree with that 
prediction?
    Answer. The recent National Petroleum Council\1\ report on natural 
gas supplies projects that the four existing LNG terminals will be 
fully utilized by 2007, and that seven additional terminals will be 
needed in North America to meet demand through 2025. Not all of these 
terminals would necessarily be constructed in the United States; for 
example, facilities in Baja California, the Bahamas and Eastern Canada 
could serve the U.S. market with the construction of adequate pipeline 
take-way capacity. Nonetheless, current projections suggest that at 
least three or four LNG terminals would be needed in the continental 
U.S. as well.
---------------------------------------------------------------------------
    \1\ Balancing Natural Gas Policy: Fueling the Demands of a Growing 
Economy, The National Petroleum Council. September, 2003.
---------------------------------------------------------------------------
    There likely will be significant attrition among the approximately 
40 LNG facilities that have been announced to date. These are complex, 
capital intensive projects that face significant siting and commercial 
challenges in making the transition from the drawing board to 
operational reality. The marketplace will be efficient in defining the 
equilibrium between the need for supply and the number of truly viable 
projects. What is important from a public policy perspective is to 
avoid the creation of unnecessary and duplicative regulatory process 
beyond that required to ensure public safety and security are 
protected.
    Question 3. The FERC Hackberry decision protected LNG owners' 
authority over their own gas. What is the significance of that decision 
on existing and future LNG development?
    Answer. LNG projects are capital-intensive and involve significant 
capital investment upstream of the regasification facility. 
Consequently, it was argued that subjecting regasification facilities 
to the FERC open season requirements would be a deterrent to the 
development of LNG supply for the United States, because a developer 
would be less likely to make the upstream investments if it lacked the 
certainty of access to commensurate regasification facilities once the 
supply was landed in the United States. The Hackberry decision waives 
the open season requirement and thereby provided developers with this 
certainty. In the absence of this decision, LNG terminal capacity would 
have to be made available to any party under open-access requirements, 
which likely would result in import capacity being allocated into 
smaller blocks. Compared to other potential global markets for LNG, 
this regulatory requirement would make the United States less 
attractive for LNG developers.
    The Hackberry doctrine as written is designed to assist developers 
who have their ``own'' gas from having to submit to the open season 
process. For all the reasons stated above (the original answer), this 
doctrine should include all developers, so that these benefits may be 
realized by two companies working together, not just those companies 
with production affiliates.
    Question 4. There has been much recent discussion about gas quality 
regarding condensate levels and interchangeability. These are two very 
distinct natural gas issues. I want to talk about interchangeability. 
As I understand it, interchangeability is an LNG matter that has to do 
with the ability to substitute LNG for traditional natural gas 
supplies. What are the concerns about doing that?
    Answer. The concerns arise from the fact that much of the LNG 
available from overseas sources has a higher BTU content (i.e., heating 
value) than natural gas consumed in North America. Furthermore, the BTU 
content of LNG varies depending on the source, so there will not 
necessarily be consistency among LNG imported into United States 
markets. This is an issue because of concerns over whether the higher-
BTU-content natural gas is compatible with home appliances, power 
generation equipment, pipeline compression engines, and other 
appliances and machines fueled by natural gas.
    An industry collaborative that includes representatives from the 
entire natural gas value chain (i.e., everyone from natural gas 
producers to natural gas appliance and combustion turbine 
manufacturers) is working to resolve these interchangeability issues. 
This same group is working on the separate, but related natural gas 
quality issues associated with the effects of high natural gas 
commodity prices and shifts in the economics of natural gas processing.
    The experience to date with existing operational LNG regasification 
facilities suggests that interchangeability solutions are site-specific 
and, therefore, that one-size-fits-all standards may not be 
appropriate. For example, at LNG terminals located sufficiently 
upstream of consuming markets, re-gasified LNG moving out of the 
terminal blends with North American gas supply in the pipeline system 
in such a way as to alleviate any concerns about high BTU content. At 
other facilities, natural gas is delivered to customers relatively soon 
after leaving the terminal, and therefore interchangeability must be 
addressed before the natural gas enters the pipeline system. For 
example, at Cove Point, we have a number of customers taking gas soon 
after it leaves the facility. As a result, the Cove Point terminal 
injects nitrogen into the natural gas before it enters the pipeline 
system, so that it meets gas equipment specifications without any 
further blending in the pipeline. We worked with our customers to 
develop this solution. This experience suggests strongly that the most 
efficient answer to the question is to provide LNG terminals, suppliers 
and customers with the flexibility to find the least cost means of 
meeting consensus-based interchangeability standards.
    Question 5. In your testimony, you state that Congress may need to 
further clarify federal supremacy in the approval and siting of 
pipeline and LNG terminals to be used in interstate and foreign 
commerce. What is your assessment of the situation regarding the LNG 
proposal by Mitsubishi in Long Beach, California and the 
``jurisdictional turf war'' taking place between the California PUC and 
FERC?
    Answer. The ``turf war'' between the California PUC and FERC is 
exactly the kind of unnecessary, and counterproductive, federal-state 
conflict that I referred to in my written and oral testimony. The Sound 
Energy Solutions' (``SES'') proposed terminal in California would be 
engaged in the importation of LNG from foreign sources. This 
transaction is clearly within the scope of the Federal Energy 
Regulatory Commission's jurisdiction under section 3 of the Natural Gas 
Act. The federal appellate courts have clearly affirmed FERC's 
interpretation of its section 3 authority to apply to the construction 
and siting of facilities for the importation of natural gas. FERC's 
recent declaratory order in the SES proceeding is firmly grounded in 
precedent and should be upheld if the State of California seeks 
judicial review.
    Still, the appellate review process is time consuming and adds an 
element of uncertainty that can be counterproductive to creating a 
conducive climate for LNG terminal siting. For example, will other 
states choose to follow California's lead and raise jurisdictional 
challenges pending the final resolution of this matter in the courts? 
Furthermore, even if one assumes that FERC prevails in this matter, 
there may be other jurisdictional conflicts that create impediments to 
LNG project siting. Already, a number of states have used their 
delegated federal authority under the Coastal Zone Management Act and 
the Clean Water Act as mechanisms for blocking interstate pipelines 
that have already been approved by the FERC. There is no reason to 
believe that the same strategy will not also be pursued with respect to 
LNG terminals.
    In other words, in addition to the prospect of jurisdictional 
conflicts between the application of federal and state law to LNG 
terminals and other energy infrastructure, there is the clear need to 
address the conflicts between federal statutes. The Natural Gas Act 
confers on FERC the exclusive authority over the approval and siting of 
interstate natural gas pipelines and facilities associated with 
importing and exporting natural gas. Still, in addition to the Natural 
Gas Act, the Congress has enacted a variety of environmental laws that 
provide other federal agencies, and in some cases state agencies acting 
pursuant to delegated authority, with jurisdiction over aspects of 
interstate natural gas pipeline siting. The certificates of public 
convenience and necessity that FERC issues under the NGA authorizing 
the construction of interstate natural gas pipelines include conditions 
requiring compliance with these laws. Furthermore, the environmental 
review that FERC conducts as part of its NGA certificate process 
includes extensive consultation with federal and state resource 
agencies. In addition, at the suggestion of INGAA, the White House Task 
Force on Energy took the lead in negotiating a memorandum of 
understanding among federal agencies with a stake in pipeline siting 
matters. This, however, does not include state agencies, who in many 
cases act pursuant to delegated federal authority. Unless something can 
be done to address this situation, there is the prospect that LNG 
terminals and interstate pipeline facilities that have been approved by 
their primary federal regulator, after a comprehensive and inclusive 
review process, could be delayed, if not blocked, by state agencies 
acting pursuant to delegated federal authority. While I would hope for 
a consensus based resolution of this growing conflict, this may well 
have reached the point where some statutory clarification of the 
hierarchy of federal laws that apply to energy project siting is 
advisable.
    Question 6. How has the pre-filing process for pipeline projects at 
FERC been working?
    Answer. FERC has done a commendable job reviewing pipeline 
applications, and approving in a timely manner those that meet the 
statutory ``public convenience and necessity'' standard. In recent 
years, tremendous progress has been made in engaging stakeholders in 
the process. FERC has spearheaded two distinct initiatives, the Federal 
Memorandum of Understanding (``MOU'') agreement, which focuses on 
coordination between federal agencies, and the pre-filing process. The 
pre-filing process is a way to identify and address the issues and 
concerns of all stakeholders, including the public, federal, state, 
tribal and local authorities, before they become a problem associated 
with the application that the pipeline files with FERC. This is an 
excellent idea and we can point to some real world success stories as a 
result of this process. Still, our experience has been that while the 
pre-filing process has been successful in engaging the public, it has 
been less effective in addressing problems associated with some federal 
and state permitting agencies. These agencies do not have, as their 
mandate, the timely review of energy infrastructure that is in the 
public convenience and necessity. Some agencies even have chosen not to 
participate in the FERC process, or to play an openly hostile and non-
constructive role. Given FERC's mission to meet ``the public 
convenience and necessity,'' these inter-governmental conflicts are 
frustrating. Coupled with the federal MOU agreement, the FERC pre-
filing process can result in a better more timely permitting process. 
Still, for the process to realize its full potential, we need all 
federal and state permitting agencies to get on board. Under the 
current framework, a single permitting authority with a narrowly-
defined mandate can stop an entire project.
      Response of Paul Koonce to a Question From Senator Campbell
    Question. The EIA recently analyzed three restricted-supply 
scenarios by 2025 and compared each with the EIA energy forecast. The 
three scenarios were:

   No new Alaska gas pipeline
   New LNG terminals limited to 3 totaling 2.5 Bcf
   Future conventional gas production remaining stagnant

    If these scenarios held true, lower-48 state wellhead price impact 
in 2025 would range from 20 cents/Mcf higher in the no-Alaska pipeline 
case to $1.21/Mcf higher if all three scenarios were combined. Do you 
believe that these price assumptions are realistic or do you believe 
that they will be better or worse?
    Answer. If all three limiting factors were to indeed occur, it is 
very possible that the effect on prices would be even greater than that 
predicted by EIA. Today's sustained high prices of over $5 per Mcf 
provides ample evidence of this. The recent National Petroleum Council 
study on natural gas projects a steady increase in natural gas demand 
between now and 2025. The worst case restricted-supply scenario 
reviewed by EIA is essentially today's policy environment plus three 
new average sized LNG terminals. Short of economically devastating 
demand destruction, it is easy to imagine escalating gas prices over 
time. We know that the Gulf of Mexico's contribution to our gas supply 
has most likely peaked, as has Canada's. Likewise, the most productive 
conventional plays in currently accessible areas of the U.S. have been 
largely exploited. So in a very real sense, the most severe restricted-
supply scenario is not an option.

      Responses of Paul Koonce to Questions From Senator Bingaman

    Question 1. Coastal Zone Management Act amendments--The Department 
of Commerce (NOAA) has proposed a rule that would limit the time for 
appeals to the Secretary of Commerce of state consistency review 
determinations. Does this proposal address your concerns about Coastal 
Zone Management Act appeals?
    Answer. The proposed rule does not fully address INGAA's concerns 
about the Coastal Zone Management Act appellate process, and in fact, 
NOAA's interpretation of the scope of its authority as part of this 
process gives rise to a number of additional concerns on the part of 
INGAA. INGAA outlined its concerns with the proposed rule in a filing 
at the Department of Commerce last August, and we would respectfully 
request that these comments be included in the record following these 
questions and answers.
    One of the central issues INGAA has with the Coastal Zone 
Management Act appeals process is something that only Congress can fix. 
Section 319 of the CZMA currently provides the Secretary of Commerce 90 
days within which to make a decision on an appeal, once the record is 
closed. The Secretary may extend this period for 45 additional days, 
but must make a decision at that point. The practical problem with the 
current scheme is that the statutory deadlines for action apply only 
after the record in the appeal is closed. The experience has been that 
the ``record'' in such appeals often has been permitted to remain open 
for months, and even years. In one recent appeal involving an 
interstate pipeline, the Secretary took 18 months to render a decision. 
This is an entirely unreasonable amount of time in which to decide what 
is, after all, an appeal of an earlier state consistency determination. 
The comprehensive energy legislation before the Senate (S. 2095) 
addresses this issue, by giving the Secretary clear timeframes in which 
to both close the record and issue a decision.

                RESIDENTIAL NATURAL GAS CONSUMER IMPACT

    Question 2. How does Dominion assure that the commodity portion of 
its natural gas bills is as low as possible?
    Answer. It has been and continues to be the policy of the Dominion 
natural gas distribution companies (Dominion East Ohio, Dominion 
Peoples and Dominion Hope) to manage gas purchasing activities to 
achieve the lowest overall cost consistent with the provision of 
reliable service over the long-term. Also, the Public Utility 
Commissions in Ohio, Pennsylvania and West Virginia are actively 
involved in the review and oversight of the purchasing activities and 
costs paid for gas supplies by gas distribution companies through 
ongoing proceedings and audits. These Commissions do not permit 
recovery of gas supply costs unless the companies have demonstrated 
that they are acquiring supplies in a prudent manner.
    Question 2a. How do you help your retail gas consumers cope with 
higher energy bills?
    Answer. Dominion offers customers a budget payment plan under which 
customers can pay a fixed budget amount each month, offers other 
payment plans to reduce arrearages, and provides customers with energy 
conservation information. Dominion also encourages eligible customers 
to participate in government assistance programs, such as the Customer 
Assistance Program (CAP) and Percent of Income Payment Plan (PIPP), and 
contributes to weatherization assistance and hardship funds. The 
Company sends out press releases advising customers of the various 
programs that are available as well as cost saving conservation tips. 
Such information is also available on the company's Web site: 
www.dom.com, In addition, Dominion actively supports the customer 
choice programs in its service territories, which allow customers to 
shop around for other energy supplier offers.
    Question 2b. Have you found that the number of customers who are 
unable to pay their bills has increased over the past few years? By how 
much?
    Answer. Key metrics measured by Customer Credit Services, show a 
declining trend each year from 2001 to 2003, regarding the number of 
gas customer bankruptcies, the average arrears per gas customer and the 
percentage 120 day arrears dollars compared to total arrears.
    Question 2c. LIHEAP assistance typically goes to households with 
incomes less than $10,000/year. Are you finding that households with 
higher incomes are also struggling to pay their bills?
    Answer. There are many older adults and working poor having 
difficulty paying their bills, and the company makes every effort to 
provide them with assistance. Dominion donates shareholder dollars to 
hardship funds in its respective states and promotes customer and 
employee donations that are matched with the shareholder funds. The 
hardship funds have higher income limits to provide help to many of the 
households that are not eligible for LIHEAP.
    Question 2d. With high natural gas prices reaching a new plateau, 
should funding for LIHEAP also increase?
    Answer. Yes. Dominion works with the American Gas Association and 
the National Fuel Funds Network to support increased funding for 
LIHEAP. The company promotes LIHEAP in all of its states and conducts 
outreach campaigns to encourage eligible customers to apply for help.
      Responses of Paul Koonce to Questions From Senator Feinstein
    Question 1. The Energy Information Administration recently issued a 
report analyzing the Energy Bill, particularly as it relates to natural 
gas and gasoline production, consumption, and prices. My reading of the 
analysis is that the energy bill does nothing to decrease petroleum or 
natural gas consumption, does nothing to reduce petroleum imports, nor 
does it reduce the price of natural gas by 2010.
    Can any of the witnesses explain to me why the federal government 
should spend at least $14 billion on a bill that purports to alleviate 
our natural gas problems and reduce our dependence on foreign oil when 
in fact ETA's numbers show that neither of these goals will be 
accomplished?
    Answer. The February, 2004 EIA report, done at the request of 
Senator Sununu, was limited to just five specific tax provisions of the 
bill, so it is difficult to agree with the premise of the question that 
the bill does nothing to reduce our dependence on foreign oil or reduce 
natural gas prices. In fact, one very bright spot in the report is 
ETA's conclusion that extension of the Section 29 tax credit for the 
production of natural gas from unconventional sources would indeed 
benefit consumers. Specifically, EIA found that extension of the credit 
would:

   Increase total domestic natural gas production from 
        unconventional resources;
   Continue to have a positive impact on production beyond the 
        reference case due to the reserve additions brought on by the 
        credit;
   Reduce average wellhead prices by almost $0.15 per thousand 
        cubic feet over the 2005 to 2010 period;
   Increase the number of unconventional gas wells drilled by 
        20% over the 2004-2006 time frame when new qualifying wells 
        could be drilled;
   Increase total unconventional gas reserves by 13% over the 
        reference case for the years 2004-1006;

    When the EIA estimate of a $0.15 per thousand cubic feet reduction 
in wellhead prices is held up against projected natural gas consumption 
during that same period of time, that reduction would result in 
consumer savings of over $10 billion, according to the Gas Technology 
Institute. This represents a benefit/cost ratio of more than 3 to 1 for 
that one provision.
    With regard to EIA's analysis of the tax credit for new advanced 
nuclear power facilities, the Nuclear Energy Institute (NEI) has 
pointed out several key flaws in their conclusion that the credit will 
not spur additional nuclear plants beyond those eligible to receive the 
credit. The central criticism of the analysis is the assumption that 
capital costs for new plants will not decrease as new units are built. 
I've attached for the record a more detailed response prepared by NEI.
    Question 2. Natural gas is the fuel of choice in California. The 
benefits of natural gas are well known. However, natural gas supplies 
are tight and costs of the gas have risen. The renewable fuels standard 
that is in the Energy Bill will increase ethanol production by 
approximately 2 billion gallons over the next 10 years.
    In order to get those ethanol plants sited, they will have to be 
powered by natural gas. How much natural gas will be used by these 
plants? What will the price impact be on natural gas?
    Answer. While Dominion is unable to quantify the amount of natural 
gas expected to be used by future ethanol plants, we do believe that 
the growing reliance on natural gas in many sectors of the U.S. economy 
is driving up the price of the commodity. Without a policy shift toward 
new nuclear and coal-fired power generation, accompanied by improved 
access to where our remaining natural gas resources are located, such 
as the Outer Continental Shelf and the Rocky Mountain regions, natural 
gas prices will remain significantly higher than historic levels.

                            GASOLINE PRICES

    Question 3. On Monday, March 1, the Energy Information Agency 
released its weekly retail gasoline prices report. Across the country, 
gas prices have risen an average of 16 cents since mid-January. In 
California, the numbers are even more startling. The overall average of 
California's reformulated gasoline rose from $1.71 on January 12 to 
$2.16 on March 1.
    At the same time, California's refineries are switching from winter 
blends to summer blends. And all of our reformulated gasoline must have 
ethanol in it since the state banned MTBE as of January 1, 2004.

   Why are gas supplies so limited in California?
   What will the effect of the closure of the Shell Bakersfield 
        facility be on California's gasoline supply?
   What can be done to increase supply to California?
   What is the impact of the 2% ethanol requirement on 
        California's gasoline supply?
   What is the long-term outlook for California's gasoline 
        supply and prices?

    Answer. Dominion does not refine nor market gasoline and is 
therefore not in a position to answer questions on gasoline price 
trends and influences.
                                 ______
                                 
             Interstate Natural Gas Association of America,
                                   Washington, DC, August 25, 2003.
Mr. David Kaiser,
Federal Consistency Coordinator, Coastal Programs Division, Office of 
        Ocean and Coastal Resource Management, NOAA, Silver Spring, MD.
    Re: Coastal Zone Management Act Federal Consistency Regulations; 
Docket No. 030604145-3145-01

    Dear Mr. Kaiser: Pursuant to the proposed rule issued in the 
referenced proceeding on June 11, 2003,\2\ the Interstate Natural Gas 
Association of America (INGAA) submits the following comments on the 
National Oceanic and Atmospheric Administration's (NOAA) proposal to 
revise the Federal Consistency regulations promulgated under the 
Coastal Zone Management Act of 1972 (CZMA).
---------------------------------------------------------------------------
    \2\ 68 Fed. Reg. 34851 (June 11, 2003).
---------------------------------------------------------------------------
    INGAA is a trade organization that advocates regulatory and 
legislative positions of importance to the interstate natural gas 
pipeline industry in North America. INGAA represents virtually all of 
the interstate natural gas transmission pipeline companies operating in 
the United States, as well as comparable companies in Canada and 
Mexico. Its members transport over 95 percent of the nation's natural 
gas through a network of 180,000 miles of pipelines. Interstate natural 
gas pipelines are certificated by the Federal Energy Regulatory 
Commission (FERC) under section 7(c) of the Natural Gas Act (NGA).
    On June 11, 2003, NOAA issued a proposed rulemaking to ``make 
improvements to the Federal Consistency regulations to clarify some 
sections and provide transparency and predictability to the Federal 
Consistency regulations'' (emphasis added). This rulemaking, in part, 
responds to Vice President Cheney's May 2001 National Energy Policy 
Report to the President (Energy Report), which specifically recommended 
that the President direct the Secretary of Commerce to reexamine 
current federal legal and policy regime (statutes, regulations, and 
Executive Orders) to determine if changes are needed regarding siting 
of energy facilities in the coastal zone.
    The preamble to the proposed rule focuses on how the Federal 
Consistency regulations affect oil and gas lease sales. While this 
focus is understandable in view of the Energy Report's specific mention 
of the Outer Continental Shelf Lands Act in connection with the CZMA, 
it still is remarkable that the preamble fails even to acknowledge the 
growing conflict between NOAA's interpretation of its CZMA authority 
and the FERC's authority under the NGA to issue certificates of public 
convenience and necessity for interstate natural gas pipelines. This 
omission is particularly glaring given that appeals to NOAA by two 
interstate pipelines from state objections to consistency 
certifications were pending when the proposed rule was issued.\3\
---------------------------------------------------------------------------
    \3\ Millennium Pipeline Company and Islander East Pipeline Company, 
L.L.C.
---------------------------------------------------------------------------
    Some of the proposed changes to NOAA's regulations represent 
incremental improvements over the current rules affecting interstate 
pipelines and, as will be detailed herein, INGAA supports these 
modifications. Still, NOAA's failure to acknowledge and address the 
larger conflict means that, with respect to interstate pipeline 
construction, the rulemaking will not achieve its stated goal of 
providing ``transparency and predictability to the Federal Consistency 
regulations.''
    The NGA, which predates the CZMA by decades, confers on FERC 
plenary authority to issue certificates of public convenience and 
necessity authorize the siting, construction and operation of 
interstate natural gas pipelines. The Congress in 1972 made clear that 
enactment of the CZMA did not diminish, modify or supersede this 
preexisting federal authority. Now, however, the pending appeals from 
state objections to consistency certifications for proposed interstate 
pipelines that have received FERC certificates calls into question 
whether this clear statement by the Congress will be followed. INGAA 
urges NOAA in its final rule to state clearly that it will give due 
weight to FERC's findings in view of the statutory scheme in the NGA 
that confers on FERC sole responsibility for determining whether, and 
under what conditions, a proposed interstate pipeline is required by 
the public convenience and necessity.\4\
---------------------------------------------------------------------------
    \4\ See ERC Comments on Millennium Consistency Appeal, November 15, 
2002. at page 2.
---------------------------------------------------------------------------
    A final rule in this proceeding will be legally deficient should it 
not address the specific legal issues and practical circumstances 
surrounding NOAA's administration of the CZMA and interstate natural 
gas pipelines that receive FERC certificates under the NGA. In the 
alternative, should NOAA not address these issues in the final rule, 
INGAA requests that NOAA initiate a separate, new rulemaking focused on 
these issues. In particular, such a rulemaking should propose amending 
NOAA's Consistency Regulations to: (1) require as a condition for 
approval of a state Coastal Management Program that the state 
participate in FERC's National Environmental Policy Act (NEPA) review 
process for a pipeline certificate application to ensure that the FERC 
has an opportunity to address the state's concerns as part of that 
process; and (2) adopt the record of the FERC certificate proceeding as 
the record for any appeal from a state's objection to a pipeline 
applicant's consistency certification in order to avoid the delays and 
legal infirmities associated with relitigating FERC's determination of 
issues reserved solely to FERC under the NGA.
    INGAA submits that the proposed rule is legally deficient due to 
NOAA's mischaracterization of its legal authority under the CZMA as it 
applies to interstate natural gas pipeline projects that have been 
authorized by the FERC pursuant to the NGA.

The Federal Consistency Process Does Not Affect a Waiver of FERC's 
        Plenary NGA Authority.
    NOAA asserts that Federal Consistency is a ``limited waiver of 
Federal Supremacy and authority'' (68 Fed. Reg. 34852, June 11, 2003). 
The Congress in the NGA, however, conferred on the FERC plenary 
authority to authorize the construction of interstate natural gas 
pipelines. NGA Section 1(a) states unequivocally that transportation 
for ultimate distribution to the public is ``affected with a public 
interest'', and that Federal regulation in matters relating to 
transportation in interstate commerce ``is necessary in the public 
interest''. Numerous Supreme Court decisions validate the preemptive 
effect of FERC's authority under the NGA.\5\ By contrast, Congress 
limited CZMA's construction with other statutes not to ``diminish 
either federal or state jurisdiction . . .'' 16 U.S.C. Sec. 
1456(e).
---------------------------------------------------------------------------
    \5\ See, e.g., Schneidewind v. ANR Pipeline Co., 485 U.S. 293 
(1988); National Fuel Gas Supply Corp. v. Public Service Commission of 
the State of New York. 894 F.2d 571 (2nd Cir.), cert. denied, 497 U.S. 
1004 (1990).
---------------------------------------------------------------------------
NOAA's and/or Delegated State Authority's Consideration of Alternatives 
        Subverts the Comprehensive Scheme for Interstate Natural Gas 
        Pipeline Authorization Under the NGA.
    The NGA and NEPA require FERC to assess all reasonable alternatives 
to a pipeline's construction proposal as a key factor in its evaluation 
and determination. Yet NOAA asserts that it must review alternatives 
that the protesting coastal state, in that state's judgment, deems 
consistent with its state coastal management plan. (68 Fed. Reg. 
34858). This subverts the comprehensive federal scheme Congress 
intended for interstate pipeline analysis.
    State consideration of issues not already covered in the FERC's 
Environmental Impact Statement (EIS) should, at the very least, be done 
within the FERC-imposed deadline for State agency comments. This would 
continue to allow for full State participation, while protecting 
federal authority to authorize interstate natural gas pipeline 
construction pursuant to the NGA.

The Scope of Appellate Review Under the CZMA is Limited.
    NOAA asserts that it has de novo review authority (68 Fed. Reg. 
34859) pursuant to the CZMA, without citation to the statute. Absent an 
express statutory grant of authority for de novo review, however, 
NOAA's authority under CZMA is appellate only. 16 U.S.C. Sec. 
1456(c)(3)(a). It is black letter law that an ``appeal'' is an 
examination by the appropriate review body of a decision record to 
determine if there are material errors of fact or application of law 
contained in that record. Therefore, NOAA lacks the authority to engage 
in a de novo review of the interstate pipeline routing alternatives 
considered by the FERC in the NGA certificate process.
    NOAA in the preamble attempts to clarify its use of the term de 
novo review:

        The Secretary's review is de novo, to determine if the project 
        is consistent with the CZMA or in the interest of national 
        security. It is not a review of the basis for the State's 
        objection or the basis for issuing the Federal agency 
        authorization. The Secretary does not substitute the 
        Secretary's judgement [sic] for that of the authorizing Federal 
        agency regarding the merits of the project, nor does the 
        Secretary determine whether a proposed project complies with 
        other Federal law. (68 Fed. Reg. 34863).

While INGAA does not object to this particular characterization of 
review authority under the CZMA, the statement fails to address the 
fact that in considering alternative routes for an interstate pipeline 
that has been certificated by the FERC, NOAA is engaging in what 
amounts to the very form of de novo review that it disclaims in the 
cited statement.
    NOAA also asserts that ``through the CZMA Congress gave the States 
the ability to review, federal actions, independent of the Federal 
agencies' reviews.'' (68 Fed. Reg. 34860) (emphasis added). This 
statement, however, is inconsistent with the fact that the CZMA limits 
NOAA's consistency review of a federal permit activity to an 
examination of whether the proposed activity is consistent to the 
maximum extent practicable with the enforceable policies of a state's 
coastal zone management plan. A state policy in its coastal zone 
management plan that has the effect of blocking the siting of an 
interstate pipeline could not be enforceable against a federally pre-
emptive NGA.

A Final Rule That Fails to Address the Conflict Between NOAA's 
        Interpretation of its CZMA Authority and The NGA Would Not be 
        Reasoned Decisionmaking.
    NOAA asserts that its regulations are designed to provide 
``reliable procedures and predictability'' to the implementation of 
Federal consistency. (68 FedReg. 34851-52). In the case of interstate 
gas pipeline construction, NOAA's procedures throw into complete 
disarray FERC's long-standing procedures for its analysis and 
determination under the NGA, NEPA, and the Administrative Procedure 
Act, and materially diminish the predictability of FERC's preemptive 
certificate determinations.

                     Comments on the Proposed Rule

    INGAA appreciates NOAA's proposals to improve its Consistency 
Regulations by specifying deadlines for action by the states and by 
NOAA itself. Still, INGAA suggests that, at least within the context of 
interstate pipeline projects that are subject to the FERC certificate 
process under the NGA, even more expedited regulations can be adopted.
    In particular, proposed section 930.130 states that one of the 
three circumstances when the 270-day period for closing the decision 
record can be stayed is when the Secretary needs additional NEPA and/or 
ESA documents. This exception makes little sense in the case of an 
appeal that has been filed following the FERC's issuance of a 
certificate of public convenience and necessity for an interstate 
pipeline. The record of the certificate proceeding will include all 
necessary NEPA and/or Endangered Species Act documents; therefore, 
there is no need for a stay in this instance.
    In fact, given the comprehensive nature of the record in a FERC 
certificate proceeding, it can be asked validly whether, in this 
context, there is the need for NOAA to develop a separate record for 
purposes of the appeal. The FERC record will address the two threshold 
questions that are relevant in the Secretarial review process under the 
CZMA: whether the proposed activity is consistent with the objectives 
of the CZMA or otherwise necessary in the interest of national 
security.
    With regard to this second criteria, NOAA's regulations at section 
930.121 require that an activity must ``significantly or 
substantially'' further the national interest before the Secretary can 
override an objection based on the statutory ``national interest'' 
criteria. INGAA submits that FERC's issuance of a certificate of public 
convenience and necessity for an interstate pipeline should by 
definition be deemed to meet the criteria that an activity 
significantly and substantially furthers the national interest. A FERC 
certificate confers on its holder the ability to exercise a federal 
right of eminent domain. The fact that the Congress in the NGA saw fit 
to confer this right on a private applicant acting pursuant to a 
federal authorization speaks volumes about the national interest 
furthered by interstate pipeline projects with FERC certificates.
    Finally, given the comprehensive nature of the record in the FERC 
certificate proceeding, INGAA questions whether the 270-day record 
closing period and the 90-day period for decision are necessary in this 
context. Together, these two periods total close to a full year, when 
all that is really needed is a period for briefing and for NOAA to 
deliberate on the briefs and the record that already is complete as a 
result of the FERC certificate process. INGAA requests that, in cases 
where the FERC certificate already has been issued when an appeal is 
filed, the combined period be reduced to 120 days. That is, 30 days for 
briefing and 90 days for deliberation.
    Thank you in advance for your consideration of INGAA's comments.

                                      Donald F. Santa, Jr.,
                                                         President.
                                 ______
                                 
 The Energy Information Administration's Analysis of New Nuclear Power 
                        Plants: Myths and Facts

                PREPARED BY THE NUCLEAR ENERGY INSTITUTE

    MYTH: In a recent report prepared at the request of Sen. John 
Sununu (R-NH), the Energy Information Administration (EIA) analyzed the 
impact of various tax-related incentives in the conference report on 
H.R. 6. That legislation includes a production tax credit of $18 per 
megawatt-hour for the first eight years of operation for the first 
6;000 megawatts of new nuclear generating capacity built in the United 
States. The EIA report (SR/OIAF/2004-02) concluded that the production 
tax credit would, in fact, stimulate construction of 6,000 megawatts of 
new nuclear power capacity, but that further expansion beyond 6,000 
megawatts would not occur because new nuclear plants would still not be 
economic.
    FACT: The EIA analysis is incorrect, because EIA used 
unrealistically inflated assumptions about the capital cost of new 
nuclear power plants in the analysis performed for Sen. Sununu and in 
its Annual Energy Outlook 2004 forecast. EIA assumed a capital cost of 
$1,928 per kilowatt of capacity for new nuclear capacity. Credible 
industry estimates show that the capital cost for the first few nuclear 
power plants will be in the range of $1,300-$1,400 per kilowatt. As 
more plants are built, capital costs will decline to the $1,000-$1,100 
per kilowatt range. At this capital cost, new nuclear plants will be 
clearly competitive with other sources of baseload electricity.
    FACT: The $18-per-megawatt-hour production tax credit provided in 
the conference report on H.R. 6 represents a substantial incentive for 
construction of new nuclear plants. The tax credit will allow companies 
to assume the investment risks and licensing risks associated with 
building the first few new nuclear plants under a new licensing process 
that is essentially untested.
    FACT: Once the first few new plants are built with the stimulus 
provided by the tax credit, companies will be satisfied that they can 
manage the licensing and investment risks and will build significant 
numbers of new plants without government assistance. In a report 
(Nuclear Power's Role in Meeting Environmental Requirements) published 
in 2003, the Electric Power Research Institute used the EIA's own model 
to forecast the amount of new capacity that would be built using more 
reasonable capital cost assumptions than EIA. The result: At $1250 per 
kilowatt, 23,000 megawatts of new nuclear capacity would be built by 
2020. At $1,125 per kilowatt, 62,000 megawatts of new nuclear capacity 
would be built by 2020.
    FACT: In its own Annual Energy Outlook 2004, EIA explored an 
alternative to its high-capitalcost base case. If the capital cost of 
new nuclear power plants falls to $1,081 per kilowatt by 2019. EIA 
projects that about 26,000 megawatts of new nuclear capacity would be 
built by 2025 (Annual Energy Outlook 2004, page 58). Since nuclear 
power plants have lower operating costs than all other forms of 
electricity generation, EIA found: ``If the $1,081 per kilowatt 
estimate could be realized [as the industry expects], it is possible 
that nuclear power could eventually be used to satisfy virtually all 
the baseload demand in the United States in future years.'' (Emphasis 
added.)

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