[Senate Hearing 108-9]
[From the U.S. Government Publishing Office]



                                                          S. Hrg. 108-9
 
                     NATURAL GAS SUPPLY AND PRICES

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

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                      ONE HUNDRED EIGHTH CONGRESS

                             FIRST SESSION

           TO RECEIVE TESTIMONY REGARDING NATURAL GAS SUPPLY 
                               AND PRICES

                               __________

                           FEBRUARY 25, 2003


                       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
                     James P. Beirne, Chief Counsel
               Robert M. Simon, Democratic Staff Director
                Sam E. Fowler, Democratic Chief Counsel
                Scott O'Malia, Professional Staff Member
                   Deborah Estes, Democratic Counsel
         Jennifer Michael, Democratic Professional Staff Member


                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Best, Robert W., Chairman, Atmos Energy Corporation, Dallas, TX..    28
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................     6
Bunning, Hon. Jim, U.S. Senator from Kentucky....................     5
Caruso, Guy F., Administrator, Energy Information Administration.     8
Domenici, Hon. Pete V., U.S. Senator from New Mexico.............     1
Johnson, Hon. Tim, U.S. Senator from South Dakota................     5
Landrieu, Hon. Mary L., U.S. Senator from Louisiana..............    41
Rattie, Keith, President and CEO, Questar Corporation............    21
Welch, David, President, BP Alaska-Canada Pipelines..............    16

                               APPENDIXES
                               Appendix I

Responses to additional questions................................    51

                              Appendix II

Additional material submitted for the record.....................    63


                     NATIONAL GAS SUPPLY AND PRICES

                              ----------                              


                       TUESDAY, FEBRUARY 25, 2003

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 2:05 p.m. in room 
SD-366, Dirksen Senate Office Building, Hon. Pete V. Domenici, 
chairman, presiding.

          OPENING STATEMENT OF HON. PETE V. DOMENICI, 
                  U.S. SENATOR FROM NEW MEXICO

    The Chairman. The hearing will please come to order. I know 
other Senators have other meetings and will be here shortly. We 
are going to depart from the plan for just 5 or 6 minutes here 
and let our new Senator, Senator Murkowski, ask a few questions 
because she has to leave us, so if Senator Bingaman does not 
object--and I have talked with him, and he is in accord--you 
can proceed, Senator, and then we will go back into the regular 
order.
    Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman, and I do 
appreciate your indulgence, and that of the committee, to allow 
me to ask just a couple of brief questions initially, and I 
know that this is out of order, as we are not having an 
opportunity to hear the testimony.
    I have had a chance to read it, and I am looking forward to 
meeting hopefully with several of you individually afterwards, 
but if I can just begin with you, Mr. Caruso, in your position 
with the Energy Information Administration, I understand that 
the Energy Business Watch had released a report just this 
morning predicting a crisis in the natural gas markets, 
specifically, found total natural gas supplies for this year 
likely to be 1.5 to 2.0 tcf below the most recent EIA forecast 
for 2003, and I would just like your reaction to that.
    Mr. Caruso. Our estimate is that natural gas production was 
down about 2.3 percent last year. However, we do expect that 
there will be some recovery in 2003, so at least our best 
assessment of 2003 on the supply side as of today is that we 
are expecting a slight improvement, as opposed to current 
projections.
    Senator Murkowski. So even though there is a recognition it 
is a little bit lower, you are relatively confident that on the 
domestic gas supplies that we can sustain, we can meet the 
demand we need for natural gas in America?
    Mr. Caruso. That is our current assessment, but I must also 
mention that we are expecting an average price for 2003 of 
$4.30 an mcf, which is a substantial increase, on average, 
compared to last year. Yes, we can meet it, but at a fairly 
substantial price increase.
    Senator Murkowski. Then if I may, Mr. Welch, have you had 
an opportunity to review this report from Energy Business 
Watch?
    Mr. Welch. No, ma'am, I have not had a chance to review 
this report out today, but I would say that the information 
that we are seeing as the production is rolling up to us 
indicates that we in all likelihood reduce production in the 
United States about 5 percent in 2002, and that trend is likely 
to continue. We are heavily drawing down the natural gas 
inventories right now. I feel like there will be plenty of gas 
to fuel the market, but it is going to come from a combination 
of the production plus potentially additional withdrawals from 
storage.
    Senator Murkowski. Well, how can the United States then 
reduce this gap, the gap between our supply and demand, without 
becoming more dependent then on foreign sources?
    Mr. Welch. I guess we will get right into it. The sources 
we see around are three major areas of accessibility in the 
United States and North America. Those three are the Rocky 
Mountain areas, which have some additional growth potential, 
Canadian frontier gas in the Mackenzie Delta, and Alaska gas, 
which is by far the largest potential source of new natural 
gas. We already have about 35 trillion cubic feet discovered 
there, and Government estimates are that there are as much as 
100 to 150 additional trillion cubic feet of natural gas to be 
discovered in Alaska.
    Senator Murkowski. In Alaska?
    The Chairman. You are interested in that, I assume.
    [Laughter.]
    Senator Murkowski. Yes, I am. It always comes back to 
Alaska. Is that not the way it is? Let us see, how much lower 
48 and Canadian production currently has some type of 
Government incentive involved?
    Mr. Welch. I would say that when you are looking at the 
total domestic supply situation, you have several different 
types of basins that are incented, Deepwater, for example, 
Deepwater royalty relief, section 29 gas. In aggregate, I would 
say that somewhere in the neighborhood of 20 to 30 percent of 
the production in the United States would fall under some sort 
of special tax regime.
    Senator Murkowski. And that includes the royalty reductions 
and----
    Mr. Welch. That would not include Canada. If you throw 
Canada in there, probably another 5 percent or so.
    Senator Murkowski. Okay. Then, given the gap between the 
supply and the demand, if the Alaska natural gas pipeline can 
come on line, and given what you believe is available up there, 
in your opinion, how is this going to affect the domestic 
market? In other words, are we going to be displacing lower 48 
gas with our Alaskan gas?
    Mr. Welch. Well, my belief is that most likely the swing 
production will be imported LNG. I personally believe we are 
going to need all sources of North American gas, gas from the 
lower 48, gas from Alaska, also gas from Canada, and we will 
have to supplement that with additional imports of LNG, so I 
think that we are going to need all the gas that we can produce 
from this continent to satisfy the natural gas demand over the 
next coming decades.
    Senator Murkowski. And what kind of time lines are we 
talking about right now?
    Mr. Welch. For the Alaska gas pipeline? Specifically, if we 
had the legislation that enabled us to go forward this year, 
the first gas would be sometime between the end of 2011, 2012 
time frame, if everything went right.
    Senator Murkowski. Now, the concern, of course, that has 
been presented with any kind of incentives, or call them fiscal 
enablers, whatever, is that it will somehow or other result in 
unfair pricing treatment towards other gas that is produced 
domestically. Can you comment on that?
    Mr. Welch. I can comment on this, and I have a slide, 
actually, to this effect that I did not have in my written 
testimony, if I could put that up, then I would be happy to 
explain that.
    Most people believe that the fiscal terms that exist 
throughout the United States are similar in just about every 
basin, but the truth of the matter is that the fiscal terms 
that exist are different in different parts of the United 
States and in Canada, and what this highlights at the top there 
is the split between discounted cash flow that goes to the 
investor and discounted cash flow that goes to the Government, 
and in the case of Alaska, 84 percent of the value created by 
the project goes to the Government and 16 goes to the investors 
who take all of the capital risk.
    In the case of the Canadian frontier regime, the investor 
keeps 26 percent.
    The Gulf of Mexico shelf, which is conventional Gulf of 
Mexico, 31 percent goes to the investor, and Gulf of Mexico 
Deepwater, because of the Deepwater royalty relief, et cetera, 
35 percent goes to the investor. Section 29 gas is being 
contemplated in both the House and the Senate for extension, 
and that would either be 27 or 33 percent.
    So you can see, in looking at the Alaska fiscal terms, we 
are disadvantaged with respect to the fiscal terms that exist 
in Alaska relative to these other, which are very important 
contributing basins, and this chart in green, which are the 
lower ones, show instances where a policy has been enacted to 
actually materially impact the supply that we have 
domestically.
    Senator Murkowski. Mr. Chairman, I have some other 
questions, but I will be meeting, as I said, with some of the 
members of the panel later. I do have some statements that I 
would like to submit for the record, if I may.
    The Chairman. Your statements will be made a part of the 
record.
    If you have additional requests in writing, we will submit 
those, and we thank you very much, and hope you are able to 
keep your schedule.
    Senator Murkowski. Thank you. I have another 5 minutes, so 
I can listen. See, we were so quick here.
    The Chairman. Okay. Very good. Thank you. Thank you very 
much, Senator Bingaman.
    I think we all know why we are here. The supply outlook and 
the recent increases in price obviously indicate to us that we 
have to try our very best to see what is happening and to get 
evidence from the experts as to what is going to happen in the 
foreseeable future, and do we have the available domestic 
resources to meet the growing demand, and the outlook for the 
growing demand, where are these resources, and what is being 
done to develop the gas and bring it to market, what has been 
the impact on consumers, and today we have four witnesses that 
are going to talk about these subjects one way or another, and 
we are going to take them in the following order, at their 
request.
    The Honorable Guy Caruso, Administrator of the Energy 
Information Agency. He is going to testify on supply and demand 
outlook, as well as address the price outlook. Mr. David Welch, 
president of BP Alaska-Canadian operations, representing 
producers and providing testimony on the U.S. reserves and 
production outlook, and we have Mr. Keith Rattie, president and 
CEO of Questar, will provide testimony regarding natural gas 
pipelines and whether or not we will have sufficient 
infrastructure to bring these new supplies on.
    Then Robert Best, chairman and CEO of Atmos Energy will 
provide testimony on behalf of the American Gas Association 
regarding the impact that price increases will have on the 
industrial and residential consumers.
    I am very appreciative of the witnesses joining us today. 
Actually, when we started setting these meetings up, we were 
not, certainly not aware that the situation would be exactly as 
it is today. It has become more volatile and changed more 
rapidly than we thought from my standpoint.
    I am going to forego opening statements and yield to 
Senator Bingaman, and then the witnesses in the order I stated.
    [The prepared statements of Senators Domenici, Bunning and 
Johnson follow:]

       Prepared Statement of Hon. Pete V. Domenici, U.S. Senator 
                            From New Mexico

    Last week, this Committee held a hearing to address the important 
issue of oil supply and prices in the United States. Witnesses spoke to 
the bleak picture of rising demand, rising prices and declining 
domestic supply. Today, we turn to the situation facing natural gas, 
and I fear the outlook is equally grim. Headlines tell the story of 
rising gas prices and the impact it is having on consumer heating bills 
as well as the impact to our economy. However, despite recent price 
spikes, gas production has not responded as it has in years past.
    In this year alone, gas supply is expected to decrease by 1 billion 
cubic feet (Bcf) per day, while demand in just the month of February is 
projected to be up 2.8 Bcf per day. Even after the winter heating 
season ends, gas supplies nationwide will be down nearly 30 percent. 
Because those supplies must be replenished, gas prices will continue to 
rise. Higher prices has led to some additional gas production from 
unconventional sources, but on the whole, the U.S. is still increasing 
imports in order to meet demand.
    Even more troubling, most new production in the United States today 
appears to be coming from existing basins. Not only does this deplete 
proven supplies at a higher rate, but failure to develop new wells 
leaves us with little to plan for in the future. Industry is turning 
away from exploratory drilling in the U.S., citing such obstacles as 
access to multiple use lands, burdensome environmental regulations, and 
disincentives in the tax code. The Energy Information Administration 
states that reducing the restrictions to multiple use lands alone would 
increase available resources by 87 billion cubic feet. Opening these 
Federal lands to environmentally safe production would secure domestic 
supplies while leaving untouched our priceless national treasures--
National Parks, wilderness areas, and National Monuments.
    In addition to concerns over gas supply and prices, I am also 
troubled by the aging infrastructure. Adequate supplies of gas are 
useless without a means of delivery. According to EIA, higher prices 
over the next ten to fifteen years should stimulate the construction of 
the Alaskan North Slope and MacKenzie Delta pipelines, but this is just 
a start. Serious investment in pipelines is necessary to encourage 
development and stabilize prices. I hope today's witnesses will be 
addressing issues related to the existing infrastructure.
    In spite of the bleak forecasts, I do believe that there are some 
positive policy options. In the short term, the Omnibus Appropriations 
bill that was just signed by the President last week allocated $1.7 
billion to the Low Income Home Energy Assistance Program, known as 
LIHEAP. These funds will go to those most harmed by skyrocketing energy 
prices--the working poor, the elderly, disabled persons, and families 
transitioning from welfare to work. In addition, in the 107th Congress, 
we passed a pipeline safety bill to protect the hard working 
individuals who are out there every day making sure the infrastructure 
we do have continues the flow of resources.
    These are positive steps, but much more needs to be done. The 
comprehensive energy bill debated in the last Congress contained loan 
guarantees for the Alaska Gas Pipeline, as well as provisions to 
stimulate exploration of unconventional sources, such as coalbed 
methane, shale, and tightsands. Unfortunately, we could not resolve 
differences between House and Senate versions of the bill prior to 
adjournment. So in the 108th Congress, we begin again.
    Last year's bill was a good start, but on the whole focused too 
much on regulation and not enough on securing domestic supplies of 
energy. As more and more production shifts overseas to increasingly 
unstable and even hostile regimes, the need for a comprehensive 
national energy policy becomes terribly serious. I am hopeful that as 
this Committee moves forward in the development of an energy bill for 
the 108th Congress, we will take meaningful steps to encourage 
production in a clean and sustainable manner that preserves both our 
environment and our national security.
    Today's hearing is part of that process. I expect the panel before 
us will provide valuable insight and information that will aid in the 
development of a strong energy bill. I look forward to hearing from 
each of you.
                                 ______
                                 
   Prepared Statement of Hon. Jim Bunning, U.S. Senator From Kentucky

    Thank you, Mr. Chairman.
    I am pleased to have this opportunity to examine the state of 
natural gas supply and prices in our country.
    Natural gas is an important form of energy for the United States.
    The United States is currently facing an energy crisis. We need to 
have access to adequate supplies of natural gas at affordable prices.
    Natural gas prices have increased this year almost 70% over the 
last year. The long cold winter we have experienced this year, the 
Venezuela crisis, and the threat of a possible war with Iraq have all 
made matters worse.
    I am concerned by the increase in price because higher prices place 
a strain on the American family's budget by causing consumer products 
to increase. It simply costs more to haul and move these goods, and in 
turn many times the increase is passed on to the consumer. This in turn 
affects our economic recovery.
    Now is the time for us to boost our domestic energy sources as well 
as promote conservation. We need a serious dual track for a real 
national energy policy.
    I look forward to hearing about the status of our natural gas 
supply today. I also appreciate the time our witnesses have taken today 
to come testify.
    Thank you.
                                 ______
                                 
         Prepared Statement of Hon. Tim Johnson, U.S. Senator 
                           From South Dakota

    Mr. Chairman, this hearing could not come at a better time. Natural 
gas prices are currently higher than they have been in recent history. 
Traditionally, natural gas prices were relatively stable and low. But 
as demand for natural gas has increased and supplies have become 
tighter, price fluctuations have become the rule rather than the norm. 
Just yesterday, wholesale natural gas prices spiked almost 40% in one 
day.
    Those who heat their homes with natural gas are all too familiar 
with the huge fluctuations in prices over the last few years. Last 
year, we had a warm winter and abundant supplies. This year, the winter 
has been cold, the supplies are lower, and the economy is slower. All 
of this is creating difficulties for consumers and could affect our 
energy security for years to come. It is Congress' responsibility to 
help find solutions to this ongoing problem.
    It is clear that unknown factors like weather and sudden changes in 
demand can still impact prices. However, it also clear that demand for 
natural gas is growing rapidly, particularly because of the increasing 
reliance of using this resource for electricity generation. Hence, more 
than most natural resources, natural gas is subject to the boom-bust 
cycle that the nation continues to experience in many sectors of the 
energy system. We have seen similar effects happening with gasoline 
prices recently.
    Like other areas of the country, these fluctuations directly affect 
the residents of South Dakota. Almost half of the state depends on 
natural gas for their heating needs. Winters are tough in South Dakota 
and many of my constituents have limited income. Spikes in heating 
bills don't help. Farmers in my state are also feeling the crunch. 
Natural gas is the fundamental feedstock ingredient and the major cost 
component for the production of nitrogen fertilizer. The cost of 
natural gas represents 70 to 90 percent of the production cost of one 
ton of anhydrous ammonia nitrogen fertilizer. With huge increases in 
natural gas prices, farmers in my state, already reeling from a 
prolonged drought, will be even more pressed to make ends meet.
    As a member of the Senate Energy and Natural Resources Committee, I 
am committed to alleviating the boom-bust cycle that we constantly 
experience. In the last Congress, the energy bill included provisions 
that eased restrictions and streamlined regulations for increased 
responsible exploration of natural gas and oil, both on-land and 
offshore. In particular, it removed barriers to allow the construction 
of a natural gas pipeline from Alaska to the lower 48 states. There are 
enormous natural gas reserves in Alaska but there is physically no way 
to move it. Construction of this pipeline would greatly alleviate any 
future shortages that could occur.
    We must continue these and other efforts this year to help ensure 
our energy security for the future. Unlike oil, natural gas is largely 
a domestic product. It is not as subject to the political winds of 
unstable areas like the Middle East and Venezuela. There is a 
tremendous supply of natural gas in the lower 48 states. We need to 
consider ways to tap these reserves in an environmentally safe manner. 
Otherwise, we may face a huge supply/demand gap in the very near future 
and may end up relying more on liquified natural gas imports from more 
unstable areas of the world like Algeria, Nigeria and Oman. At a time 
when our energy security is so inextricably tied to areas of the world 
where terrorists often reside, we must concentrate of energy supplies 
that out country can control.
    A balanced approach to improve the nation's energy situation is the 
best way to break the nation out of the boom-bust cycle we constantly 
face and bring more stability to the system. Combining increased 
exploration of traditional fossil fuels, like natural gas, with greater 
usage of clean, renewable fuels and sources of energy would help to 
displace the level of foreign oil we currently use. During these 
difficult times, it is imperative that we find ways to improve and 
stabilize the nation's energy security and reduce our dependence on 
foreign oil.

    The Chairman. Senator Bingaman.

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

    Senator Bingaman. Thank you very much, Mr. Chairman. I 
welcome all of the witnesses. I did want to just make a very 
short opening statement. We have, as I see it, two issues. One 
is short-term, one is long-term. How do we deal with both 
challenges?
    I just received today, in the last hour or so, a fax from 
John Huntsman, who is with Huntsman Corporation, the largest, 
privately-owned chemical manufacturer in the world. I just 
wanted to read a couple of the things he said in that fax and 
then just have that for you to respond to in your testimony.
    He says, to date, ``natural gas prices in America increased 
by over 40 percent from $6.61 to $9.60.'' As I say, I received 
this in the last hour. I do not know if that is still where the 
price is or not. Mr. Caruso is indicating to me that it is 
higher than that now.
    ``This unparalleled spike in prices represents the highest 
natural gas prices ever. There is pure manipulation going on to 
cause prices to increase so dramatically . . . It is killing 
manufacturing and commerce in America . . . We are losing 
thousands of jobs and our entire chemical industry because of 
the refusal of the administration to adopt an energy policy. I 
am frightened by this.''
    He goes on to talk about his view that there is fraudulent 
manipulation going on by oil companies and futures traders in 
the New York Mercantile Exchange and that is the only 
explanation for this kind of dramatic increase that he is 
talking about today.
    I would be interested in any suggestions that any of you 
could give us as to what can be done by the administration and 
the Congress to deal with this short-term crisis, because 
obviously this is not just impacting the chemical industry. It 
is going to impact consumers very dramatically if the situation 
continues.
    Thank you.
    [The prepared statement of Senator Bingaman follows:]

        Prepared Statement of Hon. Jeff Bingaman, U.S. Senator 
                            From New Mexico

    Thank you, Mr. Chairman. This is an important and timely hearing. 
Yesterday, the Henry Hub spot price for natural gas shot up to $12.50 
per mmbtu and the NYMEX futures price for March increased by 38% in one 
day--from $6.60 on Friday to over $9.00.
    It was only two winters ago that natural gas prices spiked as high 
as $10 per thousand cubic foot and caused significant economic hardship 
to residential, commercial and industrial consumers. Prices remained 
high throughout the first half of 2001. Producers responded with 
increased drilling. The natural gas rig count rose to over 1000 rigs in 
July 2001--almost 3 times the number of rigs working in 1999. 
Production increased and prices moderated for several months. However, 
gas prices began to increase this summer, and once again this winter we 
are experiencing a heating season with very high natural gas costs for 
consumers.
    For the manufacturing sector these prices are particularly painful. 
I'd like to insert for the record a message I received today from a 
chemical manufacturer. I'll quote part of his message: ``Our company 
and all others in the chemical industry will go out of business with 
gas prices this high. Billions of dollars will be lost in export trade. 
Millions of jobs are at risk . . . The manufacturing sector is . . . 
becoming uncompetitive with the rest of the world.''
    In this context it is urgent that this committee thoroughly explore 
what is happening with gas supply this afternoon.
    Is this winter a mirror image of 2001? Or are there different 
supply and demand forces at work today? Are domestic producers 
responding to these high prices with increased drilling as they did in 
2001? Many analysts say the drilling response has been tepid--why? When 
can consumers expect some moderation in their gas costs? Today's 
hearing is intended to provide us with the answers to these questions.
    Our hearing will also examine the long term gas supply challenges 
facing the North American market. Over the next decade, we see the 
demand for natural gas in the U.S. growing faster than our current 
sources of production can meet. What are our environmentally acceptable 
options for new sources of supply? Will we have increased imports of 
liquified natural gas (LNG) or additional supplies from Canada and 
Alaska? Will coalbed methane or the deep water Gulf provide additional 
gas resources? What are the obstacles to bringing those supplies to 
market? What policy choices should we in Congress make to assure that 
natural gas supply is adequate and prices are affordable?
    On the demand side, natural gas for power generation is projected 
to see the fastest growth. How will potential changes in environmental 
and energy policies--such as climate change mitigation or the promotion 
of renewable energy--affect that demand growth? How does the growth of 
gas use for power generation affect the more traditional uses of 
natural gas for industrial processes, and residential heating?
    We have an excellent panel of witnesses before us to address these 
and many other questions, Mr. Chairman. I look forward to hearing from 
them.

    The Chairman. Thank you very much. Who is this gentleman?
    Senator Bingaman. John Huntsman. He is the chairman and CEO 
of Huntsman Corporation of Salt Lake City, which is the largest 
chemical manufacturer in the country.
    The Chairman. Let me suggest--my few comments in rebuttal, 
not knowing nearly as much as he knows, but if he is as 
accurate on the facts as he is on who is responsible for not 
having an energy policy, then he is all wet, because he started 
the letter, said the administration has no energy policy. I 
think they sent us one. We did not produce one. The House did, 
the Senate did not--or the Senate did. We did not come up with 
one. So if he would have said failure on the part of Congress 
to come up with energy policy, I might have a lot more credence 
in the rest of his suggestions of knowledge.
    Having said that, I think he raises a good question and we 
ought to try to answer it if we can.
    Let us proceed with Mr. Caruso.

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

    Mr. Caruso. Thank you, Mr. Chairman. Thank you for this 
opportunity to appear today to discuss an outlook for the 
critical natural gas supply and prices in this country. My 
remarks will highlight the growing role that natural gas is 
playing in meeting U.S. energy needs not only in the short-, 
but in the longer-term, and I will be referring to the Energy 
Information Administration's Short-Term Energy Outlook and it's 
long-term Annual Energy Outlook in my remarks.
    I should note, of course, these projections are not meant 
to be exact predictions of the future but, rather, they 
represent what we believe is a highly likely energy future, 
given the technology and demographic trends we are witnessing, 
the current laws, policies, and regulations, indeed, including 
consumer behavior.
    The current U.S. natural gas market, as you have noted, is 
extremely tight, with rapidly increasing prices in recent days 
in particular. Consumption has been exceeding supply in recent 
months. Given this tight market, the amount of natural gas in 
storage has declined steadily and prices have increased 
sharply. Just to follow up on Senator Bingaman's point, the 
spot price at Henry Hub just before we left the Department was 
between $18 and $20 an mcf, so you can see it has moved 
quickly.
    The current trend is part of a general volatility in 
natural gas policies that we have witnessed in recent years. 
The first chart here shows that, and it also shows our outlook 
for prices over the next 2 years. As I mentioned to Senator 
Murkowski, we are projecting a continuation of this price above 
$4 during 2003 and 2004 in our latest Short-Term Energy 
Outlook.
    There are three major market forces behind this recent rise 
in both consumption and prices. The harsh winter weather, 
particularly in those areas of the country that are large 
consumers of heating fuels, the interruption of Venezuelan oil 
exports, which has been a primary factor in the oil price 
increases, and strong natural gas demands in both the 
industrial and electric power sectors.
    U.S. demand for natural gas is expected to remain strong, 
as indicated by these prices, in the next 12 to 18 months. We 
do expect, however, that after this period of high prices there 
will be a supply response, and what we believe we are seeing 
now is a lagged impact of the relatively low drilling for gas 
that we witnessed in 2002, following high levels in 2001. 
Recent drilling levels have been increasing, as measured by rig 
counts, and are rather high relative to past history, and we 
expect this would continue, given the price incentives we are 
seeing now.
    Now, of course, as already mentioned in earlier remarks, 
increased pipeline capacity will be needed clearly to ease some 
of these regional bottlenecks, such as those in the Rocky 
Mountains, in order to deliver the kinds of volumes of gas we 
believe will be demanded by end users in the next 12 to 18 
months.
    Turning to the longer-term outlook, this next chart shows 
that by 2025, we expect U.S. natural gas consumption to reach 
almost 35 trillion cubic feet, increasing at an average annual 
rate of 1.8 percent. The largest sectoral growth in demand 
during this time period will occur in electric power 
generation, as shown by the line in blue. Natural gas is the 
fastest growing fossil fuel in our energy mix, because it is 
the cleanest-burning, and in the generating sector it has 
higher fuel efficiencies, lower emissions, lower capital cost, 
and shorter construction lead times than any of its 
competitors.
    Of course, lining up the supplies and building the 
infrastructure needed to meet this kind of demand will be key 
as we look out over this next couple of decades. Factors that 
are driving this process, of course, include the technological 
progress we have already seen, the macroeconomic trends, 
weather, as we are witnessing this winter, and geopolitical 
factors, particularly for some of the oil, LNG, and other gas 
imports.
    The projected increases in domestic gas and imports are 
expected to satisfy the growing mid-term demand for natural gas 
as a result of these higher price incentives. The longer-term 
domestic natural gas production is projected to rise more 
slowly than demand, only 1.3 percent per annum, so that the 
difference between consumption and supply will be made up by 
growing net gas imports, as shown in this chart.
    Net imports are projected to increase to about 22 percent 
of our total demand by 2025. For reference, we are at about 16 
percent this year. Both LNG and pipeline imports are projected 
to increase 2 tcf each by 2025, compared with current levels.
    However, a variety of additional new, large volume 
suppliers also will be needed, and these sources will likely 
include deep and ultradeep offshore projects in the Gulf of 
Mexico, unconventional gas, mainly in tight sands in the Rocky 
Mountains. We expect the Mackenzie Delta pipeline will need to 
be built, as well as an Alaskan natural gas pipeline that will 
deliver gas during this time frame. As shown in this chart, we 
expect these additional supplies over the next 2 decades.
    For the longer-term, the United States does have a large 
endowment of natural gas resources. Based on estimates by the 
U.S. Geological Survey and the Minerals Management Service, we 
estimate that total resources of gas are 1,289 tcf. These 
resources must be developed to offset the sharp decline we are 
seeing in the existing fields, and this chart shows that the 
new natural gas supply will come from all of these regions, 
both the unconventional gas in the Rocky Mountains tight sands, 
Alaska, Mackenzie Delta, other Canada and LNG.
    You can see that the black area of the chart shows that the 
Alaskan gas comes on in the latter part of the forecast period. 
We have it in the reference case coming in 2021, based on our 
assumptions of where prices and technology are moving. However, 
that date can change based on prices differing from our 
assumptions, or technology changing, or other policy changes 
which I know this committee has studied in the past.
    The lower 48 States will need to increase interstate gas 
pipeline capability in order to accommodate this growth and to 
meet the consumption we expect will be demanded. These changes 
in natural gas production and delivery likely will result in 
uneven natural gas prices over this time frame as these new 
supplies come on line, but in general we do expect, after some 
reduction from the current gas prices, that it will resume an 
upward trend towards a price in nominal terms of about $7 an 
mcf by 2025. That is the kind of gas price path we see over the 
longer-term.
    We expect a reduction in the current price after this 
extremely unusual period now, but an upward trend towards 
higher prices in order to bring forth the kinds of sources we 
see in this chart.
    The Chairman. Mr. Caruso, I do not know that we set a time 
before each of you started. Perhaps I failed to do that, but we 
are getting pretty close. Can you summarize?
    Mr. Caruso. That was my last substantive point. I just want 
to conclude, Mr. Chairman, by saying we do face, as you have 
all mentioned already, highly short-term volatile natural gas 
markets, and in the long-term, we face challenges to meet the 
kind of demand outlook that we are projecting. We at the Energy 
Information Administration look forward to working with you and 
members of the committee to meet these challenges.
    And thank you very much again.
    [The prepared statement of Mr. Caruso follows:]

          Prepared Statement of Guy F. Caruso, Administrator, 
                   Energy Information Administration

    Mr. Chairman and Members of the Committee: I appreciate the 
opportunity to appear before you today to discuss the outlook for 
natural gas supply and prices in the United States.
    The Energy Information Administration (EIA) is the statutorily 
chartered statistical and analytical agency within the Department of 
Energy. We are charged with providing objective, timely, and relevant 
data, analysis, and projections for the use of the Department of 
Energy, other Government agencies, the U.S. Congress, and the public. 
We do not take positions on policy issues. We produce data and analysis 
reports that are meant to help policy makers determine energy policy. 
Because we have an element of statutory independence with respect to 
the analyses that we publish, our views are strictly those of EIA. We 
do not speak for the Department, nor for any particular point of view 
with respect to energy policy, and our views should not be construed as 
representing those of the Department or the Administration. EIA's 
baseline projections on energy trends are widely used by Government 
agencies, the private sector, and academia for their own energy 
analyses.
    The projections in this testimony are from the February 2003 Short-
Term Energy Outlook (STEO) and the Annual Energy Outlook 2003 (AEO). 
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, and 
technological breakthroughs. (Many of these uncertainties are explored 
through alternative cases.)
    The AEO is based on data available through September 2002; the STEO 
projections reflect more recent data. As a result, the short-term 
projections in the AEO and the February STEO do not necessarily match.

                        OVERVIEW AND ASSUMPTIONS

    EIA's Short-Term Energy Outlook is a monthly forecast report that 
addresses a wide range of issues in energy markets. The forecast has a 
2-year horizon, based on simulations of EIA's Short-Term Integrated 
Forecasting System (STIFS), incorporating the latest exogenous 
information available. The historical energy data are mostly EIA data 
regularly published in other EIA publications. STIFS is driven 
principally by three sets of assumptions or inputs: estimates of key 
macroeconomic variables, world oil prices, and weather. Macroeconomic 
estimates are produced by Global Insight (formerly DRI/WEFA) but are 
adjusted by EIA to reflect our own assumptions about the world price of 
crude oil, energy product prices and other factors, which may affect 
the macroeconomic outlook.
    The Annual Energy Outlook is produced using the National Energy 
Modeling System (NEMS), a computer-based, energy-economy modeling 
system of U.S. energy markets through 2025. NEMS projects annual 
production, imports, consumption, and prices of energy, subject to 
assumptions on macroeconomic and financial factors, world energy 
markets, resource availability and costs, behavioral and technological 
choice criteria, cost and performance characteristics of energy 
technologies, and demographics. Two of the key assumptions in NEMS are 
world oil prices and macroeconomic growth.
    World oil prices averaged about $23.15 per barrel in 2002 in 2001 
dollars. Between now and 2025 they are expected to rise to about $26.60 
a barrel in 2001 dollars, as world oil demand increases from 76 million 
barrels per day to 123 million barrels per day. In 2003 real gross 
domestic product (GDP) is projected to grow by 2.8 percent over 2002 
and to grow at an annual average rate of 3.0 percent between 2001 and 
2025.

                     SHORT-TERM NATURAL GAS OUTLOOK

    Over the last twelve months the U.S. natural gas market has 
tightened significantly as principal demand and supply factors have 
worked to swing market conditions from being oversupplied (excess 
storage) to being relatively undersupplied (low storage). An 
approximate doubling of average spot prices has ensued. Strong 
underlying domestic demand for natural gas has been boosted by short-
term or cyclical factors (including weather and oil market shifts) 
while domestic natural gas resource development efforts have faded 
relative to the spectacular levels of activity seen in 2001.
    A salient feature of the contrast between U.S. natural gas market 
conditions in 2003 and those during 2002 is the dramatic difference in 
the availability of natural gas in storage as a cushion between strong 
demand growth and (at least somewhat) less robust gains in domestic 
production and other new supply. Steady pressure on wellhead supply 
from strong demand, stemming from weather-related factors, spillover 
from tight oil markets, and expected growth from the industrial and 
electric power sectors, is expected to keep domestic natural gas prices 
high in 2003 and at risk for significant volatility through at least 
the next 12 to 18 months. Expected strong levels of domestic natural 
gas drilling and development should provide increases in gross 
productive capability through 2004 but increases in pipeline capacity 
will be needed to insure maximum growth in effective deliverability. 
Thus, the expected average wellhead price this year is $4.35 per 
thousand cubic feet in current dollars and $4.27 next year, compared to 
$2.95 last year.

                      NATURAL GAS OUTLOOK TO 2025

    By 2025 total natural gas consumption is expected to increase to 
almost 35 trillion cubic feet (Tcf) or 26 percent of U.S. delivered 
energy consumption (Figure 1).*
---------------------------------------------------------------------------
    * Figures 1-10 have been retained in committee files.
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    Domestic gas production is expected to increase more slowly than 
consumption over the forecast, rising from 19.5 Tcf in 2001 to 26.8 Tcf 
in 2025. Growing production reflects increasing natural gas demand and 
is supported by rising wellhead gas prices, relatively abundant gas 
resources, and improvements in technologies, particularly for 
unconventional gas. In this forecast, economic conditions allow an 
Alaskan pipeline to begin moving gas to the lower 48 States in 2021. 
The national average wellhead price is projected to reach $3.90/Mcf in 
2001 dollars by 2025.
    The difference between consumption and production is made up by 
increasing use of imports throughout the forecast, particularly from 
liquefied natural gas (LNG), with a 2 Tcf increase expected over 2001 
levels. By 2025 we expect expansion at the four existing terminals and 
construction of three new LNG terminals.
    Consumption. Total natural gas demand in 2002, based on data 
reported through September, declined by 1.4 percent from the 2001 
level. Overall weakness in the industrial sector, particularly in the 
first three quarters of the year, prevented a posting of positive 
growth. However, solid growth in natural gas demand is likely in 2003, 
especially if the industrial sector as a whole expands significantly as 
expected (Figure 2). In 2004, natural gas demand is projected to rise 
by an additional 2.4 percent as industrial demand continues its 
recovery from its 2002 lows.
    Natural gas demand this winter (fourth quarter 2002 and first 
quarter 2003) is expected to be about 8 percent above last winter's 
demand, largely due to the fact that gas consumption-weighted heating 
degree-days will be 11 percent above year ago levels, provided February 
and March post normal temperatures.
    U.S. natural gas consumption is expected to increase by 1.8 percent 
annually from 2001 through 2025. Gas consumption by electric generators 
is expected to double over the forecast, from 5.3 Tcf in 2001 to 10.6 
Tcf in 2025, an average annual growth rate of 2.9 percent (Figure 3). 
Demand by electricity generators is expected to account for 30 percent 
of total natural gas consumption in 2025.
    Most new electricity generation capacity is expected to be fueled 
by natural gas, so natural gas consumption in the electricity 
generation sector is projected to grow rapidly throughout the forecast 
as electricity consumption increases. Although average coal prices to 
electricity generators are projected to fall throughout the forecast, 
gas-fired generators are expected to have advantages over coal-fired 
generators, including lower capital costs, higher fuel efficiencies, 
shorter construction lead times, and lower emissions.
    Historically the industrial sector, excluding lease and plant fuel, 
is the largest gas-consuming sector, with significant amounts of gas 
used in the bulk chemical and refining sectors. Industrial consumption 
is expected to increase by 3.4 Tcf over the forecast, driven primarily 
by macroeconomic growth. The chemical and metal durables sectors show 
the largest growth. Combined consumption in the residential and 
commercial sectors is projected to increase 2.6 Tcf from 2001 to 2025, 
driven by increasing population, healthy economic growth, and gradually 
rising prices in real terms. Natural gas remains the overwhelming 
choice for home heating throughout the forecast period, with the number 
of natural gas furnaces rising nearly 18 million.
    Production. New data provided to EIA by the Minerals Management 
Service on natural gas production in the Federal Offshore Area of the 
Gulf of Mexico has resulted in a revised view of total domestic natural 
gas production for 2002. It is now estimated that U.S. dry natural gas 
production fell by 450 billion cubic feet (Bcf) (2.3 percent) in 2002 
from the 2001 total. At least moderate production increases are 
expected in 2003 and 2004 as high natural gas prices and strong near-
term demand pressures drive drilling activity and well completions to 
very robust levels over the period. Monthly domestic oil and gas lease 
revenues, which averaged about $280 million in 2002, are expected to 
reach the $400 million mark in 2003 and remain near that level in 2004.
    The forecast estimate of total technically recoverable natural gas 
resources as of January 1, 2002, was 1,289 Tcf. These resource 
assessments come primarily from the assessments done by the U.S. 
Geological Survey for onshore regions and by the Mineral Management 
Service for the offshore.
    These resources included 183 Tcf of proved reserves (9 years of 
consumption at 20 Tcf per year), 222 Tcf of inferred reserves, and 269 
Tcf of undiscovered non-associated conventional resources. The largest 
category was unconventional resources at 445 Tcf, with most of that in 
tight sandstones at 71 percent. Other unconventional natural gas 
resources include gas shales and coalbed methane. Alaska gas (32 Tcf) 
and associated-dissolved natural gas in lower 48 crude oil reservoirs 
(137 Tcf) round out the resource.
    Increased U.S. natural gas production through 2025 comes primarily 
from unconventional sources and from Alaska (Figures 4&5). 
Unconventional gas production increases by 4.1 Tcf over the forecast 
period more than any other source, largely because of expanded tight 
sands gas production in the Rocky Mountain region. Annual production 
from unconventional sources is expected to account for 36 percent of 
production in 2025, more than any other source, compared to 28 percent 
today.
    An Alaska natural gas pipeline begins flowing gas to the lower 48 
States in 2021, reaching 4.5 billion cubic feet (Bcf) per day in 2023, 
with further expansion beginning in 2025 (Figure 5). Alaska also 
continues to provide for consumption in the State itself and for LNG 
exports to Japan. In 2025, total Alaskan gas production is projected to 
be 2.6 Tcf.
    Conventional onshore non-associated production increases by 1.2 Tcf 
over the forecast, driven by technological improvements and rising 
natural gas prices. However, its share of total production declines 
from 34 percent in 2001 to 29 percent by 2025. Non-associated offshore 
production adds 560 Bcf, with increased drilling activity in deep 
waters; however, its share of total U.S. production declines from 22 
percent in 2001 to 18 percent by 2025.
    Associated dissolved production declines by 800 Bcf, consistent 
with a projected decline in crude oil production. Lower 48 associated-
dissolved natural gas is projected to account for 8 percent of U.S. 
natural gas production in 2025, compared with 15 percent in 2001.
    Depletion. A key question facing producers and policymakers today 
is whether natural gas resources in the mature onshore lower 48 States 
have been exploited to a point at which more rapid depletion rates 
eliminate the possibility of increasing or even maintaining current 
production levels at reasonable cost.
    Depletion is a natural phenomenon that accompanies the development 
of all nonrenewable resources. Physically, depletion is the progressive 
reduction of the overall volume of a resource over time as the resource 
is produced. In the petroleum industry, depletion may also more 
narrowly refer to the decline of production associated with a 
particular well, reservoir, or field. As existing wells, reservoirs, 
and fields are depleted, new resources must be developed to replace 
depleted reservoirs.
    Depletion has been counterbalanced historically by improvements in 
technology that have allowed gas resources to be discovered more 
efficiently and developed less expensively, have extended the economic 
life of existing fields, and have allowed natural gas to be produced 
from resources that previously were too costly to develop. In AEO2003, 
technological progress for both conventional and unconventional 
recovery is expected to continue to enhance exploration, reduce costs, 
and improve production technology.
    The depletion of conventional and unconventional natural gas 
resources is expected to continue over the projection period as the 
demand for natural gas increases significantly, continuing the trend 
that began in the mid-1990s. Nevertheless, with sustained wellhead 
prices generally over $3 per thousand cubic feet (in 2001 dollars) and 
continued technological improvements, lower 48 non-associated gas 
production is expected to increase above current levels.
    Imports. The difference between U.S. natural gas production and 
consumption is net imports. After growing by an expected 1.1 percent in 
2002 due to high stocks and lower demand, natural gas net imports are 
expected to increase by 5.6 percent in 2003, which should relieve some 
of the potential pressure on the domestic market.
    Net imports of natural gas, primarily from Canada, are projected to 
increase from 3.7 trillion cubic feet in 2001 to 7.8 trillion cubic 
feet in 2025 (Figure 6). Imports contributed 16 percent to total 
natural gas supply in 2001, compared to an expected 22 percent in 2025.
    Almost half of the increase in U.S. imports is expected to come 
from LNG. Much of the increase comes from expansion at existing sites, 
but three additional facilities are also built to serve Florida and the 
Gulf States. The three new LNG facilities are expected to have a 
combined gas delivery rate of 2 billion cubic feet per day. By 2025, 
LNG imports are expected to equal 6 percent of total U.S. gas supply.
    Growth in pipeline imports from Canada partly depends on the 
completion of the MacKenzie Delta pipeline. The MacKenzie Delta 
pipeline is expected to be completed in 2016 and expanded in 2023. The 
initial full flow rate into Alberta is assumed to be 1.5 Bcf per day. 
Additional imports will come from the Scotian Shelf in the offshore 
Atlantic. The forecast of Canadian imports largely depends on the 
ability of Canadian producers to economically produce and market their 
untapped unconventional resources, particularly coalbed methane. Net 
imports from Canada are projected to provide 15 percent of total U.S. 
supply in 2025 in the reference case, about the same as in 2001.
    Although Mexico has a considerable natural gas resource base, trade 
with Mexico has consisted primarily of exports from the United States. 
Mexico is projected to go from a net importer of U.S. natural gas to a 
net exporter in 2020, as an LNG facility begins operating in Baja 
California, Mexico, in 2019, predominantly serving the California 
market. By 2025, the United States is expected to import about 300 
billion cubic feet of natural gas from Mexico per year.
    Pipelines. The opening of an Alaskan natural gas pipeline depends 
on competing natural gas prices in the lower 48 States and Canada, 
financing, and the degree of difficulty in siting and permitting the 
pipeline, among other factors. We have assumed that lower 48 wellhead 
prices must be at least $3.48 in 2001 dollars for 3 years before 
pipeline construction begins. Construction is assumed to take 4 years. 
The cost of the pipeline from Alaska to Alberta is assumed to be $11.6 
billion in 2002 dollars with a 7.5 percent discount rate, based on a 
study released last year by the owners of the North Slope gas.\1\
---------------------------------------------------------------------------
    \1\ Additional costs would be incurred to transport this Alaskan 
gas from Alberta to the lower 48 States.
---------------------------------------------------------------------------
    While the pipeline is expected to begin operation in 2021 in the 
reference case, other assumptions--such as those about macroeconomic 
growth or the pace of technological change--affect the wellhead natural 
gas price and thus, the start date of the pipeline. In the slow oil and 
gas technology case, where the rate of technological improvement is 15 
percent slower than the reference case, the flows on the Alaska 
pipeline start in 2019. In the high economic growth case, which assumes 
a GDP growth rate of 3.5 percent, the flow starts in 2018. Other 
factors which could affect the start of an Alaska pipeline are 
restrictions on carbon emissions and assumptions about the size of the 
natural gas resource base.
    In all of these cases the MacKenzie Delta gas pipeline from 
MacKenzie Delta to Alberta starts 4 or 5 years before the Alaska 
pipeline. This $3.6 billion pipeline is assumed to be triggered by a 
lower 48 States gas price of $3.37. The MacKenzie Delta pipeline is 
assumed to have an initial flow of 1.5 Bcf per day, a planning period 
of 2 years, and a construction period of 3 years.
    Additional interstate pipeline capacity will be required in the 
lower 48 States to bring Arctic gas to market, as well as to 
accommodate the growth in consumption over the forecast. While the flow 
of gas between primary regions in the lower 48 States is expected to 
increase by 40 percent from 2001 to 2025, the pipeline capacity 
necessary to transport this gas is only expected to increase by 26 
percent. In order to do so, the annual utilization along these pipeline 
corridors will need to increase from 63 percent in 2001 to 70 percent 
by 2025. As electric generators go from a 25 percent share of end-use 
consumption in 2001 to a 33 percent share by 2025, the annual 
throughput on pipelines can expect to increase as well, since electric 
generators are primarily expected to add to either the base load 
requirements or the off-peak loads.
    Wellhead Prices. Spot wellhead natural gas prices, which exploded 
in early 2001 in response to a winter demand surge amid very low 
inventory levels, retreated to low levels in early 2002 amid very weak 
winter demand and excess natural gas in storage (Figure 7). The very 
high short-term prices accelerated a natural gas drilling recovery that 
originated during the spring of 1999. However, a brewing pessimism in 
the natural gas market outlook, following a downturn in real GDP, the 
events of September 11, 2001, falling stock prices, and fallout from 
the collapse of Enron and other previously high-flying firms stripped 
some of the enthusiasm from the search for expanded natural gas 
resources, generating a sharp decline in natural gas-directed drilling 
by late 2001 and early 2002. Thus, the seeds of resurgence in natural 
gas prices were sown at the very time that excess supply appeared at 
its greatest. At the end of February 2002, natural gas in storage was 
27 percent above the previous 5-year average; at the end of February 
2003, storage is expected to fall 12 percent below the same average. 
Between those two times, spot prices are expected to post an increase 
of 151 percent.
    Working natural gas in storage fell to about 1.52 trillion cubic 
feet at the end of January, or about 17 percent below the 5-year 
average and 35 percent below the year-ago level (Figure 8). January 
2001 is the only time since 1977 that the January natural gas working 
storage level has been lower than this year, although similar end-of-
January levels were seen in 1996, 1997, and 1999. However, the current 
level of gas in storage is relatively low, so full replenishment of 
working gas stocks in 2003 will be larger than average. The industry's 
capability to accommodate this requirement without considerable upward 
price pressure may not be as robust as in earlier years because of 
other supply factors, such as the possibility that new drilling may be 
less productive than in the past.
    Despite the revised production estimates, a large (1.5 trillion 
cubic feet) discrepancy remains in the 2002 supply/demand balance. Much 
of this remaining imbalance relates to underestimated demand, most 
likely in the industrial sector.
    The demand and supply data currently available to describe market 
developments in 2002 are somewhat contradictory in that the estimated 
demand growth from 2001 to 2002 appears to be too weak to coincide with 
the reduction in storage that demonstrably occurred. EIA's current 
estimate of production changes in 2002, based in part on recently 
received data from the Minerals Management service, indicates a 
reduction in new domestic supply of about 2.3 percent from 2001 levels. 
Other estimates suggest a decline of about 5 percent. Taking either of 
theses estimates as plausible, the remaining component of market 
changes that would be required to explain the shift in the gas storage 
position in the United States in 2002 involves stronger demand than is 
currently apparent in the data. Since the economy is expected to 
continue to recover in 2003, particularly in the gas-intensive 
industrial sector, and since continued tightness in world oil markets 
is expected to add to natural gas demand strength in the electric power 
and industrial sectors, continued strength in overall natural gas 
demand this year is expected.
    In contrast to 2002, little or no incremental help from storage to 
meet new demand is possible in 2003, implying that consistent pressure 
on wellhead deliverability for natural gas is to be expected unless 
some of the demand strength is reduced. Therefore, the average wellhead 
price in 2003 is likely to exceed the 2002 average. The expected 
average wellhead price this year is $4.35 per thousand cubic feet in 
current dollars compared to $2.95 in 2002. Weather will, as always, 
play a key role in market developments for the rest of this year, but 
assuming normal weather through the forecast leads to the expectation 
of very strong natural gas spot and average wellhead prices next 
winter. Natural gas production growth in North America of between 2 and 
3 percent, supplemented by increases in imports of liquefied natural 
gas, will probably be needed to maintain a reasonable balance in the 
domestic market through 2004. Solid increases in drilling appear likely 
for 2003 and are likely to provide the needed increase in productive 
capacity to stabilize the domestic natural gas market at wellhead 
prices between $3.50 and $4.50 per thousand cubic feet.
    In the mid-term, gas prices are projected to move higher as 
technology improvements and new supply sources prove unable to 
completely offset the effects of resource depletion and increased 
demand (Figure 9).
    Natural gas prices through 2025 are projected to increase in an 
uneven fashion as major new, large-volume supply projects temporarily 
depress prices when initially brought online. Examples include deep and 
ultra-deep offshore projects in the Gulf of Mexico, unconventional gas 
(tight sands, coalbed methane, shale), liquefied natural gas facilities 
(both the expansion of existing and development of new facilities), the 
MacKenzie Delta pipeline in Canada, and an Alaskan natural gas pipeline 
that delivers gas supplies to the lower 48 States.
    In the reference case, average wellhead natural gas prices are 
expected to increase to $3.90 per thousand cubic feet (2001 dollars) in 
2025. The increase reflects rising demand for natural gas and the 
impact of the progression of discoveries from larger and more 
profitable fields to smaller, less economical ones. In current dollars, 
natural gas prices reach $7 in 2025.
    An uncertain outlook for the pace of economic growth is one of the 
key factors that could affect gas prices. Alternative cases were used 
to assess the sensitivity of the projections to changes in growth rates 
in population, labor force, and productivity. The high economic growth 
case assumes higher projected growth rates for population (1.0 percent 
per year), labor force (1.2 percent per year), and labor productivity 
(2.3 percent per year). With higher productivity gains, inflation and 
interest rates are projected to be lower than in the reference case, 
and economic output is projected to grow by 3.5 percent per year. GDP 
per capita is expected to grow by 2.5 percent per year, compared with 
2.2 percent in the reference case. The low economic growth case assumes 
lower growth rates for population (0.6 percent per year), labor force 
(0.7 percent per year), and productivity (1.8 percent per year), 
resulting in higher projections for prices and interest rates and lower 
projections for industrial output growth. In the low growth case, 
economic output is projected to increase by 2.5 percent per year from 
2001 through 2025, and growth in GDP per capita is projected to slow to 
1.9 percent per year.
    The 2025 wellhead price is projected to reach $3.83 per thousand 
cubic feet in the low economic growth case and $4.50 per thousand cubic 
feet in the high growth case. Technically recoverable natural gas 
resources are expected to be adequate to support the production 
increases projected in the three cases. As gas resources are depleted, 
however, wellhead prices are expected to increase, and a larger portion 
of U.S. natural gas consumption is projected to be met by foreign 
supplies and by production from Alaska.
    End-use Prices. End use prices in 2003 are expected to be higher 
than last year due to colder weather and international events. January 
was about 9 percent colder than normal for the Northeast and 32 percent 
colder than January 2002 in that region. Ironically, the weather for 
the U.S. as a whole has been a bit warmer than normal in January, 
though there was a period of intense cold in the middle of the month. 
For the month of January, home heating fuel consumption was probably 
lighter than average, except in the Northeast. Spot prices for fuels 
surged, however, as crude oil and natural gas prices rose rapidly in 
the face of the Venezuelan oil export cutoff and sharply falling levels 
of domestic natural gas in storage. Some of these commodity price 
changes are still working their way to the consumer level. Normal 
temperatures through the remainder of the heating season would imply a 
28-percent increase in household natural gas heating expenditures for 
the winter season (October-March) compared to the 2001-2002 winter. 
Residential natural gas prices are projected to average $9.04 per 
thousand cubic feet this year in current dollars and $9.27 next year, 
compared to $7.87 last year, $9.63 in 2001, and $7.77 in 2000.
    Although residential price increases are expected to be 
significant, if the experience of the winter of 2000-2001 is an 
indication, industrial price increases could be even more significant, 
especially on a monthly basis. Two years ago some gas intensive 
industries, particularly ammonia and fertilizer producers, were 
particularly hard hit, with some plants shutting down production 
permanently. Industrial users who rely on spot market purchases for 
their gas and are unable to switch to an alternate fuel source face the 
greatest risk. Revival of the industrial sector may slow down at least 
until the heating season finishes and prices head downward.
    End-use natural gas prices are expected to increase gradually 
starting in about 2005 as a result of increasing wellhead prices 
(Figure 10). A portion of the increase in wellhead prices is expected 
to be offset by a projected decline in average transmission and 
distribution margins as a larger proportion of the natural gas delivery 
infrastructure becomes fully depreciated. The average end-use price is 
expected to increase by 89 cents per thousand cubic feet between 2005 
and 2025 (in constant 2001 dollars), compared with an increase of $1.07 
per thousand cubic feet in the average price of domestic and imported 
natural gas supplies over the same period. Part of this difference is 
attributable to an increasing share of natural gas sold to electric 
generators, the sector with the lowest prices.

                               CONCLUSION

    Domestic natural gas prices are expected to remain high in 2003 and 
are at risk for significant volatility through at least the next 12 to 
18 months. Strong underlying domestic demand for natural gas has been 
boosted by short-term or cyclical factors (including weather and oil 
market shifts), but expected strong levels of domestic natural gas 
drilling and development should provide increases in gross productive 
capability through 2004.
    With the projected increases in both domestic gas production and 
imports through 2025, sufficient supplies are expected to be available 
to satisfy the growing demand for natural gas with wellhead price 
increases from $2.92 in 2002 to $3.90 in 2025 in 2001 dollars.
    Thank you, Mr. Chairman and members of the Committee. I will be 
happy to answer any questions you may have.

    The Chairman. Thank you very much. Your statement will be 
made a part of the record.
    Let us go now with Mr. Welch.

STATEMENT OF DAVID WELCH, PRESIDENT, BP ALASKA-CANADA PIPELINES

    Mr. Welch. Mr. Chairman, members of the committee, I am 
David Welch, president of BP's Alaska-Canada Gas Pipelines. I 
am pleased to be here with you today to discuss the North 
American natural gas market, and commend you for holding this 
hearing of critical importance to our Nation. Today, I would 
like to discuss three things, current tight supply situation, 
how we got here, and where we might go.
    What is the current situation? The North American gas 
market consumes roughly 25 trillion cubic feet of natural gas 
per year, which is equal to 68 billion cubic feet of natural 
gas per day. The North American market is in a state of 
transition.
    Historically, the needs of consumers have been met by 
supply from existing basins, existing domestic basins, plus 
imports from Canada. As we examine the current market, we find 
that performance of supply sources is deteriorating. Most 
industry observers believe production is declining at a rate of 
about 5 percent per year, and Canadian production has also 
started to decline. At the same time, demand for natural gas 
continues to grow. Consumers are choosing gas for economic and 
environmental reasons. More than 80 percent of the new electric 
power generating capacity utilizes natural gas.
    Traditional sources of gas are unable to sustain production 
at current levels. The supply challenge is substantiated by 
several observations. First, U.S. production failed to respond 
significantly to the doubling of drilling activity that 
occurred in parts of 2000 and 2001. Secondly, Canadian 
production is also declining now, although Canadian drilling is 
high. Thirdly, in the current high-priced environment, drilling 
activity has not picked up to the degree that it did 2 years 
ago, and this is indicating fewer economic prospects are 
available, and it is probably the most telling sign of the 
supply situation in North America.
    The result of these trends has been a sharp increase in 
prices and a very large drawdown of gas inventories in storage. 
The gap between supply from traditional sources and demand will 
grow with time. If we are to meet America's increasing need for 
clean-burning, efficient natural gas without very high prices 
and its incumbent demand destruction and loss of economic 
activity, then North America will need supply from all 
available continental sources as well as imported LNG.
    How did we get here? There are a number of contributing 
factors that have led us to this situation. Access to the east 
and west coast and the eastern Gulf of Mexico is not permitted. 
There are also challenges that exist in some areas of the 
Western States. Gas deliverability from existing supply basins 
has not been as robust as has been expected. Most North 
American supply basins are very mature, and are suffering from 
production declines. The few new basins are either mostly oil, 
or have infrastructure and regulatory issues preventing rapid 
production growth.
    Regulatory and fiscal terms have not been conducive to 
attract investment in frontier gas supply areas such as Alaska 
and Canada. LNG import facilities are limited in number, and 
currently contribute less than 1 percent of U.S. supply, so all 
these factors combine to create an ever-tightening supply 
situation that could have negative impacts to the overall 
economy. Government policy needs to lead the way to help expand 
the natural gas supply.
    So what is the way forward? There is a general consensus 
that demand will continue to grow at 1 to 2 percent over the 
long run. North America will certainly continue to depend on 
current production from our traditional supply sources, but 
these alone will not be enough. New sources must also be 
brought to the market. Of the areas currently accessible, there 
are three which offer the greatest new supply potential, 
frontier gas from Alaska and Canada, gas from the Rocky 
Mountains, and LNG imports. However, in most cases, policy 
changes are needed to turn this potential into reality.
    The Canadian frontier gas pipeline from the Mackenzie 
Delta----
    The Chairman. Excuse me, Mr. Welch. Where--in those three, 
where does the offshore gas fit? Frontier, Rocky Mountain----
    Mr. Welch. Offshore gas is continuing to develop. 
Obviously, we are continuing to drill there. The big new source 
in offshore has been the deep water Gulf of Mexico, which is 
proving to be mainly oil as opposed to gas. In fact, when the 
MPC did its study 3 years ago, that was a big source of growth, 
but now what we are finding as we have gotten more experience 
in the deep water is that the gas to oil ratios are about half 
of what was anticipated about 3 years ago.
    The Chairman. So it does not belong, and these three stand 
on their own?
    Mr. Welch. These three stand on their own, yes sir. The 
Gulf of Mexico will continue to produce, but we think it will 
be more or less a stable contributor over the future.
    Just a word on the Canadian frontier. The Mackenzie Delta 
contains roughly 10 trillion cubic feet of gas. The Canadian 
Government has already created a fiscal regime there that is 
conducive to investment and is actively seeking to expedite 
this infrastructure project which is underway. Alaska, I 
believe, is a critical element of future gas supplies. The 
frontier has 35 trillion cubic feet of gas known, and the U.S. 
Government is estimating over 100 trillion cubic feet to be 
discovered.
    The major challenge to this supply is the unprecedented 
scale of the pipeline that is needed to bring this gas to 
market. The gas resource owners are considering a project that 
would bring 4 to 5 billion cubic feet per day into the market 
in the early part of the next decade. However, the fiscal terms 
of the Alaska gas project, as I have shown in my earlier chart, 
are tougher than any other significant growth options that we 
have.
    This single opportunity in Alaska could materially improve 
the North American supply outlook, but without legislation, 
this project will not attract investment capital in the 
foreseeable future, and Alaska gas will not be able to achieve 
its potential as a major and long-term source of supply. 
Federal regulatory and fiscal legislation are needed now to 
help advance this project.
    The Rocky Mountains could also play an important part in 
creating new gas supplies in this region. Additional pipeline 
capacity is required to deliver gas to the market, and there 
are also some regulatory issues which must be considered.
    And finally, LNG could enhance the supply. Much of it could 
come from stable nearby countries such as Trinidad. A more 
robust LNG infrastructure here would foster access to a 
developing global market, helping us to moderate the great 
volatility in domestic prices seen in recent years.
    If LNG is to make a material contribution, more terminals 
will be needed, and FERC has recently made a policy 
pronouncement that will encourage investment in LNG facilities, 
and we look forward to working with them to maturing LNG 
projects in the future.
    In conclusion, the way forward involves policy decisions 
that we as a Nation need to make now to enhance opportunities 
for new gas supplies to come online in the future. The 
Government can make positive policy choices about access, about 
LNG terminal development, about frontier infrastructure 
development, and the industry will respond, resulting in 
increased supply. I sincerely believe that the natural gas 
market will need all of the North American gas available, as 
well as increased sources of LNG.
    Again, thank you for the opportunity to present this, and I 
would be happy to answer any questions that might arise.
    [The prepared statement of Mr. Welch follows:]

    Prepared Statement of David Welch, President, BP Alaska-Canada 
                               Pipelines

    Mr. Chairman and members of the Committee, I am David Welch, 
President of BP's Alaska-Canada Pipelines business and a former 
Regional President for BP based in Houston, Texas. On behalf of the 
over 40,000 BP employees in America, I am pleased to appear before you 
to discuss the North American natural gas market. I want to commend the 
Committee for holding this hearing on a matter that is of critical 
importance to the medium and long-term economic well being of the 
nation.
    In my testimony today I would like to discuss three things: the 
current tight supply situation in the North American natural gas 
market, how we got where we are today and, the way forward.
    First, I would like to provide some context about BP's production 
activities in North America. BP is the largest producer of oil and gas 
and one of the largest gas marketers in America. We are involved in 
most of the major producing basins in North America the Rocky 
Mountains, the San Juan, Alaska, Canada, the Gulf Coast, the outer 
continental shelf, the deep water Gulf of Mexico and we produce roughly 
4 billion cubic feet of natural gas per day (BCF/d). BP invested $1.5 
billion in North American gas development last year alone. I mention 
these facts to give you a sense of the scale of our operations and our 
experience with the North American natural gas market.

                     WHAT IS THE CURRENT SITUATION?

    The North American natural gas market is in a state of transition. 
Historically, the needs of gas consumers have been largely met by 
traditional supply sources from existing US basins plus imports from 
Canada. Today, the North American market consumes roughly 25 trillion 
cubic feet of natural gas per year (TCF/y) or 68 BCF/d. As we examine 
the current market, we find the performance of traditional supply 
sources deteriorating. Most industry observers believe that US gas 
production is declining at a rate of five percent per year and Canadian 
production is also in decline.
    At the same time production is falling, demand for natural gas is 
growing. We expect demand to continue to grow at roughly 1-2% per 
annum. Consumers are choosing gas for both economic and environmental 
reasons. New power generation from natural gas costs less (at long run 
historical prices), requires 50% less capital for construction and, has 
50% lower greenhouse gas emissions than alternative fuels such as coal 
or oil. As a result, more than eighty percent of new electric power 
generating capacity utilizes natural gas.
    Traditional sources of North American supply are severely 
challenged to sustain production at current levels. The supply 
challenge is substantiated by several observations:

   U.S. production failed to respond appreciably to the 
        doubling of drilling activity that occurred during parts of 
        2000 and 2001. In fact, current production appears to be on a 
        slightly steeper decline than observed prior to that activity 
        ramp-up.
   Canadian production is experiencing its first decline since 
        1986-87 after seeing a similar activity increase during that 
        period.
   Current drilling activity is not responding, as 
        significantly as it did two years ago, to the recent high price 
        environment, suggesting that there are real limitations on 
        industry's capacity to continually regenerate its drilling 
        portfolio. This is probably the most telling sign of the gas 
        supply situation in North America.

    These observations are a reflection of the maturity of our 
traditional supply sources. Prospects for offsetting the declining 
production trend from these regions requires new sources of supply. 
Less mature areas such as the Deepwater Gulf of Mexico and the Eastern 
coast of Canada will help, but development in these areas takes years 
to complete. The best-case scenario for traditional North American 
supply regions is a flat to slightly declining production outlook. So, 
while demand is expected to continue growing, we believe traditional 
supplies will not keep pace.
    The result of these trends has been a sharp upward move in prices 
and increased price volatility. Prices have gone from $2 to $10, back 
to $2 and now up to $6 (at Henry Hub; NY has been above $20 this 
winter). This volatility is not in anyone's best interest. Neither 
producers nor consumers can comfortably invest when they are that 
uncertain about the future.
    This tells us is that absent the introduction of new supplies, a 
gap between supply from traditional sources and demand will grow with 
time if we are to meet America's increasing need for efficient, clean-
burning natural gas.
    Of course the market will respond to fill this gap with some 
combination of price induced fuel switching--to coal or imported oil. 
Another response is demand destruction--with its concurrent loss of 
economic activity. In our opinion, to avoid these undesirable outcomes 
North America will need supply from all available sources; from 
increased production in the traditional producing basins, from frontier 
gas like the Alaskan and Canadian Arctic, and from additional imported 
LNG.

                          HOW DID WE GET HERE?

    As is always the case, there are a number of contributing factors 
that have led us to the situation we find ourselves in today. Clearly 
access policy is an important factor--access to the East and West Coast 
is not permitted and challenges also exist in the onshore areas of the 
Western states.
    Secondly, we now understand that the gas deliverability from 
existing supply basins is not as robust as had been expected. The 1999 
National Petroleum Council natural gas study presented what now appears 
to be an overly optimistic view of supply. For example, gas-oil ratios 
factored into the study for the deepwater Gulf of Mexico were twice as 
large as is actually being experienced. Fortunately, an updated study 
has been requested by the Secretary of Energy and a large, diverse 
group of producers, consumers and, marketers of natural gas are 
involved. The study is expected to be completed around September but we 
do not anticipate the findings to differ materially from my comments 
here today.
    Other factors contributing to our current supply situation include 
pipeline capacity constraints for producers in the West. In many of 
these areas, pipeline take-away capacity limits the pace of exploration 
and development. The fact is, industry has responded in areas where 
they have been able to access new production. However, the ability to 
deliver these large new volumes of gas to the market is restricted. The 
industry has also responded by offering shipping commitments so that 
pipeline investors have the confidence to build the needed 
transportation capacity. Sadly however, due to the recent turmoil in 
the energy markets there are fewer companies in the regulated 
transportation industry and investment capital is expensive and hard to 
find. Thankfully, these issues are being dealt with by the FERC in a 
judicious fashion. But there are no overnight solutions; it will take 
time to build the infrastructure.
    As a result of the tightening supply and demand picture, gas 
storage inventories have been drawn down sharply to keep the market in 
balance. US natural gas inventories are currently 868 BCF below last 
year's level (as of 2/14/03), and 436 BCF below the 5-year average. 
Including Canadian data, North American stocks are more than 1 TCF 
below last year's level.
    Inventories are typically drawn down during the peak winter heating 
season and refilled during the summer; current trends, however, suggest 
this year's summer refill may be disappointing, which would leave the 
market vulnerable to higher prices again next winter. While low 
inventories may not be a physical problem for the market until next 
winter, the anticipation of a tight situation will be reflected in 
prices immediately.
    Unlike the oil market, consumers in the US currently have access to 
limited number of natural gas supply sources. When the oil market is 
tight, we have access to supplies from around the globe. This is not 
the case for natural gas--we only have access to existing basins on the 
continent and a very limited number of LNG receiving facilities. Mexico 
is also in need of additional supply sources and will be competing for 
new supply. All of these factors combined (declining supplies from 
traditional sources, access and capacity limitations, coupled with 
increasing demand) create an ever-tightening supply situation that 
could, if it is left to persist, have negative impacts to the overall 
economy. Government policy needs to lead the way to help expand natural 
gas supply.

                        WHAT IS THE WAY FORWARD?

    North Americans are currently consuming roughly 25 TCF/y and 68 
BCF/d. There is general consensus that demand for clean burning natural 
gas will continue to grow at 1-2% per annum over the long run. This 
means that North America will continue to depend on production from our 
traditional supply sources, but that alone will not be enough. Within 
about 10-15 years time, new sources in the neighborhood of 15 BCF/d 
must also be brought to the market if demand is to be satisfied. We 
believe that of the areas currently accessible, there are three, which 
offer good new supply potential: frontier gas from Alaska and Canada; 
Rocky Mountain gas, and LNG imports. However, in most cases, policy 
changes are needed to turn this potential into reality.
    The MacKenzie Valley project is in development to bring 1-1.5 BCF/d 
of gas from the Canadian Arctic to the market. This project is well 
underway; with some of its developers indicating first gas as soon as 
2008. We support this project and the Canadian government is expediting 
its development.
    In Alaska, North America has 35 TCF of known resource and, 
according to the MMS, an upside potential of a further 155 TCF. 
Alaska's North Slope is a world-class gas resource. The major challenge 
is the unprecedented scale of the pipeline project to transport the gas 
due to its distance from the market. The principal owners of this 
resource are considering a project that could deliver 4-5 BCF/d in the 
early part of the next decade. This single opportunity could materially 
improve the tenuous North American supply outlook with wide ranging 
benefits for the economy, the environment and energy security. However, 
without government policy changes related to regulatory and fiscal 
structures, this project cannot attract investment as project risks 
outweigh prospective rewards.
    The Rocky Mountain region can also play an important part in 
creating new gas supplies, however, much of its resource is non-
conventional thus carries higher production costs. The entire region 
needs additional pipeline capacity to deliver gas to markets. There are 
also a number of federal regulatory issues including, public land 
access and air quality, which must be taken into account. Incremental 
near-term supply growth from this area can be helped by government 
action on these critical issues.
    LNG could provide more new supply over the near to intermediate 
term (2003-10) and much of it could come from stable, nearby countries 
such as Trinidad. A more robust LNG infrastructure here would foster 
greater access to a developing global market, helping to moderate the 
wild fluctuations in domestic prices seen in recent years. However, we 
must recognize that LNG is currently less than 1% of the US market. 
There are four terminals in use today. If LNG is to make a material 
contribution to US natural gas supply, more terminals will be needed. 
FERC recently made a policy pronouncement that will encourage 
investments in new facilities and we look forward to working with them 
to implement their policy decision.

                               CONCLUSION

    Clearly, the way forward with regard to the North American natural 
gas market involves policy decisions that we as a nation will need to 
make now so that we can begin to address what is clearly an issue with 
long-term consequences. You can make policy choices about access, about 
LNG re-gasification terminal development, and about frontier basin 
development, and the industry will respond. We believe the market will 
need all of the North American gas available, along with additional 
sources of LNG.
    We believe the right policy choices are those that:

   Enhance U.S. energy and national security;
   Promote economic activity, job creation and government 
        revenues;
   Provide consumers with reasonably priced energy to maintain 
        a healthy economy;
   Stimulate non-conventional supplies;
   Continue to promote efficient and environmentally friendly 
        energy use.

    Promoting the further development of a North American gas industry 
can meet all of these policy needs.
    Again, thank you for the opportunity to present these views. I 
would be happy to answer any questions.

    The Chairman. Thank you very much.
    Mr. Rattie.

         STATEMENT OF KEITH RATTIE, PRESIDENT AND CEO, 
                      QUESTAR CORPORATION

    Mr. Rattie. Thank you, Mr. Chairman. My name is Keith 
Rattie. I am president and chief executive officer of Questar 
Corporation, based in Salt Lake City. I will try to hit a few 
points that have not been made by my colleagues on the panel 
today, and hope we will see some interesting dialogue during 
the Q&A.
    This winter, as I think everyone in the room knows, America 
is getting a wake-up call. Simply put, we have a natural gas 
supply problem, and I have three objectives this afternoon. 
First, I will briefly explain why prices are higher this 
winter, why they have jumped this winter, second, I will 
describe the magnitude of the natural gas supply challenge 
facing the country over the next 2 decades, and then third, I 
will recommend several steps that Congress can take over the 
long-term to help us get out of this mess.
    Now, I mentioned wake-up call. We got our first wake-up 
call a couple of years ago, when a confluence of events: a cold 
winter, hot summer, and a surging economy led to a sudden jump 
in demand that sent the gas prices soaring, but just as 
quickly, drilling activity in 2001 boomed, supply grew, albeit 
slightly, demand fell, and gas prices retreated, and that is 
just what you expect from a competitive deregulated market.
    Today, natural gas prices are back at winter 2001 levels 
because demand is up and supply is down. Demand is up in part 
because we are having a normal winter. Now, I know most of the 
folks who live here in the East probably take exception to my 
characterization of this winter as normal, but if you look at 
trends across the entire country, it actually is that.
    In fact, the reality is that warmer than normal weather in 
4 of the last 5 years has masked the supply problem. Consumers 
are very fortunate we have not had a colder-than-normal winter 
this year, because supply is down. U.S. natural gas production 
is down this year by some estimates 4 percent lower in the 
fourth quarter of 2002 than it was in the fourth quarter of 
2001 and, as other panelists have noted, that is in spite of a 
jump in drilling activity in recent years.
    The sobering reality is that we are drilling a lot more 
wells today than we were 5 years ago, but supply is still flat, 
or down. U.S. producers are running on an accelerating 
treadmill, running harder just to keep production flat, and for 
reasons that are partly due to technology and partly due to the 
maturing of the accessible gas resource base, the typical well 
drilled today will decline at a faster rate than a typical well 
drilled a decade ago. Moreover, because half of this country's 
current natural gas supply is coming from wells that have been 
drilled in the past 5 years, this decline trend is likely to 
continue.
    The implications are even more sobering, when we consider 
what is expected to happen to demand over the next 2 decades, 
and my colleague from the EIA has already commented on that. I 
will just note the EIA is predicting that U.S. natural gas 
consumption will increase to about 35 trillion cubic feet in 
the year 2025 from 2.7 trillion cubic feet in 2001.
    Now, let me put a 35 tcf U.S. gas market in 2025 in 
perspective. 35 tcf implies a jump in average daily gas supply 
from about 60 bcf per day today to about 95 bcf per day in 
2025, a 35 bcf per day increase in deliverability, and let me 
put that in perspective.
    Today, current production from the entire Gulf of Mexico is 
only about 14 bcf a day. As other colleagues have mentioned, 
increased imports of LNG and new pipelines from Alaska and the 
Mackenzie Delta, we need both of them. Those are clearly 
needed, and I think everybody in the industry supports their 
development, but the inescapable conclusion is that most of the 
incremental gas supplies needed to serve a growing U.S. market 
must come from the U.S. lower 48, and that implies that the 
burden of delivering a 50 percent increase in gas supply over 
the next 20 to 25 years will fall primarily on the shoulders of 
U.S. independents.
    Now, if there is one point that we make today, and if it is 
the only point that is taken away from this, I think this is 
the most important point. We have to be clear, the problem is 
not with the resource base. North America is blessed with 
abundant natural gas reserves. Most of us in the industry 
believe that the resource base is more than adequate to supply 
a 35 tcf market in 20 to 25 years, and advances in technology 
have demonstrated that over the last couple of decades. Indeed, 
technology will some day unlock vast amounts of natural gas 
trapped as hydrates beneath the ocean floor and the Arctic 
tundra.
    Some scientists believe that there is enough potential in 
gas hydrates to supply the U.S. market for at least 100 years, 
so the bottom line is, we are not running out of natural gas. 
We are not running out of places to look for natural gas.
    We are, however, running out of places where we are allowed 
to develop natural gas, and the truth that I think must be 
confronted now is that, as a matter of policy, this country has 
chosen not to develop much of its natural gas resource base, 
and I suspect that many of the 65 million American households 
that depend on natural gas for heat are unaware that this 
choice has been made on their behalf.
    By most estimates, 30 to 40 percent of our potential 
natural gas resource base is either off limits, or only open to 
development under highly restricted conditions. Onerous laws 
and regulations prohibit exploration in areas where there is 
huge potential for new supply. Permitting has become next to 
impossible for new pipelines and LNG import terminals.
    Now, opponents of domestic gas development will cite 
environmental concerns. I think you will find that many of 
these concerns are exaggerated. New technology has allowed the 
industry to dramatically reduce the footprint of its 
activities. The argument that drilling drives wildlife to 
extinction is another popular fiction. To the contrary, in most 
cases wildlife adapts and thrives in harmony with energy 
development.
    It is also time for America to rethink its fear about 
exploring and producing gas in our offshore basins. Now, 
clearly, offshore platforms have an impact on the environment, 
but offshore platforms do not hurt the environment. Natural gas 
spills do not happen, and sub-sea wells can reduce or eliminate 
the need for offshore platforms in areas where visual impacts 
are the concern.
    So the key question for policymakers is this: Can we afford 
policies that leave vast amounts of our domestic natural gas 
reserves untested and undeveloped? If the consequences of these 
policies were understood, I believe most Americans would answer 
no.
    So what do we do? In the short run, the only sensible thing 
the Congress can do is to let the market work and, indeed, it 
already is. High prices have led to a sharp increase in 
drilling activity in the last couple of months. High prices are 
also causing conservation. You can bet that increased supply 
and lower demand will cause lower prices later this year.
    But while the market takes care of the problem in the 
short-term, there is much the Congress can to help gas supply 
keep pace with demand longer-term. And I think first and 
foremost, what we need is leadership. Congress can help forge a 
national consensus that natural gas is abundant, that natural 
gas development is good for the economy, good for the 
environment, and good for society.
    Second, Congress should continue policies that have worked 
in the past, and those have been mentioned already. A decade 
ago, section 29 tax credits stimulated development of 
unconventional gas such as the San Juan Basin and the Powder 
River Basin cold bed methane plays. In 1995, Congress set in 
motion what may be the most important E&P play of the last 
decade by providing graduated royalty relief for production 
from Federal leases in deep water. Today, more than a quarter 
of our domestic gas production results from these past policy 
successes.
    Now, mindful of what has worked in the past, Congress can 
help by reestablishing section 29-type tax credits. Congress 
should also make adjustments to the tax code to address the 
misallocation of value that was described by one of the 
panelists earlier.
    Third, and most important, it is time to allow access to 
high potential Federal land in the Rockies, off the east and 
west coasts, and in the eastern Gulf of Mexico. Again, the 
industry has proven that our energy resources can be developed 
without harming wildlife or the environment.
    Fourth, policymakers can help get the pipeline industry 
back on its feet and remove barriers to pipeline construction. 
INGAA estimates that between $60 and $70 million in new capital 
investment in pipelines will be required over the next 12 to 15 
years to keep pace with demand. A financially sound pipeline 
industry is a prerequisite for this investment, and the 
pipeline industry today is anything but financially healthy. 
Uncertainty about future regulatory policy threatens capital 
formation at a critical time.
    Fifth, Congress should fund collaborative research by 
agencies such as the Gas Technology Institute and others. R&D 
spending by energy companies has plummeted over the past 
decade, and what remains is more focused on incremental 
improvements and not breakthroughs. Collaborative research is 
both vital and cost-effective.
    Mr. Chairman, energy policy issues are complex. There are 
many stakeholders in the debate. Each stakeholder has a long 
list of things they would like Congress to do. Many of these 
are worthwhile, but we cannot let the need for action on gas 
supply get lost in the debate over less urgent matters, and so 
we applaud your focus on the critical issue of gas supply here 
today, and I will be pleased to answer questions on this later.
    Thank you.
    [The prepared statement of Mr. Rattie follows:]

     Prepared Statement of Keith Rattie, President & CEO, Questar 
                              Corporation

    Good afternoon. Mr. Chairman, members of Congress, it's my 
privilege to appear before you today. My name is Keith Rattie. I'm the 
President and Chief Executive Officer of Questar Corporation. Questar 
is an integrated natural gas company headquartered in Salt Lake City. 
We have significant businesses in each part of the natural gas value 
chain--upstream exploration and production, interstate pipelines, and 
downstream retail gas distribution. We operate primarily in the Rockies 
and the Midcontinent. We're one of the fastest growing gas producers in 
the country. Our interstate pipeline companies move gas from the 
Rockies to energy markets in the West. Our retail gas distribution 
company serves 750,000 homes and businesses in Utah, Wyoming and Idaho.
    Yesterday, natural gas prices shot above $8 per mcf at the Henry 
Hub for the first time since 2001. Spot prices in New York at times 
have exceeded $20. This winter, America's getting another wake-up call. 
Simply put, we have a natural gas supply problem.
    I have three objectives this afternoon. First, I'll briefly explain 
why natural gas prices have jumped this winter. Second, I'll describe 
the magnitude of the natural gas supply challenge facing this country 
over the next two decades. Third, I'll recommend several steps that 
Congress can take to help bring natural gas prices down long-term.
    America got its first wake-up call on natural gas supply two years 
ago when a confluence of events--cold winter, hot summer and a surging 
economy--created the so-called ``perfect storm.'' This jump in demand 
sent gas prices soaring. Drilling boomed, supply grew (slightly), 
demand fell, and gas prices retreated--just what you'd expect from a 
competitive, deregulated natural gas market. But then falling natural 
gas prices predictably led to a slowdown in drilling. The industry 
drilled 30% fewer gas wells in 2002 than in 2001. This downturn in 
drilling in 2002 set the stage for another run-up in prices this 
winter.
    Today, natural gas prices are back at winter 2001 levels because 
demand is up and supply is down. Demand is up in part because we're 
having a normal winter. Now, I know that folks who live here in the 
East will take exception to my characterization of this winter as 
``normal''. This winter may seem colder than normal, but that may be 
because four of the past five winters have been warmer than normal. 
Even the winter of 2001 was normal by historical standards. Consumers 
are fortunate we haven't had a colder than normal winter.
    High oil prices are also propping up natural gas prices this 
winter. In certain markets, notably the U.S. Northeast, gas competes 
with oil products. Unlike in 2001, when high gas prices led to the 
substitution of oil for gas, substitution hasn't kicked in as quickly 
as it did two years ago.
    Meanwhile, while demand is up, U.S. natural gas production in the 
fourth quarter of 2002 was down about 4% from the fourth quarter of 
2001. Indeed, U.S. natural gas production today is lower than it was 
five years ago--despite a big jump in drilling in recent years.
    In 2001, in response to high prices, the industry drilled about 
22,000 natural gas wells, nearly double the number of wells drilled in 
each of the four prior years. In 2002, in response to falling prices, 
the industry drilled about 16,000 gas wells, 30% fewer than in the 
prior year. However, even though drilling activity declined in 2002, 
the industry still drilled and completed about 50% more wells last year 
than the average from 1995-2000.
    The sobering reality is that we're drilling a lot more wells today 
than we were five years ago, but supply is still down. U.S. gas 
producers are on an accelerating treadmill, running harder trying to 
stay in place. For reasons that are partly due to technology, and 
partly due to the maturing of the accessible natural gas resource base, 
a typical well drilled today will decline at a faster rate than a 
typical well drilled a decade ago. Moreover, because up to half of this 
country's current natural gas supply is coming from wells that have 
been drilled in the past five years, this decline trend is likely to 
continue.
    Before we can grow gas supply, we first have to replace decline. 
The U.S. natural gas decline rate will range from 26-28 % this year. In 
practical terms, if we stopped all drilling today, one year from now 
U.S. natural gas production would be 26-28% lower than it is today. 
Accelerating decline helps explain why U.S. gas deliverability has been 
stuck in the 52-54 billion cubic feet (bcf) per day range for the past 
eight years--again, despite an increase in gas-directed drilling.
    The implications are even more sobering when we consider what's 
expected to happen to demand over the next two decades.
    The EIA, in its recent Annual Energy Outlook 2003, predicts that 
U.S. natural gas consumption will increase at an average rate of 1.8% 
per year to about 35 trillion cubic feet (tcf) per year in 2025, from 
22.7 tcf in 2001. Much of this growth in natural gas demand will occur 
in the electricity market. In fact, the U.S. now has over 150,000 
megawatts (MW) of new gas-fired power plants on line that did not exist 
in the summer of 1999--the equivalent of about 70 Diablo Canyon nuclear 
power plants.
    Let's put the EIA's projected 35 tcf U.S. gas market into 
perspective. 35 tcf implies a jump in average daily gas supply from 
about 60 bcf per day today to about 95 bcf per day in 2025--a 35 bcf 
per-day increase in deliverability. To put a 35 bcf per day increase 
into perspective, current production from the entire Gulf of Mexico is 
only about 14 bcf per day, and imports from Canada are about 10 bcf per 
day.
    The EIA predicts that increased LNG imports and new pipelines from 
Alaska and the Canada Mackenzie Delta will help close the supply gap 
over the next two decades. Clearly, we need these new supplies. There's 
a lot of gas in northern Alaska and northern Canada, and there are 
enormous amounts of stranded gas around the world that can be brought 
to the U.S. on LNG ships. But again, let's put this into perspective. 
About ten new LNG import terminals have been proposed, each with 
capacities of about 1 bcf per day. Even if all of these LNG terminals 
get built, LNG would only supply about 10-15% of a 35 tcf market. Given 
the intense ``not on our beach'' opposition to siting new LNG 
terminals, a major supply impact from LNG seems a tall order.
    The proposed pipelines from Prudhoe Bay and the Mackenzie Delta, 
which are at least five years from reality, together might eventually 
deliver up to 8 bcf per day--just 8% of a 95 bcf per day market.
    The inescapable conclusion is that most of the incremental gas 
supplies needed to serve a growing U.S. market must come from the U.S. 
lower-48. And, that implies that the burden of delivering a 50% 
increase in gas supply over the next 20-25 years will fall primarily on 
the shoulders of U.S. independents. This is a key point for policy 
makers. Except for Alaska and the deepwater Gulf of Mexico--which 
incidentally is primarily an oil play, not a natural gas play--the 
majors have essentially thrown in the towel in the US. They've taken 
their know-how and their capital overseas to drill in places like 
Angola, Kazakhstan, and Nigeria. With the U.S. gas market set to boom, 
U.S. independents are being called upon to perform a large and growing 
job on behalf of U.S. prosperity and energy security.
    It's a tall order, even more so when one considers the barriers we 
throw in the way of domestic natural gas development. Frankly, unless 
we remove these barriers, there's no chance the industry can supply a 
35-tcf market in 2025.
    Now, let's be clear that the problem is not with the resource base. 
North America is blessed with abundant natural gas reserves. The 
National Petroleum Council (NPC) study in 1999 did a good job 
describing North American gas potential. Most of us in the industry 
believe that the resource base is more than adequate to supply a 30-35 
tcf market in 20-25 years.
    Last year, the RAND Corp and the Wilderness Society issued studies 
challenging the NPC estimates. Their arguments are fundamentally 
flawed, and should be ignored by policymakers. In fact, advances in 
technology--downplayed in the RAND and Wilderness society studies--have 
enabled the industry to significantly expand the potential resource 
base over the past decade. A growing percentage of U.S. gas supply 
today comes from plays that didn't exist a decade ago. Contrary to the 
impression one gets from images of dirty, sweaty roughnecks working the 
floor of a drilling derrick, this industry is a high tech industry. 
When it comes to innovation, the American oil and gas industry leads 
the rest of the world by a wide and growing margin. New technology has 
reduced both the costs and risk of gas exploration. New technology 
allows the industry to drill deeper, maintain or increase production in 
existing fields, and develop unconventional gas that only a few years 
ago was considered uneconomic.
    Indeed, technology will someday unlock vast amounts of natural gas 
trapped as hydrates beneath the ocean floor and the Arctic tundra. Some 
scientists believe that that there is enough potential in gas hydrates 
to supply the U.S. market for at least 100 years. In fact, next month 
industry will drill the first methane hydrate well on the frozen tundra 
of Alaska's North Slope.
    The bottom line: we're not running out of natural gas, and we're 
not running out of places to look for natural gas. However, we are 
running out of places where we are allowed to look for gas. The truth 
that must be confronted now is that, as a matter of policy, this 
country has chosen not to develop much of its natural gas resource 
base.
    I suspect that many of the 65 million American households that 
depend on natural gas for heat are unaware that this choice has been 
made on their behalf.
    By many estimates, 30-40% of our potential natural gas resource 
base is either off limits or only open to development under highly 
restricted conditions. Onerous laws and regulations prohibit 
exploration in areas where there is huge potential for new supplies. 
Permitting has become next to impossible for new pipelines and LNG 
import terminals.
    Opponents of domestic gas development often exaggerate 
environmental concerns. Yes, drilling disturbs the surface, but not 
much, and not for long. Among the many technological advances made by 
the industry are improved methods of restoring land after the drilling 
rig has done its thing and left. Technologies developed over the past 
decade such as horizontal drilling greatly reduce the footprint of 
drilling activities.
    The argument that drilling drives wildlife to extinction is pure 
fiction. To the contrary, in most cases wildlife adapts and thrives in 
harmony with energy development.
    It's also time for America to rethink its fear about exploring and 
producing gas in our offshore basins. Clearly, offshore platforms have 
an impact on the environment. But there is no evidence that offshore 
platforms hurt the environment. Natural gas spills do not happen. And, 
for the folks who live along our coasts who don't want to see a distant 
offshore platform on the ocean horizon, the industry has a solution. 
Subsea wells can reduce or eliminate the need for offshore platforms
    The irony, of course, is that by choosing not to develop our most 
environmentally benign fuel, we're burning more coal and running our 
aging nuclear plants harder than ever.
    The key question for policymakers is this: can we afford policies 
that leave vast amounts of our domestic natural gas reserves untested 
and undeveloped? If the consequences of these policies were understood, 
I believe most Americans would answer ``no''
    If history is any guide, angry consumers will soon be calling on 
Congress to ``do something'' about high natural gas prices.
    In the short run, the only sensible thing Congress can do is to let 
the market work. Indeed, it already is. High prices have led to a sharp 
increase in drilling activity in the past couple of months. High prices 
also encourage conservation. Increased supply and lower demand will 
cause prices to fall later this year.
    While the market takes care of the problem in the short term, in 
the intermediate and longer term, there is much that Congress can do to 
help gas supply keep pace with demand.
    First, we need leadership. Congress can help forge a national 
consensus that natural gas is abundant, and that natural gas 
development is good for our economy, good for the environment, and good 
for society.
    Second, Congress should continue policies that have worked in the 
past. A decade ago Section 29 tax credits stimulated development of 
unconventional gas such as the San Juan basin and Powder River basin 
coal-bed methane plays. In 1995 Congress set in motion the most 
important E&P play of the past decade, by providing graduated royalty 
relief for production from federal leases in deep water. Today, more 
than one-fourth of our domestic gas production results from these past 
policy successes.
    Mindful of what has worked in the past, Congress should re-
establish Section 29-type tax credits for unconventional gas. These 
credits help producers stay the course with riskier and more costly 
development in the face of extreme gas price volatility. To prevent a 
windfall to producers, these credits should be phased out as prices 
rise, and should kick-in when prices drop. Congress should also adjust 
the tax code to help mitigate the adverse impact that accelerating 
decline has on the economics of drilling. The tax code should allow 
current-year expensing of geological and geophysical costs, eliminate 
the net income limitation on percentage depletion for marginal wells, 
eliminate the 65% net taxable income limit on percentage depletion, and 
eliminate parts of the alternative minimum tax that undermine the 
incentive for drilling.
    These policies are not, as some will argue, a major giveaway by 
taxpayers. They are sensible investments in domestic natural gas 
supply. Indeed, the incremental tax revenues that will result from new 
gas supply will far exceed the tax benefit realized by producers.
    Third--and most important--it's time to allow access to high-
potential federal land in the Rockies, off the East and West coasts, 
and in the eastern Gulf of Mexico. The industry has proven that our 
energy resources can be developed without harming the environment. 
Those who oppose drilling on federal lands exploit conflicts in federal 
policies to obstruct development. One example: millions of acres of 
federal lands in the West are being managed by the BLM as if Congress 
has designated them as ``wilderness'' under the 1964 Wilderness Act, 
even though Congress has not made such a designation.
    Opponents of domestic energy development offer no viable 
alternative, only fantasies about a planet free from the scourge of 
hydrocarbon fuels. They prevail by intimidating lawmakers. If they 
continue to prevail, American prosperity may be at risk.
    Fourth, policymakers can help get the pipeline industry back on its 
feet and remove the barriers to pipeline construction. INGAA estimates 
that $60-70 billion in new pipeline investment will be required over 
the next 12-15 years to keep pace with demand. A financially sound 
pipeline industry is a prerequisite for this investment, and the 
pipeline industry today is anything but financially healthy. 
Uncertainty about future regulatory policy threatens capital formation 
at a critical time. Congress should encourage the FERC to wrap up its 
investigation of the California energy crisis and Enron, decide what 
changes in policy are necessary, make those changes, and then help the 
industry move on.
    To be sure, the shenanigans of Enron and others are deplorable, but 
they are in the past. The marketplace has rendered the justice everyone 
wants. Nothing in the frenzy of proposed new regulations can even come 
close to matching the power of the marketplace to root out fraud and 
deter bad behavior. The vast majority of energy companies conduct 
business with honesty, integrity, and transparency, and they should not 
be punished for the misdeeds of a few. It's time to close this sad 
chapter in the history of American business, and move on.
    As is the case with drilling, opponents of pipeline construction 
exploit conflicts in existing laws and overlapping jurisdiction to 
block pipeline projects. For example, the Coastal Zone Management Act 
(CZMA) has been invoked by states to block FERC-approved natural gas 
pipeline projects. Congress should reaffirm the FERC's lead role with 
respect to interstate pipelines.
    Fifth, Congress should fund collaborative research by the Gas 
Technology Institute (GTI) and others. R&D spending by energy companies 
has plummeted over the past decade, and what remains is more focused on 
incremental improvements, not breakthroughs. Collaborative research is 
both vital, and cost effective. GTI's financial well being is 
threatened by the expiration of FERC funding in the next couple years. 
The industry needs the GTI; indeed, America needs GTI.
    Mr. Chairman, energy policy issues are complex. The many 
stakeholders in this debate have long lists of things they'd like 
Congress to do. Many of these are worthwhile, but we can't let the need 
for action on gas supply get lost in the debate over less urgent 
matters. We applaud your focus on this critical issue. I will now be 
pleased to answer your questions.

    The Chairman. I want to thank you very much for your 
testimony.
    Mr. Best.

            STATEMENT OF ROBERT W. BEST, CHAIRMAN, 
              ATMOS ENERGY CORPORATION, DALLAS, TX

    Mr. Best. Thank you, Mr. Chairman. My name is Bob Best, 
chairman of Atmos Energy Corporation of Dallas, Texas, and vice 
chairman for the 2002-03 year of the American Gas Association.
    Atmos Energy serves 1.7 million customers in 12 States, 
with our largest properties being in Louisiana, Texas, 
Colorado, Missouri, Kentucky, Tennessee, Georgia, Mississippi, 
and Kansas. We serve at retail. We have no E&P properties, or 
we are not in the trading business. The American Gas 
Association is composed of 191 gas distribution companies whose 
members deliver 83 percent of the gas used in this country to 
residential, commercial, industrial, and public authority 
customers. Natural gas, as you all know, provides 25 percent of 
the energy used in this country.
    In my oral presentation, I just want to make five succinct 
points. The first is that the interests of the local 
distribution companies and the consumer are uniquely aligned. 
We do not make money when gas prices go higher. We pass those 
prices through one-for-one. We are a delivery system. We have 
no self-interest in gas prices being higher. In fact, just the 
contrary. As Senator Bingaman mentioned, when prices go high, 
it dampens our demand, it upsets our customers, and upsets our 
regulators. What we want is adequate supply at reasonable 
prices. We believe that the consumer needs to be heard in this 
debate, and that we are that link to the consumer.
    Secondly, as other speakers today have noted, natural gas 
is abundant throughout North America. 99 percent of the natural 
gas supplied to U.S. consumers originates in Canada or the 
United States. We do have a strong resource base. We are not 
dependent on imports to meet our natural gas needs, but our 
economy, as much as some people might want it to be, is going 
to be a fossil-fuel-based economy for years to come whether we 
like it or not. We certainly need to work on other forms of 
energy and conservation, but our economy will be driven by 
fossil fuels for the foreseeable future.
    No. 3, natural gas is by far the superior fossil fuel from 
an environmental standpoint. We believe that natural gas is the 
fuel of the future. Because of its superior environmental 
qualities, demand is projected to grow for natural gas more 
than 50 percent over the next 10 to 15 years, going from 22 tcf 
to as high as 35 tcf.
    Almost all new electric generating facilities built in this 
country today for environmental reasons are using natural gas.
    No. 4, this demand will not be met and the environmental 
and economic benefits will not be realized for our country 
unless Congress passes a comprehensive energy bill which 
provides additional incentives and greater access for natural 
gas exploration and production.
    We have a very simple problem. We must increase supply. We 
have a free market, so as supply goes up, even as demand goes 
up, it puts pressure on prices, and that is what we need, 
because our people cannot pay the prices our customers are 
seeing in the marketplace today.
    What are our alternatives? They are to use other fuels. But 
these fuels do not come close to providing the economic 
benefits that gas does, or they will only increase our 
dependence on foreign countries.
    No. 5, we are not here today to tell you that the sky is 
falling. We are not people that create gloom and doom. We 
continue to be optimistic about the future, but we do think 
there needs to be a sense of urgency about this issue.
    Supply and demand has tightened, there is no question about 
it. The result has been higher prices and greater price 
volatility. The bubble is gone. The bubble is gone.
    In conclusion, assuring long-term adequate natural gas 
supply will lead to reasonable prices for consumers, it will 
dampen the unacceptable volatility of wholesale natural gas 
markets, it will keep the economy growing, it will help protect 
the environment, and it will eliminate the need to rely on 
other, less-desirable fuels.
    That concludes my remarks, Mr. Chairman. I would like to 
place in the record, if I might, along with my written 
comments, a document entitled, From the Ground Up, America's 
Natural Gas Supply Challenge, which was put out several months 
ago by the American Gas Association.
    Thank you.
    [The prepared statement of Mr. Best follows:]

            Prepared Statement of Robert W. Best, Chairman, 
                  Atmos Energy Corporation, Dallas, TX

                           EXECUTIVE SUMMARY

    The American Gas Association represents the nation's local gas 
utilities. AGA member companies acquire gas supply for, and distribute 
it to, their residential and commercial customers. As a result, the 
availability of adequate supplies of competitively priced natural gas 
is of critical importance to AGA and its member companies.
    The natural gas industry is currently at a critical crossroads. The 
``gas bubble'' of the 1980s and 1990s disappeared prior to the winter 
of 2000-2001. Supply and demand is now in precarious balance. The 
industry today no longer basks in prodigious supply; rather, it treads 
a supply tightrope, bringing with it unpleasant and undesirable 
economic and political consequences--most importantly high prices and 
higher price volatility. Both consequences harm natural gas consumers--
residential, commercial, and industrial.
    Energy is the lifeblood of our economy. High, volatile natural gas 
prices put America at a competitive disadvantage, cause plant closings, 
and idle workers. Government must take prompt and appropriate steps to 
ensure the nation of adequate supplies of natural gas at reasonable 
prices. Moreover, it is expected that natural gas demand will increase 
by 50 percent over the next two decades. This growth will occur because 
natural gas is the most environmentally friendly fossil fuel and 
because natural gas is an economic and reliable source of energy. It is 
in the national interest that natural gas be available to serve the 
demands of the market.
    Many of the fields from which natural gas is currently produced are 
mature. Over the last two decades, technological advances have greatly 
enhanced the ability to find natural gas as well as to produce the 
maximum amount possible from a field. While technology will continue to 
improve, it is not likely that we will discover ways to extract even 
more hydrocarbons from existing fields.
    If America's needs for energy are to be met, there is no choice 
except for exploration and production activity to migrate into new 
areas. The nation's natural gas resource base is rich and diverse. It 
is simply a matter of taking E&P activity to the many known areas where 
natural gas is found. Regrettably, many of these areas are either 
totally closed to exploration and development or are subject to so many 
restrictions that timely and economic development is not possible. The 
E&P business is, as a result of technological improvements, enormously 
more environmentally benign today than it was 25 years ago. As a 
result, current restrictions on land access need to be reevaluated 
given the nation's energy needs.
    The most important step Congress can take to address these issues 
is to ensure that lands where natural gas is believed to exist are 
available for environmentally sound exploration and development. 
Additionally, it is appropriate to create incentives to seek and 
produce this natural gas.

                               TESTIMONY

    Good afternoon. I am Bob Best, Chairman of Atmos Energy in Dallas, 
Texas, and 2002-2003 Vice Chairman of the American Gas Association in 
Washington, D.C. (``AGA''). AGA is grateful for the opportunity to 
share its views with you on the critical importance to the nation of 
ensuring ample natural gas supplies at competitive prices. Doing so is 
necessary for the nation, both to protect consumers and to address the 
energy and economic situations we currently face.
    AGA is composed of 191 natural gas distribution companies, which 
deliver gas throughout the United States. Local gas utilities deliver 
gas to more than 64 million customers nationwide. AGA members deliver 
approximately 83 percent of this gas.
    Our members are charged with the responsibility, under local law or 
regulation, of acquiring natural gas for the majority of their 
customers. Having available adequate supplies of natural gas at 
reasonable prices is thus a critical issue for AGA and its members. 
Accordingly, AGA members and the consumers they serve share both an 
interest and a perspective on this subject.
    I would like to make clear that the bread and butter business of 
AGA members is acquiring and delivering natural gas to residential, 
commercial, and industrial consumers across America. Our members remain 
economically viable by delivering natural gas to consumers at the 
lowest reasonable price, which we do by operating our systems over a 
million miles of distribution lines--as efficiently as possible. 
Exploring for and producing natural gas is the business of our energy-
industry colleagues in the oil and gas business, whether they are 
major, independent, or ``Mom and Pop'' operators. We are not here to 
speak for them today, but their continued success in providing natural 
gas to America's consumers is of great importance to us as well.
    AGA is encouraged that Congress is coming to grips with this 
important issue. Adequate natural gas supply is crucial to all of 
America for a number of reasons. It is imperative that government take 
significant action in the very near term to assure the continued 
economic growth, environmental protection, and national security of our 
nation. The tumultuous events in energy markets over the last two years 
serve to underscore the importance of adequate and reliable supplies of 
reasonably priced natural gas to consumers, to the economy, and to 
national security.
    The natural gas industry is presently at a critical crossroads. For 
the past three years gas production has had to operate full-tilt to 
meet consumer demand. The ``surplus deliverability'' or ``gas bubble'' 
of the late 1980's and 1990's is simply gone. No longer is demand met 
while unneeded production facilities sit idle. No longer can new demand 
be met by simply opening the valve a few turns. The valves are wide 
open.
    The supply tightrope has brought with it several inexorable and 
unpleasant consequences--prices in the wholesale market have gone up 
and that market has become much more volatile. During the 2000-2001 
heating season, for example, gas prices moved from the $2 level to 
approximately $10 and back again to nearly $2. Such volatility hurts 
consumers, puts domestic industry at a competitive disadvantage, closes 
plants, and idles workers. The winter of 2000-2001 made it abundantly 
clear to us (and to you as well) that consumers do not like these price 
increases and they do not like the market volatility that is now an 
everyday norm. Unless significant actions are taken on the supply side, 
gas markets will remain tumultuous, and 64 million gas customers will 
suffer the consequences. As gas utilities, we have a number of programs 
in place to insulate consumers to some extent from the full impact of 
wholesale price volatility, but consumers must still ultimately pay the 
price.
    The demand for natural gas in the U.S. is expected to increase 50 
percent by 2015-2020. Growth seems inevitable because gas is a clean, 
economic, domestic source of available energy. It does not face the 
environmental hurdles of coal and nuclear energy, the economic and 
technological drawbacks of most renewable energy forms, or the national 
security problems associated with imported oil.
    The challenge for both government and industry is quite 
straightforward: to ensure that the current need for natural gas is met 
and that the future need for natural gas will be met at reasonable and 
economic prices. There can be no responsible question that facilitating 
this result is sound public policy. Natural gas is abundant 
domestically, and natural gas is the environmentally friendly fuel of 
choice. Ensuring adequate natural gas supply will lead to reasonable 
prices for consumers, will dampen the unacceptable volatility of 
wholesale natural gas markets, will help keep the economy growing, and 
will help protect the environment.
    America has a large and diverse natural gas resource; producing it, 
however, can be a challenge. Providing the natural gas that the economy 
requires will necessitate: (1) providing incentives to bring the 
plentiful reserves of North American natural gas to production and, 
hence, to market; (2) making available for exploration and production 
the lands where natural gas is already known to exist so gas can be 
produced on an economic and timely basis; (3) ensuring that the new 
infrastructure that will be needed to serve the market is in place in 
timely and economic fashion.
    Natural gas--our cleanest fossil fuel--is found in abundance 
throughout both North America and the world. It currently meets one-
fourth of the United States' energy needs. Unlike oil, about 99 percent 
of the natural gas supplied to U.S. consumers originates in the United 
States or Canada.
    The natural gas resource base in the U.S. has increased over the 
last several decades. In fact we now believe that we have more natural 
gas in the U.S. than we estimated twenty years ago, notwithstanding the 
production of between 300 and 400 trillion cubic feet of gas in the 
interim. This is true in part because new sources of gas, such as 
coalbed methane, have become an important part of the resource base.
    Natural gas production is sustained and grows only by drilling in 
currently productive areas or by exploring in new areas. Over the past 
two decades a number of technological revolutions have swept across our 
industry. We are able today to drill for gas with dramatically greater 
success and with significantly reduced environmental impact than we did 
twenty years ago. We are also much more efficient in producing the 
maximum amount of natural gas from a given area of land. A host of 
technological advances allows producers to identify and extract natural 
gas deeper, smarter and more efficiently. For example, the drilling 
success rate for wells deeper than 15,000 feet has improved 
dramatically. In addition, gas trapped in coal seams, tight sands or 
shale is no longer out of reach.
    While further improvements in this regard can be expected, they 
will not be sufficient to meet growing demand unless they are coupled 
with other measures. Regrettably, technology alone cannot indefinitely 
extend the production life of mature producing areas. New areas and 
sources of gas will be necessary.
    Notwithstanding the dramatic impact of innovation upon our 
business, the inevitable fact today is that we have reached a point of 
rapidly diminishing returns with many existing natural gas fields. This 
is almost entirely a product of the laws of petroleum geology. The 
first ten wells in a field may ultimately produce 60 percent of the gas 
in that field, while it may take forty more to produce the balance. In 
many of the natural gas fields in America today, we are long past those 
first ten wells and are well into those forty wells in the field. In 
other words, the low-hanging fruit have already been picked in the 
orchards that are open for business.
    Drilling activity in the U.S. has moved over time, from onshore 
Kansas, Oklahoma and Arkansas to offshore Texas and Louisiana, and then 
to the Rocky Mountains. Historically, we have been quite dependent on 
fields in the Gulf of Mexico. But recent production declines in the 
shallow waters of the Gulf of Mexico have necessitated migration of 
activity to deeper waters to offset this decline. These newer, more 
expensive, deepwater fields also tend to have short lives and 
significantly more rapid rates of decline in production than is the 
case with onshore wells.
    In short, America's natural gas fields are mature--in fact many are 
well into their golden years. There is no new technology on the horizon 
that will permit us to pull a rabbit out of a hat in these fields. 
These simple, and incontrovertible, facts explain why we are today 
walking a supply tightrope and why the winter of 2000-2001 may become a 
regular occurrence, particularly at the point the economy returns to 
its full vigor. Having the winter of 2000-2001 return every year will 
undoubtedly put a brake on the economy, once again causing lost output, 
idle productive capacity, and lost jobs.
    If we are to continue to meet the energy demands of America and its 
citizens and if we are to meet the demands that will they make upon us 
in the next two decades, we must change course. It will not be enough 
to make a slight adjustment of the tiller or to wait three or four more 
years to push it over full. Rather, we must come full about, and we 
must do it in the very near future. Lead times are long in our 
business, and meeting demand years down the road requires that we begin 
work today.
    We have several reasonable and practical options. And, as I hope 
you do understand, continuing to do what we have been doing is simply 
not enough.
    First, and most importantly, we must look to new frontiers within 
the United States. Further growth in production from this resource base 
is jeopardized by limitations currently placed on access to it. For 
example, most of the gas resource base off the East and West Coasts of 
the U.S. and the Eastern Gulf of Mexico is currently closed to any 
exploration and production activity. Moreover, access to large portions 
of the Rocky Mountains is severely restricted. The potential for 
increased production of natural gas is severely constrained so long as 
these restrictions remain in place.
    In this vein, the Rocky Mountain region is expected to be a growing 
supplier of natural gas, but only if access to key prospects is not 
unduly impeded by stipulations and restrictions. Two separate studies 
by the National Petroleum Council and the U.S. Department of the 
Interior reached a similar conclusion--that nearly 40 percent of the 
gas resource base in the Rockies was restricted from development to 
some degree, some partially and some totally. On this issue the 
Department of the Interior noted that there are nearly 1,000 different 
stipulations that can impede resource development on federal lands.
    One of the most significant new gas discoveries in North America in 
the past ten years is located just north of the US/Canada border in 
eastern Canada coastal waters on the Scotian shelf. Natural gas 
discoveries have been made at Sable Island and Deep Panuke. Gas 
production from Sable Island already serves Canada's Maritimes 
Provinces and New England through an offshore and land-based pipeline 
system. This has been done with positive economic benefits to the 
region and without environmental degradation. This experience provides 
an important example for the United States, where we believe the 
offshore Atlantic area to have similar geology.
    In some areas we appear to be marching backward. The buy-back of 
federal leases where discoveries had already been made in the Destin 
Dome area (offshore Florida) of the eastern Gulf of Mexico was a 
serious step back in terms of satisfying consumer gas demand. This 
action was contrary to what needs to be done to meet America's energy 
needs. With Destin Dome we did not come full about, as we need to do; 
rather, we ran from the storm.
    Geographic expansion of gas exploration and drilling activity has 
for the entirety of the last century been essential to sustaining 
growth in natural gas production. Future migration, to new frontiers, 
to new fields, in both the U.S. and Canada will also be critical. 
Without production from geographic areas that are currently subject to 
access restrictions, it is not at all likely that producers will be 
able to continue to provide increased amounts of natural gas from the 
lower-48 states to customers for longer than 10 or 15 years. We believe 
that the same is true in Canada as well.
    Quite simply, we do not believe that there is any way other than 
exploring for natural gas in new geographic areas to meet America's 
anticipated demand for natural gas unless we turn increasingly to 
sources located outside North America.
    We do not advance this thesis lightly. Over the past two years both 
the American Gas Association and the American Gas Foundation have 
studied this important issue vigorously. We believe it is necessary 
that policy makers embrace this thesis so that natural gas can continue 
to be--as it has been for nearly a century--a safe and reliable form of 
energy that is America's best energy value and its most environmentally 
benign fossil fuel.
    When the first energy shock transpired in the early 1970s, the 
nation learned, quite painfully, the price of dependency upon foreign 
sources of crude oil. We also learned, through long gasoline lines and 
shuttered factories, that energy is the lifeblood of our economy Yet 
thirty years later we are even more dependent upon foreign oil than we 
were in 1970. Regrettably, the nation has since failed to make the 
policy choices that would have brought us freedom from undue dependence 
on foreign-source energy supplies. We hope that the nation can reflect 
upon that thirty-year experience and today make the correct policy 
choices with regard to its future natural gas supply. We can blame some 
of the past energy problems on a lack of foresight, understanding, and 
experience. We will not be permitted to do so again.
    Meeting our nation's ever-increasing demand for energy has an 
impact on the environment, regardless of the energy source. The 
challenge, therefore, is to balance these competing policy objectives 
realistically. Even with dramatic improvements in the efficient use of 
energy, U.S. energy demand has increased more than 25 percent since 
1973, and significant continued growth is almost certain. Satisfying 
this energy demand will continue to affect air, land and water. A great 
American success story is that, with but five percent of the world's 
population, we produce nearly one-third of the planet's economic 
output. And energy is an essential--indeed critical--input for that 
success story to both continue and grow.
    It is imperative that energy needs be balanced with environmental 
impacts and that this evaluation be complete and up-to-date. There is 
no doubt that growing usage of natural gas harmonizes both objectives. 
Finding and producing natural gas is today accomplished through 
sophisticated technologies and methodologies that are cleaner, more 
efficient and much more environmentally sound than those used in the 
1970s. It is unfortunate that many restrictions on natural gas 
production have simply not taken account of the important technological 
developments of the preceding thirty years. The result has been 
policies that deter and forestall increased usage of natural gas, which 
is, after all, the nation's most environmentally benign and cost-
effective energy source.
    Natural gas consumers enjoyed stable prices from the mid-1980s to 
2000, with prices that actually fell when adjusted for inflation. 
Today, however, the balance between supply and demand has become 
extremely tight, creating the tightrope effect. Even small changes in 
weather, economic activity and world energy trends result in wholesale 
natural gas price fluctuations. We saw this most dramatically in the 
winter of 2000-2001. In the 1980s and '90s, when the wholesale 
(wellhead) price of traditional natural gas sources was around $2 per 
million British thermal units, natural gas from deep waters and Alaska, 
as well as LNG, may not have been price competitive. However, most 
analysts suggest that these sources are competitive when gas is in a 
$3.00 to $4.00 price environment. Increased volumes of natural gas from 
a wider mix of sources will be vital to meeting consumer demand and to 
ensuring that natural gas remains affordable.
    Increasing natural gas supplies will boost economic development and 
will promote environmental protection, while ensuring more stable 
prices for natural gas customers. Most importantly, increasing natural 
gas supplies will give customers ours and yours--what they seek--
reasonable prices, greater price stability, and fuel for our vibrant 
economy. However, without policy changes with regard to natural gas 
supply, as well as expansion of production, pipeline and local delivery 
infrastructure for natural gas, the natural gas industry will have 
difficulty meeting the anticipated 50 percent increase in market 
demand. Price increases, price volatility, and a brake on the economy 
will be inevitable.
    Second, we can increase our focus on non-traditional sources, such 
as liquefied natural gas (LNG). Reliance upon LNG has been modest to 
date, but it is clear that increases will be necessary to meet growing 
market demand. Today, roughly 99 percent of the U.S. gas supply comes 
from traditional land-based and offshore supply areas in North America. 
But, during the next two decades, non-traditional supply sources such 
as LNG will likely account for a significantly larger share of the 
supply mix. LNG has become increasingly economic. It is a commonly used 
worldwide technology that allows natural gas produced in one part of 
the world to be liquefied through a chilling process, transported via 
tanker and then re-gasified and injected into the pipeline system of 
the receiving country. Although LNG currently supplies less than 1 
percent of the gas consumed in the U.S., it represents 100 percent of 
the gas consumed in Japan. LNG has proven to be safe, economical and 
consistent with environmental quality. Due to constraints on other 
forms of gas supply and increasingly favorable LNG economics, LNG is 
likely to be a more significant contributor to U.S. gas markets in the 
future. It will certainly not be as large a contributor as imported oil 
(nearly 60 percent of U.S. oil consumption), but it could account for 
10-15 percent of domestic gas consumption 15-20 years from now if 
pursued aggressively and if impediments are reduced.
    Third, we can tap the huge potential of Alaska. Alaska is estimated 
to contain more than 250 trillion cubic feet enough to satisfy U.S. 
natural gas demand by itself for more than a decade. Authorizations 
were granted twenty-five years ago to move gas from the North Slope to 
the Lower-48, yet no gas is flowing today nor is any transportation 
system yet under construction. Indeed, every day the North Slope 
produces approximately 8 billion cubic feet of natural gas that is re-
injected because it has no way to market. Alaskan gas has the potential 
to be the single largest source of price and volatility relief for U.S. 
gas consumers. Deliveries from the North Slope would not only put 
downward pressure on gas prices, but they would also spur the 
development of other gas sources in the state as well as in northern 
Canada.
    Fourth, we can look to our neighbors to the north. Canadian gas 
supply has grown dramatically over the last decade in terms of the 
portion of the U.S. market that it has captured. At present, Canada 
supplies approximately 15 percent of the United States' needs. We 
should continue to rely upon Canadian gas, but it may not be realistic 
to expect the U.S. market share for Canadian gas to continue to grow as 
it has in the past or to rely upon Canadian new frontier gas to meet 
the bulk of the increased demand that lay ahead in the United States.
                            recommendations
    To promote meeting consumer needs, economic vitality, and sound 
environmental stewardship, the American Gas Association urges the 
Congress as follows:

   Current restrictions on access to new sources of natural gas 
        supply must be re-evaluated in light of technological 
        improvements that have made natural gas exploration and 
        production more environmentally sensitive.
   Federal and state officials must take the lead in overcoming 
        the pervasive ``not in my backyard'' attitude toward energy 
        infrastructure development, including gas production.
   Interagency activity directed specifically toward expediting 
        environmental review and permitting of natural gas pipelines 
        and drilling programs is necessary, and agencies must be held 
        responsible for not meeting time stipulations on lease, lease 
        review, and permitting procedures.
   Federal lands must continue to be leased for multi-purpose 
        use, including oil and gas extraction and infrastructure 
        construction.
   Tax provisions such as percentage depletion, expensing 
        geological and geophysical costs in the year incurred, Section 
        29 credits, and other credits encourage investment in drilling 
        programs, and such provisions are often necessary, particularly 
        in areas faced with increasing costs due to environmental and 
        other stipulations.
   Economic viability must be considered along with 
        environmental and technology standards in an effort to develop 
        a ``least impact'' approach to exploration and development but 
        not a ``zero impact''.
   The geologic conditions for oil and gas discovery similar to 
        that in eastern Canada extend to the U.S. mid-Atlantic area.

    Although some prospects have been previously tested, new 
evaluations of Atlantic oil and gas potential should be completed using 
today's technology in contrast to that of 20 to 30 years ago.
    The federal government should facilitate this activity by lifting 
or modifying the current moratoria regarding drilling and other 
activities in the Atlantic Offshore to ensure that adequate geological 
and geophysical evaluations can be made and that exploratory drilling 
can proceed.
    The federal government must work with the Atlantic Coast states to 
assist--not impede--the process of moving natural gas supplies to 
nearby markets should gas resources be discovered in commercial 
quantities. Federal agencies and states must work together to ensure 
the quality of the environment but they must also ensure that 
infrastructure (such as landing an offshore pipeline) is permitted and 
not held up by multi-jurisdictional roadblocks.

   The Federal government should continue to permit royalty 
        relief where appropriate to change the risk profile for 
        companies trying to manage the technical and regulatory risks 
        of operations in deepwater.
   Coastal Zone Management (CZMA) is being used to threaten or 
        thwart offshore natural gas production and the pipeline 
        infrastructure necessary to deliver natural gas to markets in 
        ways not originally intended. Companies face this impediment 
        even though leases to be developed may be 100 miles offshore. 
        These impediments must be eliminated or at least managed within 
        a context of making safe, secure delivery of natural gas to 
        market a reality.
   The U.S. government should work closely with Canadian and 
        Mexican officials to address the challenges of supplying North 
        America with competitively priced natural gas in an 
        environmentally sound manner.
   Renewable forms of energy should play a greater role in 
        meeting U.S. energy needs, but government officials and 
        customers must realize that all forms of energy have 
        environmental impacts.
   Construction of an Alaskan natural gas pipeline must begin 
        as quickly as possible.

    Construction of this pipeline is possible with acceptable levels of 
environmental impact.
    The pipeline project would be the largest private sector investment 
in history, and it would pose a huge financial risk to project 
sponsors.
    The project will not be undertaken without some form of federal 
support--loan guarantee, accelerated depreciation, investment tax 
credit and/or marginal well tax credit.
    These forms of support are not unprecedented and they would reduce 
project risk thereby reducing transportation charges that are 
ultimately borne by the consumer.

   The Federal Energy Regulatory Commission (FERC) announced in 
        a new policy in December of 2002 that it would not require LNG 
        terminals to be ``open access'' (that is, common carriers) at 
        the point where tankers offload LNG. This policy will spur LNG 
        development because it reduces project uncertainty and risk. 
        Other federal and state agencies should review any regulations 
        that impede LNG projects and act similarly to reduce or 
        eliminate these impediments.

    The siting of LNG off-loading terminals (currently four operable 
are in the U.S.) is generally the most time consuming roadblock for new 
LNG projects. Federal agencies should take the lead in demonstrating 
the need for timely approval of proposed off-loading terminals, and 
state officials must begin to view such projects as a means to satisfy 
supply and price concerns of residential, commercial and industrial 
customers.

    The Chairman. Thank you. Would you take your last sentence 
that you stated in the record and repeat it again?
    Mr. Best. The last sentence? Yes. Assuring long-term 
adequate natural gas supply will lead to reasonable prices for 
consumers, dampen the unacceptable volatility of wholesale 
natural gas markets, keep the economy growing, help protect the 
environment, and eliminate the need to rely on other, less 
desirable fuels.
    The Chairman. We are going to go on the 5-minute rule now, 
everybody, and we will get our chance here. And why don't we 
just stay with you for a minute, Mr. Best. Is that last 
statement of yours saying we need to produce more gas?
    Mr. Best. That is my belief, sir. I have been in the 
business 28 years. I have been in the interstate pipeline side. 
I am now in the retail consumer side. I believe that we need 
more gas supply. We are not an E&P. We are not going to benefit 
directly. We benefit by our demand going up. Any time the 
prices get too high, as the Senator read in that letter, our 
demand is dampened, and I will tell you this, demand is more 
elastic than we ever realized it was. People will resort to 
turning down thermostats, or other fuels. So I see it, we need 
incentives. We need an energy policy that encourages more gas 
supply.
    The Chairman. Okay, now--first, Mr. Caruso, let me ask you 
one. What percentage of the gas is sold on the spot market?
    Mr. Caruso. That is a number that, of course, is a bit 
elusive, but industry people we have spoken with unanimously 
believe it is below 10 percent, and could be substantially 
less. The problem is that many of these spot volumes get 
resold, so there is a lot more transactions than physical sales 
on the spot market.
    The Chairman. So when we hear a price of a certain amount, 
spot price at a certain time, a certain day, that does not mean 
the price across the range of users in the country. That means 
the spot.
    Mr. Caruso. Absolutely.
    The Chairman. That is the last increment that is purchased 
on that particular day at that particular time.
    Mr. Caruso. Exactly. It is the marginal supply.
    The Chairman. Now, what do you think of the accusations of 
price-fixing in the letter that was read?
    Mr. Caruso. Well, of course, the EIA is not a regulatory 
agency.
    The Chairman. I understand.
    Mr. Caruso. I think it is probably a statement born out of 
frustration. I agree with Mr. Best's last comment, that there 
is an elasticity in demand for gas, but it is a longer-term 
elasticity.
    In the very short run, as we are experiencing right now, 
with working gas and storage so low, and increased demand 
through a cold snap, or what-have-you, it is very inelastic, so 
you get very large jumps in price due to very small volumetric 
changes. I think that is what we are witnessing now.
    The Chairman. To each of you--quickly, one or two 
statements by each of you, starting with Mr. Welch. What two or 
three things do you recommend we do with reference to easing 
the natural gas problem as you see it?
    Mr. Welch. Well, there is a short- and long-term answer. 
Short-term, I think we need to let the market work. I think 
demand is elastic. When prices are high, like they are now, 
that would spur as much activity in the industry as is 
possible, and that will happen. Longer-term, I think there are 
policy decisions that need to be made now that can unlock new 
large sources of natural gas, such as the Alaska Gas Pipeline, 
which is a basin-opening piece of infrastructure.
    The Chairman. Okay.
    Mr. Best.
    Mr. Best. Mr. Chairman, I would like to make one point. 
Back to the spot market question. We, as a utility, had already 
bought 50 percent of our gas going into the winter, so we will 
not be paying these prices even that are out on the market 
today, so most companies like ours will hedge between 20 and 30 
percent of their gas so we are not paying today's prices for 
all of our gas.
    As far as your question about what should be done, I guess 
we think we would like to see five major things in the bill. I 
mentioned earlier, tax incentive and access provisions, but 
also--those are the first two. The third would be, 
encouragement of building of infrastructure to get the gas to 
market. Again, we are going to have to--and there are some 
depreciation provisions in the bill that help that.
    The fourth one is, we continue to encourage greater funding 
for LIHEAP, because as gas prices are higher, we do have 
customers who have difficulty paying their bills, and we think 
that is something that needs to be done by the Congress to make 
sure we take care of people who are less fortunate.
    And the fifth would be a continuing emphasis on 
conservation. We are for conservation, and at the forefront of 
leading that, so we think there certainly should be some 
emphasis in this bill to continue to encourage conservation.
    The Chairman. Mr. Rattie.
    Mr. Rattie. I will just try to add to that, Mr. Chairman. 
In addition to tax policies longer-term, short-term I would 
agree wholeheartedly with a statement made earlier and included 
in my remarks, we have to let the market work, and it is 
working. The rig count is rising, demand is falling. I would 
bet that prices will be lower later this year. Just as we saw 
in 2001, the market responded to the price signals.
    As other panelists have already noted, while spot prices 
have shot through the ceiling, there is not a lot of volume 
moved on that. In fact, a subsidiary of my company provides 
natural gas supply to Mr. Huntsman, at least to some of his 
facilities in Utah, and I can assure you those supplies were 
procured a long time ago at prices far below what current spot 
market prices are.
    I think it is unfortunate that leading businessmen would 
set us off on a red herring, making allegations that this is 
all due to market manipulation. These are signals that the 
market is sending us that we ignored 2 years ago. We should not 
ignore them today.
    Access to Federal lands is by far and away the most 
important issue, long-term, that Congress can deal with. We 
cannot set aside 40 percent of our potential natural gas 
resource base and expect to have supply to meet the kind of 
demand that the EIA is projecting. While we spend a lot of time 
worrying about the consequences of drilling and of industry's 
activities on the environment and wildlife, what we do not hear 
enough of is the fact that the decision not to develop our 
domestic gas resources has human consequences that are getting 
ignored, so access to Federal lands long-term is vital.
    The Chairman. All right. Senator Bingaman, we are going to 
cede in the following order: Senator Bingaman, Senator Thomas, 
Senator Landrieu, and Senator Alexander. I, again, am going to 
excuse myself shortly and let Senator Thomas conduct the 
meeting. I just want to say, by way of my concern as chairman, 
I would say to all of you, that was great testimony. I very 
much enjoyed it. We almost hear the exact same thing--we could 
go back and read it--last year. It was the same kind of 
testimony.
    Whenever we look at access, it seems like there are lands 
out there that we ought to be attempting to get resources from, 
but nobody really thinks that it is that land. They go look at 
it, and somebody has a reason for not doing it there and, of 
course, that isn't the land that is really going to make any 
difference.
    We have to get to, come up with some kind of conclusion as 
to what that means. I would say for now, the access in the 
Rocky Mountain and Western area that has been alleged by so 
many to be there in such large quantities is not proving out to 
be that much, when you look at precisely what is there, and we 
will continue to do that and have staff people do it, but it is 
very difficult to locate it in the large quantities that have 
been spoken of, unless you go offshore. If you go offshore, you 
start talking about big numbers.
    Senator Bingaman, I wanted to say, you have worked on a 
number of these issues over and over, and I would hope that in 
this area of natural gas, we could come up with something 
together that we might pursue and push ahead for what has been 
recommended here today and that we are hearing from the people.
    Thank you all very much.
    Senator Bingaman. Thank you, Mr. Chairman. I agree with 
you, there is a lot that we should be able to do together on 
this to deal with this problem. Let me get back to a statement 
Mr. Best made there about an adequate supply at reasonable 
prices is the interest that your company has. That is our 
interest, too, I think, adequate supply at reasonable prices. 
What can be done, what should be done, or could be done to deal 
with the enormous volatility in wholesale prices of natural gas 
that we are facing?
    If, in fact, the price is now $18 to $20 per mcf, that is 
about twice what it was 2 years ago in California. At that 
time, I guess, it has now come out that there were some market 
manipulation activities going on. I do not know how much of the 
price increases there were explained by that. I do not think 
any of us know that.
    Mr. Caruso, do you have any ideas of what could be done to 
get some of the volatility out of this? Or do you think that 
should not be done?
    Mr. Caruso. Well, I think volatility certainly has a 
dampening effect on investment decisions. In general the market 
should be allowed to work. One of the things that increases the 
availability of supply and options in the gas market that we do 
not have is a world global market for natural gas. So in a 
situation like this, where natural gas prices have spiked, if 
there were a world spot market, you might see LNG cargoes 
coming in very quickly.
    I think developing an infrastructure, whether it be Alaska, 
the Mackenzie Delta, domestic, and LNG, all are needed, and I 
think that is the only way you are going to really reduce the 
volatility. You will still have some volatility, but it will be 
more manageable.
    Senator Bingaman. Do any of the rest of you have a comment 
on this issue of volatility and wholesale gas prices? Whether 
any action should be taken? My own reaction is that if we want 
adequate supplies at reasonable prices and these are not 
reasonable prices. I guess it is some consolation to say most 
people are not paying these prices because they have long-term 
contracts, but some people are. I mean, some portion of the gas 
that various people are buying is being priced at this level, 
presumably, if they are in the market today.
    Mr. Best. I will just comment, one of the things we are 
trying to do, of course, in our business we are trying to take 
the volatility out of our pricing, because that is what our 
customers want. That is what our regulators want. I think the 
way that we can do some of that is convince our regulators that 
we need a little bit longer-term contracts--to be able to enter 
into some longer-term contracts, because, as I said at the 
beginning, we have hedged about 50 percent of our gas for this 
winter, and that gas was hedged under $4, so we went into the 
winter and we have some storage, and we as an LDC have to fill 
our storage. I mean, we do not try to--we are not in the 
commercial business, we are in the reliability business, so we 
have to fill our storage.
    I think if we could convince our regulators--I am not 
talking about 15-year contracts, but if there was a liquid 
enough market and we could enter into 3- to 5-year contracts at 
lower prices, now the danger is, of course, is when you do 
that, then the market falls lower than that, and then that 
causes its own set of issues, but as I see it, I do not think--
I mean, we have got deregulation at the wellhead.
    We have a market in which price regulates supply and 
demand, and so I think at long-term that still is the best 
model, but I do think that we have got to convince those that 
we deal with that we need to maybe have the ability to enter 
into longer-term contracts to try to take as much volatility 
out of the market as we can.
    Senator Bingaman. Mr. Rattie, did you have a comment?
    Mr. Rattie. Yes, sir. Volatility in energy markets is the 
way the market rationalizes demand in the face of constrained 
supply, and I think it is evidence that the markets are 
working. I would echo everything that Mr. Best said. Our 
utility has secured natural gas supplies under long-term supply 
agreements that are by and large protecting residential 
customers in our market region from the brunt of this. There is 
very little volume moving at these prices. A lot of it is 
people speculating, and speculators have a role in a market 
that is like this.
    The reason we are seeing this today and we did not see it 
10 years ago is, 10 years ago we had a lot of surplus capacity 
in our system. We had extra pipeline capacity. We had extra 
deliverability from production facilities. None of that is 
there today, so we get a situation where we get a short-term 
surge in demand and a year like last year, where drilling was 
down because prices had been lower in the first part of the 
year, and we are just too tight. We cannot deal with that.
    Senator Bingaman. Mr. Welch.
    Mr. Welch. I just wanted to mention one thing in this 
regard as well. I think the best thing you could do to improve 
volatility, which it is not good for our customers, as we just 
heard, and it is not really good for us, either, because it 
makes investment decisions almost impossible to make, the best 
thing that we could do is hook up all sources of domestic 
supply that are available within the political framework, and I 
know some areas are off limits and they will probably remain 
off limits, but the areas that are open to us, we should get 
those going.
    And I agree with Mr. Caruso that the reserve-to-production 
ratio here in the United States is around 10 or so. On the 
world market for gas, it is 60, so there is a lot of natural 
gas around the world, and I think the key to putting a little 
stability in there is making sure that we have adequate LNG 
infrastructures, which will be at the margin.
    I see there is going to be room for our gas from South 
Louisiana from the Gulf of Mexico, from the Rocky Mountains, 
from Canada, from Alaska, any place in North America, but that 
is going to be a base load. Where we get to the margin, and we 
are competing with other countries like Japan and others for 
LNG, that is where having the LNG infrastructure would help 
mitigate the volatility in the market, and fortunately FERC is 
moving in the right direction.
    Senator Bingaman. You say fortunately they are?
    Mr. Welch. They are. Indeed they are.
    Senator Bingaman. Thank you, Mr. Chairman.
    Senator Thomas. I guess I am next and then Senator 
Landrieu. We will try to hold to five minutes each in our 
questions.
    The price you mentioned, Mr. Caruso, is at Henry Hub. Do 
you have any idea what the wellhead price is in Powder River 
Basin or at the Opel Hub?
    Mr. Caruso. $6.50 wellhead.
    Senator Thomas. Do you see anything wrong with that? That 
is more than twice as much at the Henry Hub than it is at the 
wellhead.
    Mr. Caruso. It just shows the point we just referred to, 
the volatility.
    Senator Thomas. I do not think that is volatility. That has 
a little to do with the ability to transport the product. That 
has been our problem in Wyoming for a very long time. There has 
been a big price differential as close as the Cheyenne Hub, so 
I think--we talked about production all the time, but it is not 
only production. I think that is the issue here, because 
production is in the West and the market is certainly the East, 
or at least in the Midwest. What do you think, Mr. Rattie, it 
would take to really increase capacity in pipelines?
    Mr. Rattie. Senator Thomas, thank you for that question, 
and I would like to first comment on the Rockies situation, 
because you are spot on. Wellhead prices in the Rockies are 
well below the wellhead prices in other regions, and that is 
for the simple reason that this country owes a debt of 
gratitude to the State of Wyoming. It is the only State in the 
lower 48 that has grown its productive capability, the supply, 
in any significant amount in the last few years.
    Unfortunately, pipeline development has not kept pace with 
that growing supply, and we have problems getting gas out of 
the region. Only about 20 percent of the natural gas that gets 
produced in the Rocky Mountain region actually gets consumed in 
the region. The other 80 percent has to move on long-haul pipes 
that have to get to the Upper Midwest markets, or to markets 
out in the West, and we simply have not been able to keep pace 
with supply in pipeline development.
    Now, why is that? Well, a large portion of land in the 
West, in the Rockies, in key producing regions in the Rockies 
in particular, are Federal lands and State lands, and we go 
through an onerous web of complex, conflicting policy 
administration, overlapping jurisdiction. The barriers that we 
throw in the way of pipeline development out West are a 
significant contributor to some of the problems we are 
experiencing in the market today.
    We have to find a way to build the pipelines, to move the 
gas from regions like the Rockies, where supply has the 
potential to grow, to regions like California that are 
dependent upon Wyoming gas for market----
    Senator Thomas. I agree with you entirely.
    One of the difficulties with that, of course, and you are 
in the transportation business, Mr. Best, who is going to 
finance pipelines like from Alaska? Who is going to finance 
them? How are you going to adjudicate the capacity to avoid--
which is part of our problem? Someone owns capacity, so they 
buy the gas at a very low price because no one else can move 
it, and then sell it at a high price. That is distortion. How 
do you say we are going to pay for pipelines, and make them 
fair and open to everyone?
    Mr. Best. I think the economics are showing, and we are not 
in the long-line pipeline or the production business, but I 
think the economics are showing that you can have gas priced in 
the $3 to $5 range, and that those type projects can be 
financed.
    Now, I think, as Mr. Rattie said earlier, those pipelines, 
the Alaskan Oil Pipeline, a lot of the myths that were put up 
or barriers have been overcome and proven wrong, and I just, I 
think those type of projects will be financed with the right 
incentives.
    Senator Thomas. Okay. Well, I think that is probably true, 
but I think you also have to be careful about who has the 
available capacity, and eminent domain is not an easy thing, 
and there are quite a few problems attached to it, of course.
    Now, gas consumption, as you pointed out, is very seasonal. 
Who could level out the demand with the production to storage?
    Mr. Caruso. Well, we have a very robust storage system.
    Senator Thomas. Apparently it did not work very well this 
winter.
    Mr. Caruso. Not robust enough, but one of the things that 
is changing is that because of the increased demand in the 
electric power sector, the seasonality is becoming less of a 
factor. So this is a requirement of improving not only, as you 
point out, the storage, but deliverability.
    Senator Thomas. Electric generators are also a little more 
insensitive to price, because there is nothing they can do 
about it.
    Mr. Caruso. And many of them are not being built with 
alternative or switchable fuels.
    Senator Thomas. Senator Landrieu. Thank you, gentlemen.
    Senator Landrieu. Thank you, Senator. I appreciate having 
the opportunity to just make a few comments, and I have a 
statement to submit for the record.
    Senator Thomas. Without objection.
    [The prepared statement of Senator Landrieu follows:]

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

    Today, we confront a dilemma similar to the one we discussed two 
weeks ago during our hearing on oil supply and prices.
    However, unlike two weeks ago we cannot blame these very high 
prices and tight supply on the prospect of war or another country's 
political chaos. The situation we are faced with today is entirely of 
our own doing--the rising price of natural gas and shortage of supply 
to meet a growing demand falls squarely on us.
    Much is at stake. For Example, in my state of Louisiana, where 
natural gas is plentiful and produced consistently, two industries that 
depend heavily on natural gas are paying the price for the high cost.
    Over the last four years, two thousand jobs have been lost in the 
ammonia industry in my state and nine companies have been reduced to 
five. For the chemical industry, natural gas accounts for more than 
half of its energy needs in the U.S. In fact, the chemical industry is 
second only to electric utilities in domestic natural gas consumption.
    What does the high price of natural gas mean for the chemical 
industry? Well, recently one company moved more than 750 million pounds 
of ethylene production from Plaquemine, Louisiana to Germany. A 
Disconcerting omen indeed.
    Currently, we produce about 84% of the natural gas we consume. But 
there is a gap between supply and demand that is looming on the 
horizon. The Energy Information Administration is projecting domestic 
production of natural gas to grow by 1.3% per year while demand is 
expected to grow by 1.8% annually. By 2025, EIA Projects that imports 
of natural gas will provide 22% of demand. quite simply, we are facing 
the prospect of our natural gas market following in the footsteps of 
our oil market where imports continue to account for a growing 
percentage of supply.
    The ``Catch-22'' we find ourselves in, while obvious, will require 
some tough choices to solve the problem. Do we want to continue to make 
natural gas the fuel of choice for sectors such as electricity? What 
about providing tax incentives to develop unconventional sources such 
as coalbed methane or deep water drilling? While I support a number of 
these incentives are they alone the answer? What about the construction 
of a pipeline to transport what are anticipated to be vast reserves in 
Alaska's North Slope to the lower 48 states. Can we accomplish this 
feat without disrupting the natural gas market?
    Is it time to revisit areas of the country currently under 
moratoria?
    Two years ago, I, Along with the ranking member of this committee, 
led a fight to stop the current administration (Bush) from reducing the 
area of a lease sale in the eastern Gulf of Mexico--Lease Sale 181--
that had already been approved by the administration (Clinton) before 
it and could have provided as much as 8 TCF of natural gas for the 
country. In fact, the area was reduced to such an extent that on only 
1/8 of that natural gas is now available. While it is fine for states 
to determine they do not want natural gas production off their shores, 
it is hypocritical for them to continue to rely on natural gas produced 
off the shores of other states for their supply without making any 
sacrifice.
    With less and less areas available for production, and the 
deepwaters of the Gulf of Mexico still a hotspot for the foreseeable 
future, it is time for Congress and the Federal Government to recognize 
the importance of the development that has been occurring and continues 
to take place off the shores of Louisiana and Texas. The OCS currently 
supplies 25% of the nation's natural gas and in FY 2001, 80% of the gas 
produced on the OCS came from leases located offshore Louisiana--and 
compensate those states for their role in providing the nation's energy 
supply.
    Another question to consider is are we willing to reduce our demand 
for natural gas and turn to other sources of energy to generate 
electricity such as nuclear power? While one day I hope we can turn to 
renewable sources of energy to satisfy our demand it does not appear 
that we are there yet.
    Finally, if we do nothing and demand continues to surpass supply we 
will inevitably end up increasing our supply of imported natural gas or 
LNG. While most of the gas we import today comes via pipeline from 
Canada, the EIA Estimates that half of the increase in U.S. imports 
will come from LNG. Already we have three LNG terminals in the country, 
with one located in Lake Charles, Louisiana, and two more on the way to 
receive gas from countries such as Trinidad and Tobago, Qatar, Algeria, 
Nigeria, Oman, Indonesia and the United Arab Emirates.
    I look forward to the testimony of the witnesses as well as my 
colleagues on the committee. I hope we are all up to the challenge 
before us as doing nothing is not a choice.

    Senator Landrieu. But just to go over a couple of points by 
way of a question, all of you mentioned this to some degree, 
but for the record, would each of you just repeat what are the 
more promising areas of natural gas exploration in the country 
today, and maybe you could list them in your top 1, 2, and 3, 
and as you answer that, would you specifically talk about lease 
sale 181 in the gulf?
    Mr. Rattie.
    Mr. Rattie. The most promising area for natural gas 
development in the country is Alaska. We have enormous 
resources up there that are underutilized, and I think 
everybody on this panel and I think everybody in the industry 
would strongly support any effort to try to facilitate the 
development of a pipeline that would bring those supplies down 
to the lower 48.
    In addition to Alaska, the Rocky Mountain region is by far 
the most underdeveloped and under-exploited region in the 
country. We have seen significant supply growth in the last 3 
years, as I talked about earlier, but we have not really 
scratched the surface there yet. There is a lot of known 
sedimentary section below 15,000 feet that has not been drilled 
and tested. We are going to find a lot of gas in the Rockies, 
but we are going to have to get the gas out of the Rockies to 
where the markets are, the Midwest and the West, in order to 
take advantage of that abundant supply.
    And then, of course, the Gulf Coast, Texas, Louisiana, and 
the Gulf of Mexico continue to be very important. There is an 
interesting phenomena there, though that the Outer Continental 
Shelf in the Gulf of Mexico historically has been one of the 
largest producing supply basins in this country. The shelf is 
tired, and producers there are having a hard time even keeping 
production flat. In fact, it is declining.
    The Deepwater, as I think the gentleman from BP mentioned, 
has turned out to be predominantly an oil play, and there is a 
lot of associated gas, and there is a lot more exploration that 
has to be done in the Deepwater, but so far it has turned out 
to be very oily.
    And then there is this broad category of what is called 
unconventional gas that we have only begun to tap in the last 
decade. I mentioned the Powder River Basin in Wyoming, the San 
Juan Basin in the Four Corners area, New Mexico. We are looking 
at coal-based methane development in other areas of the Rockies 
that show a lot of promise right now, and those plays 
benefitted significantly in the past from a little bit of a 
boost from section 29 tax credits, and I would submit that that 
would be a prudent policy to carry forward to keep that--to 
continue to incentivize the development of those new sources.
    Senator Landrieu. But are you saying, just for the record, 
because it is contrary to what I understand, and maybe I am 
misinformed, but that Lease Sale 181, which is predominantly a 
gas field in the gulf, is tired, because that would be shocking 
because they have not drilled there.
    Mr. Rattie. No. I am saying the traditional development 
areas of the Outer Continental Shelf in shallow waters up to 
200 feet off the coast of primarily Louisiana, Texas, a little 
bit of Alabama, but Lease Sale 181 is a great example of an 
area that we have to find a way to let the industry evaluate 
the resource potential there. There are enormous amounts of 
natural gas likely to be found that can be developed in deeper 
waters, and in waters in the Eastern Gulf of Mexico, which have 
been relatively under-evaluated.
    Senator Landrieu. Mr. Best.
    Mr. Best. Senator, since we are not in the E&P business, I 
defer to Mr. Rattie and Mr. Welch, but I will agree with them 
that what Mr. Rattie said in Alaska and Rocky Mountains and 
offshore Louisiana and Texas, that what we see from a 
distribution company standpoint are the best provinces.
    Senator Landrieu. What about Mississippi, Alabama, Florida? 
There is not any gas off of those coasts?
    Mr. Best. Well, in Alabama there certainly has been some 
coal seam methane gas which has been found and developed, and 
is still being developed, and I think off of Mississippi there 
is some development going on, off of Alabama in the Mobile Bay 
area there has been some findings, but I think the three best 
provinces are still the three that Mr. Rattie mentioned.
    Senator Landrieu. Okay.
    Mr. Welch.
    Mr. Welch. Yes, Senator, I would have to agree that Alaska, 
Rocky Mountains, of the currently accessible areas are 
certainly the big two, and the third one, rather than, say, 
Gulf of Mexico, which we have a big presence in the gulf. We 
are the biggest player in Deepwater, actually. I would have to 
say it is actually LNG, which is not, I know, a domestic 
source, but it is the thing that will give us the greatest 
flexibility with respect to maintaining stability in the 
market. You can never underestimate what the Gulf of Mexico 
might do.
    As you know, Sale 181 was curtailed in the acreage, which 
was open for bidding there. What lies off the coast of Florida 
is really an unknown at this point, as are the east and west 
coast of the United States, so we have focused all of our 
effort and study on the areas that we can get at.
    Senator Landrieu. Mr. Caruso.
    Mr. Caruso. In our long-term supply outlook, the three 
largest suppliers are Alaska, as already mentioned, the 
unconventional natural gas in tight sandstone formations in the 
Rocky Mountains, and the Gulf of Mexico. Those are the three 
largest. I do not have any specific information on the Lease 
Sale 181 area.
    Senator Landrieu. Well, the reason I bring that up, 
obviously, is, as a State that produces a tremendous amount of 
natural gas, and we are proud of that production, and we 
believe that it contributes greatly to the national security of 
this Nation, because we are open to production. We are proud of 
doing it in a more and more environmentally friendly way, using 
the new technologies that are available.
    But one of the dilemmas that I find in this discussion is 
that because there are certain areas that have been explored 
more fully, and because even the just preliminary discoveries 
or exploration is prohibited in so many areas, we are not 
really getting an accurate picture of what some of these 
reserves could potentially be, whether it is oil reserves or 
gas reserves.
    In this hearing we are focused on gas, and unlike last 
week, when we had a hearing which was very helpful about the 
price of oil and the tightening of markets, and we basically 
addressed the issue of it being a world price, and we had 
limited control. We do have more control over gas than we do of 
the oil price, because it is our own market, and by opening up 
regions in this country in the appropriate ways, by building 
infrastructure for liquified natural gas, by opening up Alaska. 
We could really help to increase supply to stabilize these 
prices.
    I just want to say for the record, Mr. Chairman, that while 
some people might think, well, Senator Landrieu and Senator 
Breaux would be happy because the price is high, I want to 
agree with these panelists, it does not help us when the price 
is too high. My chemical industry is hurting, my manufacturers 
are hurting, my farmers are hurting, our agricultural interests 
are hurting, and just because we are a producer, it is not in 
our short-term or long-term interest for the price to be this 
high and volatile, so I really hope that, as we struggle to put 
together another energy bill, we will again focus on these 
issues.
    And the final point I want to make is to just throw out a 
question that needs no answer, because I think it is obvious, 
or evident. What incentive is it for States like Alaska or 
Louisiana, or for the Rocky Mountain States to produce, if 
those counties or those parishes or those States do not 
directly benefit from the production?
    Now, you might say, well, you get the jobs, and you get the 
infrastructure. You know, we work--I do not know if you all 
work this way in the Rockies or in New Mexico, but our offshore 
oil workers work 7 days on and 7 days off. People come from all 
over the country to work on the rigs offshore of Louisiana, and 
they cash their paychecks on Friday. They do not always cash 
them in Louisiana. We pick up the cost for roads, the police, 
fire protection, evacuation, the infrastructure, and getting 
fresh water to everybody out in the gulf. We are happy to 
produce it, but we do not share in the royalties, because of 
the arcane, backward and unjust rules of this Nation, in any 
percentage of those offshore oil and gas revenues.
    Just in terms of fairness, counties and parishes should 
share in that production to compensate for the impacts, where 
there are some, to environmental sensitive areas, as well as 
just for the fairness of that issue. I would hope that this 
inequity would be addressed in our next energy bill.
    Thank you for your comments, and I hope we will be more 
aggressive in the development of our domestic production. Thank 
you.
    Senator Thomas. Senator Bingaman.
    Senator Bingaman. Thank you, Mr. Chairman. Let me ask a 
couple of other questions about LNG.
    Mr. Welch, you indicated that one of the things that is 
needed is more development of LNG as a way to guard against 
increased volatility and basically provide a buffer, as I 
understand it, to add to the base supply that we have.
    Mr. Caruso, in your testimony, as I understand it, you are 
estimating that there will be three LNG--additional LNG 
terminals constructed between now and 2025?
    Mr. Caruso. Yes.
    Senator Bingaman. That does not sound very promising to me. 
As I understand it, there were 16 announced proposals for new 
LNG import terminals to serve the U.S. market, but you are 
saying only three are going to be built in the next 22 years. 
Could you explain that?
    Mr. Caruso. Yes, Senator Bingaman. We have three additional 
LNG terminals in our long-term forecast for supply. An 
additional fourth one is expected to be built in Baja Mexico to 
serve exclusively the California market, so one could include 
it.
    In addition, we also project all four of the existing 
terminals would be expanded, so there is more than just the 
four new ones, so there is a total of 2 tcf of LNG assumed to 
be imported by 2025.
    Senator Bingaman. 2 tcf out of 35?
    Mr. Caruso. Yes, 6 percent.
    Senator Bingaman. So you are estimating that we will be 6 
percent dependent upon LNG for our natural gas needs by 2025?
    Mr. Caruso. That is correct.
    Senator Bingaman. That does not sound to me like that is 
going to be adequate for the needs that I have seen on some of 
these charts and some of the testimony I am hearing here. I do 
not know, maybe----
    Mr. Caruso. It is highly dependent on the price, and what 
happens in Alaska and the Mackenzie Delta.
    Senator Bingaman. It just seems like there is a disconnect. 
You have El Paso and Dynergy putting up their energy assets for 
sale, which I would think is an indication that they do not 
think the return is going to be there long-term, or short-term. 
We have the price of gas spiking to record highs. At least you 
do not believe that there are credible proposals to do a whole 
lot to expand our LNG capacity, or our capacity to bring in 
LNG. Is that a fair statement?
    Mr. Caruso. I think given the outlook we have for prices, 
that is the balance between the new sources we see, that Alaska 
would come on, the Mackenzie Delta would come on, so there is a 
balance, a mixture of these new sources. LNG for the new 
terminals would require a higher price, for example, than 
Alaska. We have about a $3.50 price that we think would 
incentivize the Alaska line, for example, but a new LNG 
terminal in New England would be about $4.10, so it is a bit 
more expensive.
    Senator Bingaman. Do you have any thoughts on this, Mr. 
Welch, as to whether you think this is a reasonable forecast of 
what is going to happen in the LNG area?
    Mr. Welch. Let me just say that I think we have a little 
more bearish view of what the traditional basins will be able 
to supply than the EIA. I think from hearing Mr. Caruso's 
testimony, the EIA feels like they will be able to be flat, or 
actually grow from existing supply basins. My belief is that 
these older basins, which some of them we have been in for 50 
or 90 years, are going to continue to decline. Therefore, we 
would see a higher need for LNG terminals, even with these 
other large sources of gas coming in.
    I think the figures are that there is about, as soon as 
this fourth LNG facility comes online in the next quarter, 
there will be capacity for about 2 billion cubic feet of LNG 
coming into the country as of this year. Expansion of those 
four could get you to 4 billion cubic feet, and there are, as 
you mentioned, a number of proposals.
    BP in particular, we are engaged in looking at two 
proposals right now which we feel have commercial viability, 
and I am sure others do, so I think--we would believe that it 
might be a little more aggressive, and the reason for our 
belief that we would need to be more aggressive on LNG is the 
fact that we think these existing supply basins are declining a 
little bit more rapidly than the EIA is forecasting.
    Senator Bingaman. I just would indicate that I was talking 
to the head of the BLM field office there in San Juan Basin 
last year, and he was indicating that they expect to drill, I 
think, 12,000 new wells over the next 15 years, but he 
indicated also that based on their estimates, they believe that 
the production in the San Juan Basin of natural gas, coal 
methane gas peaked 2 years ago and will be declining from now 
on, even with the drilling of 12,000 additional wells.
    Mr. Welch. Senator, could I make one more point that I 
think would back up what you are hearing there? I would refer 
to my chart my colleagues have just put up, and what it shows 
on the left side there is the North American Basin cycle, and 
this particular one happens to be from the Gulf of Mexico, but 
if you look at any existing basin that we have been in for a 
long time, this is the trend you will see.
    In 1950, when the first offshore wells were drilled, the 
average size of discovery that we were making was around 2,000 
billion cubic feet. We found the biggest fields first. That is 
what you look for. Those are the easiest to find. Over time, 
the incremental reserves added per field gets smaller and 
smaller. Presently, we are finding only 10 to 15 billion cubic 
feet per field, so you would have to have an awful lot of 
fields to make up for one field that you would have back in the 
old days.
    If you look at the slide on the right, you see the 
fundamental underlying decline rate from individual wells 
within a given basin, and you are seeing that wells that were 
drilled before 1994 in this particular chart show a flatter 
decline than those that have been drilled in 1998, and it is 
even steeper today. The reason for that is two-fold. One, we 
are drilling these wells in these smaller and smaller fields, 
and secondly the technology that we have in the oil and gas 
industry with respect to completions and well bore technology 
is incredibly advanced over where it was 10 years ago.
    Today, we are able to produce a well that used to get 1 
million cubic feet a day production, we can produce 20, so if 
you combine the fact that we are getting it out faster with the 
fact that there is less there, that is why you see increasing 
declines, and why, even though more and more wells are being 
drilled, the total output is not as great.
    Senator Bingaman. That is very helpful. Thank you.
    Senator Thomas. This morning, we had a hearing with the 
Secretary talking about the budget and the money that is in 
there for enhanced recovery of oil, and the science and the 
research that can be done. Is there a potential here for having 
new techniques to recover gas?
    Mr. Rattie.
    Mr. Rattie. The answer is yes, Senator, and, in fact, 
advances in technology have been the lifeblood of this industry 
since its inception.
    I would like to comment just a little bit before I go to 
the technology issue, and I will make this connection as 
quickly as I can, but I recall back in 1976, when I was 
considering an opportunity to come into this industry or 
another one, there was a full page ad in the Wall Street 
Journal. It had a picture of a baby crying and the caption 
said, by the time this baby gets out of the eighth grade, 
America will be out of oil and gas.
    Well, eighth grade would have come about 1988 for that 
child, and obviously we are not out of oil and gas. Advances in 
technology have continued to extend the resource base. We have 
produced over 500 trillion cubic feet of gas in this country 
since that article was written, and we have found more than 
500. We have significantly grown the resource base, so I would 
not write off the industry in terms of its ability to develop 
the supplies that this country needs going forward.
    Now, let me comment on research. This is an area that ought 
to be of concern for policymakers. Research used to be done by 
the companies, the bigger companies in particular. Belt-
tightening and cost control have virtually eliminated the R&D 
effort. It now falls on the shoulders of the DOE and industry 
groups like Gas Technology Institute to do the collaborative 
research to evaluate some of these new technologies. It is 
important. We should continue to expect that advances in 
technology will help us get more out of our resource base.
    Senator Thomas. It seems sometimes kind of interesting that 
demand has gone up, from time to time the price has gone up, 
but the number of rigs has not gone up as much, and now it is 
high prices. How do you account for the fact that there seems 
to be more demand, very clearly, and yet the number of rigs 
does not go up?
    Mr. Welch. I will take a stab at that, Mr. Thomas. In fact, 
I spoke about it in my testimony before you were able to come 
in, but if you look at the 2000-01 price spike which is shown 
on this blue curve at the bottom there, you will see the green 
curve is the rig count, and the rig count actually doubled when 
prices spiked in 2001. We are seeing the rig count go up 
slightly now, but not nearly as significantly as it did, and 
part of it is because of the phenomenon I just described.
    People put a lot of money out drilling these wells, and 
what we are finding is a decreasing marginal return on the 
investment, so it is indicating to me that the prospects in 
these older basins are becoming more and more marginal, and the 
real key to unlocking additional gas supplies is to get some of 
these areas where we need infrastructure in the Rockies, where 
we need a big pipe from Alaska, and where we need a Canadian 
frontier gas pipeline to connect us to the Canadian markets.
    Senator Thomas. Take home from the wellhead in some of the 
methane gas wells has varied from less than $1 to over $5. I 
think that has something to do with the rig count, does it not?
    Mr. Welch. Absolutely, and as you pointed out earlier, in 
that particular basin, the big issue is the transportation 
bottleneck, so you are getting gas-on-gas competition. People 
are just competing to get into the pipe. If you had an adequate 
take-away, you would expect those differentials and that 
volatility would be mitigated significantly.
    Senator Thomas. Well, it is a big problem, gentlemen, and I 
hope that we can--I am for having the marketplace be the major 
thing here, but we do have to have some policy, and I hope we 
can come up with some policy, whether it is gas, whether it is 
conservation, whether it is alternatives. Some even would 
suggest that, since gas is as useful in a variety of ways, that 
we ought to have more of our energy, electric energy being 
generated with nuclear or coal.
    I understand the reason why they are having smaller 
generation plants closer to the market, rather than 2,000 
megawatt plants that have to go quite a ways, but these are 
some of the kinds of policy things I think if we look ahead--
and I appreciate what you all have said today. We do need to 
look ahead, because we know we will have to know what we are 
going to be doing 10 or 15 years from now.
    So thank you so very much for coming. There may be some 
questions that will be submitted later, but we appreciate your 
being here. The committee is adjourned.
    [Whereupon, at 3:35 p.m., the hearing was adjourned.]


                               APPENDIXES

                              ----------                              


                               Appendix I

                   Responses to Additional Questions

                              ----------                              

                                      BP Alaska-Canada Gas,
                               Calgary, AB, Canada, March 17, 2003.
Mr. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Mr. Domenici: In response to your letter of February 28, 2003, 
I am pleased to have the opportunity to address the questions raised by 
you and members of your committee following my testimony on February 
25, 2003.
    Please find enclosed our response to these questions. We stand 
ready to working further with your committee on this very important 
subject.
            Sincerely
                                               David Welch,
                                                         President.

                        Responses of David Welch

    Question 1. It is my understanding that federal lands hold 80% of 
U.S. oil reserves and estimated 57% of gas reserves. A recent study 
produced by the Department of Interior and the Department of Energy 
evaluated the existing barriers to developing resources on federal 
land. The study found that 60% of the reserves located in the 5 western 
basins were available with standard restrictions. What is your opinion 
of this study and does it accurately reflect the challenges posed to 
producers? Do you believe these reserves can be counted on to respond 
in a timely fashion to future supply constraints like we have today? 
What can be done to improve access for gas pipelines on our federal 
lands in order to serve new gas production? What policy changes would 
you recommend?
    Answer. Let me clarify by saying that I believe your question 
refers to undiscovered resources rather than proven reserves. While we 
have not conducted an independent study of restrictions on federal 
lands, the 1999 NPC study on North American gas seems to corroborate 
the estimate mentioned in the question. Specifically, the NPC study 
quoted that of estimated remaining resources (which includes both 
proved reserves and undiscovered resources) 59% are on lands with 
standard leasing restrictions, 32% are on lands with restrictions that 
could result in significant time delays and higher drilling costs, and 
9% are completely inaccessible.
    There are significant challenges to bringing on new supply even 
from the federal leases that have only standard restrictions. The 
supply sources from the western basins will tend to involve higher 
costs of development due to location and the need for significant new 
supporting infrastructure. Long lead times required for pipeline 
construction will tend to delay availability of these gas supplies. 
Collectively, these factors will tend to constrain the pace of gas 
supply growth from the western region.
    Question 1b. It is my understanding that BLM and the Forest Service 
proposed a change to the valuation of pipeline Rights-of-Way fees. This 
proposal would have done away with the existing traditional linear fee 
rent method, in exchange for a method that would value the throughput 
in assessing the fee. What impact would this have on pipeline fees?
    Answer. The existing methodology (valuation of pipeline Rights-of-
Way fees) is preferred since it is well understood and lends itself to 
periodic review, if necessary. The throughput methodology adds costs to 
a pipeline that increasing the tariff, which in turn increases the cost 
to the consumer. It also adds a level of variability and hence 
confusion to the market, because as production changes due to plants 
going down, etc. the tariff would also change.
    Question 2. It is estimated that over 50% of our natural gas 
supplies lie under federal lands. I have heard from a number of 
producers who have been frustrated by the difficult and slow process in 
receiving access to federal lands. What has been the experience of 
pipeline companies in dealing with federal land managers? What do you 
recommend to improve this situation?
    Answer. Securing federal access for gas pipeline projects requires 
significant regulatory processes, such as Environmental Impact 
Assessments, to be addressed before access may be granted. These 
processes can, at times, overwhelm Federal land managers, leading to 
delays in permitting. Expeditious processes have been achieved on those 
projects where federal and state regulators have shared scarce 
resources by dividing the work efforts and by working closely with the 
entities involved. Dedicating a land manager to a large project, and 
making that person part of the project team, especially during critical 
stages of the project has also helped situations in the past.
    Question 2b. There have been concerns regarding the price disparity 
of natural gas at the wellhead in the Rocky Mountains versus what is 
being charged at certain delivery points in the Midwest and East. It is 
my understanding that the lack of available pipeline capacity has 
contributed to higher prices. How widespread is this problem and where 
does this problem exist? What can be done to improve gas delivery?
    Answer. As you surmise, the current lack of pipeline take-away 
capacity from the Rockies and San Juan basins has depressed Rockies and 
San Juan prices relative to Henry Hub and other markets further east. 
However, regional pipeline expansions have been proposed to help 
alleviate the situation. One in particular, the Kern River pipeline 
expansion which is due to be in service this summer, should help to 
ease constraints in a portion of the Rockies basin. The end result of 
adding more take-away capacity will be to better connect Rockies and 
San Juan gas supply to the North American market, narrowing 
differentials relative to other market hubs, and ensuring supply of gas 
to where it is most needed. In the same way an Alaska Gas pipeline 
would connect that `stranded' gas resource to the North American 
market.
    Question 3. Although the LIHEAP program is not within the 
jurisdiction of this committee, I am concerned about the impact the 
recent price spike will have on low-income consumers. Obviously, higher 
prices and the forecast for additional cold weather will put pressure 
on this program. Do you believe we could be more effective in making 
gas prices affordable by providing resources through LIHEAP or to 
provide incentives to increase production to relieve the supply 
constraints? What steps are American Gas Association member companies 
taking to help low-income consumers conserve energy?
    Answer. As a producing company, our efforts are focused on 
developing new supplies of natural gas for North American consumers. To 
the extent that more of a commodity is available at any given level of 
demand, the price for that commodity will be reduced. Therefore, 
accessing new gas supplies that can be competitively delivered to the 
gas pipeline grid will be helpful to all North American consumers of 
natural gas. U.S. energy prices will always be subject to regional 
factors such as the extremes in weather recently experienced along the 
eastern seaboard. However, the peaks in demand created by these 
regional events, along with the associated price volatility, could be 
mitigated by increased access to supplies, such as Alaska and LNG. For 
example, LNG is the most fungible worldwide natural gas supply and 
increasing the number of LNG re-gasification terminals in the U.S. 
would be a way to help meet the increasing demand as well as directly 
addressing the price volatility that arises from regional events.
    Question 4. EIA recently announced that U.S. gas production in 2002 
fell by 2.3%. I understand the energy analysts such as CERA and EEA are 
predicting a further decline in 2003. Why is this occurring at a time 
when our natural gas inventories are low and prices are high? What 
financial challenges make it difficult to grow supply? Will the short-
term capital crisis have long term effects on supply and 
infrastructure? Have the mergers and acquisitions that have taken place 
in recent years contributed in any way to lower drilling levels?
    Answer. A lack of significant response in U.S. gas drilling 
activity as a result of recent high prices is the major reason why many 
third party energy analysts are predicting declining U.S. supply 
through 2003. Although gas prices have increased from $US 4.00-6.00/
MMBtu since the spring of 2002, U.S. gas rig activity has averaged only 
between 700-750 over that same time period. Due to time lags between 
drilling and production, no material increase in supply is expected 
later this year because of currently stagnated drilling activity. As a 
result, natural decline rates within existing basins will prevail, 
resulting in a decrease in production throughout 2003.
    The lack of rig response to the price increase has been due to a 
number of factors. First and foremost, producers are citing ``a lack of 
quality prospects'' as the main reason for limited exploration and 
production (E&P) activity; maturing traditional basins (such as 
Permian/Mid-continent) coupled with restricted land access rights to 
new supply areas (especially in the West) are resulting in fewer and 
smaller prospects for new exploration. Increased drilling activity 
during the previous price spike in 2000-1 yielded minimal additional 
prospects. Second, a number of financial and structural challenges have 
caused major E&P companies to reduce their 2003 capital budgets. The 
current investment climate has prompted many companies to allocate 
money to consolidating balance sheets and paying down debt as opposed 
to investing in new capital projects. Within the reduced capital 
environment, many global companies are choosing to spend capital 
dollars on investments where superior prospects or fiscal environment 
make investment more attractive. Finally, producers are concerned about 
the volatility in North American gas prices. A similar boom/bust cycle 
was witnessed in late 2000/early 2001; the sudden increase in prices 
followed by a severe price collapse at that time has led to speculation 
regarding the sustainability of current market prices.
    Increasing exploration and production capital spending coupled with 
new pipeline infrastructure is required to ensure adequate supply is 
available to meet future demand. The short-term capital concerns will 
result in fewer companies stepping up to sponsor these new projects, on 
both the customer and the supplier end. Turmoil in the energy merchant 
sector has had a negative impact on many corporate balance sheets, 
including E&P companies as well as the parent companies of many 
prominent gas transmission firms. As a result, producers are spending 
their money to consolidate balance sheets (as mentioned earlier) while 
marketing firms and end-users (such as local distribution companies, 
industrials and power generators) have less of an appetite to sign 
long-term firm contracts to support new pipeline projects. Finally, 
pipeline companies are also dealing with solvency issues; meaning less 
capital is available to develop new pipeline projects. Due to the long 
lead times associated with major E&P and pipeline projects, a delay in 
development right now will result in a delay in new supply or 
infrastructure available over the long-term.
    A record amount of merger and acquisition activity has taken place 
over the past few years. These new companies have consolidated assets 
as well as balance sheets, and revisited capital expenditure programs 
to ensure new company goals will be achieved. We believe that as merger 
and acquisition activity slows down and as balance sheets are shored 
up, drilling and production could become more of a focus for companies.
    Question 5. Canada is our largest source of imported natural gas 
(15% of our total consumption). What are short term and long-term 
projects for Canadian supply and exports to the U.S.? What are the 
prospects for a pipeline from the Mackenzie Delta? How much of the gas 
from the Mackenzie Delta is likely to be used in Canada for the 
production of Alberta Oil Sands?
    Answer. According to preliminary results from its recent supply and 
demand study, the National Energy Board (NEB) states that Canadian 
deliverability (which consists primarily of the Western Canadian 
Sedimentary Basin or WCSB and the East Coast of Nova Scotia) will 
remain relatively flat to slightly increasing over the short-term. The 
NEB's view of long-term Canadian deliverability differs depending on 
two major scenario drivers: technological development and action on the 
environment. In its ``Supply Push'' scenario, characterized by a low 
pace of technological development and low action on the environment, 
Canadian deliverability is expected to peak in 2010, and decline 
steadily thereafter. Conversely, in its ``Techno Vert'' scenario, 
characterized by a high pace of technological development and high 
action on the environment, Canadian deliverability is expected to 
increase steadily over the long-term. Overall, the pace of 
technological development in the E&P business will play a major role in 
enhancing future Canadian deliverability.
    A consortium of Mackenzie Valley producers, led by Imperial Oil, is 
currently proposing to build a 1.2 Bcfd pipeline from the Mackenzie 
Valley area to interconnect with existing infrastructure within 
Alberta. The Mackenzie Valley Pipeline is expected to begin operations 
in 2008, at least three years ahead of any Alaska gas pipeline. Once in 
Alberta, a large portion of the Mackenzie Valley gas will be used to 
satisfy growing demand in Alberta's oil sands business as well as 
overall Canadian demand.
    Question 6. According to a study by the NPC, increased U.S. natural 
gas consumption will require significant investment in new pipelines 
and other natural gas infrastructure--$1.5 trillion over the next 15 
years. However, the current level of volatility in natural gas markets 
(prices swinging from $2.50 to $10 mmbtu), has discouraged many 
companies from committing to such long-term investments. In some cases, 
they cannot get financing. Where are the areas of greatest demand 
growth in the U.S.? Where are the areas of greatest supply growth? Is 
the pipeline infrastructure that currently exists adequate to move the 
gas where it needs to go to satisfy the market's supply/demand balance? 
What does this mean for the current system that we are so heavily 
dependent upon? What is the minimum level of investment necessary to 
insure adequate capacity, and how can we best achieve this?
    Answer. The greatest area of U.S. demand growth is expected in the 
power generation sector, particularly in the Midwest, South Atlantic 
and Northeast regions of the country. In contrast, the greatest areas 
of traditional and frontier supply growth include the Rocky Mountains, 
the deepwater Gulf of Mexico, Canada and Alaska. Given the geographic 
disparity between growing supply sources and growing demand markets, 
more pipeline infrastructure will be required to ensure that future 
supply can access growing demand. The existing U.S. pipeline system is 
aging, and, as stated in the recently passed pipeline bill, ongoing 
investment will be required over the long-term to ensure public safety 
concerns are addressed. Above and beyond this, numerous infrastructure 
proposals are currently under development across the country, although 
it is unclear at this point just how much new capacity will ultimately 
be required.
    In the short-term, gas price volatility will continue to increase 
as concerns over supply and long-term infrastructure development 
persist. However, the market has demonstrated an ability to balance 
supply and demand consistently over time. Continued rationalization in 
the energy merchant sector will help restore investor confidence and 
boost investment capital. Plus, ongoing communication between market 
participants and regulators will ensure adequate price transparency in 
the market as well as a streamlined process for future infrastructure 
development.
    Question 7. Last Congress, as part of the energy bill, I worked on 
provisions intended to streamline the FERC process for granting a 
certificate for an Alaska natural gas pipeline and to provide some 
financial incentives to expedite construction. The EIA reviewed the 
provisions of the Senate Energy bill. The analysis indicated that the 
energy bill provisions would result in natural gas reaching consumers 
earlier than otherwise (i.e. between 2014 and 2020 instead of after 
2020) and could reduce the cost of natural gas by up to $0.32 an mcf.
    Answer. We applaud the efforts of the last Congress to develop 
comprehensive energy legislation and for the inclusion of Alaska gas 
regulatory and fiscal provisions. As new energy legislation is 
considered, BP encourages the current Congress to capitalize on these 
past efforts and stands ready to inform this debate.
    As to price impacts from Alaska gas coming into the North American 
market; we believe the lead-time associated with a project of this 
scale will have a minimal long-term impact on natural gas prices. 
Furthermore, we believe an Alaska gas pipeline project will have a 
stabilizing effect on the North American natural gas market.
    Question 8. What is the time-line you foresee for an Alaska 
pipeline absent legislation and how would that change with the 
legislation?
    Answer. There are many examples of pipeline projects being delayed 
due to a lack of regulatory priority and clarity. What could be 
achieved within two years has in some instances taken five years or 
more, or projects have been ceased altogether.
    Absent the proposed regulatory and fiscal legislation, one result 
is crystal clear; a project will not move forward given current project 
economics, market dynamics and regulatory uncertainty. Without these 
provisions, I believe the project could be delayed, indefinitely.
    The best-case scenario for an Alaska gas pipeline project, if 
regulatory and fiscal measures are enacted this year, is for gas to 
begin flowing in late 2011 with full rampup to 4.5 bcf/day in early 
2012.
    Question 9. This morning I asked the Secretary of Energy what the 
Administration was doing to mitigate the impact of high-energy prices. 
His only concrete response was that they support the Low Income Home 
Energy Assistance Program. The reality of the LIHEAP program is that 
historic funding levels have never met the needs of all of the eligible 
low-income households in the U.S. I would add that if gas prices are 
going to remain at these high levels many middle class households will 
need assistance as well. Do you think it is time that we expanded 
LIHEAP funding to a new level? Do you support the level passed by the 
Senate last year in the Energy Bill ($3.4 billion per year)?
    Answer. Please refer to my comments following question 3.
    Question 10. Last Congress, as part of the energy bill, I worked on 
a provision that would have provided royalty relief for production of 
natural gas from marginal wells on federal lands. I am of the belief 
that it is crucial to keep marginal wells under production. Onshore oil 
and gas production from federal lands makes a significant contribution 
to our domestic energy supply. Would you support granting royalty 
relief for marginal gas production?
    Answer. As stated previously, we feel that the North American gas 
market will need all available sources of supply to meet future demand. 
Extending marginal well production is a positive step just as are other 
actions that encourage the development and importation of natural gas.
    Question 11. A recent report on LNG (University of Houston, 
Institute for Energy, Law and Enterprise) notes that 8 federal agencies 
have some regulatory role over LNG--with the Coast Guard, DOT and FERC 
having major roles and DOE playing a coordinating role. I understand 
that the FERC has recently updated its policy on LNG facilities. It may 
be too early to tell how this division of responsibilities is working, 
but do you care to comment on the various agency roles and how well 
they work together?
    Answer. BP believes new LNG supply will be needed to meet the 
growth in demand for natural gas in North America. We remain committed 
to working with the relevant federal and state agencies to secure new 
LNG supply for the nation and appreciate the constructive working 
relationship we believe we have with each one of these agencies.
    Question 12. How confident are we in our ability to collect data 
about the supply of natural gas? What amount do we think is being 
flared? Does the EIA have adequate funds to perform the data gathering 
tasks demanded?
    Answer. As the largest natural gas producer in North America, BP 
makes a concerted effort to understand its business and collect 
industry data to monitor natural gas supply and demand. This data is 
published annually in the ``BP Statistical Review of Energy'', 
available at www.bp.com. As a producer, we are aware and track flaring 
from our own fields, but cannot comment on the amount of gas flared by 
the entire industry. On that note, in 1998 BP set out to reduce its 
company-wide emissions to 10% below 1990 levels by 2010, and announced 
last year that it had achieved this goal, some 8 years early.
    Question 13. President's Energy Plan announced last March predicted 
that between 1300-1900 new power plants would need to be built to meet 
future energy demands. At the time, experts predicted a large 
percentage of these would be natural gas driven. Given the current 
volatility in natural gas markets, some fear that a large number of 
these plants will never be built. Instead, future electricity demands 
may in fact be met by large Midwestern coal plants which would be built 
using old, dirty technology. Do you agree with this? Does the current 
level of volatility discourage new gas fired generation from being 
built? Also, to what degree are delays in pipeline development perhaps 
leaving the door open for alternate fuels?
    Answer. Over the last three years, the U.S. has seen an 
unprecedented increase in generating capacity--the vast majority has 
been gas-fired. 2003 will continue to see significant new generating 
capacity additions as plants currently under construction are 
completed. Few, if any, coal-fired power plants are under construction 
due to the high capital costs and environmental constraints. As a 
result of the increase in generating capacity over the last three 
years, generating reserve margins (unused available capacity) have 
increased rapidly as capacity additions have outstripped demand growth.
    Current high gas prices are partly a product of high oil prices. 
Lower oil prices would see gas prices moderate as a result of inter-
fuel competition. In addition, the current price volatility reflects a 
market in transition from a long period of over supply. In the longer 
term, the equilibrium price is likely to be at a lower level than 
today's prices. There is plenty of economic gas supply available at 
prices that would allow gas to compete effectively with new-build coal 
fired-plan, including gas from Alaska, the Rockies and LNG.
    Current, high and volatile gas prices and high reserve margins are 
resulting in a number of proposed power plant projects being postponed 
or withdrawn. However, given the capacity additions already in place 
and under construction, the vast majority of incremental power demand 
over the next decade will be supplied by gas-fired power plant.
    Pipeline investment is driven by market signals--when the 
differential between pricing points indicates the demand for additional 
pipeline capacity. In this way, pipeline investment has historically 
been made according to market demand and there is no indication that 
this process has disadvantaged gas.
    No one, including producers, likes high prices or price volatility 
because they do not produce market dynamics conducive to predictable 
investment.
    Question 14. What is the role of natural gas storage in North 
America and how is this changing?
    Answer. The role of natural gas storage in the North American 
market is to balance supply and demand during peak times (namely the 
winter heating season). A typical reservoir storage facility injects 
gas into the reservoir during the summer months (April to October) and 
withdraws gas to meet demand in the winter months (November to March). 
Local distribution companies and pipeline companies use storage to 
balance customer demand as well as to maintain the operational 
integrity of their respective systems. The emergence of increased power 
generation demand for gas during the peak summer months has resulted in 
an increased need for high deliverability storage. Customers are 
interested in more cycles per year as well as higher peak 
deliverability, which have renewed focus on salt dome storage 
development. New capital investment from non-traditional storage 
operators has been an important source of new infrastructure 
development.
    Question 15. The United States is currently facing low levels of 
gas inventories. Given this, do you think we need to tap into new 
sources of gas such as the Alaskan gas reserves and liquefied natural 
gas (LNG)? What do you think is the best source for new inventories of 
natural gas?
    Answer. Yes, all new sources of supply including Alaska, the 
Rockies and LNG will be needed to meet the growth in North American 
demand for natural gas. LNG will provide ``peakloading'' to reduce 
volatility during times of exceptional demand.
    Alaska clearly offers the largest domestic source of new supply to 
meet projected demand and for that reason we believe it should be given 
sufficient consideration. New LNG receiving terminals and Rockies 
development will provide smaller, incremental volumes.
    Question 16. How should the United States work with Canada and 
Mexico to ensure we increase our gas supply at competitive prices?
    Answer. The U.S. government, through the Department of State, has a 
regular and ongoing energy dialogue with the governments of Canada and 
Mexico where the participants collectively examine North American 
energy needs. This forum is intended to establish a common 
understanding of continental energy needs. We encourage the U.S. 
Government to continue these engagements and to consider a special 
session dedicated to natural gas supply issues. Close cooperation with 
Canada and Mexico is essential to fostering new sources of gas supply 
such as frontier gas in Alaska and Canada and LNG.
    Question 17. How will construction of the Alaska Natural Gas 
Pipeline affect Kentucky? How much gas is it expected to provide the 
United States as a whole?
    Answer. Energy consumers in the state of Kentucky have typically 
enjoyed low energy prices owing to the presence of readily available 
energy resources such as coal. However, Kentucky currently consumes 
about two and one-half times the natural gas that it produces each 
year. And Kentucky is just one of thirty-eight states which are net 
consumers of natural gas. New sources of gas will be required as 
America's demand for inexpensive, clean-burning natural gas continues 
to grow.
    An Alaska gas pipeline will provide benefits to Kentuckians beyond 
just improving the nations energy supply situation. Kentucky, as one of 
the top four auto producers in the nation, will be in prime position to 
capitalize on the light truck (~1300) and heavy duty vehicle (~1000) 
supply opportunities created by the Alaska gas pipeline project. Among 
new business opportunities for Kentucky's manufacturing sector could 
include manufacture of pipe laying equipment (~$900 million 
opportunity).
                                 ______
                                 
                                  American Gas Association,
                                    Washington, DC, March 17, 2003.
Hon. Pete Domenici,
Chairman, Senate Energy and Natural Resources Committee, Dirksen Senate 
        Office Building, Washington, DC.
    Dear Mr. Chairman: Thank you for the opportunity to appear before 
the Senate Committee on Energy and Natural Resources on February 25, 
2003 to give testimony regarding natural gas supply and prices.
    Enclosed please find our answers to the questions that were 
submitted subsequent to the hearing.
            Sincerely,
                                   Robert W. Best,
                                           Chairman, President and CEO
                                           Atmos Energy Corporation.

              Responses to Questions From Senator Domenici

    Question 1a. It is my understanding that federal lands hold 80% of 
U.S. oil reserves and estimated 57% of gas reserves. A recent study 
produced by the Department of Interior and the Department of Energy 
evaluated the existing barriers to developing resources on federal 
land. The study found that 60 percent of the reserves located in the 5 
western basins were available with standard restrictions.
    Question 1b. What is your opinion of this study and does it 
accurately reflect the challenges posed to producers?
    Answer. I have no reason to believe that the study is inaccurate 
from a factual perspective. However, I think people have a tendency to 
view this glass as ``half full,'' and I am convinced it is ``half 
empty''. In a gas market as tight as we have today, restricting 40 
percent of the reserves beyond standard restrictions is devastating. 
When markets are tight even ``minor'' alterations in supply or demand 
can have dramatic impacts on price--a point evidenced this winter and 
in 2000-2001.
    I would also point out that standard restrictions do not imply no 
problems. Leases being worked in areas with standard restrictions are 
subject to a variety of constraints that could be reduced in an effort 
to streamline the process. We need to make it easier to get all of this 
gas to market more quickly, regardless of the DOI/DOE classification.
    Question 1c. Do you believe these reserves can be counted on to 
respond in a timely fashion to future supply constraints like we have 
today?
    Answer. I do not believe the situation gas consumers faced in 2000-
2001 and that they face today are acceptable. Prices are relatively 
high because supply is having trouble keeping pace with demand. I 
believe that gas can be produced in an environmentally sensitive 
fashion, and we must make it less cumbersome for producers to access 
reserves in order to respond to demand in a timely fashion. Today it is 
not possible.
    Question 1d. What can be done to improve access for gas pipelines 
on our federal lands in order to serve new gas production? What policy 
changes would you recommend?
    Answer. AGA member companies, particularly those in the West, have 
considerable experience in siting natural gas distribution lines and 
intrastate pipelines on federal lands. AGA has, over a period of years, 
also discussed these issues with other stakeholders in the industry. 
While siting infrastructure on federal lands has its own unique 
problems, they are merely a subset of the problems that are regularly 
faced in siting natural gas infrastructure in the United States 
generally. In broad-brush fashion, the difficulties are two-fold: (1) 
The multiplicity of federal, state, and municipal authorizations that 
are required to site natural gas infrastructure, in which duplicative 
information is regularly collected and in which consecutive, rather 
than concurrent, review processes are the norm. (2) The absence of 
binding time frames in which these reviews are to be completed.
    AGA has participated in two formal sets of discussions over the 
last several years addressing these issues. The first, which was 
sponsored jointly by the Interstate Oil and Gas Compact Commission and 
the National Association of Regulatory Utility Commissioners, resulted 
in a report dated July 2001 that addressed the types of difficulties 
that have been confronted and suggested several means to address them. 
A similar process was undertaken by energy industry stakeholders under 
the auspices of the Keystone Center in Colorado. That collaborative 
also produced a report dated March, 2002 addressing the difficulties 
involved and making policy recommendations. Copies of both reports are 
attached to these answers.*
---------------------------------------------------------------------------
    * The reports have been retained in committee files.
---------------------------------------------------------------------------
    Several months ago, FERC signed a memorandum of understanding with 
nine other federal agencies, including the Bureau of Land Management, 
the Fish and Wildlife Service, and the Environmental Protection Agency. 
The goal of the MOU is to make the permitting process less onerous for 
pipelines. These agencies have committed to review pipeline 
construction applications concurrently, rather than consecutively. This 
process has promise. AGA encourages Congress to encourage the 
signatories to this MOU to commit to this process, perhaps by codifying 
the MOU.
    Question 1e. Rights of Way--It is my understanding that BLM and the 
Forest Service proposed a change to the valuation of pipeline rights-
of-way fees. This proposal would have done away with the existing 
traditional linear fee rent method, in exchange for a method that would 
value the throughput in assessing the fee.
    Question 1f. What impact would this have on pipeline fees?
    Answer. I believe that the proposed change would significantly 
increase the cost of gas to the consumer and that this would be 
extremely unwise. A study prepared by the INGAA Foundation supports 
this conclusion.
    Question 2a. It is estimated that over 50 percent of natural gas 
supplies lie under federal lands. I have heard from a number of 
producers who have been frustrated by the difficult and slow process in 
receiving access to federal lands.
    Question 2b. What has been the experience of pipeline companies in 
dealing with federal land managers?
    Answer. The overriding complaint from both producers and pipelines 
with respect to federal land is that jurisdictions overlap, and dealing 
with multiple federal and state agencies is time consuming and 
expensive. Multiple permits are required for these projects, and 
guidance from the various agencies involved is often slow and sometimes 
contradictory.
    Question 2c. What do you recommend to improve this situation?
    Answer. In addition to the items cited in 1d above, one step in the 
right direction was the recently signed MOU between FERC and nine other 
federal agencies aimed at a more coordinated pipeline permitting 
process. We are hopeful but would encourage the Congress to ensure that 
the agencies do not retreat from the intent of this action. We would 
also like to see the relevant agencies pursue right-of-way corridors 
for pipeline projects that would allow for expedited approvals. If 
expedited approval was a reality in these corridors, pipelines would 
have an incentive to utilize them.
    Question 2d. There have been concerns regarding the price disparity 
of natural gas at the well head in the Rocky Mountains versus what is 
being charged at certain delivery points in the Midwest and East. It is 
my understanding that the lack of available pipeline capacity has 
contributed to higher prices.
    Question 2e. How widespread is this problem and where does it 
exist?
    Question 2f. What can be done to improve gas delivery?
    Answer. See the responses to 1d and 2c above.
    Question 3a. Although the LIHEAP program is not within the 
jurisdiction of this committee, I am concerned about the impact the 
recent price spike will have on low income consumers. Obviously, higher 
prices and the forecast of additional cold weather will put pressure on 
this program.
    Question 3b. Do you believe we could be more effective in making 
gas prices affordable by providing resources through LIHEAP or to 
provide incentives to increase production to relieve supply 
constraints.
    Answer. You correctly note that recent natural gas price levels 
will place pressure on the LIHEAP program. As I noted at the hearing 
before the Committee, most local distribution companies have hedged a 
portion of their gas supply, by injecting natural gas into storage in 
the summer, by entering into fixed-price gas purchase contracts, by 
purchasing futures contracts, or by using various financial 
instruments. Thus, current price increases for natural gas will tend to 
be moderated somewhat at the consumer level. Despite utility efforts to 
moderate price increases by portfolio purchasing and use of hedging, 
continuing higher natural gas prices inevitably show up in consumer 
bills. Inevitably, to one extent or another, higher prices will put 
pressure on the LIHEAP program. As you know, notwithstanding authorized 
and appropriated levels for LIHEAP, the funding available has not come 
close to meeting needs.
    AGA believes that the goal of affordable energy for all Americans, 
including low-income Americans, is best served by providing reasonable, 
targeted incentives to bring forth natural gas supply. Every dollar 
saved by low-income Americans on their energy bills translates directly 
into a dollar less needed for LIHEAP funding. AGA believes that 
Americans can save real, significant dollars through natural gas 
production incentives that are measured in cents rather than dollars. 
This is a good policy tradeoff for the nation, for the economy, and for 
low-income energy consumers as well.
    There will always be a need for LIHEAP protection of the low-income 
consumer. At the same time, production incentives can increase supplies 
and make gas more affordable for all consumers. LIHEAP protection is 
critical for the disadvantaged and necessary, while increased supplies 
are necessary to ensure reasonable prices, economic growth, 
environmental protection and the achievement of national energy 
security.
    Question 3c. What steps are American Gas Association member 
companies taking to help low income consumers conserve energy?
    Answer. AGA represents 191 local utilities, and the programs they 
offer are extensive and varied. Our members provide their customers 
with information on high-efficiency appliances and techniques to reduce 
energy consumption, they offer convenient financing for these 
appliances and weatherization programs, they fund related research and 
perform energy audits. According to the LIHEAP Clearinghouse, energy 
utilities spent $100 million in FY 2001 on customer weatherization 
programs. An indicator of the success of these programs is the fact 
that residential gas consumption per household decreased by 21 percent 
from 1980 through 2001 and commercial gas consumption per customer 
decreased by 18 percent from 1979 to 1999.

              Responses to Questions From Senator Bingaman

    Question 4a. EIA recently announced that U.S. gas production in 
2002 fell by 2.3%, I understand that energy analysts [such as CERA 
(Cambridge Energy Research Associates) and EEA (Energy and 
Environmental Analysis)] are predicting a further decline in 2003.
    Question 4b. Why is this occurring at a time when our natural gas 
inventories are low and prices are high?
    Answer. I believe producers are having a difficult time increasing 
production in mature fields. In order to increase supplies and develop 
a market more responsive to consumer needs we must look to new areas of 
supply and new forms of supply. We have relied on the same supply 
sources for decades and it is inevitable that production declines will 
occur. There has been some movement into the Rocky Mountains in terms 
of production, but a further migration is needed to deeper waters in 
the Gulf as well as to those areas where offshore access is currently 
denied. Additionally, gas from Alaska and in the form of imported LNG 
must be vigorously pursued.
    Question 4c. What financial challenges make it difficult to grow 
supply?
    Answer. A real difficulty in this industry is matching short-term 
and long-term needs. We must make investments today in order to meet 
demand years from now. Additionally, we must convince both lenders and 
regulators that the investments we are making are prudent and 
necessary.
    Question 4d. Will the short-term capital crisis have long-term 
effects on supply and infrastructure?
    Answer. In order to meet growing gas demand, hundreds of billions 
of dollars must be invested in production, transmission and 
distribution facilities. This is a very difficult proposition in light 
of current market conditions and economic uncertainty. Any actions that 
reduce risk, uncertainty and infrastructure construction time will 
reduce costs that are ultimately borne by the consumer.
    Question 4e. Have the mergers and acquisitions that have taken 
place in recent years contributed in any way to lower drilling levels?
    Answer. The producing sector would be in a better position to 
respond to this question.
    Question 5a. Canada is our largest source of imported natural gas 
(15% of our total consumption)
    Question 5b. What are short and long term projections for Canadian 
supply and exports to the U.S.?
    Answer. Canadian production faces many of the same hurdles as does 
U.S. production. In particular, production in mature areas of Western 
Canada has slowed similar to key producing areas in the U.S. However, 
the Canadians have been more proactive in allowing the development of 
non-traditional producing areas such as the offshore Atlantic and the 
Mackenzie Delta-Beaufort Sea areas. While it would not be wise to 
assume that Canadian successes will necessarily continue to satisfy 
growing U.S. demand, it would be wise to emulate their willingness to 
explore new production frontiers.
    Question 5c. How much of the gas from the Mackenzie Delta is likely 
to be used in Canada for the production of the Alberta oil sands?
    Answer. Many analysts believe that most of the gas from the 
Mackenzie Delta will be used for this purpose rather than for export to 
the U.S. However, I think that it is premature to conclude this--
relative market needs and prices in the U.S. and Canada will ultimately 
decide the destination for this gas.
    Question 6a. According to a study by the NPC, increased U.S. 
natural gas consumption will require significant investments in new 
pipelines and other natural gas infrastructure--1.5 trillion over the 
next 15 years. However, the current level of volatility in gas markets 
(price swinging from $2.50 to $10 mmbtu), has discouraged many 
companies from committing to such long-term investments. In some cases, 
they cannot get the financing.
    Question 6b. Where are the areas of greatest demand growth in the 
U.S.?
    Answer. Growth is anticipated in all geographic areas of the 
country and for all consuming sectors. However, the demand for 
electricity generation will be the largest single source of new gas 
demand in the coming years. Growth for electricity generation and 
natural gas demand will be particularly strong in the Southeast, the 
Southwest and the Midwest.
    Question 6c. Where are the areas of greatest supply growth?
    Answer. In the near term, most supply growth is anticipated in the 
Rocky Mountains and potentially the deepwaters of the Gulf of Mexico. 
In the three to five year time frame there are also potential supply 
sources from many coastal areas via LNG. Alaskan gas has a 10 year time 
frame.
    Question 6d. Is the pipeline infrastructure that currently exists 
adequate to move the gas where it needs to go to satisfy the market's 
supply/demand balance?
    Answer. Pipeline and distribution system infrastructure will have 
to increase dramatically in most areas of the country to serve a demand 
increase that could approach 50 percent over the next 15 to 20 years. 
The most glaring lack of infrastructure is for pipeline capacity to 
move gas out of the Rocky Mountain Region, although a number of 
projects are being constructed or planned to address this issue. It is 
a problem that we have known about for a long time, but addressing it 
has been too slow and arduous.
    Question 6e. What does this mean for the current system that we are 
so heavily dependent upon?
    Question 6f. What is the minimum level of investment necessary to 
insure adequate capacity, and how can we best achieve this?
    Answer. Natural gas utilities will need to spend $100 billion by 
2020 to meet projected demand growth, excluding the funds required for 
normal safety and maintenance activities. Attracting this amount of 
capital will be a very difficult challenge for utilities. One action 
that would bring utilities more in line with other industries in this 
regard is accelerated depreciation from the current 20 year level 
allowed for pipeline and distribution infrastructure additions. 
Although utilities compete for capital with other industries, their 
allowed depreciation schedule is much less favorable. Expedited review 
and approval of system expansions will also serve to add infrastructure 
more economically.
    Question 7a. This morning I asked the Secretary of Energy what the 
Administration was doing to mitigate the impact of high energy prices. 
His only concrete response was that they support the Low Income Home 
Energy Assistance Program. The reality of the LIHEAP program is that 
historic funding levels have never met the needs of all of the eligible 
low-income households in the U.S. I would add that if gas prices are 
going to remain at these high levels many middle class households will 
need assistance as well.
    Question 7b. Do you think it is time that we expanded LIHEAP 
funding to a new level? Do you support the level passed by the Senate 
last year in the Energy bill ($3.4 billion per year)?
    Answer. AGA and its member companies enthusiastically endorse 
increased LIHEAP funding as authorized by the Senate last year in H.R. 
4. You are quite right in noting that, at current levels of funding, 
the LIHEAP program does not approach meeting all the human needs it is 
intended to serve.
    You also correctly note that this year's higher natural gas prices 
will increase the needs for LIHEAP funding. In addition to higher 
levels of LIHEAP funding, these needs can be addressed by taking 
decisive action in the very near term to increase natural gas supply, 
which will help moderate natural gas price levels.
    Question 8a. Last Congress, as part of the energy bill, I worked on 
a provision that would have provided royalty relief for production of 
natural gas from marginal wells on federal lands. I am of the belief 
that it is crucial to keep marginal wells under production. Onshore oil 
and gas production from federal lands makes a significant contribution 
to our domestic energy supply.
    Question 8b. Would you support granting royalty relief for marginal 
gas production?
    Answer. AGA supports royalty relief for marginal production. AGA 
supports, and has supported, an array of targeted, reasonable 
incentives to bring forth more natural gas supply. These include 
Section 29 tax credits, expensing geological and geophysical costs, 
expensing delay rental payments, tax credits for marginal wells, five-
year net operating loss carryback, and temporary repeal of the 
Alternative Minimum Tax for intangible drilling costs.
    Question 9. A recent report on LNG (University of Houston, 
Institute for Energy, Law & Enterprise) notes that 8 federal agencies 
have some regulatory role over LNG--with the Coast Guard, DOT and FERC 
having major roles and DOE playing a coordinating role. I understand 
that the FERC has recently updated its policies on LNG facilities. It 
may be too early to tell how this division of responsibilities is 
working, but do you care to comment on the various agency roles and how 
well they work together?
    Answer. The pattern of multiple agencies with responsibility over 
energy infrastructure is almost universal in our industry. Similar 
patterns apply with regard to natural gas production, transmission, and 
distribution. With respect to LNG in particular, siting in a timely 
fashion is the critical concern, and agency overlap invariably leads to 
delays. Our concern is that LNG terminal siting may become an even 
longer process.
    It is quite clear that LNG will play a critical role in natural gas 
supply in the future. In addition to bringing forth additional supply, 
it will have a very significant role in pricing at the margin. AGA 
endorses the recently announced FERC policy with regard to LNG 
offloading facilities. The new FERC policy will not adversely affect 
consumer protection, and it will increase regulatory certainty for 
developers of new LNG offloading facilities.
    Question 10a. How confident are we in our ability to collect data 
about the supply of natural gas?
    Answer. Data on natural gas supplies are limited and not timely. 
Other than the weekly natural gas storage data that EIA overtook 
recently from AGA, there are little real-time data. Further, there is 
little or no consistency between the federal and state supply data.
    Question 10b. What amount do we think is being flared?
    Answer. Virtually no natural gas is flared today.
    Question 10c. Does EIA have adequate funds to perform the data 
gathering tasks demanded?
    Answer. This is beyond our area of expertise. However, we have 
noted a number of indicators (delayed reporting, extensive revisions, 
etc.) that suggest resource constraints.
    Question 11a. The Presidents Energy Plan announced last March 
predicated that between 1300-1900 new power plants would need to be 
built to meet future electricity demands. At the time, experts 
predicted a large percentage of these would be natural gas driven. 
Given the current volatility in natural gas markets, some fear that a 
large number of these plants will never be built. Instead, future 
electricity demands may in fact be met by large Midwestern coal plants 
which would be using, dirty technology.
    Question 11b. Do you agree with this?
    Answer. Gas has become the fuel of choice for electricity 
generation because gas plants are clean, efficient, quicker to 
construct, economic and flexible to operate. Clearly developers are 
examining the coal option as a result of gas pricing concerns. However, 
it is very difficult and costly to meet all the environmental concerns 
related to coal. It is unfortunate that governmental policies 
overwhelmingly drive electricity generators to gas but at the same time 
impede our ability to produce and deliver gas from our vast resources.
    Question 11c. Does the current level of volatility discourage new 
gas fired generation from being built?
    Answer. Natural gas remains the dominant fuel choice for new 
generating capacity, although the dominance has been reduced marginally 
over the past couple of years, primarily in response to gas pricing 
concerns.
    Question 11d. Also, to what degree are delays in pipeline 
development perhaps leaving the door open for alternative fuels.
    Answer. We need to pursue all forms of energy and I do not know 
that there is any correlation between pipeline development and the 
development of alternative fuels. I do know that there are 64 million 
natural gas customers in the U.S. today, and that less than one-half of 
one percent of our energy needs are currently met by solar, wind or 
other renewable sources. We need to do all we can to supply the 64 
million gas customers as efficiently and cost-effectively as possible 
while also moving forward aggressively on the renewable front. 
Renewables offer hope for tomorrow but not relief today.

              Responses to Questions From Senator Bunning

    Question 12a. What is the potential for coal mining on federal 
lands?
    Answer. This is not our area of expertise.
    Question 12b. How much coal is available to be mined on federally 
owned land?
    Answer. This is not our area of expertise.
    Question 12c. Is coal on federal lands available for mining in the 
eastern United States? If so, where is it available where the Federal 
government owns the rights to the coal?
    Answer. This is not our area of expertise.
    Question 13.How do you think federal laws should be changed to best 
bring about a balanced energy policy that will boost domestic energy 
production while also promoting conservation?
    Answer. AGA and its members companies are extremely attuned to the 
need for the nation to implement a balanced energy policy. On a 
national basis, we have seen per-customer consumption of natural gas 
declining, largely as a result of conservation measures. Nevertheless, 
we have also seen the natural gas market as whole grow. Increases in 
the market of as much as 50 percent are in the foreseeable future.
    AGA believes that H.R. 4 as passed by the House of Representatives 
in August 2001, represents an appropriate balance among the multitude 
of factors to be considered in crafting a national energy policy, 
including energy supply and energy conservation.
    Question 14. What are some of the obstacles in current regulations 
that have prevented the United States from boosting its energy 
production on federally owned lands?
    Answer. AGA would defer to the natural gas producer community with 
regard to this question. Nevertheless, we also direct your attention to 
AGA's response to Question No. 1 above.
                              Appendix II

              Additional Material Submitted for the Record

                              ----------                              

                     National Association of Manufacturers,
                                 Washington, DC, February 24, 2003.
Hon. Pete V. Domenici,
Chairman, Energy and Natural Resources Committee, Hart Senate Office 
        Building, Washington, DC.
    Dear Mr. Chairman: On behalf of the National Association of 
Manufacturers (NAM), I would like to make clear to the Committee on 
Energy and Natural Resources the seriousness with which the NAM views 
the need for having access to adequate supplies of natural gas at 
affordable prices. The NAM is the nation's largest industrial trade 
association and represents 14,000 members, including 10,000 small and 
medium companies.
    The manufacturing sector (excluding electric generation) uses about 
one-third of the nation's energy, including 40 percent of its natural 
gas and 30 percent of its electricity. Many industries are heavily 
impacted when natural gas prices rise, most particularly the chemical 
and fertilizer industries, which use natural gas as both an energy 
source and a feedstock for their products. In addition, natural gas has 
unique properties to heat and to dry and is used extensively to melt 
scrap aluminum and steel ingots, for paint drying for cars and 
appliances, in making glass and in heat-treating metals. In addition, 
natural gas is used in many facilities for space heating and the steam 
is necessary for many manufacturing processes. In hundreds of larger 
facilities, that steam is recycled to generate very economical 
electricity by means of combined heat and power systems.
    Finally, increased natural gas costs have a double impact on gas-
using manufacturers. Because increasing volumes of natural gas are 
being consumed to generate electricity, the competition for tight 
supplies means that consumers' electricity costs will also rise. In 
fact, the largest energy input cost for the manufacturing sector is 
electricity. Thus, natural gas price increases are being felt by 
virtually all manufacturers, irrespective of their product lines.
    Manufacturing is on the front line in the unprecedented competition 
we are seeing in the world marketplace. More and more frequently, 
domestic manufacturers cannot pass through cost increases on their 
products, making it more difficult to stay competitive in the United 
States or sell into the export market. Our analysis shows that weak 
exports, coupled with low capital investments, are prolonging the 
anemic recovery in the manufacturing sector. The economic situation in 
the manufacturing sector is serious, after experiencing 30 straight 
months of employment decline that has totaled two million net jobs lost 
in the past two years. Anything the federal government can do to 
increase natural gas supplies at affordable prices, while avoiding 
mandates that would drive up the cost of natural gas or electricity, 
will help to reduce product costs and improve the condition of U.S. 
manufacturing and its millions of workers.
    As the members of the committee may know, the spike in prices for 
oil, natural gas and electricity in the fall of 2000 precipitated the 
manufacturing recession, although they were not the only causes. The 
wellhead price of natural gas in January 2000 reached over $8.00 per 
million Btu, more than four times the average for the previous ten 
years, which was $1.91. Not surprisingly, that was the first month in 
recent history that the United States was a net importer of basic 
chemicals. Moreover, high domestic natural gas prices affect 
electricity prices as well, because natural gas is increasingly used to 
generate electricity. In fact, natural gas use in electric generation 
increased by over one-third (35 percent) between 1990 and 2001. Because 
electricity generation itself has increased, the volumes of natural gas 
used in electricity production grew by two-thirds (66 percent) during 
this same period of 1990 to 2001. Given that domestic production of 
natural gas in 2001 was less than 9 percent higher than in 1990, while 
overall domestic consumption of natural gas increased more than 18 
percent, we are concerned about the price and reliability of this 
important energy source into the future.
    Although, there was an initial boost in U.S. natural gas production 
following the high prices of 2001, domestic gas production has fallen 
for the last three quarters. Moreover, this first cold winter in 
several years, steady population growth and steady, although anemic, 
economic growth have used up the temporary increase in domestic natural 
gas production. Thus, by the end of January 2003, the wholesale price 
of natural gas was over $6.00, which is more than three times the 
average price from 1991 to 1998. Once again, supplies are tight and 
prices have been streaking upward. One natural gas price spike in 
twenty years might be considered an anomaly, but two might be feared as 
a trend.
    In August 2000, the NAM raised its members' concerns about the 
impending natural gas supply crisis and the high prices during that 
winter proved their concerns valid. The new Administration quickly 
produced a National Energy Policy, and asked Congress for comprehensive 
energy legislation. Many valuable elements of a final bill were agreed 
to only to fall victim to the elements of disagreement as the 107th 
Congress ended.
    We must observe, however, that conservation mandates are not the 
right solution. They add to manufacturing costs without providing 
commensurate economic benefits. Industry has been steadily increasing 
the efficiency with which it uses energy since the mid-1970s. 
Manufacturing has been focusing on cost cutting, including ways to 
reduce energy use, through its implementation of Total Quality 
Management procedures that became common in industry during the 1980s 
and continue today. Although perhaps well-meaning, mandatory energy 
reductions only divert capital that is in short supply to investments 
in ventures that go beyond those that are economically sound, or worse, 
stop economic activity altogether.
    Accordingly, the NAM strongly opposes a renewable portfolio 
standard as a solution to the rapid growth in the use of natural gas in 
electric generation. Some renewable energy sources, such as wind and 
solar, are unreliable and very expensive. If renewable portfolio 
standards are adopted, the costs of generating electricity will rise 
just as if there was a new tax on electricity. These costs will be 
passed on as a new energy cost to manufacturers, as well as home 
owners, commercial and state and local governments. Let me remind the 
committee that the recent economic downturn hit manufacturers much 
harder than the rest of the economy both in terms of depth and 
duration.
    Manufacturers began slipping into recession in the second quarter 
of 2000--well ahead of the rest of the economy. And by the time that 
manufacturing output began to turn up in the beginning of 2002, 
industrial output already had fallen by 8 percent over the previous 18 
months. This performance was much worse than that of the rest of the 
economy. Overall, GDP slipped less than half a percent during the first 
three quarters of 2001--the second-mildest recession in 50 years.
    And while the overall economy grew a modest 3 percent last year, 
manufacturing output edged up only 1.7 percent. This manufacturing 
``recovery'' is slower than the first year of any recovery over the 
past 40 years and less than one-fifth the average 10 percent growth 
during the initial 12 months of the past six expansions.
    Weak business investment demand and export growth have constrained 
the recovery for manufacturers, the producers of capital goods used by 
American industry and the source of two-thirds of overall exports. In 
short, the expansion to date has been narrow, unbalanced and 
historically sluggish. Despite historically low interest rates, and a 
bonus depreciation stimulus package passed last year, significant 
inhibitors to economic growth remain. Some of the challenges facing 
manufacturers are long-term problems that need to be addressed to 
create a better environment for manufacturing in America.
    Energy prices are not the only concern to industry executives when 
considering where to put their investment dollars. Certainly, the 
still-overvalued U.S. dollar, abusive product liability litigation, 
skyrocketing health-care costs and an unfavorable tax climate are other 
major factors. But, because none of these costs can be easily endured, 
all of these costsincluding energy count to whether a company is 
profitable or not. Since July 2000, manufacturing employment has fallen 
by 2 million over the course of 30 consecutive monthly declines. By 
contrast, the employment in the rest of the economy has grown by 
954,000, with a brief, sharp drop in employment immediately following 
September 1 1 sandwiched between months of modest employment growth.
    We applaud this committee's declaration that it will act promptly 
and expansively on a new comprehensive energy bill that will address 
the need for energy to renew industrial economic growth. It is vital 
that the 108th Congress act quickly to stem the national energy crisis 
by implementing legislation that provides for adequate supplies of 
reliable and affordable energy. There is an obvious and undeniable need 
for Congress to provide additional access to federally controlled lands 
that clearly contain significant natural gas resources.
    We request that this letter be made part of the record during the 
full committee hearing on gas supply and prices. If you have any 
questions, please have your staff contact Mark Whitenton at (202) 637-
3157. Thank you.
            Sincerely,
                                        Michael E. Baroody,
                                          Executive Vice President.
                                 ______
                                 
                                  Arctic Resources Company,
                                    Houston, TX, February 24, 2003.
Hon. Pete Domenici,
Chairman, Senate Energy and Natural Resources Committee, Dirksen Senate 
        Office Building, Washington, DC.
    Dear Chairman Domenici: I understand that, as part of your efforts 
to draft and pass a comprehensive energy bill this year, your Committee 
is holding a hearing on February 25, 2003 on Natural Gas Supply and 
Prices. I would like to submit for the official hearing record the 
attached testimony on behalf of Arctic Resources Company. The testimony 
details the importance of allowing free markets to work in construction 
of a natural gas pipeline from Alaska's North Slope to the lower-48 
states.
    I appreciate your consideration of this request, and I look forward 
to working with you and the Committee to ensure that appropriate 
legislation is enacted to expedite permitting and construction of a 
North Slope pipeline route that the market chooses and without 
subsidies.
            Sincerely,
                                        Forrest E. Hoglund,
                                                    Chairman & CEO.

 Statement of Forrest Hoglund, Chairman & CEO, Arctic Resources Company
    Mr. Chairman, Members of the Committee: I represent Arctic 
Resources Company (ARC), a special purpose company formed to develop 
and build a natural gas pipeline connecting the natural gas reserves of 
the North Slope of Alaska and the Canadian Northwest Territories for 
delivery to Canada and the lower-48 states. The route we are proposing 
is the shortest, fastest and most economic option. This route, which is 
often referred to as the Northern Route, will also tap into the 
enormous future reserve potential of Alaska and the Canadian Arctic, 
and is the most environmentally responsible route to achieve that 
objective.
    I understand that the purpose of this hearing is to receive 
testimony on natural gas supply and prices in the U.S. today, and in 
the future. Our country is facing a shortage of natural gas and prices 
of the fuel are rising. In order to meet future energy requirements, it 
is vital to develop our vast domestic natural gas supplies on Alaska's 
North Slope as quickly and economically as possible. This testimony 
will provide the Committee with a status report on our project; but 
first, let me address the need to streamline the permitting process to 
make it as efficient as possible.
    To expedite the construction of a natural gas pipeline from Alaska, 
I suggest that Congress pass legislation to set timetables for 
regulatory and environmental approvals and consider legislation for a 
government guarantee of debt to allow for additional capacity to be 
built and to give incentives for producers to commit their gas to the 
project. I firmly believe that we can complete the Northern Route 
without either of these actions; but, that type of legislation would 
undoubtedly speed the process and lower the risks of the project.
    ARC does not need subsidies or tax breaks to implement the northern 
gas pipeline project, and we urge Congress to reject any unnecessary 
subsidies for any pipeline project. We need more than legislation from 
Washington. What we need and what the country needs is for government 
to let the markets work and allow the natural gas and associated 
industries in Alaska, Canada and the lower-48 United States to develop 
the pipeline project in an economically rational manner. We need those 
who would mandate routes to stand down from their efforts, and instead 
focus on providing a clear opportunity for expeditious permitting of 
the most cost effective route.
    Current market conditions should foster the expeditious development 
of an economic pipeline. We believe that the market will support the 
development of the Northern Route and that route can fulfill the needs 
of Alaskans, the needs of our Canadian neighbors, and help meet the 
growing natural gas demand in the lower-48.
    To be successful, however, the U.S. and Canada must work closely 
together. The two governments must be committed to the lowest-cost 
system and accessing the largest supply base. Government decision 
makers and business, civic, social and environmental leaders must not 
limit their perspective to a 25-year-old, second-best answer. We must 
be open to consideration of a third party consortium of interested 
parties to oversee the project in order to overcome the many real and 
imagined challenges to this project.
    As is evident in this testimony, we have been working hard in the 
development of our project to take into consideration the interests of 
every U.S. energy consumer, every U.S. taxpayer, the economic interests 
of Alaskan citizens and the State of Alaska, the interests of our 
Canadian neighbors, the interests of non-governmental organizations 
that are concerned with social and environmental issues, and even the 
interests of natural gas producers at Prudhoe Bay and in northern 
Canada. I realize that some of these interested parties may have some 
questions about our efforts, but I urge each of you to give the 
Northern Route the opportunity to succeed. It is the only route that is 
economically viable today and into the foreseeable future.
    The reserves on Alaska's North Slope and in Canada's Mackenzie 
Valley are enormous and constitute the only major proven new supply of 
natural gas that can help meet the nation's growing demand for natural 
gas. There are currently proven reserves of 35 Tcf on Alaska's North 
Slope and 9 Tcf in the Mackenzie Delta region of Canada. That gas was 
found roughly 30 years ago when explorers were looking for oil. The 
exploration potential for each area is very large: 100 Tcf in Alaska 
and 90 Tcf in Canada.
    The most economic pipeline system must be built to tap these proven 
and potential reserves. The lower the cost of the system, the greater 
the incentive to find and produce more natural gas. ARC's Northern 
Route proposal is today the only pipeline project that is economic. 
Delivering this proven natural gas resource to market is the most 
important single energy project that we know of to supply significantly 
larger volumes of the clean-burning fuel within the next 7 to 15 years. 
Without these new sources, the U.S. economy will most likely have to 
endure short supplies of natural gas and rely on coal, imported oil, 
and liquefied natural gas (LNG) to meet new demand. I have often 
likened the importance of this project, the first transportation system 
for Arctic natural gas, to the first railroad built to California for 
the U.S. or to the West Coast for the Canadians.
Two-Pipeline Option
    In recent years, a significant effort has been made to convince 
Congress that the currently preferred route of the State of Alaska, the 
Alaska Natural Gas Transportation System (ANGTS), is the only route 
available to bring to market North Slope gas. That system would 
parallel the Alyeska oil pipeline right-of-way to Fairbanks then follow 
the Alaska Highway to northeastern British Columbia. That is not far 
enough to get to the main hub of existing gas pipelines for take-away 
capacity, so it will need to extend to interconnects near Edmonton, 
Alberta. The assertion that this is the only option available to 
develop these resources is simply not true.
    Furthermore, one of the main problems of the ANGTS route is that a 
second pipeline will be needed to tie in the Canadian reserves in the 
Mackenzie Valley (See Table 1).* This immediately creates conflict 
between the U.S. and Canada. Which line goes first? The first line can 
lower the value of the second line by delaying the need for the gas, 
possibly for decades. The Alaskans have always assumed that their line 
would go first, but approximately two-thirds of the ANGTS line goes 
through Canada. During last year's energy bill debate, the Canadian and 
Northwest Territories governments defended Canada's right and duty to 
protect its own energy interests. In numerous instances last year, 
Canadian government representatives intimated that final permitting for 
an ANGST line would not be allowed while Canadian Mackenzie Valley 
reserves remained stranded.\1\ This year, Canada has reiterated the 
need to develop Mackenzie Valley gas either before or in conjunction 
with permitting a line for North Slope gas.
---------------------------------------------------------------------------
    * Tables 1-3 have been retained in committee files.
    \1\ Canadian Energy Minister Herb Dhaliwal statement, The Globe and 
Mail, ``Ottawa Girds for Trade War with U.S.'', May 3, 2002.
---------------------------------------------------------------------------
The Northern Route
    The best alternative available for development of these vital 
reserves is the single pipeline system solution, the so-called Northern 
Route, or as we refer to it, the Northern Gas Pipeline Project (NGPP). 
This one pipeline system enables both Prudhoe Bay gas and Canadian 
Arctic (NWT, Yukon and Nunavut) gas to be tapped. The line goes from 
Prudhoe Bay, offshore east into and beneath the Beaufort Sea to the 
Mackenzie Delta, and then down the Mackenzie Valley to the pipeline 
interconnects near Edmonton, Alberta (See Table 2).
    Our approach calls for a phased implementation of the project. In 
Phase 1 we would lay an initial 36-inch pipeline from Edmonton, Alberta 
north to the reserves in the Mackenzie Delta. In Phase 2 we would 
extend the initial 36-inch line over to the Prudhoe Bay unit, allowing 
staging of the volumes into the markets. That would be followed by 
Phase 3--a second 36-inch pipeline from Edmonton up the Mackenzie 
Valley. In Phase 4 we would lay a second 36-inch line over to the 
Prudhoe Bay unit, allowing for a full deliverable capacity of 5.2 Bcf/
day. This would be an open-access line with spare capacity for the 
volumes from new exploration finds. This project has great cost, supply 
reliability and market advantages, since materials, equipment and 
construction services are available to construct 36-inch pipelines and 
many pipe mills, including mills in Canada and the U.S., can supply 
this size of pipe.
Economics
    The economic and environmental impacts of the two-pipeline option 
versus the Northern Route are vastly different, as evidenced using 
released or third party numbers. The capital construction cost of the 
ANGTS route is estimated at $11.6 billion, the line is 2,140 miles long 
from Prudhoe Bay to interconnects near Edmonton, and it crosses 
approximately 900 miles of pristine mountains. Furthermore, it does not 
go through the major future exploration potential areas. Current 
industry proposals suggest a pipeline 52 inches in diameter carrying 
4.5 Bcf/day. The associated and necessary Mackenzie Valley only line 
would be an additional 1,350 miles long with an added cost of $3 
billion to get to pipeline interconnections near Edmonton. It would 
have a diameter of 30 inches with a design capacity of 1.2 Bcf/day. 
Together, the two pipeline projects would cost $14.6 billion and would 
have a combined length of 3,500 miles, leaving two environmental 
footprints.
    The Northern Route would be approximately 1,700 miles long--
approximately 350 miles offshore and 1,350 miles onshore--and would not 
cross any mountains. Furthermore, it would go close to or through all 
present and future exploration areas in both Canada and Alaska. 
Approximately 90% of the line would be in Canada.
    The most telling difference in the two approaches is how much of 
the eventual proceeds will be available to the producer. That is 
defined as the wellhead netback, proceeds after all transportation 
costs are deducted. One of the major producers has stated that they 
will not consider moving forward with development of any gas projects 
unless they provide an adequate (15%) rate of return with gas prices at 
$2.50 per thousand cubic feet (Mcf).\2\ Though gas prices have been 
uncharacteristically high in recent months, a project still needs to 
provide sufficient wellhead netbacks. At $2.50/Mcf gas, the ANGSS route 
is clearly uneconomical, as is the Mackenzie only pipeline, with 
essentially no wellhead netback. (See attached Table 3 that compares 
the project costs.) It would take very large subsidies--perhaps $5 to 
$6 billion in direct funding--to make the two pipeline approach 
financially viable. There also remains the Canadian conflict situation 
and a higher chance of cost overruns. It has been estimated that if 
both an ANGST and Mackenzie Valley only pipeline were to be constructed 
at the same time, construction costs would be 20% to 30% higher due to 
lack of construction resources, materials and equipment. The bottom 
line: economics do matter and they point overwhelmingly to the Northern 
Route.
---------------------------------------------------------------------------
    \2\ Senator Frank Murkowski and The Williams Companies Chairman 
Keith E. Bailey, Senate Energy & Natural Resources Committee Hearing on 
an Alaska Natural Gas Pipeline, October 2, 2001.
---------------------------------------------------------------------------
Alaska's Situation
    Alaska's preference of the ANGTS route is easily understood. If all 
things were equal, it is clearly more desirable to have the pipeline 
come through the state, provide gas to Fairbanks and other communities 
along the Alaska Highway, and possibly even to Anchorage some day, and 
to provide more short-term construction jobs in Alaska. The problem, 
though, is that all things are not equal. Alaska is pushing for a 
system that is uneconomical, will require two pipelines to be built, 
and creates conflict with Canada, where approximately two-thirds of 
their pipeline and additional takeaway capacity lines must be approved 
and constructed. I do not believe Canada will approve the ANGTS route, 
lower the value of Canadian reserves and require the construction of a 
second line to deliver the Mackenzie Valley gas to market.
    Alaska should not trade short-term economics when it knows that at 
historical prices, the State will make about $145 to $201 million or 
more per year off of higher taxes and state royalties with the Northern 
Route.\3\ The Northern Route will enable the State to receive the 
maximum possible value for their existing and future reserves. That 
should be the overriding objective of the State of Alaska.
---------------------------------------------------------------------------
    \3\ Alaska Economic Report & Alaska Legislative Digest Special 
Resource Supplement, Gas--The Value Chain, September 29, 2000.
---------------------------------------------------------------------------
    It is quite clear that the single pipeline system approach is the 
best on all counts. Last year, Alaska tried to use its Congressional 
seniority and political muscle to prohibit the Northern Route, but that 
could work against them in the end by causing delays in the development 
of any pipeline project and U.S. consumers and the citizens of Alaska 
will suffer as a result.
The Myths of the Northern Route
    The major myths associated with the Northern Route fit in the 
following categories:

First Myth: Arctic offshore construction is unproven and risky 
environmentally.

    There are currently offshore pipelines in similar environments, and 
more recently off Prudhoe Bay. No major construction companies or major 
oil companies have said it is not feasible. British Petroleum is 
already operating the Northstar oil pipeline in Prudhoe Bay in the 
Alaskan Arctic--a Northern Route gas pipeline would be similar. Canada 
already has regulations in place for pipelines of this nature. The 
present design calls for the pipeline to be buried approximately 15 
feet below the ocean floor. Historical ice scour data for the proposed 
area of construction is in the 1 to 2 foot range. This will be a 
conditioned natural gas pipeline. If a leak or rupture ever occurred, 
the gas would vaporize into the air and would not leave a spill like an 
oil pipeline. It is important to note that with current metallurgical 
and pipeline test standards, it is unlikely that a pipeline carrying 
conditioned natural gas would suffer such a structural failure.
    The real environmental problems lie with the two-pipeline approach. 
Two environmental footprints, scarring 3,400 miles, including 900 miles 
of mountains, would occur with this approach. With the single pipeline 
route approach, there would be one environmental footprint for a 1,700 
mile pipeline, crossing no mountains. The major environmental concern 
should be the emissions consequences of delays in the development of a 
pipeline system to deliver the Arctic gas to markets from the resulting 
increase in the use of coal, oil and less efficient imported LNG. 
Federal price subsidies and the belief that Federal price subsidies may 
become available to incentivize an uneconomic pipeline will delay the 
development of any pipeline system and result in environmental 
degradation from growing the North American economy on less 
environmentally friendly fuels.

Second Myth: It will hurt whale migration.

    Migratory Bowhead whales pass through this area twice each year. 
Present construction methodology has the offshore portion of the 
pipeline being laid during the winter and summer seasons. There is no 
whale migration during the winter.
    When summer construction is carried out, it would be scheduled 
around whale migration and other wildlife or subsistence issues. The 
line would be buried below the ocean floor, with no surface structures 
to impede the movements of the whales or other mammals in the area. 
Once laid, the pipeline is out of sight and out of mind.

Third Myth: The pipeline is a step toward opening up ANWR for drilling.

    This project has no bearing on the ANWR question. One is either in 
favor of or against the development of ANWR. This pipeline project is 
designed to connect existing Prudhoe Bay reserves and related future 
exploration areas where leases are available.

Fourth Myth: Existing regulatory and international agreements prohibit 
the Northern Route.

    The Federal Energy Regulatory Commission (FERC) and the Department 
of Energy have testified that that is not true.\4\ In addition, in the 
event that the Alaska Coastal Commission uses its authority to declare 
the Northern Route inconsistent with the Alaska Coastal Zone Management 
Plan, there is an appeals process established in the Coastal Zone 
Management Act that can be employed to adjudicate that decision. Other 
statutes and regulations may also be employed in an effort to impede 
the development of a project. That is to be expected. Any project that 
is ultimately permitted to deliver Arctic natural gas to market will 
likely face regulatory and legal challenges. That is the nature of 
major energy project development in the 21st Century. Any prudent 
project planning process must take such challenges into account.
---------------------------------------------------------------------------
    \4\ FERC Chairman Patrick Wood III and DOE Acting Assistant 
Secretary for Fossile of Energy Robert S. Kripowicz testimony, Senate 
Energy & Natural Resources Committee Hearing on an Alaska Natural Gas 
Pipeline, October 2, 2001.
---------------------------------------------------------------------------
How To Do the Project
    The real question is not which route. The real question, I believe, 
is what is the best way to get the project built? There are basically 
two approaches: the ARC approach or a project led by the major oil 
companies.
    Twenty-five years ago, the same two routes were considered. 
Industry fought for 3 years and spent around $750 million in this 
effort. The major oil companies wanted a northern onshore route similar 
to ARC's northern offshore route,\5\ but the Canadian Government placed 
a ten-year moratorium on pipelines in the Mackenzie Valley and blocked 
it due to unsettled Aboriginal land claims. I was Vice President of 
Natural Gas for Exxon at that time and in that effort learned a lot 
about how not to get projects done.
---------------------------------------------------------------------------
    \5\ Alaskan Arctic Gas Pipeline Co., Public Affairs Department, Why 
the Arctic Gas Project is Best for All America, June, 1977.
---------------------------------------------------------------------------
    ARC at this time is the only company sponsoring the Northern Route. 
ArcticGas Resources Limited Partnership, the Canadian affiliate of ARC, 
on January 16, 2002, filed a Preliminary Information Package with the 
National Energy Board in Canada on behalf of the Northern Route Gas 
Pipeline Corporation (NGRPC). Our approach is twofold: create the most 
economical project, and eliminate as many roadblocks as possible. We 
know this approach is not conventional, and do not expect to get the 
immediate support of the major reserve holders. However, it is the best 
way to do the project. The 4 main features of our proposal are as 
follows:
    1. The best route--best economics. This feature has been covered.
    2. Significant Northern Canadian Aboriginal ownership. This is 
perhaps one of the most controversial parts, but we consider it very 
important. The Northern Canadian Aboriginals own part of the lands 
through settlement of their land claims with Canada and they are in a 
position to help the project considerably. We wanted to include them up 
front and in a meaningful and significant way. They have formed a 100% 
Aboriginal owned Pipeline Company, the NRGPC. This company would issue 
the debt for the pipeline. Arctic Resources Company (which is planned 
to be, ultimately, a consortium of the founders, the major reserve 
holders, the major gas customers, and the Aboriginal for profit groups, 
pipeline companies, NGO's and other interested parties), through its 
Canadian affiliate, ArcticGas Resources Corp., would be the program 
manager for NRGPC. ARC would oversee the project development, 
financing, engineering, construction, and ongoing operations; and would 
be in place to manage the repayment of the bond obligations.
    3. Our financing concept is to use municipal type, taxable, non-
recourse revenue bonds, with the revenue stream guaranteed by shippers' 
throughput agreements at a negotiated toll level agreed to by U.S. and 
Canadian regulatory authorities. This is very similar to many 
infrastructure projects in place today. Some examples are toll ways, 
stadiums and airports. This will be 100% debt financed and, by not 
having the more costly equity component, the project is able to pay the 
Aboriginal landowners sufficient land use fees and still keep the 
overall toll low. This approach is the best way to eliminate roadblocks 
and keep the lowest toll possible. It has the added benefit of creating 
a revenue stream for the Aboriginals that will end up helping their 
progress dramatically. The same type of approach can be used in Alaska 
as well.
    4. The major oil companies have said on several occasions that this 
is a world-class project and a world-class company is needed to run it. 
Once they and others join the consortium, ARC will truly become a 
world-class company and a world-class international consortium. In the 
meantime, we are telling our story, gathering Aboriginal support, and 
working through the permitting process at the National Energy Board 
(NEB) in Canada. On January 24, 2003, the K'ahsho Got'ine, through 
their K'ahsho Got'ine Land Corporation, announced their intention to 
sign, subject to certain conditions, a Cooperation and Land Access 
Agreement for the Northern Gas Pipeline Project and to joining NRGPC. 
That agreement will provide for Aboriginal control of their own lands 
and environment through ownership of the Northern Gas Pipeline Project, 
while providing the lowest transportation costs to Alaskan and NWT 
shippers through the line.
Summary
    There is only one clear choice for the best way to do this 
project--the most important energy project of this new century for 
North America. A political consensus between the U.S. and Canada, and 
eventually Alaska, can be achieved. It is truly an international 
project and we believe that joint discussions between the U.S. and 
Canada as to the best project, and the best way to get it approved, 
should be encouraged. The Northern Route provides U.S. consumers with 
the opportunity to benefit from the largest supply of natural gas from 
both Alaska and Canada. It can be the fastest project because it will 
not be shut in due to high tariffs as gas prices fall. Additionally, 
the U.S. will make at least $5 to $10 billion more on income taxes. 
Alaska will also benefit by $100 million or more per year for the same 
reason.
    This project is about the economic future of the U.S. and Canada. 
It is the best answer for delivering Alaskan and Canadian Arctic 
natural gas for U.S. and Canadian gas consumers and taxpayers. We ask 
that the U.S. Senate not take any actions that would artificially limit 
our options for delivering Alaskan and Canadian natural gas to market. 
Last year's adoption by the House and Senate of an amendment 
prohibiting a ``certain pipeline route'' from being permitted by the 
FERC in their respective energy bills was an affront to our neighbor 
Canada and, if ultimately enacted, a financial roadblock to the 
delivery of Arctic natural gas to U.S. markets.
    We are only asking for a fair playing field, a provision to speed 
up the regulatory and review process and the equivalence of any 
economic support that might be offered to any other project. The U.S., 
Canada and Alaska will all benefit from the most economic project that 
will provide for the greatest exploration incentive for new reserves.
                                 ______
                                 
                                        Morgan Meguire LLC,
                                 Washington, DC, February 25, 2003.
Shane Perkins,
Staff Assistant, Senate Energy and Natural Resources Committee, Dirksen 
        Senate Office Building, Washington, DC.
    Shane: Enclosed, please find hard copies of and a CD containing 
testimony for today's hearing on Natural Gas Supply and Prices 
submitted by Dan Lopez, President of New Mexico Tech. We attempted to 
e-mail you the documents yesterday, but the attached presentations to 
the letter were too large to e-mail.
    Please contact me or Kyle Simpson at 202-661-6180 if you have any 
questions or concerns.
            Best regards,
                                          Jack N. Jacobson,
                                                         Associate.

[Note: The Technology Roadmap for Unconventional Gas Resources and 
Future Natural Gas Supplies and the Ultra-Deepwater Gulf of Mexico have 
been retained in committee files.]

                                   New Mexico Tech,
                                   Office of the President,
                                    Socorro, NM, February 24, 2003.
Hon. Pete V. Domenici,
Chairman, Senate Energy and Natural Resources Committee, Dirksen Senate 
        Office Building, Washington, DC.
    Dear Mr. Chairman: I am writing to encourage you to make certain 
that any energy bill that is reported from the Senate Energy and 
Natural Resources Committee and passed in this Congress authorizes the 
Energy Research, Development, Demonstration, and Commercial Application 
Act of 2003. In the House, authorization for this new program is 
contained in H.R. 238, the Energy Research, Development, Demonstration, 
and Commercial Application Act of 2003. The bill was introduced on 
January 8, 2003, by Representatives Sherwood Boehlert (R-NY) and Ralph 
Hall (D-TX). The language is the compromise language that was worked 
out by the staff of the conference committee on the energy legislation 
in the 107th Congress. Your Committee is holding a hearing on gas 
supply and prices on Tuesday, February 25, 2003. I respectfully request 
that you include this letter and the two attachments in the record of 
the hearing.
    If authorized, the measure would establish new programs of 
research, development, demonstration, and commercial (R,D,D&C) 
application of technologies for ultra-deepwater and unconventional 
onshore natural gas and other petroleum resource exploration and 
production, including safe operations and environmental mitigation. 
These programs constitute a new method for managing joint industry and 
government funded R,D,D&C activities to more closely match Federal 
resources to industry investment practices and technology needs. Most 
of the research will be managed and conducted by consortia of industry, 
academia, other research institutions and National Laboratories. The 
benefit will be increased gas and oil production in the near term as a 
result of the timely development and demonstration of new technologies 
that will lower the cost of production by 30 to 50 percent from 
domestic ultra-deepwater and unconventional onshore reserves.
    The legislation authorizes the Department of Energy, in partnership 
with industry, to develop technologies to produce natural gas and oil 
reserves in the ultra-deepwater of the Central and Western Gulf of 
Mexico, with a focus on improving, while lowering costs and reducing 
environmental impacts, the safety and efficiency of the recovery of 
ultra-deepwater resources and sub-sea production technology used for 
such recovery. The program is also will advance the science and 
technology available to domestic onshore unconventional natural gas and 
oil producers, particularly independent producers, through advances in 
technology for production of unconventional resources. These new 
programs are designed to help the nation meet its growing energy supply 
needs over the next two decades.
    According to the Energy Information Administration (EIA), 
``Domestic natural gas production is expected to increase more slowly 
than consumption.'' In the Annual Energy Outlook 2003 (AEO 2003), EIA 
has reduced its projections of domestic production by 3.4 Tcf to 25.1 
Tcf per year in 2020, in part due to ``reduced expectations for 
technological improvement for unconventional gas.'' In 2025, domestic 
production is expected to reach only 26.8 Tcf and 2.6 Tcf of that 
amount will be in Alaska. Consumption is expected to increase from 22.6 
Tcf in 2001 to between 31.8 Tcf and 37.5 Tcf in 2025. EIA projects the 
difference between production and consumption will be met with imports, 
including 2.1 Tcf in the form of LNG, unless production technology for 
the lower-48 unconventional and ultra-deepwater offshore is 
dramatically improved.
    Technology improvements can make a difference. In the AEO 2000, EIA 
projected that ``a higher rate of technological progress is expected to 
result in a higher projection for domestic natural gas production.'' 
That is consistent with the National Petroleum Council (NPC) 
recommendations for meeting natural gas demand in their 1999 natural 
gas study. In that study, the NPC recommended that, ``The government 
should continue investing in research and development through 
collaborations with industry, state organizations, national 
laboratories and universities.'' Enacting the Ultra-deepwater and 
Unconventional Natural Gas and Other Petroleum Resources Program would 
be responsive to the NPC recommendation.
    The new ultra-deepwater and unconventional energy R&D programs 
included in the measure would help to meet our growing demand for 
natural gas by establishing industry-led programs to develop reserves 
in the ultra-deepwater of the Central and Western Gulf of Mexico and 
unconventional onshore reserves in deep formations and other gas 
resources such as tight sands, gas shales and coal bed methane. The 
legislation would also authorize additional funding for DOE's long-
term, cross-cutting, enabling energy supply R&D to support this 
program.
    Natural gas and other petroleum in the ultra-deepwater and 
unconventional onshore reserves can provide a significant portion of 
the incremental supply of energy needed to meet growing demand over the 
next 20 years if the economic and technical impediments to development 
are minimized. Modeling shows that, over the next 15 years, with 
advanced technology developed to increase production from the ultra-
deepwater and unconventional onshore resources, we could economically 
add productive capacity of at least 6.7 Tcf of natural gas per year. To 
offer another perspective on the extent of this resource, the deepwater 
and ultra-deepwater Gulf of Mexico and the unconventional onshore are 
the largest opportunities remaining in the United States in areas that 
are currently available to be developed.
    There is a clear and significant public purpose for the development 
of domestic resources. The costs and risks associated with this 
development are sufficiently high that without a strong and focused 
public/private partnership these resources will not be economically 
producible to meet our mid-term energy needs. If we are to develop 
these domestic resources to meet the nation's energy requirements over 
the next ten to twenty years, it is critical that we provide federal 
R&D investment through public/private partnerships to lower the cost, 
increase the safety and mitigate the environmental impact of producing 
from these areas.
    These new natural gas R&D programs have the support of a diverse 
coalition ranging from large industrial end-use consumers, to research 
organizations and academia, to key industry players both large and 
small. It also has bipartisan support in Congress. I believe these 
programs are a critical component of our nation's future energy 
security. I urge you to include them in an energy bill that is passed 
by the Senate and ultimately enacted into law.
            Sincerely,
                                           Daniel H. Lopez,
                                                         President.
                                 ______
                                 
                                    EnerSea Transport, LLC,
                                    Houston, TX, February 25, 2003.
Hon. Pete Domenici,
U.S. Senate, Energy and Natural Resources Committee, Dirksen Senate 
        Building, Washington, DC.
    Dear Chairman Domenici: It is my understanding that you will be 
holding a hearing on the important issue of natural gas supply and 
prices on February 25, 2003. On behalf of EnerSea Transport, a Houston 
based compressed natural gas (CNG) transportation and storage company, 
I would like to request the attached written testimony be submitted for 
the record. I believe it will help to expand the discussion of how CNG 
is a viable option for transporting and delivering natural gas to the 
marketplace.
    Thank you for your consideration on this matter and I look forward 
to working with you to find solutions to meet increasing natural gas 
demand in the U.S.
            Regards,
                                              Paul Britton,
                                                 Managing Director.

  Statement of Paul Britton, Managing Director, EnerSea Transport, LLC
    On behalf of EnerSea Transport, a Houston-based compressed natural 
gas (CNG) transportation and storage company, I would like to submit 
the following written comments for the record. My comments will be 
focused on how marine transportation of CNG can make a significant 
contribution to the effort to meet future natural gas demand in the 
U.S. and around the world.
    At EnerSea, we are commercializing a breakthrough, cost effective 
CNG marine transport and storage system. We have been able to develop a 
total delivery solution for transporting remote and heretofore stranded 
gas supplies to the marketplace. Specifically, the volume optimized 
transport and storage CNG system known as VOTRANSTM can best 
be described as a sea-going pipeline, comprised of long, large-diameter 
pipes contained within an insulated structure, integrated into a ship. 
We have improved upon previous COG concepts by combining optimal 
storage efficiency, the ability to transport both lean and rich gas, an 
innovative off-loading process to offshore ports, and significantly 
lower compression requirements. The result is increased vessel 
capacities and reduced overall costs.
    Our recently patented CNG technology has the ability to transport 
as much as 2 billion cubic feet of gas per ship to markets up to 4,000 
miles away at substantially lower cost than other gas transportation 
alternatives. The system provides unprecedented flexibility and risk 
management capabilities to accommodate expanding production volumes and 
developing markets--a value to consumers, producers and nations 
worldwide.
    To help meet increasing natural gas demand in the U.S., we are 
working to apply our CNG technology to stranded natural gas reserves in 
North and South America--specifically in places such as East Coast 
Canada, ultra-deepwater Gulf of Mexico, Alaska, Venezuela, Colombia and 
the Caribbean. Today, up to 80% of the natural gas fields worldwide are 
stranded and have yet to be developed--potentially a tremendous 
resource.
    As you are aware, these large gas reserves have been stranded 
because they are uneconomic to pursue due to geographic or geopolitical 
constraints. Through technological innovation, VOTRANSTM 
will reduce the need for field processing facilities. The scalability 
of the VOTRANSTM technology also allows for phased 
development opportunities to match fields with market demand centers. 
This provides the ability to pursue smaller and more remote gas 
reserves. In addition, fields can typically be brought on stream 
earlier compared to more capital intensive alternatives.
    I want to briefly highlight several activities that EnerSea has 
undertaken to date. EnerSea Canada was established to bring forward the 
development of Atlantic Canada offshore gas, specifically in the Grand 
Banks Region off the coast of Newfoundland to supply Northeast U.S. 
markets. We are establishing the world's first CNG Center of Excellence 
to promote and coordinate the participation of government, academia, 
the exploration and production industry and offshore service companies 
in the advancement of this emerging CNG industry for worldwide 
applications.
    In continuing our efforts to employ our innovative CNG technology 
and execute world-scale projects, we created partnerships in June and 
July of this year with Hyundai Heavy Industries, the world's largest 
shipbuilder and ``K'' Line, a leading LNG ship owner and operator. Both 
entities are working with us during our current Maritime Work Program 
to commercialize the technology and provide highly qualified gas ship 
operations experience. EnerSea is also working with American Bureau of 
Shipping to achieve Class Approval in Principle of its designs in early 
2003. EnerSea has had numerous discussions with the U.S. Coast Guard 
over the last 18 months and plans to submit its engineering package for 
USCG ``Concept Review'' in Summer 2003.
    In addition, we have been working with all the major producers to 
educate them on the benefits of CNG and specifically the application of 
EnerSea's CNG technology. Given these advances, we strongly believe 
that CNG is a viable option in the portfolio of technologies that will 
be needed to meet increasing natural gas demand. And, we are not alone 
in this belief. Congress recently passed, and President Bush signed 
into law the Maritime Transportation Security Act of 2002 that expanded 
the Deepwater Ports Act to create a regulatory framework for permitting 
the safe and secure transport and delivery of natural gas in a 
compressed or liquefied form to offshore terminals in the United 
States. Given this, our plan is to have completed transportation 
agreements in 2003 with gas delivery services to follow within 30-36 
months.
    Our nation's growing appetite for natural gas is a great 
opportunity as well as a challenge. All options must be considered for 
meeting that demand. EnerSea's CNG technology is a safe, viable and 
cost-effective option. When shaping the regulatory framework for the 
future, I encourage policymakers, industry planners and decision makers 
to be certain to include the application of CNG technologies for 
delivering currently stranded natural gas to market.
    Thank you for this opportunity to inform the Committee of the 
advances that our company is making and the promise of CNG transport 
for meeting our Nation's growing demand for natural gas.
                                 ______
                                 
                              American Petroleum Institute,
                                    Washington, DC, March 10, 2003.
Hon. Pete V. Domenici,
U.S. Senate, Washington, DC.
    Dear Senator Domenici: On February 25, 2003, the Senate Energy and 
Natural Resources Committee conducted a hearing on Natural Gas Supply 
and Prices. The American Petroleum Institute (API) is pleased to submit 
this letter and its attachment for the hearing's written record. API 
represents all sectors of the U.S. oil and natural gas industry, 
including those who explore for and produce oil and natural gas.
    Natural gas provides more than one-fifth of the nation's energy. It 
heats and cools millions of homes, fires a significant number of 
electric power plants, and is an essential feedstock for myriad 
industrial and agricultural products. The U.S. Energy Information 
Administration projects national consumption of natural gas will grow 
by 50 percent by 2025 and will provide a greater percentage of the 
nation's energy in the years ahead. It is expected that more than 80 
percent of new electric power generating capacity will use natural gas 
if sufficient supplies are available.
    Tighter inventories and higher prices for natural gas have raised 
questions about the adequacy of natural gas supplies--both now and in 
the future. The current market reflects this winter's colder weather in 
the Midwest, Mid-Atlantic and Northeast, which has increased demand for 
natural gas and reduced inventories. It also reflects the legacy of 
previous energy policy decisions that have discouraged or blocked 
exploration and production of domestic supplies of natural gas. Over 
the near term, higher prices may encourage some additional drilling and 
increase in supplies. However, there are significant obstacles to a 
future of ample and affordable supplies. Some of these include access 
and development restrictions, infrastructure constraints, high 
investment costs, and dwindling production from traditional sources.
    To change the future to one where our domestic energy resource 
potential is fully realized, it is imperative that comprehensive energy 
legislation be enacted.
    Looking specifically at natural gas prices, drilling and production 
and the challenges to increasing production in the years ahead, the 
following factors must be considered as energy legislation is shaped:
 Drilling has increased in recent years, but production has 
        declined
    U.S. natural gas production in the fourth quarter of 2002 was down 
about four percent from the fourth quarter of 2001. Indeed, U.S. 
natural gas production today is lower than it was five years ago, 
despite increases in drilling in recent years. In 2001, the industry 
drilled about 22,000 natural gas wells, nearly double the number of 
wells drilled in each of the four previous years. Drilling activity 
declined by 30 percent in 2002.
 Historically, rig counts and new production have lagged behind 
        price rises
    Higher prices do not necessarily lead to immediate increases in rig 
counts and new production. Additional production can take months or 
longer depending on factors such as government permitting, availability 
of drilling equipment, labor availability, time to drill the well, 
infrastructure to connect to natural gas pipelines, and the weather at 
the production site.
 Traditional sources/fields are in decline
    Since 1970, the United States has seen a progressive decline in the 
ability to satisfy the growth in natural gas demand from traditional 
sources--most of which are on private or state lands in the lower 48 
states. While the U.S. is a ``mature'' area, untapped fields remain. 
However, finding them and producing this gas is becoming more and more 
expensive. Canadian production also seems to be declining.
    Offshore production has declined in the shallow waters of the Gulf 
of Mexico. However, technology advances have allowed greater activity 
in deeper waters. Deepwater gas supplies offset most of the decline in 
shallow waters, thus stabilizing OCS gas supply. In addition to long 
lead times, deepwater fields tend to have shorter lives than onshore 
wells.
    Less mature areas such as the deep waters of the Gulf of Mexico and 
the eastern coast of Canada will help, but developing such areas can 
take years. In addition, the same technology that is helping us reach 
more areas is making it possible to deplete the gas found at a much 
faster rate, so that a typical well drilled today will decline at a 
faster rate than a well drilled 10 years ago.
 The denial or restriction of access and barriers to 
        development have made the industry ``prospect poor''
    Nearly 40 percent of the potential domestic natural gas resource 
base on federal land is either off limits or only open to development 
under highly restricted conditions. Offshore, federal moratoria 
prohibit the exploration and development of some of the nation's most 
promising resources. Federal policies in the Rocky Mountains have also 
placed substantial resources off limits. Studies by the National 
Petroleum Council and the Interior Department have concluded that 
nearly 40 percent of the gas resource base in the Rockies is restricted 
from development either partially or totally.
    The recent Energy Policy and Conservation Act (EPCA) inventory of 
onshore federal lands concentrated on land available for leasing. It 
did not adequately examine the significant impediments to development 
on lands already leased. Obtaining all the permits to begin a well 
after a lease has been obtained can take months or years, making the 
process extremely expensive and, in some cases, prohibitive.
    According to the Independent Petroleum Association of Mountain 
States, Applications for Permit to Drill (APD) that are supposed to 
take 30 days to process, took an average 137 days to be approved in 
2002--at least one took 370 days. From 2001 to 2002, the average time 
it took to obtain approval of a drilling permit increased 60 percent.
    The high cost of obtaining permits has made some projects 
marginally economic and has prevented some smaller companies from 
operating on some public lands.
    Opponents of drilling contribute to delay by exploiting conflicts 
in federal policies. For example, the Coastal Zone Management Act has 
been invoked by states to block natural gas pipeline projects as well 
as to block offshore leasing and development.
    Without production from areas currently under access and 
development restrictions, it is unlikely producers can significantly 
increase gas from the lower 48 states.
 Substantial E&P capital investment decisions, especially in 
        frontier areas, are not based on short-term prices
    To meet future natural gas demand, producers must invest many 
billions of dollars annually. To get these funds, the industry must 
compete against other domestic investment options that produce higher 
returns as well as competing against potentially lower cost foreign 
investments. Exploration and production planning can be risky because 
market volatility, as has recently been experienced, can deny producers 
reasonable assurance that their investments will be rewarded. For 
example, over the past two years prices have ranged from about $2 per 
million cubic feet of natural gas to $10 per million cubic feet. 
Prudent planning demands that producers average out prices over the 
long term to determine investments.
 There are serious infrastructure constraints
    Even with greater access, there may be significant challenges to 
delivering new gas. In the Rockies, there is concern about adequate 
pipeline capacity. Similarly, to tap the huge natural gas reserves in 
Alaska, a new pipeline is needed. Permitting challenges are formidable 
in Alaska and the lower 48 states. Recent uncertainty in the energy 
markets and questions about future regulatory policy may also 
discourage new pipeline construction.
    In summary, we appreciate the committee's interest in natural gas 
supplies and how our domestic energy resources can be developed to 
enhance economic growth while continuing to protect the environment. 
Natural gas is a clean-burning fuel and is essential to industrial, 
agricultural and residential consumers. Enclosed is a paper, Natural 
gas: will the promise be realized? * that further delineates the 
challenges ahead. Enacting comprehensive energy policy legislation that 
encourages the development of our domestic energy resources is 
imperative so that consumers can continue to enjoy reliable and 
affordable energy supplies. Again, API appreciates this opportunity to 
provide comments for the record. We would be pleased to answer any 
additional questions you may have.
---------------------------------------------------------------------------
    * The paper entitled ``Natural Gas: Will the Promise Be Realized'' 
has been retained in committee files.
---------------------------------------------------------------------------
            Sincerely,
                                        Charles E. Sandler,
                                                    Vice President.
                                 ______
                                 
     Statement of the National Petrochemical & Refiners Association

    The National Petrochemical & Refiners Association (NPRA) is a trade 
association representing virtually all of the U.S. refining industry 
and petrochemical producers that use processes similar to those by the 
refining industry. NPRA appreciates the interest of the Senate 
Committee on Energy & Natural Resources in developing a national energy 
plan that includes traditional supply and market-oriented policies for 
fossil fuels, including natural gas.
    NPRA believes that as part of the debate on national energy policy, 
it is essential that lawmakers recognize that natural gas is used as 
both a fuel and a feedstock to U.S. petrochemical producers and that 
its cost must be reasonable and its supply adequate and predictable in 
order to maintain a competitive U.S. petrochemical industry in a 
worldwide marketplace. Environmental requirements are creating 
increasing pressure for industrial facilities to convert to natural gas 
use. The impact of these environmental policies on natural gas demand 
has not been assessed, and must be part of the energy debate. NPRA 
believes that diverse, robust, and affordable supplies of all fossil 
fuels are essential for maintaining national security, economic growth, 
and the viability of the U.S. refining and petrochemical industries.

            NATURAL GAS IS AN INDUSTRIAL FEEDSTOCK AND FUEL

    Natural gas and natural gas liquids extracted from natural gas are 
important raw materials or feedstocks used in the manufacture of 
petrochemicals. About 70% of U.S. petrochemical manufacturers use 
natural gas liquids as feedstocks. In contrast, about 70% of 
petrochemical producers in Western Europe and Asia use naphtha (a heavy 
oil) as a feedstock. While oil is a global commodity whose price is set 
on the global market, natural gas liquids are more locally-traded 
commodities, so price increases in natural gas have had more impact on 
competitiveness in North American-produced petrochemicals. For many 
years, the U.S. has enjoyed a low-cost feedstock position relative to 
competitors in Europe and Asia. However, that advantage has been lost 
as the price of natural gas has soared. Also, domestic petrochemical 
manufacturers rely on large quantities of natural gas in their 
production processes, to fuel combined heat and power units, and to 
achieve energy efficiency.

                 PRODUCTS OF THE PETROCHEMICAL INDUSTRY

    The petrochemical industry supplies consumers with a wide variety 
of products that are used daily in homes and businesses. The industry 
manufactures chemicals that serve as ``building blocks'' in making 
everything from plastics to clothing to medicine to computers. They 
also contribute essential materials for making food and beverage 
containers, surgical gloves and gowns, fertilizer, blankets, cold 
weather and rain gear, sneakers, computers, insulation, cameras, 
medicines, artificial joints, auto and aircraft parts, disposable 
diapers, CDs, and many more key consumer products. Therefore, the costs 
of natural gas and natural gas liquids to petrochemical manufacturers 
affect the cost and availability of these essential consumer products.

           RECENT HISTORY OF UNPRECEDENTED PRICE INCREASES--
                   U.S. AT A COMPETITIVE DISADVANTAGE

    In 2000-2001, North American natural gas and natural gas liquids 
prices have risen to unprecedented levels and placed a significant 
portion of the domestic petrochemical industry at a disadvantage to 
European and Asian producers who use crude and its derivatives as 
feedstocks.
    Two years of extraordinarily high natural gas prices has resulted 
in a negative trade balance for the U.S. economy. This negative trade 
balance is permitting foreign businesses to capture U.S. market share 
because European and Asian producers are not experiencing increased 
feedstock prices.
    Another example of the competitive imbalance is the shortage and 
cost of ethane and ethylene. Ethane is the principal hydrocarbon raw 
material for organic chemistry in the United States. Currently, only 
50% of the ethane available is actually extracted from the raw gas 
stream. NPRA believes it is also important for the Congress to ensure 
there is enough ethane available to preserve the global competitiveness 
of this important U.S. industry.

          PUBLIC DEBATE ON THE FUTURE OF NATURAL GAS SUPPLIES

    There is serious public debate on the future of natural gas and 
natural gas supplies. Natural gas demand is projected to increase by 
60% by the year 2020. Based on this forecast, Congress must act on 
policies which will create additional natural gas supply sources on 
public lands. Environmental policies that promote multi-pollutant 
approaches to emission reductions and tax incentives for alternative-
fueled vehicles will drive up the demand for gas and have significant 
impacts on natural gas supply and price. The impact on natural gas 
supply of such policies and programs that result in fuel switching 
should be factored in when making any relevant policy decisions. If the 
Congress should decide to press forward with increased use of natural 
gas, it must be mindful of what increased demand will do to the costs 
and competitiveness of businesses that use this fuel as a feedstock.
    If policies regarding natural gas are to be modified, they must 
include increased access and development opportunities to onshore 
public lands as well as those on the Outer Continental Shelf. New and 
promising domestic areas for development must be open for exploration 
and production. In the meantime, NPRA would urge caution as Congress 
and the Administration consider policies that will accelerate the 
demand for natural gas, unless they are accompanied by efforts to 
increase its supply.

            SENATE-PASSED ENERGY LEGISLATION--107TH CONGRESS

    During the second session of the 107th Congress, the Senate passed 
energy legislation that could have negatively impacted U.S. 
petrochemical producers who use natural gas as a fuel and feedstock. 
These provisions were not adequately debated and could have resulted in 
short-sighted energy policy if allowed to prevail.
    Ethanol Mandate--NPRA is on record in strong opposition to the 
Senate-passed ethanol mandate which would require that gasoline contain 
5 billion gallons of ethanol by 2012. In addition to our policy of 
opposing bans and mandates, NPRA believes that the ethanol provision 
could have significantly impacted petrochemical producers who use 
natural gas as a fuel and feedstock. The ethanol mandate was intended 
to spur uneconomic production and consumption of ethanol, which means 
that additional plants would be built in excess of what we would see 
under current law.
    These new ethanol production plants may very well be natural-gas 
fired, which would increase competition for natural gas and in all 
probability, this would result in increased feedstock costs. These 
increased costs would put additional competitive pressure on the 
domestic petrochemical industry which is already feeling the effects of 
rising international competition.
    Combined Heat & Power--Combined heat & power (CHP) facilities use 
natural gas to create electric power and steam with the same, constant 
amount of fuel. These power generation facilities are usually located 
physically closer to the power sources and are usually more efficient 
because they avoid transmission losses associated with the consumption 
of power generated many miles away by large electric utilities. Thus, 
CHP facilities enhance energy efficient projects.
    Last year's energy bill included a provision that would have 
eliminated requirements that utilities purchase or sell electricity to 
qualifying cogeneration facilities under the Public Utility Regulatory 
Policies Act (PURPA). PURPA has been has been important in allowing CHP 
units that serve as industrial and commercial facilities to compete in 
an otherwise monopoly market. NPRA supported an amendment by Senators 
Tom Carper (D-Delaware) and Susan Collins (R-Maine) that would have 
continued current law, and required utilities to purchase electricity 
from cogeneration facilities that did not have access to competitive 
wholesale markets. If electricity deregulation is included in the 
energy bill for the 108th Congress, the Senate must act to preserve the 
critical energy supplies provided by CHP.

                               CONCLUSION

    Natural gas and natural gas liquids provide the primary feedstocks 
in domestic petrochemical plants. Their availability at a reasonable 
cost is essential to keep the U.S. petrochemical industry competitive 
in a worldwide marketplace. We hope that the Congress will recognize 
that increased demands on natural gas supplies result in even tighter 
supplies and the cost of gas as a feedstock will continue to rise. 
While the principal focus of the natural gas debate will be on 
development of resources on public lands, policy makers should 
recognize that since natural gas is used as both a fuel and an 
industrial feedstock that there could be negative impacts to our 
businesses if natural gas demand increases but supplies remain tight. 
One thing is certainly clear; we need a thorough review and analysis of 
natural gas-related policies and gas supply and demand to maintain a 
vibrant U.S. petrochemical industry and U.S. economy.
                                 ______
                                 
              Statement of the American Chemistry Council

    The American Chemistry Council (ACC) submits the following 
statement regarding natural gas supply and prices.
    ACC represents the U.S.'s leading companies engaged in the business 
of chemistry. ACC members apply the science of chemistry to produce 
innovative products and services that make people's lives better, 
healthier and safer. ACC is committed to improved environmental, health 
and safety performance through Responsible Care, common sense 
advocacy designed to address major public policy issues, and health and 
environmental research and product testing. The $460 billion business 
of chemistry is a key element of the nation's economy. It is the 
country's largest exporter, accounting for ten cents out of every 
dollar in U.S. exports. Chemistry companies invest more in research and 
development than any other business sector. Safety and security have 
always been primary concerns of ACC members, and they have intensified 
their efforts, working closely with government agencies to improve 
security and to defend against any threat to the nation's critical 
infrastructure.

                          SUMMARY OF TESTIMONY

    The U.S. chemistry business is highly dependent on natural gas, 
both as a source of fuel and as a raw material for many of its 
products. Our industry is a significant component of the U.S. economy. 
However, despite our advances in energy efficiency, this contribution 
requires enormous quantities of reasonably priced natural gas. Current 
high natural gas prices, caused primarily by constrained supplies and 
increased demand, are having a devastating impact on our industry. 
Federal government policies that contribute to constrained domestic 
natural gas production and caused utilities and other industries to 
switch from other fuels to natural gas contribute to our industry's 
situation. If the U.S. chemistry business is to remain competitive in 
today's global market and continue to contribute revenue, jobs, 
research and other benefits to the U.S. economy, natural gas prices 
must come down. Appropriate federal policies are needed to ensure a 
better balance between the supply of and demand for natural gas, and to 
keep prices at a reasonable level.

      THE BUSINESS OF CHEMISTRY IS HIGHLY DEPENDENT ON NATURAL GAS

    The current price of natural gas is the chemical industry's number 
one economic issue. Natural gas is the lifeblood of the chemistry 
business in the U.S. Not only do we use natural gas as a fuel in our 
manufacturing processes, much like other industries, but we also use it 
as an ingredient, or feedstock, for many of the products we make.
    Natural gas and natural gas liquids contain hydrocarbon molecules 
that are split apart during processing and then recombined into useful 
chemical products. These products include life-saving medicines, health 
improvement products, technology-enhanced agricultural products, more 
protective packaging materials, synthetic fibers and permanent press-
clothing, longer-lasting paints, stronger adhesives, faster 
microprocessors, more durable and safer tires, lightweight automobile 
parts, and stronger composite materials for aircraft and spacecraft. 
The business of chemistry also makes many of the products that help 
save energy throughout the entire economy, including insulation, house 
wraps, lubricants, and high-strength light-weight materials, enabling 
American industries and consumers to be more energy efficient. The 
business of chemistry is the only part of the economy that adds value 
to these hydrocarbon molecules rather than combusting them for energy.
    Natural gas accounts for nearly thirty-nine percent of all energy 
consumption by the business of chemistry. Natural gas liquids that are 
derived from natural gas or refinery operations account for another 
twenty-three percent. In total, more than half of the U.S. business of 
chemistry's energy needs come from natural gas.
    On average, more than $1 of every $10 the industry spends on 
materials is for natural gas. For some petrochemical producers, natural 
gas represents nearly one-quarter of the cost of materials. And 
nitrogenous fertilizer producers spend $9 of every $10 for natural gas.
    The U.S. business of chemistry has invested billions of dollars in 
facilities that make chemical products from natural gas and natural gas 
components. These facilities do not have the ability to switch to other 
inputs and produce these products. This infrastructure was built based 
on the competitive advantage the U.S. offered through its natural gas 
supply.
    While the U.S. chemistry business is the nation's single largest 
manufacturing consumer of natural gas, we are extremely energy 
efficient in the use of that gas. Through the use of combined heat and 
power (``CHP'') generation, our facilities create two forms of energy--
electric energy and thermal energy or steam, and both are put to work. 
The efficiency rating of many of our CHP facilities is often twice that 
of traditional electric generators. This efficiency level is further 
enhanced because the generation is physically located close to where it 
is used, avoiding transmission line losses. Use of CHP technologies by 
the business of chemistry accounts for nearly a third of all CHP used 
in manufacturing. And through the use of CHP technology, the business 
of chemistry has reduced its total fuel and power energy consumption 
per unit of output by more than fortythree percent since 1974. 
Nonetheless, our industry's natural gas fuel needs remain substantial.
    Because of our industry's duel use of natural gas, as well as our 
significant presence in the U.S., the business of chemistry today 
accounts for eleven percent of domestic natural gas consumption, second 
only to electric utilities. As a result, changes in the natural gas 
market, such as constricted supply and inflated prices, have a 
particularly severe impact. In order for the domestic business of 
chemistry to remain competitive in the global marketplace and to be 
able to continue to provide employment and other benefits here at home, 
it is essential that measures be taken to increase natural gas supplies 
and to make these supplies available at reasonable prices.

          NATURAL GAS DEMAND IS INCREASING, SUPPLY IS SHORT, 
                          AND PRICES ARE HIGH

    The recent history of natural gas prices is a study in commodity 
price volatility. On January 4, 2000, the average spot price of natural 
gas at the Henry Hub was $2.15/mmBtu. On January 5, 2001, the price had 
spiked up to $9.82/mmBtu. On January 4, 2002, the price was $2.36/mmBtu 
and on January 3, 2003, the average spot price at the Henry Hub was 
$5.13/mmBtu. While this extreme volatility is indicative of a very 
tight supply situation in general, the more worrisome aspect of the 
experience of the last three years is what it foretells for the long-
term. Historically, when gas prices began an upward climb, producers 
responded to the higher prices by drilling more wells, which produced 
additional supply and consequently lowered the price.
    Our experiences over the past few years have not followed this 
history. Although gas producers responded to the extraordinary high 
prices of 2001 by greatly increasing the number of wells drilled, this 
activity did not lead to a commensurate increase in supply. The supply 
of natural gas actually increased only marginally during 2001 despite 
record high levels of drilling rigs operating. The price decline from 
January 2001 to January 2002 was a result of what economists call 
``demand destruction,'' brought about by a mild spring and summer and, 
ominously, the closing or curtailment of manufacturing facilities. In 
other words prices dropped not because supply increased, but because 
demand decreased.
    The reaction of producers during this most recent price run-up is 
much more cautious. Fewer new rigs are going into the fields and gas 
production has not responded to higher prices. This ``Catch-22'' 
response of producers not placing new rigs in service because they are 
fearful that prices will drop before they can recoup their costs only 
serves to keep the price high.
    A disturbing reality of the U.S. natural gas market is that nearly 
70% of it is price insensitive. This means that 70% of gas consumers 
have no option to either stop using energy or to use a different form 
of energy and must pay whatever the price is for the gas they need. The 
remaining 30% of demand, predominantly industrial manufacturers, can 
adjust to gas price swings by switching to more reasonably priced fuels 
or by ceasing to operate their manufacturing facilities. It is in this 
30% that demand destruction occurs. In the past, this demand 
destruction generally has been temporary. Higher prices led to 
increased production and lesser demand, thereby increasing supply and 
moderating prices. Once prices returned to more economic levels, 
industrial consumers switched back to natural gas or restarted idled 
facilities.
    In light of recent trends--record numbers of working drill rigs in 
2001 did not increase supply; more stringent air quality regulations 
that limit or eliminate the ability to fuel switch; ever increasing 
demand for natural gas from price insensitive users--there is a 
significant risk that this historical pattern will not repeat itself. 
Rather, ACC is concerned that temporary demand destruction may become 
permanent demand destruction for many of its members.

                     THE IMPACT OF HIGH GAS PRICES

    Restricted supplies and high prices for natural gas severely limit 
the ability of U.S. chemical manufacturers to remain competitive with 
foreign competitors. The business of chemistry in the U.S. is 
concentrated in the Gulf Coast region largely because of the region's 
proximity to a traditionally abundant, low cost supply of natural gas 
resources. While about seventy percent of U.S. petrochemicals 
production uses natural gas as a feedstock, the same percentage of 
producers in Western Europe and Asia use naphtha, a crude oil 
derivative. Unlike crude oil, the price of which is set by the global 
market, natural gas is not as broadly traded, with the result that 
price increases for natural gas in North America are felt only in North 
America. For many years, the U.S. business of chemistry enjoyed the 
benefit of relatively low cost feedstocks relative to our foreign 
competitors, enabling the industry to become the global leader in 
chemical products. A tightened natural gas market and soaring natural 
gas prices, however, put this position in jeopardy. For the business of 
chemistry, experience shows that, although this number fluctuates 
depending on the price of crude oil, the price for natural gas at which 
we become unable to compete in global markets is between $3.25 and 
$4.00. Current prices are hovering around $6.00.
    High natural gas prices significantly cut into our industry's 
profitability. For every one-dollar increase in the price of natural 
gas, over the course of a year, our industry incurs approximately $1 
billion in additional costs. Yet, because we compete in a global 
market, U.S. companies are unable to pass these added costs for natural 
gas along to their customers if our products are to remain 
competitively priced with those produced by our foreign competitors. In 
1999, when the price of natural gas averaged $2.27, the operating 
margin for basic chemical companies was 6.8%. In 2001, when the price 
of natural gas rose to an average of $4.27, the operating margin 
dropped to 0.6%.
    High natural gas prices also negatively impact productivity and 
employment in our industry. In any industry, a company faced with 
declining profitability must evaluate whether or not to continue 
operations. During the 2000-2001 ``spike'' in natural gas prices, many 
companies idled their operations. About fifty percent of the industry's 
methanol capacity and fifteen percent of the industry's ethylene 
capacity were simply shut down during this time. Many workers were sent 
home. As natural gas prices came down plants reopened. These relatively 
short-term increases in natural gas prices led to relatively short-term 
shutdowns. However, there are serious questions regarding how these 
companies will respond over the long-term if faced with a business 
environment with sustained conditions of tightened natural gas supply 
and high natural gas prices. For our employees, demand destruction 
sooner or later becomes job destruction.
    As the second largest consumer of natural gas in the United States, 
trailing only electric utilities, the business of chemistry has been 
severely affected by these steep increases in natural gas prices. Prior 
to the run-up in gas prices in 2000 and 2001, the business of 
chemistry, America's largest export industry, contributed one of the 
nation's highest positive trade balances. Today, after two years of 
high gas prices, our industry is facing a negative trade balance for 
the first time ever. High U.S. manufacturing costs, tied to inflated 
natural gas prices, allow foreign competitors, who do not face the same 
elevated energy and feedstock prices, to become low cost producers and 
capture market share at our expense. This has resulted in thousands of 
jobs lost and plants shut down, and the movement of investment capital 
overseas.
    Here are some specific examples of the dramatic effect that the 
2001 spike in natural gas prices had on companies in the business of 
chemistry:

   Almost one-half of the nation's methanol capacity and one-
        third of its ammonia capacity were shut down. Five years ago, 
        the U.S. was relatively self-sufficient for its methanol needs. 
        Now, we import about the same amount of methanol as we do crude 
        oil.
   One company moved more than 750,000 pounds of ethylene 
        production from Louisiana to Germany solely because of high 
        natural gas prices. Much of this is then sold into U.S. 
        markets, enhancing Germany's trade balance and further harming 
        the U.S. balance of trade.
   Ethylene capacity dropped between ten and fifteen percent, 
        with at least five percent of this drop due to plant shutdowns. 
        Net trade in ethylene was at one-fifth of the 1997 level in 
        2001.
   The Gulf Coast region's economy, where most of the U.S. 
        petrochemical industry is located, was hit particularly hard 
        with widespread job losses due to plant shutdowns. In Louisiana 
        alone, for example, over 2,000 jobs have been lost over the 
        last four years just in the ammonia industry.
   The combined effect of higher natural gas prices led to 
        fewer U.S. exports, greater U.S. imports, and a rising U.S. 
        trade deficit. As a result, the U.S.'s export levels in 2001 
        fell at least $13.5 billion, $4.5 billion of which was 
        attributable to the business of chemistry.
   Historically, ethylene production based on U.S. ethane (from 
        natural gas) has had the lowest cost per pound after the Middle 
        East, which has abundant inexpensive natural gas resources. 
        However, in 2002, that low cost position was eroded. In 2002, 
        ethylene production costs rose globally as the price of oil 
        also rose above historic levels. Natural gas experienced higher 
        price increases relative to oil, however, with the result that 
        U.S. ethane-based production lost its clear low cost position.

    Although the impact on our business is felt particularly hard, the 
chemical industry is not alone. For example, the U.S. fertilizer 
industry is similarly dependent upon natural gas and similarly 
affected, as are its customers, America's farmers. U.S. consumers also 
are affected in everything from increased home heating and electricity 
costs to higher prices on consumer goods as production costs rise. 
Those at the lower end of the income scale are particularly hard hit.

                         POLICY RECOMMENDATIONS

    Faced with the rising demand for natural gas and falling levels of 
domestic production, and the resultant impact on natural gas prices, it 
is now more important than ever for Congress to look for ways to 
promote abundant and diversified sources of domestic energy, including 
natural gas, coal, oil, nuclear, and cost-competitive renewable 
resources. Natural gas prices need not be this high. Appropriate 
policies can ensure adequate supplies of natural gas, helping keep 
prices at a reasonable level and therefore helping U.S. companies to 
remain competitive in the global market.
    As Congress and this Committee consider how to address our nation's 
growing energy needs, we urge you to consider the following policies:

   The U.S. must increase its domestic production of natural 
        gas. Recent legislative, regulatory and market trends have 
        placed greater demands on our natural gas supply without 
        providing for commensurate measures to increase production. 
        Congress must take appropriate action to ensure adequate 
        supplies, produced in an environmentally protective manner.
   To do this, Congress must reject initiatives to place 
        moratoria on new exploration and production. In addition, it 
        must open new, promising areas to exploration and production. 
        This includes portions of the Rocky Mountain region, the Outer 
        Continental Shelf areas, and the Eastern Gulf of Mexico and 
        Alaska. Current gas fields are quite mature and failing to 
        adequately meet current demand. Rig counts in these mature 
        fields rose dramatically in response to the 2000-01 price 
        spikes, but gas production did not. Access to new reserves is 
        necessary not only to meet new demands, but simply to sustain 
        current production levels. In addition, Congress should support 
        environmentally protective development and production of 
        natural gas from coal bed methane.
   Congress also should take action to enable timely increases 
        in the amount of natural gas that is imported to the U.S. via 
        pipelines, particularly from Canada, and in the form of 
        liquefied natural gas (``LNG'') from various other countries. 
        In a similar vein, consideration must be given to the 
        disturbing growth of natural gas exports from the U.S. to 
        energy-rich Mexico. The Administration and Congress should seek 
        to work with the Mexican government to develop greater gas and 
        electricity production in that country in order to meet its 
        projected demand and provide opportunities for export to the 
        U.S.
   It is not sufficient to merely have access to ample economic 
        supplies of gas. We must also ensure that this gas can be 
        delivered to the consumer. In this regard, Congress needs to 
        recognize the fundamental change occurring in the energy 
        industry as a whole and in the natural gas industry in 
        particular. During this evolution, the ability of industry 
        participants to capitalize and finance high-risk infrastructure 
        projects to deliver gas from the wellhead to the consumer has 
        been severely limited. It is critical that current federal 
        policies do not exacerbate this capital liquidity problem. It 
        may even be necessary for the federal government to act 
        affirmatively to ensure that critically needed infrastructure 
        can be financed and constructed.
   In addition, Congress should support the FERC's efforts to 
        streamline natural gas pipeline construction to enable gas to 
        enter the mid-continent and Northeastern markets, enhance gas 
        supply and distribution capabilities, and relieve system 
        constraints.
   On the demand side, Congress and the Administration must 
        take a more balanced approach to fuel use and demand. Policies 
        that discourage the use of coal and encourage the use of 
        natural gas to reduce emissions from utility and manufacturing 
        operations must be balanced with policies that ensure adequate 
        supplies of gas to avoid upsetting the demand-supply balance. 
        The adoption by the last Congress, with the blessing of the 
        Administration, of a moratorium on oil and gas production in 
        the Eastern Gulf of Mexico, while faced with legislation that 
        would drive even greater reliance on gas for electric power 
        production, exhibits a gross disconnect between demand and 
        supply policies that simply cannot continue without causing 
        significant damage to the U.S. economy.
   Congress should also encourage the expanded use of highly 
        efficient combined heat and power (``CHP'') generation systems. 
        CHP plants are about twice as efficient as traditional utility 
        power plants and are generally located at or near the demand 
        site, which even further improves efficiency by reducing energy 
        lost through transmission ``line-loss.'' The emission and 
        resource use benefits of this technology are obvious. Federal 
        statutes that allow CHP systems to operate in monopoly utility 
        regions must remain. New rules and statutes that promote CHP 
        should be adopted.

    Finally, our nation must rely on its natural resource strengths. 
Certainly our most obvious natural energy resource strength is abundant 
coal. Congress and the Administration must advance development of 
electric power production from clean coal technologies. We cannot, as a 
nation, walk away from such an obvious choice for energy self-reliance. 
We should take all reasonable measures to advance its use.
    Failing the enactment of these and other policies to increase 
domestic natural gas production and the importation of natural gas from 
abroad, to expedite the gathering and transportation of such gas, and 
to improve the efficiency of gas usage, the U.S. will continue to see 
contraction of the chemical industry, more jobs lost, and a greater 
reliance upon foreign sources for materials critical to our national 
economy.
    Thank you again for giving us the opportunity to present our views 
and concerns. We stand ready to discuss these issues and potential 
legislation, and to assist the Committee in any way we can.
                                 ______
                                 
         Statement of the Fertilizer Institute, Washington, DC

    The Fertilizer Institute (TFI) appreciates the opportunity to 
submit this testimony before the Senate Energy and Natural Resources 
Committee regarding the natural gas supply and price impact on the 
fertilizer industry.
    TFI is the leading voice of the nation's fertilizer industry, 
representing the public policy, communication and statistical needs of 
manufactures, producers, retailers and transporters of fertilizer. In 
addition to energy policy, issues of interest to TFI members include 
the environment, international trade, security, transportation and 
worker health and safety.
                         fertilizer and energy
    Issue: U.S. manufacturers of fertilizer products are currently 
facing a natural gas and electricity crisis due to the rising price and 
lack of supply of natural gas and the increased demand for electricity. 
These energy sources are essential components in the production of 
plant nutrients which are, in turn, necessary inputs in the nation's 
food production system.
    Background: The United States needs reliable and plentiful supplies 
of natural gas for nitrogen fertilizer production, to meet critical 
agriculture and food production needs. Natural gas is the fundamental 
feedstock ingredient for the production of nitrogen fertilizer and 
represents 70 to 90 percent of the production cost of one ton of 
anhydrous ammonia--the building block for most other forms of 
commercial nitrogen plant nutrients.
    According to the U.S. Department of Commerce, 13.05 million short 
tons of ammonia were produced in calendar year 2001, with 88 percent of 
this total used to produce fertilizer. According to The Fertilizer 
Institute's (TFI) 2000 production cost survey, the production of one 
ton of ammonia requires an average of 33.6 million British Thermal 
Units (MMBtu--the standard measure of thermal energy in the United 
States) of natural gas. Therefore, an estimated 440 trillion Btu's of 
natural gas were used in 2001 for ammonia manufacturing, consuming 
about 3 percent of the total U.S. natural gas consumption.
    Phosphate and potash fertilizers originate as minerals and are 
mined from surface (phosphate) and deep shaft (potash) mines, which use 
significant amounts of ``green source'' electricity. The U.S. 
Department of Energy estimates that demand for electricity will 
increase 43 percent by 2020. If the majority of new electricity-
generating plants use natural gas as a fuel source, and if supplies do 
not keep pace with this growing demand, the North American nitrogen 
fertilizer industry risks becoming uncompetitive in the world market.
    TFI Action: To address the natural gas and electricity crisis 
currently facing U.S. consumers and fertilizer manufacturers, TFI is 
working to include the following policy objectives in federal energy 
legislation:

   Increasing the supply of natural gas through specific 
        production incentives, including tax incentives for natural gas 
        production from marginal wells and sources that are more 
        difficult to find and maintain (tight formation, coal seams and 
        deepwater); selected tax incentives for investment in assets 
        and technologies used in exploring for natural gas; opening of 
        additional federal lands and offshore areas to environmentally 
        sensitive exploration efforts; and increased staff and 
        infrastructure to expedite permitting process for exploration 
        on federal lands and Outer Continental Shelf.
   Elimination of disincentives relating to the use of 
        conventional fuel sources, such as coal, oil and nuclear, for 
        electric power production by allowing owners to make 
        improvements, modifications and expansions of existing coal-
        fired power plants without invoking the application of new air 
        quality requirements; and expediting the re-licensing process 
        for hydro and nuclear plants.
   Eliminate environmental disincentives so as not to 
        discourage hydrocarbon production. Environmental disincentives 
        such as increased regulations on greenhouse gas and ammonia 
        emissions, water issues preventing coal bed methane production, 
        and regulations that keep energy producing lands out of use, 
        discourage manufacturing and production capability and have 
        negative affects on a healthy economy.
   Increasing natural gas pipeline capacity by expediting and 
        streamlining the approval process for new natural gas pipeline 
        projects.
   Supporting tax and other incentives for the production of 
        electricity from industrial process waste heat sources.
   Supporting research into ``clean coal'' and coal 
        gasification technologies to produce electricity.
   Promotion of alternative fuel sources such as biomass and 
        renewable fuels.
   Encouraging greater use of energy sources other than natural 
        gas for those uses, unlike fertilizer production, where there 
        is an alternative.
   Providing assistance to farmers facing high-energy costs by 
        providing tax rebates on fuel and/or fertilizer purchases and 
        reduced taxes on diesel fuel.
   Improving electricity delivery infrastructure with the 
        construction of additional electric power transmission lines, 
        supporting the Federal Energy Regulatory Commission's (FERC) 
        efforts to place transmission lines under the control of 
        independent Regional Transmission Organizations (RTOs) when 
        these transfers are completed on a cost effective basis and 
        retail customers are adequately protected from potential long- 
        and short-term market power abuses, delegating federal powers 
        of eminent domain to RTOs attempting to build FERC-approved 
        lines.
   Ensure that industrial cogenerators and other small power 
        producers have access to the transmission grid on fair and 
        reasonable terms, without unfair scheduling penalties, tariff 
        requirements or regulatory impediments. Furthermore, oppose 
        efforts to repeal the Public Utilities Holding Company Act 
        (PUHCA) or the Public Utility Regulatory Policies Act (PURPA).
Questions and Answers
    Q. Are there any viable substitutes for natural gas in nitrogen 
fertilizer production?
    A. Natural gas is the fundamental feedstock ingredient, for which 
there is no practical substitute, for the production of nitrogen 
fertilizer and the major cost component of making all basic nitrogen 
fertilizer products. The cost of natural gas represents 70 to 90 
percent of the production cost of one ton of anhydrous ammonia nitrogen 
fertilizer. Anhydrous ammonia is the building block for most other 
forms of commercial nitrogen plant nutrients and a significant input 
for many phosphate fertilizers.
    Q. What is hedging and to what extent do fertilizer companies hedge 
gas purchases?
    A. When they are faced with fluctuating market prices for natural 
gas, fertilizer companies can use hedging to reduce the risk of natural 
gas price fluctuations. Utilizing a variety of tools (including options 
and futures contracts), a company can ``lock-in'' the price at which it 
will buy (or sell) a quantity of natural gas in a particular future 
month. Obviously, the prices which can be locked-in are those which are 
available on the futures market at the time of the arrangement; these 
prices reflect the market's current expectation of the future market 
price in the delivery month. Hedging does not guarantee a ``low'' gas 
price, and it does not guarantee a ``belowmarket'' gas price. Indeed, 
when the delivery month arrives, a company may find that the price it 
has locked-in is higher than the prevailing spot market price. For this 
reason, fertilizer companies typically hedge only a portion of their 
total gas purchases, leaving the remainder for purchase at the 
prevailing market price in the delivery month. The idea is to ``smooth 
out'' natural gas input costs.
    Q. Do natural gas prices affect fertilizer prices and what factors 
determine how much a farmer pays for fertilizer?
    A. While the cost of natural gas plays a significant role in 
determining the profitability of tile North American nitrogen 
fertilizer manufacturing industry, natural gas prices and fertilizer 
retail prices are not directly related. There are many market variables 
that ultimately determine the price a farmer pays for fertilizer 
products. Time of year, transportation costs, proximity from major 
ports or terminals, weather effects on field work and planting are just 
a few of the supply/demand market forces that ultimately determine the 
price of fertilizer.
    Q. Where does the United States get its natural gas from?
    A. Natural gas used in America for industrial purposes, heating 
homes and other uses come from numerous oil and gas fields located in 
many states. Louisiana, Texas, Oklahoma, Wyoming, Alaska, California, 
Kansas, Colorado, West Virginia, Pennsylvania and the Gulf Coast are 
just a few of the traditional U.S. oil and gas producing states. A 
significant but varying amount of natural gas is also imported to the 
United States from Canada via pipelines.
    However, the United States is the most mature oil-producing region 
in the world, and much of our easy-to-find resource base has been 
depleted. The Gulf of Mexico, the U.S. East Coast from Maryland to 
Florida and the U.S. Pacific Coast from the state of Washington all the 
way down to California's border with Mexico, are also rich in oil and 
gas resources. Unfortunately, much of the nation's oil and gas resource 
base in these areas reside on federal lands and in federal waters, 
which is not currently open to exploration or development.
    Q. On average, how much did natural gas cost per million Btu in 
2002?
    A. According to Natural Gas Week, the U.S. wellhead natural gas 
price average for 2002 was approximately $3.33 mmbtu.
    Q. How much do U.S. consumers spend annually on fertilizer?
    A. U.S. food producers, lawn and garden specialists and homeowners 
annually invest more than $10 billion in fertilizer products.

                             ----URGENT----

To: Senator Jeff Bingaman

From: Jon M. Huntsman

Regarding Outrageous Increases in Natural Gas Pricing

    Today, natural gas prices in America increased by over 40% from 
$6.61 to $9.60, This unparalleled spike in prices represents the 
highest natural gas prices ever. There is pure manipulation going on to 
cause prices to increase so dramatically. One year ago, prices of 
natural gas were at $3.15 per MMBtu. The average price of natural gas 
for the past ten years is $2.61. Our company and all others in the 
chemical industry, and most of the manufacturing jobs in America, will 
go out of business with gas prices this high. Billions of dollars will 
be lost in export trade. Millions of jobs are at risk. As our nation 
moves toward war, our entire manufacturing sector is jeopardized and 
becoming uncompetitive with the rest of the world. There is no energy 
policy with this administration. It is killing manufacturing and 
commerce in America. I repeat, Jeff, we are losing thousands of jobs, 
and our entire chemical industry because this administration refuses to 
adopt an energy policy. I am very frightened!
    This only happened once before in history--in 2000-2001, Felonious 
price manipulation existed that almost sank the chemical industry and 
cost our company hundreds of millions of dollars. Evidence indicated 
that false trades occurred and the market was fraudulently manipulated. 
There was enormous turmoil in California and all the western states as 
a result.
    In the longer term, we know that greater use of coal, the 
advancement of nuclear power and other safe alternatives will 
transpire, but in the short turn, our company, our industry, and 
manufacturing in general, as well as the consumer--millions and 
millions of consumers--are being fraudulently ripped off by big oil 
companies and futures traders at the New York Mercantile Exchange who 
establish the prices for natural gas.

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