[House Hearing, 107 Congress]
[From the U.S. Government Printing Office]





   FIRST IN SERIES ON EFFECT OF FEDERAL TAX LAWS ON THE PRODUCTION, 
                   SUPPLY, AND CONSERVATION OF ENERGY

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

                                HEARING

                               before the

                SUBCOMMITTEE ON SELECT REVENUE MEASURES

                                 of the

                      COMMITTEE ON WAYS AND MEANS
                        HOUSE OF REPRESENTATIVES

                      ONE HUNDRED SEVENTH CONGRESS

                             FIRST SESSION

                               __________

                              MAY 3, 2001

                               __________

                           Serial No. 107-19

                               __________

         Printed for the use of the Committee on Ways and Means


                    U.S. GOVERNMENT PRINTING OFFICE
74-221                      WASHINGTON : 2001

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_______________________________________________________________________



                      COMMITTEE ON WAYS AND MEANS

                   BILL THOMAS, California, Chairman

PHILIP M. CRANE, Illinois            CHARLES B. RANGEL, New York
E. CLAY SHAW, Jr., Florida           FORTNEY PETE STARK, California
NANCY L. JOHNSON, Connecticut        ROBERT T. MATSUI, California
AMO HOUGHTON, New York               WILLIAM J. COYNE, Pennsylvania
WALLY HERGER, California             SANDER M. LEVIN, Michigan
JIM McCRERY, Louisiana               BENJAMIN L. CARDIN, Maryland
DAVE CAMP, Michigan                  JIM McDERMOTT, Washington
JIM RAMSTAD, Minnesota               GERALD D. KLECZKA, Wisconsin
JIM NUSSLE, Iowa                     JOHN LEWIS, Georgia
SAM JOHNSON, Texas                   RICHARD E. NEAL, Massachusetts
JENNIFER DUNN, Washington            MICHAEL R. McNULTY, New York
MAC COLLINS, Georgia                 WILLIAM J. JEFFERSON, Louisiana
ROB PORTMAN, Ohio                    JOHN S. TANNER, Tennessee
PHIL ENGLISH, Pennsylvania           XAVIER BECERRA, California
WES WATKINS, Oklahoma                KAREN L. THURMAN, Florida
J. D. HAYWORTH, Arizona              LLOYD DOGGETT, Texas
JERRY WELLER, Illinois               EARL POMEROY, North Dakota
KENNY C. HULSHOF, Missouri
SCOTT McINNIS, Colorado
RON LEWIS, Kentucky
MARK FOLEY, Florida
KEVIN BRADY, Texas
PAUL RYAN, Wisconsin

                     Allison Giles, Chief of Staff

                  Janice Mays, Minority Chief Counsel

                                 ______

                Subcommittee on Select Revenue Measures

                    JIM McCRERY, Louisiana, Chairman

J.D. HAYWORTH, Arizona               MICHAEL R. McNULTY, New York
JERRY WELLER, Illinois               RICHARD E. NEAL, Massachusetts
RON LEWIS, Kentucky                  WILLIAM J. JEFFERSON, Louisiana
MARK FOLEY, Florida                  JOHN S. TANNER, Tennessee
KEVIN BRADY, Texas
PAUL RYAN, Wisconsin

Pursuant to clause 2(e)(4) of Rule XI of the Rules of the House, public 
hearing records of the Committee on Ways and Means are also published 
in electronic form. The printed hearing record remains the official 
version. Because electronic submissions are used to prepare both 
printed and electronic versions of the hearing record, the process of 
converting between various electronic formats may introduce 
unintentional errors or omissions. Such occurrences are inherent in the 
current publication process and should diminish as the process is 
further refined.
.................................................................




                            C O N T E N T S

                               __________
                                                                   Page

Advisory of April 26, 2001, announcing the hearing...............     2

                               WITNESSES


U.S. Department of the Treasury, Joseph Mikrut, Tax Legislative 
  Counsel........................................................     9
U.S. Department of Energy, Mary J. Hutzler, Director, Office of 
  Integrated Analysis and Forecasting, Energy Information 
  Administration.................................................    31
                               __________
Columbus Oil Company, Dan Wallace................................    87
FPL Energy, LLC, Robert Morrison.................................    76
Petroleum Development Corporation, Steven R. Williams............    59
USA Biomass Power Producers Alliance, and Wheelabrator 
  Environmental Systems, Inc., William H. Carlson................    83

                       SUBMISSIONS FOR THE RECORD


American Gas Association, Charles Fritts, statement..............    99
Electric Vehicle Association of the Americas, statement and 
  attachments....................................................   103
Fibrowatt LLC, Yardley, PA, Rupert J. Fraser, statement..........   106
Solid Waste Association of North America, Silver Spring, MD, John 
  H. Skinner, statement..........................................   109

 
   FIRST IN SERIES ON EFFECT OF FEDERAL TAX LAWS ON THE PRODUCTION, 
                   SUPPLY, AND CONSERVATION OF ENERGY

                              ----------                              


                         THURSDAY, MAY 3, 2001

                  House of Representatives,
                       Committee on Ways and Means,
                   Subcommittee on Select Revenue Measures,
                                                    Washington, DC.
    The Subcommittee met, pursuant to notice, at 10:04 a.m., in 
room 1100 Longworth House Office Building, Hon. Jim McCrery, 
(Chairman of the Subcommittee) presiding.
    [The advisory announcing the hearing follows:]

ADVISORY

FROM THE COMMITTEE ON WAYS AND MEANS 
SUBCOMMITTEE ON SELECT REVENUE MEASURES

                                                CONTACT: (202) 226-5911
FOR IMMEDIATE RELEASE
April 26, 2001
No. SRM-1

            McCrery Announces First in a Series of Hearings

                on the Effect of Federal Tax Laws on the

             Production, Supply, and Conservation of Energy

    Congressman Jim McCrery (R-LA), Chairman, Subcommittee on Select 
Revenue Measures of the Committee on Ways and Means, today announced 
that the Subcommittee will hold the first in a series of hearings on 
the effect of current Federal tax laws on the production, supply, and 
conservation of energy. The hearing will take place on Thursday, May 3, 
2001, in the main Committee hearing room, 1100 Longworth House Office 
Building, beginning at 10:00 a.m.
    Oral testimony at this hearing will be from invited witnesses only. 
Invited witnesses include representatives of the U.S. Department of the 
Treasury, the U.S. Department of Energy, energy producers, and 
consumers. However, any individual or organization not scheduled for an 
oral appearance may submit a written statement for consideration by the 
Committee and for inclusion in the printed record of the hearing.
      

BACKGROUND:

      
    The Internal Revenue Code provides several incentives for the 
domestic production of oil and gas including: (1) expensing of certain 
exploration and development costs, (2) depletion rules, and (3) a tax 
credit for enhanced oil recovery costs. The tax code provides 
incentives for the production of electricity from certain renewable 
resources, including wind and closed-loop biomass facilities. The tax 
code also encourages energy conservation by allowing taxpayers to 
exclude from income the value of certain energy conservation measures 
provided by a utility company to consumers.
    In announcing the hearing, Chairman McCrery stated: ``With Summer 
approaching and gasoline prices on the rise, Americans are becoming 
increasingly concerned about the energy problems we face. My 
Subcommittee's review will help explore ways that the tax code can 
promote sound energy policy which may alleviate these problems.''
      

FOCUS OF THE HEARING:

      
    The hearing will focus on current tax incentives in the Internal 
Revenue Code for the production and conservation of energy, including 
expiring and time-limited energy-related tax provisions, such as the 
suspension of the 100 percent net income limitation for marginal 
properties, the credit for producing fuel from nonconventional sources, 
and the credit for electricity produced from certain renewable 
resources.
      

DETAILS FOR SUBMISSION OF WRITTEN COMMENTS:

      
    Any person or organization wishing to submit a written statement 
for the printed record of the hearing should submit six (6) single-
spaced copies of their statement, along with an IBM compatible 3.5-inch 
diskette in WordPerfect or MS Word format, with their name, address, 
and hearing date noted on a label, by the close of business, Thursday, 
May 17, 2001, to Allison Giles, Chief of Staff, Committee on Ways and 
Means, U.S. House of Representatives, 1102 Longworth House Office 
Building, Washington, D.C. 20515. If those filing written statements 
wish to have their statements distributed to the press and interested 
public at the hearing, they may deliver 200 additional copies for this 
purpose to the Subcommittee on Select Revenue Measures office, room 
1135 Longworth House Office Building, by close of business the day 
before the hearing.
      

FORMATTING REQUIREMENTS:

      
    Each statement presented for printing to the Committee by a 
witness, any written statement or exhibit submitted for the printed 
record or any written comments in response to a request for written 
comments must conform to the guidelines listed below. Any statement or 
exhibit not in compliance with these guidelines will not be printed, 
but will be maintained in the Committee files for review and use by the 
Committee.

    1. All statements and any accompanying exhibits for printing must 
be submitted on an IBM compatible 3.5-inch diskette in WordPerfect or 
MS Word format, typed in single space and may not exceed a total of 10 
pages including attachments. Witnesses are advised that the Committee 
will rely on electronic submissions for printing the official hearing 
record.

    2. Copies of whole documents submitted as exhibit material will not 
be accepted for printing. Instead, exhibit material should be 
referenced and quoted or paraphrased. All exhibit material not meeting 
these specifications will be maintained in the Committee files for 
review and use by the Committee.

    3. A witness appearing at a public hearing, or submitting a 
statement for the record of a public hearing, or submitting written 
comments in response to a published request for comments by the 
Committee, must include on his statement or submission a list of all 
clients, persons, or organizations on whose behalf the witness appears.

    4. A supplemental sheet must accompany each statement listing the 
name, company, address, telephone and fax numbers where the witness or 
the designated representative may be reached. This supplemental sheet 
will not be included in the printed record.

    The above restrictions and limitations apply only to material being 
submitted for printing. Statements and exhibits or supplementary 
material submitted solely for distribution to the Members, the press, 
and the public during the course of a public hearing may be submitted 
in other forms.

    Note: All Committee advisaries and news releases are available on 
the World Wide Web at ``http://waysandmeans.house.gov''.

    The Committee seeks to make its facilities accessible to persons 
with disabilities. If you are in need of special accommodations, please 
call 202-225-1721 or 202-226-3411 TTD/TTY in advance of the event (four 
business days notice is requested). Questions with regard to special 
accommodation needs in general (including availability of Committee 
materials in alternative formats) may be directed to the Committee as 
noted above.

                                


    Chairman McCrery. The hearing will come to order.
    Good morning, everyone. This is the first hearing conducted 
by the newly reconstituted Select Revenue Measures Subcommittee 
of the Ways and Means Committee. We will begin our first 
hearing shortly.
    However, we have just been advised that we have one vote on 
the floor, so I believe before we get into opening statements 
and into the witnesses, I will recess this morning's hearing 
just for a few minutes so that the Members may go across the 
street and vote. I would ask the Members to vote as quickly as 
possible and get back to the hearing room, so that we may 
being.
    The Committee is in recess.
    [Recess.]
    Chairman McCrery. The Committee will come to order.
    This morning, since it is our first Subcommittee hearing, 
I'm going to allow any Member of the Subcommittee to make an 
opening statement. However, after today, I will ask that all 
Members, except for the chairman and Ranking Member, submit any 
opening statements in writing for the record.
    This morning will be the first in a series of hearings by 
the Subcommittee, examining how our Tax Code can contribute to 
a safe and stable supply of energy. Our country continues to 
struggle with the fact that our domestic energy production does 
not meet our demand.
    The fragile nature of our energy supply is easy to see. We 
can see it in the rolling blackouts in California and in the 
spikes in natural gas prices during the winter. Today, as 
summer approaches and families begin planning vacations, we are 
becoming increasingly focused and concerned about soaring 
gasoline prices.
    In an effort to avoid the mistakes of the past, it is 
important we examine all angles of America's energy policy. 
Today, I hope we will be able to learn more about how the Tax 
Code affects energy production, exploration, and supply. The 
focus will be mostly on a review of current law, though I hope 
our witness, Mr. Mikrut from the Treasury Department, will also 
discuss the energy-related tax provisions in President Bush's 
budget.
    We will then hear from Miss Mary Hutzler from the Energy 
Information Administration, who will discuss our current and 
future energy needs, as well as give us greater insights into 
how energy is produced and consumed in this country. Her 
insights will serve the Committee well as we go forward with 
this inquiry, and I thank her for being with us this morning.
    Finally, we will hear from the private sector, the people 
actually working to secure our energy supply, about three time 
limit provisions in the Tax Code. First, we will hear testimony 
about section 29's credit for the production of energy from 
non-conventional sources, and we will learn more about the 
section 45 tax credit for wind energy. Also on the subject of 
section 45, we will hear testimony on how the credit works, or 
does not work, to encourage the production of electricity from 
biomass. Finally, we will hear testimony on the expiring Tax 
Code provision which allows small oil and gas producers to 
recover their capital costs in excess of their income from a 
particular property.
    Supporters argue that the provision is important in 
encouraging independent producers to try their luck with 
marginal wells. It is my hope that this hearing will shed some 
light on our economy's complex energy problems and begin to 
explore solutions available to us.
    As I stated at the outset, this is only the first in a 
series of hearings on this important issue. I look forward to 
working with my colleagues as we wrestle with it.
    At this time I am pleased to yield to my Ranking Member, 
Michael McNulty from New York. Welcome, Michael. It's good to 
be with you. The floor is yours.
    [The opening statement of Chairman McCrery follows:]
 Opening Statement of the Hon. Jim McCrery, a Representative From the 
   State of Louisiana, and Chairman, Subcommittee on Select Revenue 
                                Measures
    Good morning and welcome to the first hearing of the Select Revenue 
Measures Subcommittee for the 107th Congress. Today will be 
the first in a series of hearings examining how our tax code can 
contribute to a safe and stable supply of energy.
    Our country continues to struggle with the fact that our domestic 
energy production does not meet our demand. The fragile nature of our 
energy supply is easy to see. We can see it in the rolling blackouts in 
California and in the spikes in natural gas prices during the winter. 
And today, as summer approaches and families begin planning vacations, 
we are becoming increasingly focused and concerned about soaring 
gasoline prices.
    In an effort to avoid the mistakes of the past, it is important we 
examine all angles of America's energy policy. Today, I hope we will be 
able to learn more about how the tax code affects energy exploration, 
production, and supply.
    The focus will be mostly on a review of current law, though I hope 
our first witness, Joe Mikrut, Tax Legislative Counsel for the Treasury 
Department, will also discuss the energy-related tax provisions in 
President Bush's budget.
    We will then hear from Ms. Mary Hutzler, from the Energy 
Information Administration, who will discuss our current and future 
energy needs as well as give us greater insights into how energy is 
produced and consumed in America. Her insights will serve the Committee 
well as we go forward with this inquiry, and I thank her for being with 
us this morning.
    Finally, we will hear from the private sector--the people actually 
working to secure our energy supply, about three time-limited 
provisions in the tax code. First, we will hear testimony about Section 
29's credit for the production of energy from non-conventional sources 
and will learn more about the Section 45 tax credit for wind energy.
    Also on the subject of Section 45, we will hear testimony on how 
the credit works--or does not work--to encourage the production of 
electricity from biomass.
    Finally, we will hear testimony on an expiring tax code provision 
which allows small oil and gas producers to recover their capital costs 
in excess of their income from a particular property. Supporters argue 
the provision is important in encouraging independent producers to try 
their luck with marginal wells.
    It is my hope that this hearing will shed some light on our 
country's complex energy problems and begin to explore solutions 
available to us. As I stated at the outset, this is the first in a 
series of hearings on this important issue and I look forward to 
working with my colleagues as we wrestle with it.
    At this time, I am pleased to yield to my Ranking Member, Mr. 
McNulty, for an opening statement.

                                


    Mr. McNulty. Thank you, Mr. Chairman.
    Today we discuss an issue of great importance to Americans 
all over the country: the effect of Federal tax laws on the 
production, supply and conservation of energy. Before we begin 
the hearing, I want to officially congratulate our new 
Subcommittee chairman, Congressman Jim McCrery, for the 
important role he is assuming on the Committee on Ways and 
Means during the 107th Congress. It is my pleasure to serve 
with him on the Select Revenue Measures Subcommittee as the 
Ranking Member.
    I may also interject at this point that Jim and I share a 
special relationship. Many years ago I accompanied him and his 
wife, Jonna, on their honeymoon. Beyond that, I will have no 
further comment.
    [Laughter.]
    I was a Member of this Subcommittee in earlier years, and I 
appreciate the role that this Subcommittee can play in 
evaluating specific tax provisions and in developing 
appropriate legislative reforms. I know we will be a good team 
and I look forward to working with Subcommittee chairman 
McCrery and each of the Subcommittee Members as we proceed to 
address tax issues of concern to us all.
    My constituents in the 21st District of New York know first 
hand the impact of rising energy costs and how that affects our 
lives. Many have faced major increases in their monthly heating 
bills and they are sure to face similarly high utility costs in 
the coming months, particularly this summer. Businesses are 
directly impacted by high energy costs in the production of 
consumer goods and services, and in competing nationally and 
internationally.
    As this Subcommittee considers the role the Tax Code plays 
in providing adequate incentives for fuel production and 
conservation, we should keep a focus on the impact the current 
law has on consumers and businesses. Also, as the Subcommittee 
continues its series of energy hearings, I would hope that soon 
we can consider specific legislative proposals to promote 
energy production and conservation. I have introduced 
legislation to provide tax incentives for a cutting-edge 
technology involving the use of fuel cells in creating 
electricity. This space age technology is ready to come to 
market as a clean, chemical-free way to increase the supply of 
electricity on the commercial market.
    Mr. Chairman, I look forward to working with you and all of 
the Members of the Subcommittee, and I thank you for the time.
    [The opening statement of Mr. McNulty follows:]
 Opening Statement of the Hon. Michael McNulty, a Representative From 
                         the State of New York
    Today we discuss an issue of great importance to Americans 
nationwide-the effect of our Federal tax laws on the production, supply 
and conservation of energy.
    Before we begin the hearing, I want to officially congratulate our 
new Subcommittee Chairman, Congressman Jim McCrery, for the important 
role he is assuming on the Committee on Ways and Means during the 107th 
Congress. It is my pleasure to serve with him on the Select Revenue 
Subcommittee, as the Ranking Member.
    I was a Member of this Subcommittee in earlier years and I 
appreciate the role this Subcommittee can play in evaluating specific 
tax provisions and in developing appropriate legislative reforms. I 
know we will be a good team and I look forward to working with 
Subcommittee Chairman McCrery and each of the Subcommittee Members as 
we proceed to address tax issues of concern to us all.
    My constituents in the 21st Congressional District of New York 
State know first-hand the impact rising energy costs can have on our 
lives. Many have faced major increases in their monthly heating bills 
and are sure to face similarly high utility costs in the coming months, 
particularly this summer. Businesses are directly impacted by high 
energy costs in the production of consumer goods and services and in 
competing nationally and internationally.
    As this Subcommittee considers the role the tax code plays in 
providing adequate incentives for fuel production and conservation, we 
should keep a focus on the impact the current law has on consumers and 
businesses.
    Also, as the Subcommittee continues its series of energy hearings, 
I would hope that soon we can consider specific legislative proposals 
to promote energy production and conservation. I have introduced 
legislation to provide tax incentives for a cutting edge technology 
involving the use of fuel cells in creating electricity. This ``space 
age'' technology is ready to come to market as a clean, chemical-free 
way to increase the supply of electricity on the commercial market.
    Thank you.

                                


    Chairman McCrery. Thank you, Mr. McNulty.
    I would now ask any other Member who wishes to make an 
opening statement at this time, to raise your hand. Mr. Foley.
    Mr. Foley. Thank you, Mr. Chairman. I am delighted to be 
part of the Subcommittee and I'm delighted that our first order 
of business is, in fact, to undertake a pertinent discussion 
relative to the energy policy and opportunities where this 
Committee may weigh in on options that are available.
    I am also delighted that one of my hometown constituents is 
here, Florida Power and Light, who is going to be testifying on 
a panel today relative to wind energy. We have supplied every 
Member of the panel with a tape from ABC News that I think you 
will find informative.
    I also want to take a moment to reiterate Florida's strong 
opposition to any offshore oil drilling. I know that's not the 
subject of today's hearing, but the Governor of Florida and I 
met on Monday, and since we are talking about energy resources, 
I did want to at least underline his opposition and that of the 
entire Delegation as we proceed to look for alternative 
opportunities for energy.
    I think again that today presents a unique opportunity to 
explore the full range of options. I am particularly pleased 
with Mr. McNulty's comments because I think, as we do further 
research on fuel cells and those opportunities, we will see a 
tremendous way in which to reduce our dependency on fossil 
fuels, finding ways to produce energy in a more efficient and 
cost-effective manner, and I think that will do a great deal 
for us in not looking necessarily at always drilling but 
finding sources that are nonpolluting, nonthreatening, and 
contribute to the economic and electrical diversification plans 
of our country.
    Thank you, Mr. Chairman.
    Chairman McCrery. Thank you, Mr. Foley. Mr. Brady.
    Mr. Brady. Thank you, Mr. Chairman.
    I, too, want to thank you for your leadership on this 
issue. I'm excited about this new Subcommittee. As a new Member 
of Ways and Means, I am hopeful that ultimately we can replace 
this Tax Code with one much better for our children than the 
one we've had to live with.
    But while we have the ``stinker'' that we do, it is 
important that we look at ways to improve it. This issue of 
energy independence is so important. I think we all know that 
America has paid an awfully steep price for not having an 
energy game plan. I know, just within the energy community that 
I represent in Texas, we have lost 100,000 jobs over the last 
decade because of this ``boom or bust'' mentality. That is ten 
times more jobs than steel, and that's as many jobs as 
agriculture. We have paid a steep price. In the economy and in 
our individual homes, we have all paid a price because of the 
volatility of the market.
    The problem is that we're addicted to foreign oil. The 
approach so far has been to try to convince the dealers to sell 
us a better street price for this, but the answer is to kick 
the habit. We can start doing that by encouraging production 
and encouraging supply, and encouraging conservation as well.
    As America starts taking responsibility for our own energy 
needs, and although last year we saw a number of Members of 
Congress and the White House releasing a great deal of natural 
gas, about the price of oil, blaming energy companies for it, I 
was pleased that, while that was front page news, buried in the 
pages of the media recently have been the results of two 
Federal investigations that showed, in fact, the energy 
companies acted appropriately, that it was supply and demand 
and environmental regulations that added to the volatility of 
our prices. So I am real hopeful that we can move on past some 
of the political issues and start ``folksing'' together, 
Republicans and Democrats, on energy independence.
    Thank you, Mr. Chairman.
    Chairman McCrery. Thank you, Mr. Brady. Mr. Ryan.
    Mr. Ryan. Thank you, Mr. Chairman.
    I, too, want to join my colleagues in thanking you for 
holding this hearing, and for the first hearing of the Select 
Revenue Measures Subcommittee. It's very exciting to be here.
    As a new Member of the Committee, a new Member of the 
Subcommittee, I come from an oil-consuming State, Wisconsin. We 
don't do a lot of oil producing. We consume a lot of oil. Our 
prices are going through the roof right now.
    We have 45 different boutique fuels roaming this country. 
We have a supply chain that is constrained. We haven't had new 
refineries built in about 20 years. So I am looking forward to 
hearing from the administration about different ideas that we 
can explore to improve our capacity, to steady the supply, and 
I would like to hear about different ways of spreading out the 
number, regionalizing the fuels, perhaps. Those are the kinds 
of answers that we're looking for in Wisconsin, in addition to 
longer term solutions for renewable cleaner fuels.
    I just wanted to thank you for having this hearing. I look 
forward to the number of energy hearings we're going to have. 
It's a very important and timely topic affecting all of us, and 
I want to thank you for that.
    Chairman McCrery. Thank you, Mr. Ryan.
    We have one ``interloper'' with us today. Mr. Watkins is 
not a Member of the Subcommittee. However, he is a Member of 
the full Committee and has, of course, a strong interest in the 
subject of energy. I recognize Mr. Watkins for any statement he 
would like to make at this time.
    Mr. Watkins. Thank you, Mr. Chairman. To you and the other 
Members, thank you for allowing me to come down and join you 
for this very special Subcommittee and this panel and this 
subject. It is very timely and is probably in the minds of 
everyone's pocketbooks throughout this country.
    At the appropriate time, Mr. Chairman, I have a special 
friend who will be on the panel and I would like to introduce 
him at that time. But thank you for letting me come and be here 
today.
    Chairman McCrery. Thank you, Mr. Watkins.
    Now, our first witness is Mr. Joseph Mikrut, Tax 
Legislative Counsel, with the United States Department of the 
Treasury. Mr. Mikrut, your full written testimony will be 
submitted for the record. If you would summarize that in five 
minutes, we would appreciate it. You may proceed.

   STATEMENT OF JOSEPH MIKRUT, TAX LEGISLATIVE COUNSEL, U.S. 
                   DEPARTMENT OF THE TREASURY

    Mr. Mikrut. Thank you, Mr. Chairman, Mr. McNulty, Members 
of the Subcommittee. Good morning. It is a pleasure to be here 
for your inaugural hearing, and I appreciate the opportunity to 
discuss with you today tax incentives for the production, 
supply and conservation of energy.
    As you noted in your opening remarks, there has been a 
renewed interest in the role of tax incentives in our National 
energy policy. The Subcommittee should be commended for taking 
on this issue at this time.
    I would like to begin my testimony with a brief discussion 
of the general principles that may be relevant in analyzing any 
energy tax proposal. I will conclude, as you mentioned, Mr. 
Chairman, with a description of the energy-related tax 
proposals in the administration's fiscal year 2002 budget.
    I would also like to remind the Members of the Subcommittee 
that an interagency task force, headed by Vice President 
Cheney, will submit to Congress later this month a plan for a 
comprehensive national energy policy. This task force is 
considering additional tax and nontax provisions not contained 
in the budget proposal. We would be happy to come back and 
brief you later to the extent there are any additional tax 
proposals.
    The fundamental principle underlying a sound energy policy 
is that the market should be allowed to function freely and 
market intervention should be avoided, unless justified by 
compelling energy security, economic, environmental, or other 
concerns.
    In some instances, markets do not properly value the 
benefits of certain investments. For example, a market rate of 
return for investments that increase domestic oil and gas 
reserves may not reflect the contribution of those investments 
to ensuring stability in supply and price, thereby reducing 
U.S. vulnerability to oil supply disruptions. Similarly, market 
prices may not reflect the benefits of energy produced from 
clean and renewable energy sources. Individuals and businesses 
may not invest in energy saving and alternative energy 
technologies at a level that reflects the benefits provided to 
society as a whole from such technologies.
    For example, if a new technology reduces pollution, this 
external benefit should be included in decisions on whether to 
undertake an investment or not. However, private investors only 
look to private returns and may not invest in such 
technologies. Thus, they avoid nonprofitable ventures that may 
benefit society as a whole.
    Tax incentives, on the other hand, can and do offset the 
failure of market prices to signal the desirable level of 
investment in energy saving technologies because they increase 
the private return by reducing the aftertax cost of the 
taxpayer. The increase in private return encourages additional 
investments in energy saving and environmentally preferable 
technologies.
    The Federal Government has many tools for advancing energy 
policy goals. One of these is the Internal Revenue Code. Beyond 
the fundamental issue of whether a tax incentive is justified 
at all, a number of other, often contradictory considerations 
must be taken into account. For example, incentives should be 
appropriately targeted to induce desired activities in a cost-
effective manner. Thus, incentives should be designed to 
minimize windfalls for investments that would have been made in 
any event and strive to encourage investment upon the margin.
    At the same time, however, incentives that are targeted too 
narrowly may reduce the cost of only some technologies and 
leave other technologies behind. This can result in economic 
inefficiency and will contribute to perceptions that the tax 
system is unfair and targeted only toward certain taxpayers.
    Finally, incentives should also be designed to minimize 
complexity and avoid unnecessary increases in taxpayer 
compliance burdens and IRS administrative costs.
    The importance of maintaining a strong domestic energy 
industry has been long recognized and policymakers have 
balanced the concerns I have just described so that the 
Internal Revenue Code currently includes a variety of measures 
to stimulate energy exploration, production, and conservation. 
Similarly, the administration's budget proposals for fiscal 
year 2002 contain four tax incentives to extend and modify 
these present law provisions. I would like to briefly describe 
these two proposals.
    First, under present law, a 1.7 cents per kilowatt hour 
production credit is provided for electricity produced from 
certain renewable sources. The administration proposes to 
extend the credit for electricity produced from wind and 
biomass for 3 years for properties placed in service before 
2005. Moreover, the eligible biomass sources would be expanded 
from the current law closed-loop biomass to additional open-
loop biomass sources. Special rules would apply to biomass 
facilities placed in service before 2002.
    Electricity produced at such facilities from newly eligible 
sources would be eligible for the credit through 2004, at a 60-
percent rate, and electricity produced from newly eligible 
sources at coal-fired plants would be eligible for the credit 
through 2004 at a 30-percent rate.
    Our second proposal would supplement the present law 
investment tax credit available for businesses investing in 
certain energy property. The administration proposes a new tax 
credit for individuals that purchase solar energy equipment 
used to generate electricity or heat water. The proposed credit 
would be equal to 15 percent of the cost of the equipment and 
its installation, and would be capped at $2,000 per individual, 
per residence. The credit would apply for water heating 
equipment placed in service before 2006, and to electric 
generating systems placed in service before 2008.
    Our third proposal deals with nuclear decommissioning 
funds. Present law provides an accelerated deduction and a 
favorable tax rate with respect to funds set aside for public 
utilities for decommissioning nuclear power plants. In 
recognition of the deregulation of the electricity generating 
industry, the administration proposes to modify these 
underlying rules. Specifically, we would eliminate the cost of 
service requirement; we would clarify that transfers of funds 
from one taxpayer to another would be nontaxable transactions; 
we would allow funding up for pre-1984 liabilities; and we 
would clarify that nuclear decommissioning expenditures are 
deductible when incurred.
    Finally, the last proposal in the administration's fiscal 
year 2002 budget concerns the 100 percent of net income 
limitation for percentage depletion, which is scheduled to 
expire at the end of the year. The administration proposes a 1-
year extension of the provision suspending this limitation for 
marginal oil and gas wells. Under the administration's 
proposal, marginal wells would be continued to be exempt from 
the limitation during years beginning in 2002. Without such a 
provision, the percentage depletion limitation for marginal 
wells will be limited to the income from the property and may 
discourage development of such properties.
    Mr. Chairman, this concludes my prepared testimony. I would 
be happy to answer any questions you or the Members may have.
    [The prepared statement of Mr. Mikrut follows:]
Statement of Joseph Mikrut, Tax Legislative Counsel, U.S. Department of 
                              the Treasury
    Mr. Chairman, Mr. McNulty, and Members of the Subcommittee:
    I appreciate the opportunity to discuss with you today tax 
incentives for the domestic production of oil and gas and for energy 
conservation. There has been renewed interest in the role of tax 
incentives in our national energy policy and I would like to begin my 
testimony with a discussion of general principles that may be relevant 
in analyzing particular incentives.
General Principles
    The fundamental principle underlying a sound energy policy is that 
markets should be allowed to function freely and market interventions 
should be avoided unless justified by compelling energy security, 
economic, environmental, or other concerns. In some instances, markets 
may not properly value the benefits of certain investments. For 
example, a market rate of return for investments that increase domestic 
oil and gas reserves may not reflect the contribution of those 
investments to ensuring stability in supply and thereby reducing our 
vulnerability to oil supply disruptions.
    Similarly, market prices may not reflect the environmental damage 
from the use of fossil fuels or the benefits of energy produced from 
clean and renewable energy sources. Individuals and businesses may not 
invest in energy-saving and alternative energy technologies at a level 
that reflects the benefits the technologies provide to society in 
excess of their private returns. If a new technology reduces pollution 
or emissions of greenhouse gases, those ``external benefits'' should be 
included in the decision about whether to undertake the investment. But 
potential investors have an incentive to consider only the private 
benefits in making decisions. Thus, they avoid technologies that are 
not profitable even though their total benefits to society exceed their 
costs. Tax incentives can offset the failure of market prices to signal 
the desirable level of investment in energy-saving and alternative 
energy technologies because they increase the private return from the 
investment by reducing its after-tax cost. The increase in private 
return encourages additional investment in energy-saving and 
environmentally preferable technologies.
    Beyond the fundamental issue of whether a tax incentive is 
justified at all, a number of other, often contradictory, 
considerations must be taken into account in the design of any 
particular incentive. For example, incentives should be appropriately 
targeted to induce desired activities in a cost-effective manner. Thus, 
incentives should be designed to minimize windfalls for investments 
that would have been made in the absence of an incentive. At the same 
time, however, incentives that are targeted too narrowly may reduce the 
cost of only some technologies and discourage investment in other 
promising approaches. This can result in economic inefficiency and will 
contribute to perceptions that the tax system is being used 
inappropriately to pick winners and losers among competing 
technologies.
    In addition, incentives should also be designed to minimize 
complexity and avoid unnecessary increases in taxpayer compliance 
burdens and IRS administrative costs.
Increasing Domestic Oil and Gas Production
    Before I turn to my discussion of the present tax treatment of oil 
and gas activities, I would like to provide a brief overview of this 
sector.
Overview
    Oil is an internationally traded commodity with its domestic price 
set by world supply and demand. Domestic exploration and production 
activity is affected by the world price of crude oil. Historically, 
world oil prices have fluctuated substantially. From 1970 to the early 
1980s, there was a fivefold increase in real oil prices. World oil 
prices fell sharply in 1986 and were relatively more stable from 1986 
through 1997. During that period, average refiner acquisition costs 
ranged from $14.91 to $23.59 in real 1992 dollars. In 1998, however, 
oil costs to the refiner declined to $12.52 per barrel in nominal 
dollars ($11.14 per barrel in 1992 dollars), their lowest level in 25 
years in real terms. Since 1998, the decline has reversed with refiner 
acquisition costs (in nominal dollars) rising to $17.51 per barrel in 
1999 and $27.69 per barrel in 2000 (the price has since dropped to 
$26.05 per barrel in February 2001, the latest month for which 
composite figures are available). The equivalent prices in 1992 dollars 
are $15.31 per barrel in 1999, $24.28 per barrel in 2000, and $22.03 
per barrel in February 2001.
    Domestic oil production has been on the decline since the mid-
1980s. From 1978 to 1983 oil consumption in the United States also 
declined, but increasing consumption since 1983 has morethan offset 
this decline. In 2000, domestic oil consumption was 28 percent higher 
than in 1970. The decline in oil production and increase in consumption 
have led to an increase in oil imports. Net petroleum (crude and 
product) imports have risen from approximately 38 percent of 
consumption in 1988 to 52 percent in 2000.
    A similar pattern of large recent price increases and increasing 
dependence on imports has occurred in the natural gas market. During 
the second half of the 1990s, spot prices for natural gas exceeded 
$4.00 per million Btu (MMBtu) in only one month (February 1996). The 
spot price again exceeded $4.00 per MMBtu in May 2000, rose above $5.00 
per MMBtu in September 2000, and exceeded $10.00 per MMBtu for several 
days last winter. The current spot price is approximately $5.00 per 
MMBtu.\1\
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    \1\ All price references are to the spot price at the Henry Hub and 
are in nominal dollars.
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    The United States has large natural gas reserves and was 
essentially self-sufficient in natural gas until the late 1980s. Since 
1986, natural gas consumption has increased by more than 30 percent but 
natural gas production has increased by only 17 percent. Net imports as 
a share of consumption nearly quadrupled from 1986 to 2000, rising from 
4.2 percent to 15.6 percent. Natural gas from Canada makes up nearly 
all of the imports into the United States.
Current law tax incentives for oil and gas production
    The importance of maintaining a strong domestic energy industry has 
been long recognized and the Internal Revenue Code includes a variety 
of measures to stimulate domestic exploration and production. They are 
generally justified on the ground that they reduce vulnerability to an 
oil supply disruption through increases in domestic production, 
reserves, exploration activity, and production capacity. The tax 
incentives contained in present law address the drop in domestic 
exploratory drilling that has occurred since the mid-1950s and the 
continuing loss of production from mature fields and marginal 
properties.
    Incentives for oil and gas production in the form of tax 
expenditures are estimated to total $9.8 billion for fiscal years 2002 
through 2006.\2\ They include the nonconventional fuels (i.e., oil 
produced from shale and tar sands, gas produced from geopressured 
brine, Devonian shale, coal seams, tight formations, or biomass, and 
synthetic fuel produced from coal) production credit ($2.4 billion), 
the enhanced oil recovery credit ($4.4 billion), the allowance of 
percentage depletion for independent producers and royalty owners, 
including increased percentage depletion for stripper wells ($2.3 
billion), the exception from the passive loss limitation for working 
interests in oil and gas properties ($100 million), and the expensing 
of intangible drilling and development costs ($640 million). In 
addition to those tax expenditures, oil and gas activities have largely 
been eliminated from the alternative minimum tax. These provisions are 
described in detail below.
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    \2\ Analytical Perspectives, Budget of the United States 
Government, Fiscal Year 2002, U.S. Government Printing Office, 
Washington, DC, 2001, p. 63, These estimates are measured on an 
``outlay equivalent'' basis. They show the amount of outlay that would 
be required to provide the taxpayer the same after-tax income as would 
be received through the tax preference. This outlay equivalent measure 
allows a comparison of the cost of the tax expenditure with that of a 
direct Federal outlay
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Percentage depletion
    Certain costs incurred prior to drilling an oil- or gas-producing 
property are recovered through the depletion deduction. These include 
costs of acquiring the lease or other interest in the property, and 
geological and geophysical costs (in advance of actual drilling). Any 
taxpayer having an economic interest in a producing property may use 
the cost depletion method. Under this method, the basis recovery for a 
taxable year is proportional to the exhaustion of the property during 
the year. The cost depletion method does not permit cost recovery 
deductions that exceed the taxpayer's basis in the property or that are 
allowable on an accelerated basis. Thus, the deduction for cost 
depletion is not generally viewed as a tax incentive.
    Independent producers and royalty owners (as contrasted to 
integrated oil companies)\3\ may qualify for percentage depletion. A 
qualifying taxpayer determines the depletion deduction for each oil or 
gas property under both the percentage depletion method and the cost 
depletion method and deducts the larger of the two amounts. Under the 
percentage depletion method, generally 15 percent of the taxpayer's 
gross income from an oil- or gas-producing property is allowed as a 
deduction in each taxable year. The amount deducted may not exceed 100 
percent of the net income from that property in any year (the ``net-
income limitation'').\4\ Additionally, the percentage depletion 
deduction for all oil and gas properties may not exceed 65 percent of 
the taxpayer's overall taxable income (determined before such deduction 
and adjusted for certain loss carrybacks and trust distributions).\5\
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    \3\ An independent producer is any producer who is not a 
``retailer'' or ``refiner.'' A retailer is any person who directly, or 
through a related person, sells oil or natural gas or any product 
derived therefrom (1) through any retail outlet operated by the 
taxpayer or related person, or (2) to any person that is obligated to 
market or distribute such oil or natural gas (or product derived 
therefrom) under the name of the taxpayer or the related person, or 
that has the authority to occupy any retail outlet owned by the 
taxpayer or a related person. Bulk sales of crude oil and natural gas 
to commercial or industrial users, and bulk sales of aviation fuel to 
the Department of Defense, are not treated as retail sales for this 
purpose. Further, a person is not a retailer within the meaning of this 
provision if the combined gross receipts of that person and all related 
persons from the retail sale of oil, natural gas, or any product 
derived therefrom do not exceed $5 million for the taxable year. A 
refiner is any person who directly or through a related person engages 
in the refining of crude oil, but only if such person or related person 
has a refinery run in excess of 50,000 barrels per day on any day 
during the taxable year.
    \4\ By contrast, for any other mineral qualifying for the 
percentage depletion deduction, the deduction may not exceed 50 percent 
of the taxpayer's taxable income from the depletable property.
    \5\ Amounts disallowed as a result of this rule may be carried 
forward and deducted in subsequent taxable years, subject to the 65-
percent-of-taxable-income limitation for those years.
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    A taxpayer may claim percentage depletion with respect to up to 
1,000 barrels of average daily production of domestic crude oil or an 
equivalent amount of domestic natural gas. For producers of both oil 
and natural gas, this limitation applies on a combined basis. All 
production owned by businesses under common control and members of the 
same family must be aggregated; each group is then treated as one 
producer for application of the 1,000-barrel limitation.
    Special percentage depletion provisions apply to oil and gas 
production from marginal properties. The statutory percentage depletion 
rate is increased (from the general rate of 15 percent) by one 
percentage point for each whole dollar that the average price of crude 
oil (as determined under the provisions of the nonconventional fuels 
production credit of section 29) for the immediately preceding calendar 
year is less than $20 per barrel. In no event may the rate of 
percentage depletion under this provision exceed 25 percent for any 
taxable year. The increased rate applies for the taxpayer's taxable 
year which immediately follows a calendar year for which the average 
crude oil price falls below the $20 floor. To illustrate the 
application of this provision, the average price of a barrel of crude 
oil for calendar year 1999 was $15.56; thus, the percentage depletion 
rate for production from marginal wells was increased by four percent 
(to 19 percent) for taxable years beginning in 2000. The 100-percent-
of-net-income limitation has been suspended for marginal wells for 
taxable years beginning after December 31, 1997, and before January 1, 
2002.
    Marginal production is defined for this purpose as domestic crude 
oil or domestic natural gas which is produced during any taxable year 
from a property which (1) is a stripper well property for the calendar 
year in which the taxable year begins, or (2) is a property 
substantially all of the production from which during such calendar 
year is heavy oil (i.e., oil that has a weighted average gravity of 20 
degrees API or less corrected to 60 degrees Fahrenheit). A stripper 
well property is any oil or gas property for which daily average 
production per producing oil or gas well is not more than 15 barrel 
equivalents in the calendar year during which the taxpayer's taxable 
year begins.\6\ A property qualifies as a stripper well property for a 
calendar year only if the wells on such property were producing during 
that period at their maximum efficient rate of flow.
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    \6\ Equivalent barrels is computed as the sum of (1) the number of 
barrels of crude oil produced, and (2) the number of cubic feet of 
natural gas produced divided by 6,000. If a well produced 10 barrels of 
crude oil and 12,000 cubic feet of natural gas, its equivalent barrels 
produced would equal 12 (i.e., 10+(12,000/6,000)).
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    If a taxpayer's property consists of a partial interest in one or 
more oil- or gas-producing wells, the determination of whether the 
property is a stripper well property or a heavy oil property is made 
with respect to total production from such wells, including the portion 
of total production attributable to ownership interests other than the 
taxpayer's. If the property satisfies the requirements of a stripper 
well property, then each owner receives the benefits of this provision 
with respect to its allocable share of the production from the property 
for its taxable year that begins during the calendar year in which the 
property so qualifies.
    The allowance for percentage depletion on production from marginal 
oil and gas properties is subject to the 1,000-barrel-per-day 
limitation discussed above. Unless a taxpayer elects otherwise, 
marginal production is given priority over other production for 
purposes of utilization of that limitation.
    Because percentage depletion, unlike cost depletion, is computed 
without regard to the taxpayer's basis in the depletable property, 
cumulative depletion deductions may be far greater than the amount 
expended by the taxpayer to acquire or develop the property. The excess 
of the percentage depletion deduction over the deduction for cost 
depletion is generally viewed as a tax expenditure.
Intangible drilling and development costs
    In general, costs that benefit future periods must be capitalized 
and recovered over such periods for income tax purposes, rather than 
being expensed in the period the costs are incurred. In addition, the 
uniform capitalization rules require certain direct and indirect costs 
allocable to property to be included in inventory or capitalized as 
part of the basis of such property. In general, the uniform 
capitalization rules apply to real and tangible personal property 
produced by the taxpayer or acquired for resale.
    Special rules apply to intangible drilling and development costs 
(``IDCs'').\7\ Under these special rules, an operator (i.e., a person 
who holds a working or operating interest in any tract or parcel of 
land either as a fee owner or under a lease or any other form of 
contract granting working or operating rights) who pays or incurs IDCs 
in the development of an oil or gas property located in the United 
States may elect either to expense or capitalize those costs. The 
uniform capitalization rules do not apply to otherwise deductible IDCs.
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    \7\ IDCs include all expenditures made by an operator for wages, 
fuel, repairs, hauling, supplies, etc., incident to and necessary for 
the drilling of wells and the preparation of wells for the production 
of oil and gas. In addition, IDCs include the cost to operators of any 
drilling or development work (excluding amounts payable only out of 
production or gross or net proceeds from production, if the amounts are 
depletable income to the recipient, and amounts properly allocable to 
the cost of depreciable property) done by contractors under any form of 
contract (including a turnkey contract). Such work includes labor, 
fuel, repairs, hauling, and supplies which are used in the drilling, 
shooting, and cleaning of wells; in such clearing of ground, draining, 
road making, surveying, and geological works as are necessary in 
preparation for the drilling of wells; and in the construction of such 
derricks, tanks, pipelines, and other physical structures as are 
necessary for the drilling of wells and the preparation of wells for 
the production of oil and gas. Generally, IDCs do not include expenses 
for items which have a salvage value (such as pipes and casings) or 
items which are part of the acquisition price of an interest in the 
property.
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    If a taxpayer elects to expense IDCs, the amount of the IDCs is 
deductible as an expense in the taxable year the cost is paid or 
incurred. Generally, IDCs that a taxpayer elects to capitalize may be 
recovered through depletion or depreciation, as appropriate; or in the 
case of a nonproductive well (``dry hole''), the operator may elect to 
deduct the costs. In the case of an integrated oil company (i.e., a 
company that engages, either directly or through a related enterprise, 
in substantial retailing or refining activities) that has elected to 
expense IDCs, 30 percent of the IDCs on productive wells must be 
capitalized and amortized over a 60-month period.\8\
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    \8\ The IRS has ruled that if an integrated oil company ceases to 
be an integrated oil company, it may not immediately write off the 
unamortized portion of the IDCs capitalized under this rule, but 
instead must continue to amortize those IDCs over the 60-month 
amortization period.
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    A taxpayer that has elected to deduct IDCs may, nevertheless, elect 
to capitalize and amortize certain IDCs over a 60-month period 
beginning with the month the expenditure was paid or incurred. This 
rule applies on an expenditure-by-expenditure basis; that is, for any 
particular taxable year, a taxpayer may deduct some portion of its IDCs 
and capitalize the rest under this provision. This allows the taxpayer 
to reduce or eliminate IDC adjustments or preferences under the 
alternative minimum tax.
    The election to deduct IDCs applies only to those IDCs associated 
with domestic properties.\9\ For this purpose, the United States 
includes certain wells drilled offshore.\10\
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    \9\ In the case of IDCs paid or incurred with respect to an oil or 
gas well located outside of the United States, the costs, at the 
election of the taxpayer, are either (1) included in adjusted basis for 
purposes of computing the amount of any deduction allowable for cost 
depletion or (2) capitalized and amortized ratably over a 10-year 
period beginning with the taxable year such costs were paid or 
incurred.
    \10\ The term ``United States'' for this purpose includes the 
seabed and subsoil of those submerged lands that are adjacent to the 
territorial waters of the United States and over which the United 
States has exclusive rights, in accordance with international law, with 
respect to the exploration and exploitation of natural resources (i.e., 
the Continental Shelf area).
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    Intangible drilling costs are a major portion of the costs 
necessary to locate and develop oil and gas reserves. Because the 
benefits obtained from these expenditures are of value throughout the 
life of the project, these costs would be capitalized and recovered 
over the period of production under generally applicable accounting 
principles. The acceleration of the deduction for IDCs is viewed as a 
tax expenditure.
Nonconventional fuels production credit
    Taxpayers that produce certain qualifying fuels from 
nonconventional sources are eligible for a tax credit (``the section 29 
credit'') equal to $3 per barrel or barrel-of-oil equivalent.\11\ Fuels 
qualifying for the credit must be produced domestically from a well 
drilled, or a facility treated as placed in service before January 1, 
1993.\12\ The section 29 credit generally is available for qualified 
fuels sold to unrelated persons before January 1, 2003.\13\
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    \11\ A barrel-of-oil equivalent generally means that amount of the 
qualifying fuel which has a Btu (British thermal unit) content of 5.8 
million.
    \12\ A facility that produces gas from biomass or produces liquid, 
gaseous, or solid synthetic fuels from coal (including lignite) 
generally will be treated as being placed in service before January 1, 
1993, if it is placed in service by the taxpayer before July 1, 1998, 
pursuant to a written binding contract in effect before January 1, 
1997. In the case of a facility that produces coke or coke gas, 
however, this provision applies only if the original use of the 
facility commences with the taxpayer. Also, the IRS has ruled that 
production from certain post-1992 ``recompletions'' of wells that were 
originally drilled prior to the expiration date of the credit would 
qualify for the section 29 credit.
    \13\ If a facility that qualifies for the binding contract rule is 
originally placed in service after December 31, 1992, production from 
the facility may qualify for the credit if sold to an unrelated person 
before January 1, 2008.
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    For purposes of the credit, qualified fuels include: (1) oil 
produced from shale and tar sands; (2) gas produced from geopressured 
brine, Devonian shale, coal seams, a tight formation, or biomass (i.e., 
any organic material other than oil, natural gas, or coal (or any 
product thereof); and (3) liquid, gaseous, or solid synthetic fuels 
produced from coal (including lignite), including such fuels when used 
as feedstocks. The amount of the credit is determined without regard to 
any production attributable to a property from which gas from Devonian 
shale, coal seams, geopressured brine, or a tight formation was 
produced in marketable quantities before 1980.
    The amount of the section 29 credit generally is adjusted by an 
inflation adjustment factor for the calendar year in which the sale 
occurs.\14\ There is no adjustment for inflation in the case of the 
credit for sales of natural gas produced from a tight formation. The 
credit begins to phase out if the annual average unregulated wellhead 
price per barrel of domestic crude oil exceeds $23.50 multiplied by the 
inflation adjustment factor.\15\
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    \14\ The inflation adjustment factor for the 2000 taxable year was 
2.0454. Therefore, the inflation-adjusted amount of the credit for that 
year was $6.14 per barrel or barrel equivalent.
    \15\ For 2000, the inflation adjusted threshold for onset of the 
phaseout was $48.07 ($23.502.0454) and the average wellhead 
price for that year was $26.73.
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    The amount of the section 29 credit allowable with respect to a 
project is reduced by any unrecaptured business energy tax credit or 
enhanced oil recovery credit claimed with respect to such project.
    As with most other credits, the section 29 credit may not be used 
to offset alternative minimum tax liability. Any unused section 29 
credit generally may not be carried back or forward to another taxable 
year; however, a taxpayer receives a credit for prior year minimum tax 
liability to the extent that a section 29 credit is disallowed as a 
result of the operation of the alternative minimum tax. The credit is 
limited to what would have been the regular tax liability but for the 
alternative minimum tax.
    The provision provides a significant tax incentive (currently about 
$6 per barrel of oil equivalent or $1 per thousand cubic feet of 
natural gas). Coalbed methane and gas from tight formations currently 
account for most of the credit.
Enhanced oil recovery credit
    Taxpayers are permitted to claim a general business credit, which 
consists of several different components. One component of the general 
business credit is the enhanced oil recovery credit. The general 
business credit for a taxable year may not exceed the excess (if any) 
of the taxpayer's net income tax over the greater of (1) the tentative 
minimum tax, or (2) 25 percent of so much of the taxpayer's net regular 
tax liability as exceeds $25,000. Any unused general business credit 
generally may be carried back one taxable year and carried forward 20 
taxable years.
    The enhanced oil recovery credit for a taxable year is equal to 15 
percent of certain costs attributable to qualified enhanced oil 
recovery (``EOR'') projects undertaken by the taxpayer in the United 
States during the taxable year. To the extent that a credit is allowed 
for such costs, the taxpayer must reduce the amount otherwise 
deductible or required to be capitalized and recovered through 
depreciation, depletion, or amortization, as appropriate, with respect 
to the costs. A taxpayer may elect not to have the enhanced oil 
recovery credit apply for a taxable year.
    The amount of the enhanced oil recovery credit is reduced in a 
taxable year following a calendar year during which the annual average 
unregulated wellhead price per barrel of domestic crude oil exceeds $28 
(adjusted for inflation since 1990).\16\ In such a case, the credit 
would be reduced ratably over a $6 phaseout range.
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    \16\ The average per-barrel price of crude oil for this purpose is 
determined in the same manner as for purposes of the section 29 credit.
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    For purposes of the credit, qualified enhanced oil recovery costs 
include the following costs which are paid or incurred with respect to 
a qualified EOR project: (1) the cost of tangible property which is an 
integral part of the project and with respect to which depreciation or 
amortization is allowable; (2) IDCs that the taxpayer may elect to 
deduct;\17\ and (3) the cost of tertiary injectants with respect to 
which a deduction is allowable, whether or not chargeable to capital 
account.
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    \17\ In the case of an integrated oil company, the credit base 
includes those IDCs which the taxpayer is required to capitalize.
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    A qualified EOR project means any project that is located within 
the United States and involves the application (in accordance with 
sound engineering principles) of one or more qualifying tertiary 
recovery methods which can reasonably be expected to result in more 
than an insignificant increase in the amount of crude oil which 
ultimately will be recovered. The qualifying tertiary recovery methods 
generally include the following nine methods: miscible fluid 
displacement, steam-drive injection, microemulsion flooding, in situ 
combustion, polymer-augmented water flooding, cyclic-steam injection, 
alkaline flooding, carbonated water flooding, and immiscible non-
hydrocarbon gas displacement, or any other method approved by the IRS. 
In addition, for purposes of the enhanced oil recovery credit, 
immiscible non-hydrocarbon gas displacement generally is considered a 
qualifying tertiary recovery method, even if the gas injected is not 
carbon dioxide.
    A project is not considered a qualified EOR project unless the 
project's operator submits to the IRS a certification from a petroleum 
engineer that the project meets the requirements set forth in the 
preceding paragraph.
    The enhanced oil recovery credit is effective for taxable years 
beginning after December 31, 1990, with respect to costs paid or 
incurred in EOR projects begun or significantly expanded after that 
date.
    Conventional oil recovery methods do not recover all of a well's 
oil. Some of the remaining oil can be extracted by unconventional 
methods, but these methods are generally more costly. At current world 
oil prices, a large part of the remaining oil in place is uneconomic to 
recover by unconventional methods. In this environment, the EOR credit 
can increase recoverable reserves. Although recovering oil using EOR 
methods is more expensive than recovering it using conventional 
methods, it may be less expensive than producing oil from new 
reservoirs. Although the credit could phase out at higher oil prices, 
it is fully effective at present world oil prices.
Alternative minimum tax
    A taxpayer is subject to an alternative minimum tax (``AMT'') to 
the extent that its tentative minimum tax exceeds its regular income 
tax liability. A corporate taxpayer's tentative minimum tax generally 
equals 20 percent of its alternative minimum taxable income in excess 
of an exemption amount. (The marginal AMT rate for a noncorporate 
taxpayer is 26 or 28 percent, depending on the amount of its 
alternative minimum taxable income above an exemption amount.) 
Alternative minimum taxable income (``AMTI'') is the taxpayer's taxable 
income increased by certain tax preferences and adjusted by determining 
the tax treatment of certain items in a manner which negates the 
deferral of income resulting from the regular tax treatment of those 
items.
    As a general rule, percentage depletion deductions claimed in 
excess of the basis of the depletable property constitute an item of 
tax preference in determining the AMT. In addition, the AMTI of a 
corporation is increased by an amount equal to 75 percent of the amount 
by which adjusted current earnings (``ACE'') of the corporation exceed 
AMTI (as determined before this adjustment). In general, ACE means AMTI 
with additional adjustments that generally follow the rules presently 
applicable to corporations in computing their earnings and profits. As 
a general rule a corporation must use the cost depletion method in 
computing its ACE adjustment. Thus, the difference between a 
corporation's percentage depletion deduction (if any) claimed for 
regular tax purposes and its allowable deduction determined under the 
cost depletion method is factored into its overall ACE adjustment.
    Excess percentage depletion deductions related to crude oil and 
natural gas production are not items of tax preference for AMT 
purposes. In addition, corporations that are independent oil and gas 
producers and royalty owners may determine depletion deductions using 
the percentage depletion method in computing their ACE adjustments.
    The difference between the amount of a taxpayer's IDC deductions 
and the amount which would have been currently deductible had IDC's 
been capitalized and recovered over a 10-year period may constitute an 
item of tax preference for the AMT to the extent that this amount 
exceeds 65 percent of the taxpayer's net income from oil and gas 
properties for the taxable year (the ``excess IDC preference''). In 
addition, for purposes of computing a corporation's ACE adjustment to 
the AMT, IDCs are capitalized and amortized over the 60-month period 
beginning with the month in which they are paid or incurred. The 
preference does not apply if the taxpayer elects to capitalize and 
amortize IDCs over a 60-month period for regular tax purposes.
    IDC's related to oil and gas wells are generally not taken into 
account in computing the excess IDC preference of taxpayers that are 
not integrated oil companies. This treatment does not apply, however, 
to the extent it would reduce the amount of the taxpayer's AMTI by more 
than 40 percent of the amount that the taxpayer's AMTI would have been 
if those IDCs had been taken into account.
    In addition, for corporations other than integrated oil companies, 
there is no ACE adjustment for IDCs with respect to oil and gas wells. 
That is, such a taxpayer is permitted to use its regular tax method of 
writing off those IDCs for purposes of computing its adjusted current 
earnings.
    Absent these rules, the incentive effect of the special provisions 
for oil and gas would be reduced for firms subject to the AMT. These 
rules, however, effectively eliminate AMT concerns for independent 
producers.
Passive activity loss and credit rules
    A taxpayer's deductions from passive trade or business activities, 
to the extent they exceed income from all such passive activities of 
the taxpayer (exclusive of portfolio income), generally may not be 
deducted against other income.\18\ Thus, for example, an individual 
taxpayer may not deduct losses from a passive activity against income 
from wages. Losses suspended under this ``passive activity loss'' 
limitation are carried forward and treated as deductions from passive 
activities in the following year, and thus may offset any income from 
passive activities generated in that later year. Losses from a passive 
activity may be deducted in full when the taxpayer disposes of its 
entire interest in that activity to an unrelated party in a transaction 
in which all realized gain or loss is recognized.
---------------------------------------------------------------------------
    \18\ This provision applies to individuals, estates, trusts, 
personal service corporations, and closely held C corporations.
---------------------------------------------------------------------------
    An activity generally is treated as passive if the taxpayer does 
not materially participate in it. A taxpayer is treated as materially 
participating in an activity only if the taxpayer is involved in the 
operations of the activity on a basis which is regular, continuous, and 
substantial.
    A working interest in an oil or gas property generally is not 
treated as a passive activity, whether or not the taxpayer materially 
participates in the activities related to that property. This exception 
from the passive activity rules does not apply if the taxpayer holds 
the working interest through an entity which limits the liability of 
the taxpayer with respect to the interest. In addition, if a taxpayer 
has any loss for any taxable year from a working interest in an oil or 
gas property which is treated pursuant to this working interest 
exception as a loss which is not from a passive activity, then any net 
income from such property (or any property the basis of which is 
determined in whole or in part by reference to the basis of such 
property) for any succeeding taxable year is treated as income of the 
taxpayer which is not from a passive activity.
    Similar limitations apply to the utilization of tax credits 
attributable to passive activities. Thus, for example, the passive 
activity rules (and, consequently, the oil and gas working interest 
exception to those rules) apply to the nonconventional fuels production 
credit and the enhanced oil recovery credit. However, if a taxpayer has 
net income from a working interest in an oil and gas property which is 
treated as not arising from a passive activity, then any tax credits 
attributable to the interest in that property would be treated as 
credits not from a passive activity (and, thus, not subject to the 
passive activity credit limitation) to the extent that the amount of 
the credits does not exceed the regular tax liability which is 
allocable to such net income.
    As a result of this exception from the passive loss limitations, 
owners of working interests in oil and gas properties may use losses 
from such interests to offset income from other sources.
Tertiary injectants
    Taxpayers are allowed to deduct the cost of qualified tertiary 
injectant expenses for the taxable year. Qualified tertiary injectant 
expenses are amounts paid or incurred for any tertiary injectant (other 
than recoverable hydrocarbon injectants) which is used as a part of a 
tertiary recovery method.
    The provision allowing the deduction for qualified tertiary 
injectant expenses resolves a disagreement between taxpayers (who 
considered such costs to be IDCs or operating expenses) and the IRS 
(which considered such costs to be subject to capitalization).
Energy Efficiency and Alternative Energy Sources
    Incentives for energy efficiency and alternative energy sources are 
also essential elements of national energy policy. The continuing 
strength of our economy over the past two years, despite oil price 
rises, underscores the dramatic improvements in energy efficiency we 
have achieved over the past quarter century, as well as the changing 
economy. While past oil shortages have taken a significant toll on the 
U.S. economy, the recent increases in oil prices have not affected the 
economy much. Increased energy efficiency in cars, homes, and 
manufacturing has helped insulate the economy from these short-term 
market fluctuations. In 1974, we consumed 15 barrels of oil for every 
$10,000 of gross domestic product. Today we consume only 8 barrels of 
oil for the same amount (in constant dollars) of economic output.
Current law tax incentives for energy efficiency and alternative fuels
    Tax incentives currently provide an important element of support 
for energy-efficiency improvements and increased use of renewable and 
alternative fuels. Current incentives in the form of tax expenditures 
are estimated to total $1.2 billion for fiscal years 2002 through 2006. 
They include a tax credit for electric vehicles and expensing for 
clean-fuel vehicles ($20 million), a tax credit for the production of 
electricity from wind or biomass and a tax credit for certain solar 
energy property ($590 million), and an exclusion from gross income for 
certain energy conservation subsidies provided by public utilities to 
their customers ($580 million).\19\
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    \19\ Analytical Perspectives, Budget of the United States 
Government, Fiscal Year 2002, U.S. Government Printing Office, 
Washington, DC, 2001, p. 63.
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Electric and clean-fuel vehicles and clean-fuel vehicle refueling 
        property
    A 10-percent tax credit is provided for the cost of a qualified 
electric vehicle, up to a maximum credit of $4,000. A qualified 
electric vehicle is a motor vehicle that is powered primarily by an 
electric motor drawing current from rechargeable batteries, fuel cells, 
or other portable sources of electric current, the original use of 
which commences with the taxpayer, and that is acquired for use by the 
taxpayer and not for resale. The full amount of the credit is available 
for purchases prior to 2002. The credit begins to phase down in 2002 
and does not apply to vehicles placed in service after 2004.
    Certain costs of qualified clean-fuel vehicles and clean-fuel 
vehicle refueling property may be deducted when such property is placed 
in service. Qualified electric vehicles do not qualify for the clean-
fuel vehicle deduction. The deduction begins to phase down in 2002 and 
does not apply to property placed in service after 2004.
Energy from wind or biomass
    A 1.5-cent-per-kilowatt-hour tax credit is provided for electricity 
produced from wind, ``closed-loop'' biomass (organic material from a 
plant that is planted exclusively for purposes of being used at a 
qualified facility to produce electricity), and poultry waste. The 
electricity must be sold to an unrelated person and the credit is 
limited to the first 10 years of production. The credit applies only to 
facilities placed in service before January 1, 2002. The credit amount 
is indexed for inflation after 1992.
Solar energy
    A 10-percent investment tax credit is provided to businesses for 
qualifying equipment that uses solar energy to generate electricity, to 
heat or cool or provide hot water for use in a structure, or to provide 
solar process heat.
Energy conservation subsidies
    Subsidies provided by public utilities to their customers for the 
purchase or installation of energy conservation measures are excluded 
from the customers' gross income. An energy conservation measure is any 
installation or modification primarily designed to reduce consumption 
of electricity or natural gas or to improve the management of energy 
demand with respect to a dwelling unit.
Administration proposals
    The Administration's budget proposals for fiscal year 2002 include 
tax incentives for renewable energy resources. The budget also contains 
proposals to modify the tax treatment of nuclear decommissioning funds 
related to electricity production and to extend the suspension of the 
net income limitation applicable to certain oil and gas production. The 
Administration's proposals are described below.\20\
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    \20\ For a more detailed description, see General Explanations of 
the Administration's Fiscal Year 2002 Tax Relief Proposals, Department 
of the Treasury, April 2001.
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Electricity from wind and biomass
    The Administration proposes to extend the credit for electricity 
produced from wind and biomass for three years to facilities placed in 
service before January 1, 2005. In addition, eligible biomass sources 
would be expanded to include certain biomass from forest-related 
resources, agricultural sources, and other specified sources. Special 
rules would apply to biomass facilities placed in service before 
January 1, 2002. Electricity produced at such facilities from newly 
eligible sources would be eligible for the credit only from January 1, 
2002, through December 31, 2004. The credit for such electricity would 
be computed at a rate equal to 60 percent of the generally applicable 
rate. Electricity produced from newly eligible biomass co-fired in coal 
plants would also be eligible for the credit only from January 1, 2002, 
through December 31, 2004. The credit for such electricity would be 
computed at a rate equal to 30 percent of the generally applicable 
rate.
Residential solar energy systems
    The Administration proposes a new tax credit for individuals that 
purchase solar energy equipment used to generate electricity 
(photovoltaic equipment) or heat water (solar water heating equipment) 
for use in a dwelling unit that the individual uses as a residence. The 
credit would be available only for equipment used exclusively for 
purposes other than heating swimming pools. The proposed credit would 
be equal to 15 percent of the cost of the equipment and its 
installation. The credit would be nonrefundable and an individual would 
be allowed a lifetime maximum credit of $2,000 per residence for 
photovoltaic equipment and $2,000 per residence for solar water heating 
equipment. The credit would apply only to solar water heating equipment 
placed in service after December 31, 2001, and before January 1, 2006, 
and to photovoltaic systems placed in service after December 31, 2001, 
and before January 1, 2008.
Nuclear decommissioning funds
    The Administration proposes to repeal the current law provision 
that limits deductible contributions to a nuclear decommissioning fund 
to the amount included in the taxpayer's cost of service for ratemaking 
purposes. Thus, unregulated taxpayers would be allowed a deduction for 
amounts contributed to a qualified nuclear decommissioning fund. The 
Administration also proposes to permit funding of all decommissioning 
costs (including pre-1984 costs) through qualified nuclear 
decommissioning funds. Contributions to fund pre-1984 costs would be 
deductible except to the extent a deduction (other than under the 
qualified fund rules) or an exclusion from income has been previously 
allowed with respect to those costs. The Administration's proposal 
would clarify that any transfer of a qualified nuclear decommissioning 
fund in connection with the transfer of the power plant with which it 
is associated would be nontaxable and no gain or loss will be 
recognized by the transferor or transferee as a result of the transfer. 
In addition, the proposal would permit taxpayers to make deductible 
contributions to a qualified fund after the end of the nuclear power 
plant's estimated useful life and would provide that nuclear 
decommissioning costs are deductible when paid.
Net income limitation on percentage depletion from marginal wells
    The Administration proposes a one-year extension of the provision 
suspending the 100-percent-of-net-income limitation for marginal oil 
and gas wells. Under the Administration proposal, marginal wells would 
continue to be exempt from the limitation during taxable years 
beginning in 2002.
    Mr. Chairman, this concludes my prepared testimony. I will be 
pleased to answer any questions you or other members of the 
Subcommittee may have.

                                


    Chairman McCrery. Thank you, Mr. Mikrut.
    One of the goals of our energy policy, obviously, is to 
secure and increase domestic production to try to add to the 
supply here at home. In the administration's opinion, are the 
incentives which are currently in the Tax Code helping us to 
achieve that goal?
    Mr. Mikrut. Well, the administration hasn't proposed to 
repeal any of the incentives, so implicitly, yes, Mr. Mccrery. 
In addition, through the budget proposals, we believe that some 
of these incentives must be supplemented. Those are the four 
items that I mentioned previously. Vice President Cheney's task 
force is considering additional supplements, and those will 
come out later in the month.
    We do believe it is important to continue to analyze the 
current law incentives that are in the Code. Many of these are 
expiring provisions, so Congress and other policymakers can 
take this analysis up on a routine basis as the provisions 
begin to expire and can evaluate to what extent the provisions 
have provided the desired incentives and to what extent the 
provisions have to be modified. This is an ongoing process and 
we welcome the ability to express our views with respect to 
these provisions, both in hearings like this and at proposed 
markups.
    Chairman McCrery. Do you know if Vice President Cheney's 
task force is going to include any tax proposals in their 
report?
    Mr. Mikrut. There are several tax proposals that are being 
considered, but developing a comprehensive national energy 
policy is very much like a jigsaw puzzle. You have to put in 
some of the bigger pieces first, dealing directly with energy 
policy, and then see what's missing. Then you have to determine 
whether tax incentives can fill in those missing holes.
    As such, the analysis isn't done until it's all done, and 
the extent tax policy needs to supplement some of the basic 
energy policies is the question that is being considered 
currently.
    Chairman McCrery. Do you know when we should expect a 
report from the task force?
    Mr. Mikrut. I believe the task force hopes to finish by the 
end of the month, and perhaps by mid-month. So it's very soon, 
Mr. Chairman.
    Chairman McCrery. How about the conservation subsidies that 
you mentioned in your testimony. Can you give us some idea of 
the impact those have had on conservation?
    Mr. Mikrut. Under current law, Mr. Chairman, there is a 
conservation subsidy that allows public utilities to give to 
their residential customers tax-free benefits for certain 
equipment or weatherization or other benefits for energy 
conservation. We understand that those have been effective with 
respect to residential properties.
    We have also found that some of the renewable fuels 
provisions have also been effective and, as modified in the 
President's proposal, we think we should increase production of 
energy from these renewable sources.
    Chairman McCrery. Two years ago, we were hearing, from our 
independent producers particularly, that the low prices were 
driving them out of business, essentially. Now prices are up 
and the independent producers who are still in business are 
doing better.
    My question is, do we need, even in times of high prices, 
the incentives in the tax laws that we have?
    Mr. Mikrut. As I recall, Mr. Chairman, it was almost 2 
years ago that the Treasury was testifying before Mr. 
Houghton's Oversight Subcommittee on this very issue. What came 
out of the testimony then is that during a period of low 
prices--and price probably being the major incentive for 
someone to produce from oil and gas properties--that in a 
period of low prices, producers will cap marginal wells, and 
that once a marginal well is capped, it is almost permanently 
out of service. If it is prohibitively expensive to regenerate 
that production, that production is permanently lost.
    I believe your suggestion that, even in a period of 
relatively high prices, one should consider whether incentives 
are necessary to keep such properties producing during a period 
of low prices, is appropriate. I think the administration 
proposal to further extend the marginal well net income 
limitation is a step in that direction.
    Chairman McCrery. Well, thank you, Mr. Mikrut. In fact, my 
last question was going to be concerning that provision, which 
suspends the 100 percent net income limitation. I gather from 
your response to that question that the administration is 
convinced that this suspension should continue.
    My only question, I guess, would be, if it's so important 
to encourage continued production from marginal wells, why does 
the administration only propose a 1-year extension? Why don't 
we make it permanent?
    Mr. Mikrut. That is one of the issues that will be taken up 
by the task force. The provisions that will expire this year, 
including the 100 percent limitation, have been proposed to be 
extended for 1 year in order to again evaluate whether it is 
necessary to provide further extensions. But I think the case 
you're making is something that has to be taken into account, 
whether a permanent extension is warranted or not.
    Chairman McCrery. Thank you, Mr. Mikrut. Mr. McNulty.
    Mr. McNulty. Thank you, Mr. Chairman. Thank you, Mr. 
Mikrut, for your testimony.
    Mr. Mikrut, given the fact that energy conservation 
incentives have the potential for a more immediate impact than 
building new power plants, which we also need to do, why isn't 
there more of an emphasis on the conservation tax incentives, 
or do you think there will be in the task force report?
    Mr. Mikrut. I think the task force is taking very seriously 
conservation measures as well as production measures. I think 
under current projections--and the representative from EIA can 
tell you better--that currently it appears that energy demand 
will be increasing, so we have to address that immediately. 
Over time, I believe energy conservation will become more and 
more important. So I think the immediate concern is what's 
facing us on the short-term horizon, which is increased demand, 
making sure there's an adequate supply and, over time, to look 
at the conservation measures.
    Mr. McNulty. What is your analysis of why energy costs have 
skyrocketed in recent months? Who's to blame for that?
    Mr. Mikrut. I don't believe it's the result of the tax 
system, Mr. McNulty, so I'm probably not the right person to 
answer your question.
    Mr. McNulty. Do you have any analysis of what to expect 
over the next year--not assuming anything new is done with 
regard to the issues we're discussing--but an analysis of what 
we should look forward to in terms of prices over the next 
year?
    Mr. Mikrut. Again, Mr. McNulty, I will have to defer to the 
experts at EIA, who can probably give you a more informed 
analysis of that question.
    Mr. McNulty. I have no further questions, Mr. Chairman.
    Chairman McCrery. Mr. Hayworth.
    Mr. Hayworth. Mr. Chairman, congratulations on this opening 
hearing. It's an honor to serve with you on this Subcommittee. 
Mr. Mikrut, thank you for stopping by.
    One of the advantages of seating arrangements, the 
gentleman from Illinois, Mr. Weller, is a seat-mate of mine on 
the full Committee as well. We have topics of common interest. 
In fact, to presage his questioning, he will probably get into 
the whole area of nuclear decommissioning.
    I just wanted to articulate to you, Mr. Mikrut, that I have 
been working with my colleague from Illinois, as well as 
Congressmen English, Matsui and Neal, on a legislative package 
that is designed to address some of the Federal tax 
consequences of electricity restructuring. Our legislation, the 
Electric Power Industry Tax Modernization Act, or H.R. 1459, 
includes the nuclear decommissioning bill that my friend, Mr. 
Weller, has introduced. My private use bill, tax relief for 
contributions in aid of construction, had a provision that 
addresses the use of tax-exempt bonds for transmission 
facilities.
    I forwarded a copy of H.R. 1459 to the Treasury Department, 
and I hope I can work with Secretary O'Neill and you on these 
important issues in the days ahead. So I just wanted to let you 
know that it's down there.
    Turning to questions, so many different things have been 
done, and so many alternative forms of energy have been 
encouraged. I think when I drive into the neighboring State of 
California, where there are certainly challenges, to put it 
euphemistically, about electricity, and I see the windmills 
there. I'm interested in the wind energy credit. That section 
45 tax credit was enacted in 1992.
    Could you give us an assessment of the impact that credit 
has had on the production of energy since that point in time?
    Mr. Mikrut. I think, Mr. Hayworth, in order to analyze the 
section 45 credit, one has to look not only at how much 
electricity is being produced from alternative sources but, as 
well, what sort of additional activity is going on because of 
the credit.
    One of the things that we found is that new production 
facilities have come on line. Although clearly they are not the 
predominant sources of production in the United States--
predominant production still comes from fossil fuels---there 
have been alternative sources of energy developed because of 
the credit.
    In addition, not only have new sources come online, I 
believe there is more research being done and that the section 
45 credit would stimulate research beyond that stimulated by 
the research (R&E) credit. This research was undertaken because 
perhaps taxpayers or entrepreneurs thought they could develop a 
technology that could qualify for the section 45 credit. What 
we have been able to determine in talking to taxpayers is that 
they continue, because of these tax incentives, to try to 
discover new sources of energy.
    Mr. Hayworth. I thank you, Mr. Mikrut. Mr. Chairman, I have 
no further questions.
    Chairman McCrery. Thank you, Mr. Hayworth. Mr. Weller.
    Mr. Weller. Thank you, Mr. Chairman. Let me again commend 
you for kicking off the first hearing of the Select Revenue 
Subcommittee on an important issue that we're all facing, 
particularly back home where we now have gasoline prices well 
over two dollars in the Chicago area and, of course, inching 
higher. It certainly tells us what the result is when our 
Nation fails to have an energy policy over the last decade and 
why we need one. Of course, the Tax Code does have an impact.
    I have been working with my friend, Mr. Foley, on extension 
of the wind energy tax credit, which is a key part, I believe, 
in reducing our dependence on imported oil and, of course, 
looking for alternative sources of energy, particularly in the 
area of ``green power''. I am pleased that the administration 
has included an extension of the wind energy credit in your 
budget.
    Mr. Mikrut, I would like to focus my first question on the 
area of nuclear decommissioning, an issue in which 
Representative Cardin and I introduced legislation which was 
basically included in legislation sent to President Clinton 
and, unfortunately, vetoed as part of a much larger tax 
package. Mr. Cardin and I are reintroducing that legislation 
this week.
    Clearly, there is a need for modernizing the tax treatment 
of nuclear decommissioning funds, particularly on the 
restructuring in electricity that's going on around the 
country. We are now having nuclear power plants changing hands 
and, of course, we need to modernize the tax treatment of those 
nuclear decommissioning funds. Again, I want to note that the 
President has included provisions regarding modernizing the 
treatment of nuclear decommissioning funds in his budget. I 
believe it's quite similar to what Representative Cardin and I 
have introduced in the past, and similar to the legislation 
that we will be reintroducing this week, which is identical to 
what President Clinton vetoed.
    But there are several questions I would like to ask, Mr. 
Mikrut, in relation to the proposal that the administration 
included in your budget.
    You know, many nuclear power plants were constructed prior 
to 1984, when the tax laws were changed to allow contributions 
into qualified funds. The administration's proposal differs 
from the legislation that Mr. Cardin and I have introduced with 
respect to how to treat pre-1984 costs.
    I was wondering, can you explain why you prefer the 
administration's approach versus the approach that this 
Committee has taken in the past?
    Mr. Mikrut. Certainly, Mr. Weller, although I would like to 
point out where the proposals are very much the same. We think 
it is very important that amounts that were incurred for 
decommissioning, or anticipated to be incurred for 
decommissioning, prior to 1984, should be fully funded. That is 
the thrust of your bill, Mr. Hayworth's bill, and several other 
congressional proposals that have come forward. We think it's 
very important that amounts that have been collected to 
decommission a nuclear plant in the future, even though that 
decommissioning relates to pre-1984 periods, should be placed 
in the funds and get the beneficial treatment that the funds 
provide.
    Clearly, in 1984, when Congress put these rules in, there 
were certain budget deficit costs that probably prohibited 
expansion of the provision at that time. But current surpluses 
allow us to free up some of those tax dollars and put them 
toward the funds.
    I think it is clear, though, that you do not want a one-
time hit, so that a large amount of money goes into the fund at 
one time and becomes deductible all at once. I believe both 
your bill, H.R. 1459, as well as the administration's proposal, 
lengthens or stretches out those deductions over a period of 
years.
    I think the only difference is the methodology that we use 
versus the methodology that you use in computing the deduction. 
We would like to work with you to see if one is better than the 
other. Ours is very simple, it's straightforward, it spreads 
the cost straight line over a ten-year period. Your method, I 
believe, goes through the former costs of service type 
calculation, a level funding calculation, that is aplicable to 
the post-'83 amounts.
    Again, I think the difference is not that significant. The 
significant part is that both proposals allow for the pre-1984 
amounts to be fully funded.
    Mr. Weller. Again, we're very anxious to work with you. We 
appreciate the fact that the administration recognizes the 
importance of this issue. Nuclear power is a clean way to 
generate energy and, of course, is a key part of our energy 
source. It must be part of any new, modern energy policy.
    Let me just ask, from a policy standpoint, why you feel 
that, in facilitating the transfer of nuclear power plant 
ownership from one entity to another, why a tax-free transfer 
is so important?
    Mr. Mikrut. We have talked with several taxpayers who were 
contemplating transfers of nuclear plants, and those types of 
transfers took all forms. Some were tax free mergers, some were 
contributions to joint ventures, some were just outright sales 
of the plants.
    But the issue that has come up is what to do with the 
amounts that are in these funds and what to do with the 
contingency liability that decommissioning represents in the 
future. It seems that, especially with respect to some of the 
taxable transfers, where there is a taxable sale of the plant, 
such a sale could trigger the inside buildup in the funds, and 
that was prohibitive for the transaction and probably stopped 
the transaction in its tracks.
    One can almost view the transfer of the nuclear 
decommissioning fund and the assumption of that liability as a 
separate transaction, separate from the plant sale itself. We 
think it's appropriate to try to match, as present law tries to 
match, the fund with the contingent liability. Essentially, 
what is happening is that the transferee is stepping in the 
shoes of the transferor and to that extend there is no taxable 
event, because the moneys are still in the fund and they can't 
be reached except for the decommissioning that will happen 
several years in the future.
    So we thought, in order to facilitate various forms of 
transfers of generating properties that deregulation will be 
forcing, that the major stumbling block to transferring the 
funds should be clarified. The Service has ruled in the past, 
with respect to certain transactions, that it is a tax-free 
event. We propose to further effectuate that policy for other 
types of transactions.
    Mr. Weller. Thank you, Mr. Mikrut.
    Mr. Chairman, I have a few more questions. Are we going to 
have a second chance if we hang around, or is time going to 
allow for that, or should I just submit my questions and ask 
him to respond in writing? I have additional questions.
    Chairman McCrery. Why don't you and I discuss it after Mr. 
Lewis is recognized.
    Mr. Weller. All right. Thank you, Mr. Chairman.
    Chairman McCrery. Mr. Lewis.
    Mr. Lewis. Thank you, Mr. Chairman.
    I guess my question deals with the ag community and the 
particular need that we have for biodiesel, ethanol. Will the 
President, through the report that Mr. Cheney is going to be 
providing us, will that continue to support the tax credit for 
the use of those renewable fuels?
    Mr. Mikrut. Mr. Lewis, I clearly can't get ahead of the 
Vice President and provide what will be in the final plan. As I 
mentioned before, all the proposals have to be taken in 
context, and the analysis is not over until it's over.
    I can assure you that all the proposals that have been 
considered in the public forum, in the Congress and by the 
administration over the last several years are being considered 
and taken into account and evaluated.
    Mr. Lewis. Thank you.
    Chairman McCrery. Mr. Foley.
    Mr. Foley. Thank you very much, Mr. Chairman.
    I just wanted to commend the gentleman from Illinois, Mr. 
Weller, on coauthoring with me the wind energy extension. I 
think it's a very important public policy area and I appreciate 
his work on this in years past, and obviously welcome our joint 
cooperation on this very important bill.
    Let me ask you a question relative to section 29 credits, 
particularly dealing with the size of crushed coal. How do you 
reconcile the new requirement, or at least the ruling, of one-
eighth inch or smaller in size of coal, based on IRS's prior 
rulings, particularly the many which have provided that 
taxpayers will use coal fines, run of mine coals, run of mine 
coal fines, feedstock from a wide variety of sources, or simply 
coal without stating a specific coal size?
    Mr. Mikrut. Before I answer directly your question, Mr. 
Foley, for the benefit of the Members who are not as familiar 
with the section 29 issue as I know you are, let me give you a 
bit of background.
    Present law provides a tax credit for synthetic fuels 
produced from coal. The credit is approximately $25 a ton, I 
believe, under current prices. Late last summer and fall, the 
Treasury and the IRS received significant correspondence from 
Members of Congress, Governors of States, and several of our 
trading partners, that some taxpayers were producing synfuels 
that may or may not have met former IRS ruling policies and 
asked us to look into this issue.
    Last October, the IRS and Treasury suspended the ruling 
policy and requested comments before we reinstituted the 
rulings. Several taxpayers came in and talked to us. We had a 
frank discussion with them, an open and frank discussion. We 
studied the matter in great detail and 2 weeks ago we renewed 
our ruling program.
    What we decided is that the policy that we would go forward 
with was to be consistent with the prior rulings and the 
standards established by the IRS in 1986, in Revenue Ruling 86-
100, requiring a significant chemical change in order to 
determine whether coal production produces synfuels. We believe 
this standard was an appropriate interpretation of 
congressional intent. We also clarified some of the placed in 
service rules for certain properties that had to be met in 
1998.
    In evaluating comments, we looked at prior rulings. It 
seemed to us that the bulk of the rulings dealt with coals that 
were in a very small state, one-eighth of an inch or less. 
Since 2 weeks ago, when we issued our ruling, we have received 
significant comments from many taxpayers that perhaps three-
eighths of an inch is a better industry standard. We have asked 
the industry to come back to us with an additional study. They 
were very responsive and came back, I think, with it yesterday, 
so it was within a week.
    We do think that they made a point and we're looking to 
modify the ruling policy that we put forth 2 weeks ago to 
accommodate what we believe the industry standards are. To be 
more specific as to your question, we are looking at adopting 
the three-eighths inch standard.
    Mr. Foley. That is welcome news, because I understand there 
is a deadline of May 7th for permanency on this policy. Do you 
feel we'll be able to capture it by then?
    Mr. Mikrut. We would hope to move very quickly on this, 
yes, Mr. Foley.
    Mr. Foley. I think Mr. Hayworth mentioned wind energy. I 
would like you to elaborate because I, too, was delighted that 
the President chose to include it in his proposal. Obviously, 
we feel it is a significant alternative to fossil fuels.
    You would anticipate strong support from the administration 
if, in fact, we extended it in Congress?
    Mr. Mikrut. The administration, in its fiscal year 2002 
budget, does have an extension of the wind energy credit 
through 2004, so yes, Mr. Foley.
    Mr. Foley. Thank you.
    Chairman McCrery. Mr. Jefferson.
    Mr. Jefferson. Thank you, Mr. Chairman.
    I'm coming in late, so I hope I don't cover territory that 
others have already covered, but I want to ask this general 
question.
    To what extent do you think tax incentives are themselves 
effective and efficient in promoting production, conservation, 
or whatever the energy policy is directed toward, to what 
extent do you think tax incentives are effective and efficient 
in getting that done?
    Mr. Mikrut. Mr. Jefferson, this is a question that's the 
major focus of this hearing. Clearly, I think the most 
important incentive for energy production is price, and fossil 
fuels are generally priced on a world market so there is very 
little that can be done to affect that price. There is very 
little that can be done through the Internal Revenue Code to 
affect the world market price. So many of the policies that you 
can put forth through the Internal Revenue Code work on the 
edges and work on the margin.
    Where they seem to be the most effective is not in dealing 
necessarily with fossil fuel production, or exploration for 
those items, but with respect to energy that would otherwise 
not be tapped into. For example, marginal well production is 
one area where the Congress has traditionally provided tax 
incentives, and the administration, in its fiscal year 2002 
budget, would provide additional incentives.
    In addition, alternative fuels, whether they be wind 
energy, section 29 qualified energy sources, or section 45 
qualified energy sources, is another area that the Internal 
Revenue Code can be, in certain instances, effective in 
providing incentives.
    Finally, the last thing you mentioned is, of course, 
conservation. Conservation is another area greatly influenced 
by price. The higher the price for energy, the more the 
incentive to conserve without any tax incentives.
    But on the margin one can provide incentives for increased 
conservation. The Congress has done that through the provision 
of section 136 and exclusion for residential homeowners for 
conservation measures provided by utilities, as well as other 
provisions that Congress has considered over the years.
    Mr. Jefferson. I think I have your answer. It's around the 
edges, as you say, around the margins. You would leave a 
program of tax incentives for exploration that wouldn't 
otherwise take place, in the judgment of the Congress, or 
alternative fuels, and maybe in conservation in times when 
prices aren't high; that's kind of how you would generally 
summarize what you just said, right?
    Mr. Mikrut. Yes, Mr. Jefferson.
    Mr. Jefferson. So we ought to be looking in areas like that 
if we're going to try to do something that's effective and 
efficient with the Tax Code.
    I'm sorry I haven't been able to compare them myself, but 
to what extent do the proposals by the current administration 
differ from that which the prior administration took in this 
area?
    Mr. Mikrut. Some of the proposals are very similar. The 
prior administration also proposed extension of some of the 
expiring provisions, and also would have allowed the open-loop 
biomass to qualify for the section 45 credit. They would have 
also allowed the credit for plants placed in service in prior 
years at a reduced rate.
    The nuclear decommissioning proposal in the Clinton 
administration was somewhat more limited than to the one 
currently in the administration's proposal, and was more 
limited than H.R. 1459, or Mr. Weller's proposal.
    There are other areas with respect to hybrid vehicles that 
the prior administration proposed that were not in the current 
budget but are being considered by the task force, so you may 
be seeing those when Vice President Cheney produces his 
recommendations later this month. The tax credit for 
residential solar energy was something that was in the prior 
administration's proposal and has moved forward into the 
current budget proposal as well.
    So, in general, I think many of the proposals that are 
currently in the administration's budget did have analogues to 
the prior administration proposals. In addition, there will be 
further proposals coming forth through the Vice President's 
task force that may go well beyond those.
    Mr. Jefferson. Would you characterize the differences as 
rather small?
    Mr. Mikrut. In some proposals, yes. I mean, there were 
other----
    Mr. Jefferson. I mean, any big, new ideas. That's what I'm 
trying to get at, I guess. Any new, big, blockbuster ideas here 
that the prior administration did not pursue?
    Mr. Mikrut. There are no major new blockbuster proposals in 
the fiscal year 2002 budget. However, I think the comprehensive 
energy policy that the task force is putting together will 
subsume a lot of the things that were in the budget, and when 
you see it, you may think they're blockbuster proposals.
    Mr. Jefferson. One last thing, Mr. Chairman, if I might. 
The proposals are mostly on the production side, or are there 
any on the conservation side? Or is it both?
    Mr. Mikrut. I think they're on both.
    Mr. Jefferson. I'm done. Go ahead. I'm telling the Chairman 
I'm done. I didn't want to stop you from talking.
    Mr. Mikrut. I think the proposals with respect to the 
expansion of section 45 and the residential solar systems can 
be treated as conservation because they conserve the production 
of fossil fuels. They are alternatives to fossil fuels. 
Therefore, because you are encouraging production from 
renewable sources, they're conservation type measures.
    Mr. Jefferson. I might say that Wes Watkins and I have had 
some luck over the last several years in getting incentives in 
stripper wells and marginal wells production that we're very 
proud of. We continue to support expanding production.
    Obviously, with what we know now about how to protect the 
environment at the same time in doing that, we can introduce 
these technologies into the expanded production capacity. But 
we have worked on trying to make sure we have more industry 
security within our own control than we've had and I think 
that's very important. I am real proud to have worked with Wes 
on these things.
    Chairman McCrery. Mr. Watkins.
    Mr. Watkins. Mr. Chairman, just one comment. It's kind of a 
big umbrella statement, if I might.
    You know, our Nation has not had an energy policy, and it's 
for a lot of reasons. We can point fingers. And we're at fault. 
I guess we can take part of the blame here in the U.S. 
Congress. Past administrations, both Democrat and Republican, 
have to take part of the blame.
    Today, we have two of the most knowledgeable men concerning 
energy in the White House, George W. Bush and Dick Cheney. I 
have a lot of faith, that they have a lot of the answers. I 
know they have an understanding of the energy industry.
    It would be a simple mistake and a great failure on our 
part if we cannot come together and make sure we at least put 
tax provisions in there that will allow us to develop a quality 
and quantity of energy, from a variety of sources, throughout 
this country.
    I notice that Dick Cheney said we need 120 to 150 power 
generating plants. I don't question that at all. It has to be 
fired by natural gas, coal, or other fossil fuels, and we need 
to move and we need to make it our utmost priority during this 
administration, to get a policy to move our country forward.
    So, Mr. Chairman, I think this is a very important and 
timely topic, and we want you to take the message back to the 
administration, that we hope and pray they will not fail, and 
that we will be there to try to help them.
    Mr. Mikrut. Thank you, Mr. Watkins.
    Chairman McCrery. Thank you, Mr. Watkins. I hope you and 
Mr. Jefferson will continue to work very well together for the 
interests of energy policy in the United States.
    Mr. Weller has one more question, Mr. Mikrut, and then 
we'll let you go.
    Mr. Weller. Thank you, Mr. Chairman. Mr. Mikrut, thank you 
for participating in what is a very important hearing today.
    I do want to also thank you on the issue that my friend, 
Mr. Foley, raised regarding crushed coal and your review of 
those standards. That's good news and it has a positive impact. 
I believe we can address that issue in an environmentally 
responsible way. I am glad to hear the good news and look 
forward to working with you on that issue as well.
    The last area of questioning I would like to raise with you 
is regarding the section 29 tax credit, which was designed to 
provide incentives for the production of non-conventional 
fuels. Have you seen an increase in the production of non-
conventional fuels over the past 10 years, and what has been 
the result?
    Mr. Mikrut. I believe there has been an increase in the 
production of some non-conventional fuels. I believe that our 
estimate of the current tax expenditure costs--that is, what an 
outlay cost would be--is about $1.2 billion a year, which is 
rather significant.
    We have seen, again in our study of the section 29 credit, 
with respect to coal production, that there seems to be an 
increase in activity in that area. It is not necessarily true 
that it comes at a decrease in other areas, so I would think, 
in general, the production of section 29 qualified synfuels has 
increased over time.
    Mr. Weller. So you believe it has had a positive impact 
then, from the standpoint of increased production of non-
conventional fuels?
    Mr. Mikrut. I believe there has been more credit-qualified 
production over time.
    Mr. Weller. Do you believe that an extension of this credit 
could help then, as we look for ways of finding more affordable 
energy for Americans?
    Mr. Mikrut. Well, with respect to the synfuels from coal, 
that provision is not scheduled to expire until 2008, so we 
have a great deal of time to do further analysis to see where 
we are at that point, what new technologies have come on line, 
whether we want to reshift the credit toward new technologies 
rather than paying for old technologies, which may or may not 
need the credit. There may be some technologies that qualify 
for the credit that you may no longer want to support at all. 
You may want to put those resources to a better use.
    Again, I think we have some time to do an analysis with 
respect to that portion of the section 29 credit--until 2008. 
Another portion of the credit does not expire until 2003, so 
again, you have some time there. Through hearings like this, 
and developments of further budgets, we can analyze those 
portions of the credit as well.
    Mr. Weller. You know, Mr. Mikrut, my experience with 
various tax credits and other incentives, when they're in a 
temporary nature, when they sunset over a short period of time, 
many times, once they're made permanent, or there's a very 
lengthy extension, there is a greater investment as a result of 
that because of the tax consequences and business 
decisionmakers trying to decide on whether to invest their 
capital look at that long-term consequence. When they know a 
tax provision is going to be there permanently, or for a long 
period of time, they are more inclined to use it. That's why 
extension of the wind energy credit is so important and, of 
course, why this issue is important.
    Let me just ask this. As we look at the energy policy, 
which we're all anxiously awaiting to come forward from the 
administration in the next two weeks, do you feel that we have 
an adequate supply of non-conventional fuels to meet the demand 
we're looking at? What's your point of view?
    Mr. Mikrut. I think, through the budget proposals, where 
we're suggesting an extension of alternative fuels, and through 
the discussions that we've had in looking at some of the 
proposals that have come forth before the task force, there is 
a renewed interest in trying to develop fuel production to meet 
demand in non-conventional ways, or alternative ways. And I 
think this is an important component.
    However, as the Vice President said, it is hard to imagine 
alternative fuels being the major source of energy production 
in the near term, but it is something where investments in 
research and incentives through tax credits may provide a 
stimulus for the longer term.
    Mr. Weller. Thank you, Mr. Mikrut. Mr. Chairman, thanks for 
the courtesy of the opportunity to have a second turn. I 
appreciate it very much, Mr. Chairman. It's a good hearing.
    Chairman McCrery. Mr. Mikrut, thank you very much for 
appearing before us today. We will probably be seeing you some 
more.
    Mr. Mikrut. Thank you, Mr. Chairman.
    Chairman McCrery. Miss Hutzler is next. Miss Hutzler is 
Director of the Office of Integrated Analysis and Forecasting, 
Energy Information Administration, with the United States 
Department of Energy.
    Miss Hutzler, welcome. Your written testimony will be 
submitted for the record in its entirety, and if you could 
summarize within about 5 minutes, we would appreciate it. You 
may proceed.

 STATEMENT OF MARY J. HUTZLER, DIRECTOR, OFFICE OF INTEGRATED 
 ANALYSIS AND FORECASTING, ENERGY INFORMATION ADMINISTRATION, 
                   U.S. DEPARTMENT OF ENERGY

    Ms. Hutzler. Thank you, Mr. Chairman, and Members of the 
Subcommittee. I appreciate the opportunity to appear before you 
today to discuss energy consumption, supply, and efficiency in 
the United States.
    The Energy Information Administration (EIA) is an 
autonomous 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, other government agencies, the U.S. Congress 
as well as the public.
    The projections in this testimony are from the Annual 
Energy Outlook 2001, which provides analysis of domestic energy 
consumption, supply and prices. These baseline projections are 
widely used by government agencies, the private sector, and 
academia for their own analyses. They are not meant to be exact 
predictions. They represent a likely energy future, giving 
technological and demographic trends, current laws and 
regulations, and consumer behavior.
    We expect total energy consumption to increase from an 
estimated 97 quadrillion Btu in 1999 to 127 quadrillion Btu in 
2020, an average annual increase of 1.3 percent. This is lower 
than the growth we have experienced since 1983, when energy 
consumption grew at a rate of 1.7 percent per year. We have 
seen energy consumption decline twice in the past 30 years, in 
the mid-seventies and the early eighties, with both occurring 
during oil price increases.
    Today, petroleum, natural gas, and coal make up about 85 
percent of the total energy consumed in the United States. We 
project that these fossil fuels will increase their share 
slightly over the next 20 years. Petroleum represents about 40 
percent of today's consumption, and is mainly used for 
transportation fuels and in the industrial sector for petro-
chemical feedstocks, plastics, asphalt, and areas where little 
substitution potential exists.
    Coal and natural gas each represent about 23 percent of our 
current energy consumption. Ninety percent of our coal is used 
for electricity generation. Natural gas is consumed in the 
residential and commercial sectors, mainly for space heating, 
and in the industrial and electricity generation sectors as a 
boiler and generating fuel. We are expecting a 52-percent 
increase in natural gas total consumption by 2020.
    In this next chart, the inset box shows the expected 
increase in electricity demand over the next 20 years. To meet 
that demand, natural gas consumption for electricity generation 
is projected to triple between now and 2020. We expect natural 
gas generating technologies to supply 92 percent of our new 
capacity over the next 20 years because of their lower capital 
costs, higher efficiencies, better load following, and shorter 
construction lead times relative to the other technologies.
    Natural gas is expected to increase its share of total 
generation from 16 percent today to 36 percent in 2020. And 
coal is expected to decrease its current share of generation 
from 52 percent to 44 percent.
    Nuclear generating capacity is projected to decline through 
2020 due to retirements of some existing facilities, for which 
continued operation is not economical compared to the cost of 
building a new generating facility. Of the 97 gigawatts of 
nuclear capacity available in 1999, 26 gigawatts is projected 
to be retired by 2020, and no new plants are expected to be 
constructed. As a result, nuclear generation decreases its 
share from 20 percent today to 11 percent in 2020.
    The use of renewable technologies for electricity 
generation, including cogeneration, is projected to increase 
slowly, primarily due to moderate expected fossil fuel prices. 
Most of the growth in renewable electricity generation is 
expected from biomass, landfill gas, geothermal energy, and 
wind power. State mandates and other incentives, including the 
Federal production tax credit for wind generation, encourage 
most of the growth in renewables in the earlier part of the 
forecast.
    The next chart shows our domestic supply of fuels. Coal is 
our Nation's most abundant fossil fuel resource, providing 32 
percent of our current domestic production. We expect domestic 
natural gas production to surpass coal by 2015, increasing its 
share of production from 27 percent today to 35 percent in 
2020.
    Our domestic petroleum supply is projected to remain 
roughly flat for the next 20 years, resulting from decreasing 
crude production and increasing production from natural gas 
plant liquids and refinery gains. However, because of our 
increasing demand for petroleum, net imports are expected to 
increase from their 52 percent share today to 64 percent in 
2020.
    The lower energy growth rate that we are forecasting for 
the future is partly a result of improved energy intensity, 
which is the bottom line on this graph. Energy intensity has 
declined since 1970, most notably when energy prices have 
increased rapidly. Between 1970 and 1986, energy intensity 
declined at an average rate of 2.3 percent per year, as the 
economy shifted to less energy intensive industries and more 
efficient technologies.
    Without significant price increases, and with the growth of 
more energy intensive industries, the intensity decline slowed 
to an average of 1.3 percent per year between 1986 and 1999. 
Through 2020, we project energy intensity to decline at an 
average annual rate of 1.6 percent, as efficiency gains and 
structural shifts in the economy offset growth and demand for 
energy services.
    In conclusion, through 2020, continuing growth in the U.S. 
economy is expected to stimulate more energy demand, with 
fossil fuels remaining the dominant source of energy. 
Renewables are expected to supply 7 percent of our total 
consumption in 2020, the same share as today. Nuclear is 
expected to supply a declining share due to retirements of 
existing capacity.
    Thank you, Mr. Chairman, and Members of the Subcommittee. I 
will be happy to answer any questions you have.
    [The prepared statement of Ms. Hutzler follows:]
 Statement of Mary J. Hutzler, Director, Office of Integrated Analysis 
and Forecasting, Energy Information Administration, U.S. Department of 
                                 Energy
    Mr. Chairman and Members of the Subcommittee:
    I appreciate the opportunity to appear before you today to discuss 
the long-term outlook for energy markets in the United States.
    The Energy Information Administration (EIA) is an autonomous 
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, but we do 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. However, 
EIA's baseline projections on energy trends are widely used by 
government agencies, the private sector, and academia for their own 
energy analyses.
    Each year, EIA publishes the Annual Energy Outlook, which provides 
projections and analysis of domestic energy consumption, supply, 
prices, and energy-related carbon dioxide emissions through 2020. The 
projections in this testimony are from the Annual Energy Outlook 2001 
(AEO2001), published by EIA in December 2000. 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. In 
addition to these short-term phenomena, long-term trends in technology 
development, demographics, economic growth, and energy resources may 
evolve along a different path than assumed in the AEO2001 reference 
case. Many of these uncertainties are explored through alternative 
cases in AEO2001.
Energy Consumption
    Total energy consumption in the United States is projected to 
increase from 97.1 to 127.0 quadrillion British thermal units (Btu) 
between 1999 and 2020, an average annual increase of 1.3 percent. 
Energy consumption increased from 67.9 quadrillion Btu in 1970 to 81.0 
quadrillion Btu in 1979, with a downturn in 1974 and 1975 during the 
first oil price increase. During the early 1980s, energy consumption 
again declined to 73.3 quadrillion Btu in 1983, due in part to the 
second oil price increase. Since 1983, energy consumption has been 
generally increasing, with an average annual increase of 1.8 percent 
through 2000.
    Transportation energy demand is expected to increase at an average 
annual rate of 1.8 percent to 38.5 quadrillion Btu in 2020 and is the 
fastest growing end-use sector (Figure 1). The growth in transportation 
use is driven by 3.6-percent projected annual growth in air travel, the 
most rapidly increasing transportation mode, and 1.9-percent annual 
growth in light-duty vehicle travel, the largest component of 
transportation energy demand, coupled with slow projected growth in 
vehicle efficiency. The projected growth in travel is a result of 
continued growth in the economy and in personal income.
    Residential and commercial energy consumption is projected to 
increase at average annual rates of 1.2 and 1.4 percent, respectively, 
reaching 24.4 quadrillion Btu in 2020 for residential demand and 20.8 
quadrillion Btu for commercial demand. Projected economic and 
population growth leads to expansion of the housing and commercial 
building stock. In addition, it is expected that the growth in personal 
income will increase equipment purchases and continue the trend to 
larger new homes. In both sectors, the growth in demand is led by 
electricity consumption for a variety of equipment--telecommunications, 
computers, office equipment, and other appliances. Electricity use is 
projected to increase at annual rates of 1.9 and 2.0 percent, in the 
residential and commercial sectors, respectively. Industrial energy 
demand is projected to increase at an average rate of 1.0 percent per 
year, reaching 43.4 quadrillion Btu in 2020, as efficiency improvements 
in the use of energy help to offset growth in manufacturing output.
    The projections incorporate promulgated efficiency standards for 
new energy-using equipment in buildings, as authorized by the National 
Appliance Energy Conservation Act of 1987 and periodically updated by 
the Department of Energy, and for motors, as required by the Energy 
Policy Act of 1992. Since AEO2001 included only those laws, 
regulations, and standards in effect as of July 1, 2000, the new 
standards for residential clothes washers, water heaters, and central 
air conditioners and heat pumps and commercial heating, cooling, and 
water heating equipment issued in January 2001 and revised in April are 
not included. In addition to the impact of efficiency standards, 
improvements in efficiency are projected as a result of expected 
technological improvement and market forces.
    Petroleum demand is projected to grow at an average rate of 1.4 
percent per year through 2020, led by the growth in demand for 
transportation (Figure 2). Petroleum demand has declined during periods 
of high oil prices and economic slowdowns, specifically 1973 to 1975, 
1978 to 1983, and 1989 to 1991. Since 1991, petroleum consumption has 
increased at an average annual rate of 1.7 percent, from 16.7 million 
barrels per day to record levels of 19.5 million barrels per day in 
1999 and 2000. Through 2020, consumption of petroleum for 
transportation uses is projected to increase from about two-thirds to 
72 percent of total petroleum demand. Projected growth in travel more 
than offsets efficiency gains, and expected economic growth increases 
petroleum use for freight and shipping through 2020.
    Natural gas consumption is expected to increase at an average rate 
of 2.3 percent per year. The demand for natural gas generally declined 
through most of the 1970s and earlier 1980s but began to increase again 
after its recent low of 16.2 trillion cubic feet in 1986. Between 1994 
and 1999, natural gas demand remained in the range of 21 to 22 trillion 
cubic feet but increased by 1 trillion cubic feet from 1999 to 2000, 
reaching a record high of 22.7 trillion cubic feet. In the projections, 
natural gas consumption is expected to increase in all sectors, but the 
most rapid growth is for electricity generation, where natural gas use 
(excluding cogenerators) is projected to grow from 3.8 to 11.3 trillion 
cubic feet between 1999 and 2020.
    Total coal consumption is expected to increase from 1,044 to 1,297 
million tons per year between 1999 and 2020, an average annual increase 
of 1.0 percent. Unlike petroleum and natural gas, coal consumption has 
generally increased since 1970, growing at an average annual rate of 
2.4 percent over the last three decades. In the projections, coal 
remains the primary fuel for generation, although its share of 
generation is expected to decline from 51 to 44 percent between 1999 
and 2020. About 90 percent of all coal consumption is used for 
electricity generation.
    Total renewable fuel consumption, including ethanol used in 
gasoline, is projected to increase at an average rate of 1.1 percent 
per year through 2020. In 2020, about 55 percent of renewable energy is 
used for electricity generation and the rest for dispersed heating and 
cooling, industrial uses, and fuel blending. Since 1973, total 
renewable energy consumption is estimated to have increased from 4.6 
quadrillion Btu to 7.1 quadrillion Btu in 2000, with 75 percent of the 
growth in the use of wood and waste.
    Nuclear generating capacity is projected to decline through 2020 
due to retirements of some existing facilities, for which continued 
operation is not economical compared to the cost of a new generating 
facility. Nuclear generating capacity increased from 7 to 100 gigawatts 
between 1970 and 1990, peaking at 101 gigawatts in 1996. Between 1970 
to 2000, nuclear generation increased from 22 to 754 billion 
kilowatthours. Of the 97 gigawatts of nuclear capacity available in 
1999, 26 gigawatts is projected to be retired by 2020, and no new 
plants are expected to be constructed by 2020. As a result, nuclear 
generation is projected to decline by about 21 percent by 2020.
    Total electricity consumption is projected to grow by 1.8 percent 
per year through 2020, led by growth in the residential and commercial 
sectors (Figure 3). Between 1970 and 2000, the average annual growth in 
electricity demand was 3.0 percent, and, during the 1960s, electricity 
demand grew by more than 7 percent per year. Several factors have 
contributed to the slowing growth in demand, including increased market 
saturation of electric appliances, improvements in equipment efficiency 
and utility investments in demand-side management programs, and more 
stringent equipment efficiency standards. Throughout the forecast, the 
projected growth in demand for office equipment, personal computers, 
and other equipment is dampened by slowing growth or reductions in 
demand for space heating and cooling, refrigeration, water heating, and 
lighting, the continuing saturation of electricity appliances, the 
availability and adoption of more efficient equipment, and efficiency 
standards.
Energy Intensity
    Energy intensity, measured as energy use per dollar of gross 
domestic product (GDP), has declined since 1970, most notably when 
energy prices have increased rapidly (Figure 4). Between 1970 and 1986, 
energy intensity declined at an average rate of 2.3 percent per year as 
the economy shifted to less energy-intensive industries and more 
efficient technologies. Without significant price increases and with 
the growth of more energy-intensive industries, intensity declines 
moderated to an average of 1.5 percent per year between 1986 and 2000. 
Through 2020, energy intensity is projected to decline at an average 
rate of 1.6 percent per year as efficiency gains and structural shifts 
in the economy offset growth in demand for energy services. Energy use 
per person generally declined from 1970 through the mid-1980s, and then 
tended to increase as energy prices declined. Per capita energy use is 
expected to increase slightly through 2020, as efficiency gains only 
partly offset higher demand for energy services.
Electricity Generation
    Generation from both natural gas and coal is projected to increase 
through 2020 to meet growing demand for electricity and offset the 
decline in nuclear power expected from retirements of some existing 
facilities (Figure 5). As noted above, the share of coal generation is 
expected to decline through 2020 because assumptions about electricity 
industry restructuring, such as higher cost of capital and shorter 
financial life of plants, favor the less capital-intensive and more 
efficient natural gas generation technologies. The natural gas share of 
total generation is expected to increase from 16 to 36 percent between 
1999 and 2020. It is projected that 413 gigawatts of new generating 
capacity will be needed in the forecast period, including cogeneration. 
Assuming an average plant size of 300 megawatts, this totals to nearly 
1,400 new generating plants. This capacity is needed to meet growing 
electricity demand and to offset the expected retirements of about 9 
percent of current generating capacity. The regions with the greatest 
capacity additions are the Southeast, Midwest, Texas, and California 
(Figure 6). Of this new generating capacity, it is projected that 92 
percent will be fueled by natural gas, 5 percent by coal, and 3 percent 
by renewables (Figure 7) because natural gas technologies are generally 
the least expensive options for new capacity when comparing total 
generation costs.
    The use of renewable technologies for electricity generation, 
including cogeneration, is projected to increase slowly at an average 
rate of 0.7 percent per year, primarily due to moderate fossil fuel 
prices. Most of the projected growth in renewable electricity 
generation is expected from biomass, landfill gas, geothermal energy, 
and wind power. State mandates and other incentives, including the 
Federal production tax credit for generation from wind, encourage much 
of the growth in renewables in the earlier part of the forecast period. 
Hydropower is expected to decline slightly through 2020, as output from 
existing facilities declines, and no large new sites are expected to be 
available for development.
Energy Supply
    Total domestic petroleum supply, including refinery gain and 
natural gas plant liquids, is projected to remain nearly flat through 
2020 (Figure 8). However, domestic crude oil production is projected to 
decline at an average rate of 0.7 percent per year, from 5.9 million 
barrels per day in 1999 to 5.1 million barrels per day in 2020. 
Conventional onshore production in the lower 48 States, which accounted 
for 44 percent of total U.S. crude oil production in 1999, is projected 
to decrease to 38 percent in 2020, as production from mature areas 
declines (Figure 9). Production from Alaska is also expected to decline 
between 1999 and 2020; however, projected declines in production from 
most of Alaska's oil fields--particularly Prudhoe Bay, the State's 
largest producing field--are expected to be offset by production from 
the National Petroleum Reserve-Alaska, which is projected to begin in 
2010. Offshore oil production is projected to range from 1.6 to 2.1 
million barrels per day throughout the forecast, and production from 
enhanced oil recovery is expected to increase later in the forecast 
period along with the world oil price projections.
    As a result of increasing projected petroleum demand, net petroleum 
imports are expected to rise through 2020, to meet growing demand 
(Figure 10). Between 1999 and 2020, net imports of petroleum are 
projected to increase from 51 percent to 64 percent of domestic 
petroleum demand. In 2020, the United States is expected to require net 
imports of crude oil and petroleum products totaling 16.5 million 
barrels per day.
    Unlike oil, domestic natural gas production, with its larger and 
more accessible resource base, is expected to increase from 18.6 
trillion cubic feet in 1999 to 29.0 trillion cubic feet in 2020. 
Increased production comes primarily from lower 48 onshore conventional 
nonassociated sources, although onshore unconventional production 
(including coalbed methane and low-permeability formations of sandstone 
and shale) is expected to increase at a faster rate than other sources 
as a result of technology advances (Figure 11). Offshore production is 
projected to increase less rapidly than onshore production but remains 
a major source of domestic supply. Natural gas production from Alaska 
is projected to increase slightly through 2020, not including gas from 
the North Slope. Production of associated-dissolved natural gas from 
lower 48 crude oil reservoirs generally declines in the projections, 
following the pattern of domestic crude oil production. In order to 
fill the gap between domestic production and consumption, net natural 
gas imports are expected to increase from 3.4 trillion cubic feet in 
1999 to 5.8 trillion cubic feet in 2020, mostly pipeline natural gas 
imports from Canada (Figure 12). Net liquefied natural gas imports are 
projected to increase from 0.1 to 0.7 trillion cubic feet by 2020. Two 
liquefied natural gas import facilities at Elba Island, Georgia, and 
Cove Point, Maryland, were expected to reopen in 2003 at the time the 
AEO2001 projections were finalized; however, 2002 appears to be a more 
likely date at this time.
    Coal production is expected to increase from 1,100 million tons in 
1999 to 1,331 million tons in 2020, an average of 0.9 percent per year, 
to meet rising domestic demand. From 1999 to 2020, low-sulfur coal 
production is expected to increase while the production of high- and 
medium-sulfur coal declines, due to the need to reduce sulfur dioxide 
emissions from coal-fired electricity plants required by the Clean Air 
Act Amendments of 1990. As a result, western coal production--the 
primary source of new low-sulfur coal--is expected to continue its 
historic growth, reaching 787 million tons in 2020, an annual growth 
rate of 2.2 percent (Figure 13). Western coal is surface mined and less 
costly to produce than eastern coal.
Energy Prices
    Energy markets and energy prices are subject to much uncertainty. 
Random events including severe deviations from normal weather, 
political disruptions, strikes, and failures of vital equipment, such 
as refineries, generating plants, and pipelines, are all likely 
occurrences that may cause energy prices to fluctuate from one year to 
the next or to fluctuate, sometimes dramatically, from the average 
annual prices presented in AEO2001. Because the occurrence and timing 
of these events cannot be foreseen, the prices projected in AEO2001 are 
based upon the expected trends for longer-term demand, supply, and 
technology development.
    At the time the AEO2001 projections were finalized in September 
2000, the average world oil price was projected to increase from $17.26 
per barrel in 1999 (1999 dollars) to about $27.60 per barrel in 2000, 
then fall through 2003 (Figure 14). In 2020, the projected price 
reaches $22.41 per barrel. At this time EIA is projecting a somewhat 
slower rate of decline in its Short-Term Energy Outlook. World oil 
demand is expected to increase at an average annual rate of 2.1 percent 
through 2020; however, projected growth in production in both OPEC and 
non-OPEC nations leads to relatively slow projected growth of prices 
through 2020. OPEC oil production is expected to reach 57.6 million 
barrels per day in 2020, nearly double the 29.9 million barrels per day 
in 1999. The June 2000 recoverable oil resource assessment by the U.S. 
Geological Survey raised world resources by about 700 billion barrels 
from the 1994 assessment. As a result, non-OPEC oil production is 
expected to increase from 44.8 million barrels per day to 59.5 million 
barrels per day between 1999 and 2020.
    The average wellhead price of natural gas is projected to increase 
from $2.17 per thousand cubic feet in 1999 to $3.13 per thousand cubic 
feet in 2020 (Figure 15). Natural gas prices have been high in 2000 and 
2001, due to higher than expected demand and to tight supplies, 
resulting from reduced drilling in reaction to low prices in 1998. At 
this time, EIA's Short-Term Energy Outlook projects natural gas prices 
to be higher in 2001 and 2002 than at the time the AEO2001 projections 
were finalized. The higher prices projected for 2001 and 2002 will 
result in a longer transition period before natural gas stocks can be 
sufficiently replenished to cause prices to fall to the long-term price 
path. In the longer-term projections, technological improvements in 
natural gas exploration and production are expected to slow price 
increases.
    The average minemouth price of coal is projected to decline from 
$16.98 per ton in 1999 to $12.70 per ton in 2020 (Figure 16). In a 
continuation of historical trends, the average price of coal is 
expected to decline through 2020 due to increasing productivity in 
mining, a shift to lower-cost western production, and competitive 
pressures on labor costs.
    Average retail electricity prices are projected generally to 
decline from 6.7 cents per kilowatthour in 1999 to 6.0 cents per 
kilowatthour in 2020, although they increase slightly at the end of the 
forecast due to rising projected natural gas prices (Figure 17). 
Electricity industry restructuring is expected to contribute to lower 
prices through reductions in operating and maintenance, administrative, 
and other costs. At the time the projections were finalized, twenty-
four States and the District of Columbia had passed legislation or 
promulgated regulations to restructure their electricity markets, which 
is incorporated in the projections.
Carbon Dioxide Emissions
    Energy-related carbon dioxide emissions are projected to increase 
at an average of 1.4 percent per year from 1999 to 2020, reaching 2,041 
million metric tons of carbon equivalent, 35 percent higher than in 
1999 and 51 percent higher than in 1990 (Figure 18). Projected 
increases in carbon dioxide emissions primarily result from continued 
reliance on coal for electricity generation and on petroleum fuels in 
the transportation sector.
Alternative Cases
    In order to show the impact of alternative assumptions concerning 
the key factors driving energy markets, we include a number of 
alternative cases in AEO2001. Two sets of these cases illustrate the 
impacts of improved technology in energy-consuming equipment and in the 
production of oil and gas.
    One alternative case assumes more rapid improvement in new 
technologies for end-use demand, through lower costs, higher 
efficiencies, and earlier availability for new technologies, relative 
to the reference case, as well as more rapid improvement in the costs 
and efficiencies of advanced fossil-fired and new renewable generating 
technologies. As a result, projected energy demand in 2020 is 8 
quadrillion Btu lower than in the reference case (Figure 19). Such 
technology improvements could result from increased research and 
development, but should not be considered the most optimistic 
improvements that could occur with a very aggressive program of 
research and development. The AEO2001 reference case assumes continued 
improvements in technology for both energy consumption and production; 
however, it is possible that technology could develop at a slower rate. 
In the 2001 technology case, it is assumed that all future equipment 
choices will be made from the equipment and vehicles available in 2001, 
with new building shell and industrial plant efficiencies frozen at 
2001 levels. Also, new generating technologies are assumed not to 
improve over time. In this case, efficiencies improve over the forecast 
period as new equipment is chosen to replace older stock and the 
capital stock expands; however, projected energy demand in 2020 is 6 
quadrillion Btu higher than in the reference case.
    Another alternative case assumes more rapid technological 
improvement in the exploration and production of petroleum and natural 
gas. By 2020, these assumed improvements are expected to raise natural 
gas production by 1.1 trillion cubic feet and raise lower 48 crude oil 
production by nearly 300 thousand barrels per day compared to the 
reference case. The more rapid technology progress would also be 
expected to reduce the average wellhead price of natural gas in the 
United States from $3.13 per thousand cubic feet (1999 dollars) in the 
reference case to $2.50 per thousand cubic feet in 2020 (Figure 20). 
Conversely, slower technological improvements are assumed in another 
case, which reduce natural gas production by 1.9 trillion cubic feet 
and reduce lower 48 crude oil production by nearly 400 thousand barrels 
per day in 2020 relative to the reference case. In this slow technology 
case, the average wellhead price of natural gas in 2020 reaches $4.23 
per thousand cubic feet.
Conclusion
    Through 2020, continuing growth in the U.S. economy is expected to 
stimulate more energy demand, with fossil fuels remaining the dominant 
source of energy. As a result, our dependence on foreign sources of 
petroleum is expected to increase and domestic natural gas production 
and natural gas imports are expected to grow significantly. These 
forecasts incorporate an expectation of efficiency improvements in both 
demand and supply although different paths for technological 
development could lead to slower or more rapid efficiency gains.
    Thank you, Mr. Chairman and members of the Subcommittee. I will be 
happy to answer any questions you may have.
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    Chairman McCrery. Thank you, Miss Hutzler.
    Before I begin my questioning, I want to say that I read 
your resume. It's a very impressive resume, and I dare say that 
you're an expert on energy. So we are pleased to have such a 
distinguished witness before us to discuss the Nation's energy 
concerns.
    You raise some interesting questions with your charts. 
Maybe I misunderstood you, so I want you to clarify it. I think 
you said that renewable sources of energy over the next 20 
years will remain relatively flat and that one reason for that 
is moderate prices for fossil fuels. Is that what you said?
    Ms. Hutzler. Yes, I did. Let me first clarify what I said 
about renewables. I said their share would stay flat. We do see 
a slight growth in renewable energy over that period, but its 
share will remain at 7 percent.
    In terms of our fuel prices, we are actually forecasting in 
the future that the current higher prices that you're seeing 
today will be coming down. We are seeing actually a declining 
trend for coal prices in real dollars. In nominal dollars, they 
will stay about flat.
    For natural gas prices, we see them coming down in real 
dollars to about $2.50 per thousand cubic feet in the year 
2004-2005, and then increasing again as demand increases and as 
we have to drill more difficult wells. Essentially, we're 
seeing pretty moderate prices in the future, not the high 
prices that we're seeing at this moment.
    Chairman McCrery. That's interesting in light of your 
projections of a fairly steep increase in consumption of 
petroleum and natural gas, combined with your projection that 
imported petroleum will grow from 52 percent of consumption to 
64 percent of consumption.
    What assumptions are you making on our foreign suppliers of 
petroleum in terms of price?
    Ms. Hutzler. We look at a world oil price in our Reference 
Case (the projections I have showed you are for the Reference 
Case) of about $22.40 per barrel in real 1999 dollars for 2020. 
In nominal dollars, that's about $36 a barrel in the year 2020.
    It turns out that there are parts of the world, 
particularly the OPEC area, where you can get oil out of the 
ground at a very low cost--two to five dollars a barrel. We see 
that OPEC's role in the future and the amount of production 
that it will be having in the future will increase 
substantially to deal with worldwide demand. We look at this on 
a worldwide basis, and we see world demand growing from about 
77 million barrels per day in 1999 to about 117 million barrels 
per day in 2020. It is not just us that will be increasing our 
demand on the oil sector, but it will be other parts of the 
world as well.
    Chairman McCrery. That's very interesting. We'll see.
    On energy intensity, your chart shows that energy use per 
dollar of GDP is projected to continue to decline over the next 
20 years. Looking at the history from 1970 to 2000, it declined 
at a fairly steep rate, and you gave us some of the reasons for 
that.
    Do the reasons include conservation as well?
    Ms. Hutzler. When you get higher energy prices--and we saw 
higher energy prices in that period between 1970 and 1986--that 
does mean that consumers will turn down their thermostats and 
turn to more efficient technology. So that is embedded in the 
energy intensity measure.
    But it also means that there is a movement to structural 
shifts in the economy, where the economy changes over time, 
moving from more energy intensive industries to less energy 
intensive industries in that period.
    Chairman McCrery. Getting back to the question of supply, 
do your projections assume, for example, production in ANWR?
    Ms. Hutzler. No. We only assume current laws and 
regulations, and since that production is not permitted at this 
point in time, we do not assume ANWR in these projections.
    Chairman McCrery. I hesitate to ask this, because I don't 
know the answer, and I don't know what answer you're going to 
give me. But what is your opinion of the efficacy of our 
efforts to increase domestic supply in terms of price, in terms 
of dependency on other sources? Are we fighting a losing battle 
here? Are we wasting taxpayer dollars in providing incentives 
for increased exploration, development and so forth? What's 
your opinion?
    Ms. Hutzler. Our forecasts looked at the most economical 
way of achieving the demands that we forecast. We forecast both 
the demands and the supply of energy. In these forecasts, we 
don't have a shortfall. There is an equilibrium solution based 
on where we can get our sources of supply and where it's most 
economical to get those sources of supply.
    The United States really doesn't have a comparative 
advantage in oil today, because we're essentially depleting our 
oil reserves and resources. As a result, we need to deal with 
foreign sources in order to meet our demands for oil, unless we 
do something else in the sectors where we get that demand, 
which is, for instance, the transportation sector.
    It turns out that, certainly in our forecasts, the 
alternative fuel vehicles do not penetrate, that they're 
certainly not economic compared to the other vehicles, and they 
are not the vehicle of choice for consumers today. Consumers in 
this country look at horsepower rather than looking at 
efficiency, and they prefer their large automobiles with the 
higher horsepower. As a result, we put a large strain on demand 
for oil. With our current resources of oil, we're not going to 
be able to keep pace with that level.
    Chairman McCrery. Mr. McNulty.
    Mr. McNulty. Thank you, Mr. Chairman, and thank you, Miss 
Hutzler, for your testimony.
    If you had to reverse roles with me or the chairman or any 
other Member of Congress, going home this weekend and facing 
constituents, and they ask you the question ``why were my 
heating bills so high this winter, and why do the gasoline 
prices seem to be spiking up as we go into the summer months'', 
what would your answer be?
    Ms. Hutzler. We're going to need to deal with that on a 
fuel basis, so let me talk about it by fuel type.
    In terms of natural gas--and that's part of the larger 
heating bills that you saw this past winter--we had very low 
natural gas prices in 1998 and 1999. As a result of those low 
prices, the producing companies downsized and they didn't do 
the investments needed when demand spurred. They were not 
investing in the amount of drilling that was necessary to meet 
future demand.
    We had relatively cold winters compared to the warmer-than-
normal winters of the '98 and '99 time period. That demand, 
plus the extra demand for natural gas that we're seeing because 
of the generating plants, caused a huge demand for natural gas 
that wasn't readily available in terms of production.
    As a result, we had to take from our storage areas the 
additional supplies needed to meet that demand which then made 
the storage go down. That produces a very tight market, and 
under a tight market situation, prices go up.
    What is happening today is that those higher prices mean 
that we're drilling a whole lot more, and the companies are 
investing very heavily in drilling. We've seen close to record 
highs for the amount of drilling that's going on right now. So 
that's the reason why we anticipate, in the longer run, that 
the natural gas prices will be coming down.
    We are forecasting the year 2001 to be the highest price 
for natural gas, over five dollars per thousand cubic foot at 
the wellhead. But then we expect it to come down a bit in 2001, 
and as I said, in the longer term, come down even further.
    Mr. McNulty. What about the gasoline prices?
    Ms. Hutzler. The current situation with gasoline prices is 
that when refineries transition from the heating oil to the 
gasoline market, they realize that summer is their peak period 
and they have to run full-out during the summer period. Thus, 
they try to do some of their maintenance now in order to get 
ready for that peak period.
    There are other issues, too, with refineries. We have this 
boutique of fuels, which means refineries have to gear up to be 
producing quite a few varieties of gasoline to meet the 
different environmental restrictions in different areas of the 
country. As a result, there were high spot prices and wholesale 
prices that have now gone into the retail market.
    Another situation that we didn't foresee was that demand 
was actually higher than we had thought it was. We have gotten 
revised data in, showing that higher demand. Therefore, our 
demand forecast for the summer is probably going to be higher 
than we anticipated earlier, which will mean the price is going 
to probably be slightly higher, when we put out our next Short-
Term Energy Outlook, which will come out on Monday.
    Mr. McNulty. Now, looking toward the future, do you see the 
same moderation in the future with regard to gasoline prices as 
you do for the home heating fuel prices?
    Ms. Hutzler. Yes, we do. But most of the moderation is in 
the situation that we think world oil prices will be lower in 
the long term than we see them right now. Also, we do see 
expansion at existing refineries to give us the additional 
capacity that's needed.
    Mr. McNulty. Do you see the entire reason for these price 
spikes the reasons you just gave, or do you see any evidence at 
all of price gouging?
    Ms. Hutzler. We do not have data to actually be able to 
investigate that question in detail. What we do see is that the 
productive capacity is not there for instance, natural gas 
right now. Therefore, it brings on the tight markets.
    With the increased productive capacity that we will be 
getting from more drilling, we should be able to bring these 
prices down in the future.
    Mr. McNulty. Is it correct that, outside of the West, the 
greatest potential for blackouts and brownouts would be in the 
New York region?
    Ms. Hutzler. We see New York as being probably the next 
area to watch, particularly because the New York City area has 
problems with transmission, getting electricity into that 
particular area. The city is trying to bring on more capacity 
by bringing on distributed gas-fired technologies within the 
area so they don't have to rely on the grid as much. But that 
doesn't necessarily mean, if they get a very hot peak day this 
summer, that there might not be some potential for a brownout.
    Mr. McNulty. And what is your specific view again on the 
specific subject of today's hearing, which is with regard to 
energy conservation and production, the role that tax 
incentives can play?
    Ms. Hutzler. We have looked at tax incentives in a couple 
of different ways, one of which was that we were asked by two 
Congressional Committees to take a look at President Clinton's 
climate change technology initiative, and we did examine that 
to see what the impact would be on energy use based on those 
tax incentives.
    Essentially, what our analysis indicated is that, for tax 
incentives to be successful, they need to be of the appropriate 
size--that is, amount, in terms of reduction. They must be of a 
certain length of time to make it reasonable for whatever 
they're trying to spur to have happen, and also that their 
timing has to be right. In other words, if the tax incentive is 
there but the technology for which they're directed at is not 
there, it is not going to give you what you want, which is to 
try to bring these technologies on so they can stand on their 
own two feet.
    Now, in terms of what we have seen historically, one area 
that the tax credits have helped significantly is coalbed 
methane. Back in 1989, we were getting very little production 
from coalbed methane. Today, coalbed methane is providing about 
a 7 percent market share in terms of natural gas production. So 
the tax incentive has seemed to do quite well with that 
particular technology.
    In terms of wind, if you take a look at the amount of wind 
capacity that has come online between 1994 and 1999, we got 
just over 900 megawatts of capacity. Between '94 and '97, only 
about 12 percent of that amount came on time. Eighty-8 percent 
came on after '97, in '98 and '99, and that was due to the fact 
that States enacted mandates that required that renewable 
technologies to come on time. Wind was a choice technology 
because it also had the tax credit.
    We are seeing that, in the next 2 years, wind should double 
its capacity. It's about 2.6 gigawatts at the end of '99, and 
we see it doubling to about 5.2. That increase is being spurred 
by renewable portfolio standards that the States have enacted. 
The States tell us that they see the renewable mandate as a 
partnership with the Federal government's tax credits. The two 
programs are working together to try to promote these 
technologies.
    But prior to the 1997 period, when the States did not have 
program to push renewables, tax incentives didn't add much 
renewable capacity.
    Mr. McNulty. Mr. Chairman, I see my time is up, but could I 
ask one more quick question?
    Chairman McCrery. If you like, we can do a second round.
    Mr. McNulty. Okay.
    Chairman McCrery. Mr. Ryan.
    Mr. Ryan. Thank you, Mr. Chairman.
    Miss Hutzler, it is nice to have you here. I represent 
southeastern Wisconsin, which is facing a very unique problem 
today. That is, in the Milwaukee/Chicago region, which is an 
ozone nonattainment area, we have reformulated gas, phase two. 
We have a unique blend of reformulated gas, phase two, so we're 
experiencing a tremendous price spike at this time. So I wanted 
to direct my questions to you on reformulated gas and refinery 
supply and capacity.
    Last year, we experienced a similar price spike, and the 
EIA produced a study analyzing reformulated gas, and it 
attributed--and correct me if I'm wrong--I think it attributed 
the range of the price increase of about 12 to 15 cents of the 
price per gallon of gas, to the reformulated gas switch over 
from phase one to phase two.
    One of the things I wanted to ask you about is the 
transformation between the winter blend to the summer blend of 
gasoline. It had been our understanding, after consulting with 
the EIA, the EPA and the refineries themselves, that when you 
switch your tanks from winter to summer blend, on sort of a 
``cold turkey'' basis--May 1st is actually the wholesale date 
that that takes place--that that injects into the system, which 
is already in tight supply, a huge supply crunch which causes a 
spike in price.
    What is your opinion on that, and number two, this year we 
had hoped that we would receive the kind of regulatory relief 
from a different agency, not DOE, to allow the co-blending of 
winter and summer fuels to take place between May 1 and June 1, 
which is when the retail date for reformulated gas has to 
actually hit the pump. Do you believe that co-blending winter 
and summer blends during that transition period would have been 
able to ease the supplies and, therefore, reduce the price?
    Ms. Hutzler. Unfortunately, I'm not a refinery expert. I 
would prefer to submit the answer to your question for the 
record.
    [The following was subsequently received:]

    Transitioning from winter to summer gasoline is one of many 
factors that could lead to higher gasoline prices in the 
spring. Since refiners do not want an excess of winter gasoline 
that they can not sell at the end of the winter season, they 
wait until the last moment to transition from winter gasoline 
to summer gasoline. In most parts of the country, the 
transition could start in April without affecting engine 
performance. However, it is not economical to make summer 
gasoline earlier than necessary due to its increased cost. 
Thus, many refiners wait until the May 1 deadline to make the 
transition. Allowing refiners to mix seasonal grades during the 
month of May would probably not make that much difference, 
since it would most likely still result in refiners waiting to 
produce summer gasoline with the transition occurring two to 
four weeks later.

                                


    Mr. Ryan. Okay. Let me move to refineries then. At this 
time, we have six refineries that feed--this is an example that 
I think can be applied across the country--we have six 
refineries feeding the Milwaukee region with its gasoline. 
That's down from seven last year, where the Prime Core refinery 
shut down. We had a fire this last week in one refinery and 
that shut down. We have another refinery, the LaMont refinery, 
that shut down. So now we're at about four refineries, maybe 
five, if we're lucky to get something back up and running.
    Do you believe that these are sufficient problems that need 
to be addressed on an emergency basis, more or less, and what 
are the solutions? The problem we're faced with is this: we 
know we can't pass a bill tomorrow to reduce the price of gas. 
We know we can't do something tomorrow to flip a switch and 
improve the supply going into the regions.
    But what are some of the short-term solutions that can be 
achieved in giving flexibility to have different fuels, perhaps 
ethanol-based RFG fuels, coming into the region? Is that an 
alternative? Can the EPA and the DOE give the flexibility to do 
that?
    Number two, what can we do through the incentive area tax 
policies to incentivize the improved and increased capacity in 
the construction of new refineries, and is the new source 
review regulatory scheme a big player in making it much more 
difficult to produce new refineries?
    Ms. Hutzler. Well, whatever we can do to increase the 
flexibility to produce these fuels, and to get them into the 
area, of course, is going to help alleviate the problems. As 
you indicated, the fire was one problem and that caused a 
situation with one refinery, and then there have been other 
issues.
    Mr. Ryan. It ripples through, doesn't it?
    Ms. Hutzler. Yes, it certainly does. Of course, that does 
mean that the markets get tight and you're going to have a 
higher price spike due to that particular situation. You need 
to do whatever one is able to do in the short term in order to 
be able to produce flexibility.
    Now, some of the things that you mentioned are areas of 
producing that flexibility. However, EIA is not a policy 
organization, so when you bring up what EPA should do, EIA 
cannot answer.
    Mr. Ryan. Sure.
    Ms. Hutzler. That's not our place to answer.
    Mr. Ryan. Let me just ask you from an analytical point of 
view. Do you believe that allowing different fuels into the 
region at this time, this summer, would help reduce the price?
    Ms. Hutzler. If you provide more flexibility, that 
generally is the direction it goes in.
    Mr. Ryan. How about the ability to improve capacity and 
construct new refineries? Are there tax incentives that are 
options that would lead to that? When was the last time a new 
refinery was built in this country, and is the new source 
review regulatory structure such that it has been very 
difficult? Has it led to complications that have dis-
incentivized the construction of new refineries?
    Ms. Hutzler. Well, the last large new refinery was built a 
good 20 years ago. We also saw in the seventies a lot of the 
small refineries essentially going out of business because it 
was difficult for them to compete.
    We have seen the existing refineries, though, add more 
capacity, so it's not like we've been totally stagnant. We have 
had more capacity being added at existing refineries.
    It turns out, though, that the environmental situation is a 
situation that causes problems with bringing new refineries. It 
is also the situation with the public, where it's the ``not in 
my backyard'' syndrome. People just don't want these kinds of 
refineries or plants in their back yard.
    Mr. Ryan. It's fine if we could put them in Illinois. We 
would be OK with that, I think.
    [Laughter.]
    Ms. Hutzler. Of course, those issues are certainly holding 
back the development, or the building or construction of new 
refineries.
    Mr. Ryan. Do you think specifically the new source review 
has really been a disincentive in constructing new refineries?
    Ms. Hutzler. I can't answer that question directly because 
I haven't done an analysis of it, but I will try to get back to 
you for the record.
    [The following was subsequently received:]

    There are a number of reasons why a new refinery has not 
been built in a long time, chief among them is that in the 
first half of the 1990s, return on investment for major 
refiners averaged 2.4 percent, improving to 7.2 percent in 1998 
and 1999. In addition, it is generally more economic to add 
capacity at existing refineries than to attempt ``green field'' 
construction of a new refinery.
    Tighter environmental standards (for air emissions as well 
as water pollution control) also have added to the cost of 
building new facilities and may be a factor in encouraging 
capacity expansion in existing refineries rather than the 
construction of new ones. None the less, NSR can have an effect 
on capacity expansion at existing facilities. Some major 
refining companies have indicated to EIA that New Source Review 
interpretations have affected capacity expansion at their 
existing refineries. For example, one company that was 
considering replacing an old air compressor unit on its 
catalytic cracker wanted to use a new air compressor unit that 
would have increased the overall refinery capacity by 5 
percent. Because EPA decided that this would fall under NSR, 
the replacement was not made. This company stated that NSR has 
caused them to defer investments in replacement equipment and 
refinery improvements. While EIA has not fully analyzed this 
issue, it does appear that NSR has had some impact on reducing 
refinery capacity expansion.

                                


    Mr. Ryan. I would appreciate that. Thank you. Thank you, 
Mr. Chairman.
    Chairman McCrery. Thank you, Mr. Ryan. Mr. Jefferson.
    Mr. Jefferson. Good morning. It's still barely morning.
    I'm looking at these projections you have on domestic 
production, which essentially says there may be some 
variations, with some going up and some going down, but largely 
it remains flat, right?
    Ms. Hutzler. Domestic production of what fuel?
    Mr. Jefferson. Domestic production of energy in this 
country, everything--coal, natural gas, petroleum. When you add 
them all together, unless I missed it here, it is projected to 
remain flat, although natural gas and coal production will 
increase, domestic crude oil production is expected to decrease 
by 7 percent a year. As a result, net petroleum imports are 
expected to increase from 51 to 64 percent to meet domestic 
petroleum demand.
    In other words, what you're telling us is that, down the 
road, we're going to get worse off with respect to dependency 
on foreign sources of energy rather than better off, if the 
assumptions which you're using remain in place. Of course, 
these projections are based on certain assumptions.
    Now, my question is, what assumptions do we have to change, 
if you will, if domestic production is going to increase, and 
how can we in the Congress work to support some changes that 
might bring about different factors for your assuming what will 
happen in the future with respect to domestic production? How 
can we increase domestic production, because most of us here 
are concerned about that. We hope we can do it through the Tax 
Code or through some energy policy or whatever. But it's a 
pretty bleak picture if down the road we're going to have more 
dependency on foreign sources.
    So what are the assumptions that have to be in place so 
that you can say, based on these assumptions, there will be an 
increase in production on the domestic side rather than a flat 
projection?
    Ms. Hutzler. First of all, we are saying that only oil is a 
flat projection. We are showing increased production of coal, 
and increased production of natural gas.
    One could perhaps increase these even more than we 
forecast. In terms of coal, we have a huge amount of resources 
in this country of coal. The real question for coal is its 
demand. Currently, coal is thought of as being not as 
environmentally clean as its major competitor in the electric 
utility sector, which is natural gas.
    If you're going to build a new generating plant, coal and 
natural gas are fairly close to being competitors in terms of 
the cost of a new plant. Their average generation cost is about 
four cents per kilowatt hour. That's a lot less than renewable 
technologies.
    Mr. Jefferson. May I interrupt you there. I understood you 
said coal production would increase and natural gas production 
would increase and oil production would decrease--petroleum 
production would decrease. Nonetheless, we end up with a 64 
percent dependency on foreign products. In the end, we simply 
are depending more on foreign.
    So now my question is this and what I want to have you 
clarify for me. Coal is not a choice source of energy here, 
because you say the demand isn't there because of the concern 
of pollutants, I guess, and so on. So let's say that's a 
problem.
    Natural gas now is a cleaner burning fuel. Can increased 
production in that area make us less dependent on some sources 
of foreign energy or not?
    Ms. Hutzler. In terms of natural gas, we do expect a large 
increase in its production and its demand in these particular 
forecasts. However, we also see more imports of natural gas 
coming into this country. The percentage share only goes up by 
1 percent from now to 2020, from 16 percent to 17 percent. But 
most of that comes from Canada. It is within the North American 
continent that we are importing most of the gas.
    Mr. Jefferson. Is that because we don't have the capacity 
to produce the amount of natural gas we need or what, or don't 
have the resources to do it?
    Ms. Hutzler. We expect the production of natural gas to go 
up a lot in this country to 29 trillion cubic feet, from just 
under 20 right now. That's a huge increase, but it is all 
dependent on economics and resources.
    We do have a vast resource base of natural gas, at 1200 
trillion cubic feet, so that's fairly immense. But the Canadian 
area is able to produce it cheaper than we are, so we're going 
to import some of that here. So it is based on relative 
economics, on what our resource base is, and what it costs to 
produce it in different areas of the country and of the world, 
of course, depending on what particular supply source you're 
looking at.
    Mr. Jefferson. So a lot of these assumptions that you use 
to come up with these projections is based on what you expect 
to happen in the cost of producing this energy in different 
parts of the world, and how we will respond to those economic 
issues out there because we want to pay less, if we can, for 
the fuel that's consumed here.
    So that's a thing which we don't have control over, but if 
it were controlled in some way or other--I don't mean 
controlled by the government, but if the price were controlled 
for purposes of our analysis, you will never match the ones in 
Saudi Arabia, but of course, in Canada, that's quite a 
different picture.
    But one of the reasons why we are projecting, even though 
we have these huge resources of natural gas, we can't meet the 
requirements with our own production because of the economics 
of getting it out of the ground into commerce, as opposed to 
what we can do in other places, right?
    Ms. Hutzler. Again, it depends on the fuel, yes.
    Mr. Jefferson.So if we do something here to shorten the 
cost of it, to make the cost less, then perhaps it would be 
effective in spurring more domestic production of natural gas 
to meet the demand, which is going to far outstrip what we do 
now with respect to meeting the demand of the public, right? So 
that's one area.
    Now, with respect--one last little thing. With respect to 
oil production, are you saying that we have depleted the 
resources in the ones we now know about? Is that why we don't 
expect increases there, or is it also related to the economies 
of price?
    Ms. Hutzler. We look at a resource base that the USGS and 
the Mineral Management Service develop. The resource base is 
quite large for natural gas. The only area where we're seeing 
depletion effects is in the oil area, for the most part, and 
that's why we have declining crude oil production.
    Mr. Jefferson. That's what I'm asking, though. This will be 
the last thing.
    Does it mean that--Let's say we're off the Louisiana coast 
and you were looking at, let's just say, god forbid, the 
California coast, or the Florida coast, or the Atlantic coast. 
When you talk about limitations on oil production, does it mean 
the universe of oil that we now know to be available to us in 
reserves in these areas is included in your analysis?
    Ms. Hutzler. Yes.
    Mr. Jefferson. You include everything. California, this and 
that, Florida and all the rest of it?
    Ms. Hutzler. Absolutely.
    Mr. Jefferson. And even then, your analysis is that there's 
not enough oil around this country to increase our oil 
production significantly to alter the factors here, even if we 
open up those areas to production?
    Ms. Hutzler. All non-restricted areas we include right now. 
We don't include the restricted areas, such as in ANWR. If we 
included them, we would get more oil production, though I don't 
think we would be able to meet the demand. It's going to take 
time to open those areas and to get them at their max 
production. You might think of seven to 10 years as the time 
needed to get them to be at their peak production levels.
    Chairman McCrery. Mr. Jefferson, I had pursued a similar 
line of questioning earlier. I think the answer that I got was 
that all the charts that we've been looking at, which project 
supply of the various sources of energy, are based on current 
law, which includes current law restrictions on production like 
in ANWR or off-shore Florida, California and so forth. So Miss 
Hutzler's projections are based on only the currently available 
sources for legally producing petroleum.
    Ms. Hutzler. That's correct.
    Chairman McCrery. So her projections do not include those 
areas that you were referring to, which may or may not come 
into play in future generations.
    Mr. Watkins, did you want to ask some----
    Mr. Watkins. I have no questions. I would make some 
comments, but I know we've got another panel and, for the sake 
of time, I will wait until then. I think you will hear some 
real live discussion about how incentives can really be of 
help.
    Chairman McCrery. Miss Hutzler, two quick questions. How 
important are independent oil producers, independent oil and 
gas producers, to our energy supply in this country?
    Ms. Hutzler. Quite important.
    Chairman McCrery. Could you speak up, please. She said 
``quite important''. Okay.
    Ms. Hutzler. They produced 44 percent of the oil that was 
produced in 1997, and they produced about 60 percent of the on-
shore oil in that particular year.
    Chairman McCrery. And how about exploration and new wells 
being drilled on-shore? Is that a fairly high percentage being 
done by independent producers?
    Ms. Hutzler. I would say so. I don't have the exact figure, 
though.
    Chairman McCrery. Vice President Cheney announced that the 
administration hopes to triple the use of renewable fuels--
solar, biomass, and wind power--from filling basically 2 
percent of our needs to 6 percent within 20 years.
    Do you think, based on your analysis, that this is 
feasible?
    Ms. Hutzler. Our analysis shows them not growing that far, 
so they cannot do that without some other help. It would not be 
economic to do that without some other help.
    Chairman McCrery. In other words, if we're going to achieve 
that goal, in your opinion, we're going to need additional 
incentives to achieve that?
    Ms. Hutzler. That's correct.
    Chairman McCrery. Thank you. Mr. McNulty.
    Mr. McNulty. Thank you, Mr. Chairman. Miss Hutzler, thank 
you again for your testimony today. It is quite helpful. I had 
one more question.
    Have you at all taken a look at the fuel cell technology 
that companies like Plug Power are working on, and if you have, 
what is your analysis of their potential for helping us to 
address our energy shortages?
    Ms. Hutzler. We do have the fuel cell within our forecast. 
Now, the fuel cell technology we look at is fueled by natural 
gas. Its capital costs are much higher than the competitive 
natural gas technologies, i.e., the combined cycle or turbine 
technology. We get very little penetration of fuel cells. I 
think by 2020 we get 300 megawatts and that's about it. So 
right now it is not economical against the competition.
    Mr. McNulty. Thank you.
    Chairman McCrery. Miss Hutzler, thank you very much for 
appearing before us today. We appreciate the good information 
you brought us.
    I will now call our final panel, Mr. Williams, Mr. 
Morrison, Mr. Carlson and Mr. Wallace, if you will come 
forward. This panel is composed of Steven R. Williams, 
President, Petroleum Development Corporation, from Bridgeport, 
WVA, and Bill Carlson, Vice President, Wheelabrator 
Environmental Systems, Inc., Anderson, CA.
    To introduce our two other panelists, I will refer first to 
my colleague from Florida, Mr. Foley.
    Mr. Foley. Thank you very much, Mr. Chairman. Briefly, I 
wanted to introduce Bob Morrison, who is Vice President of FPL 
Energy, which is headquartered in my district, one of the 
largest employers in my congressional district.
    They have been in wind energy production since the first 
farm was created in Altamont Pass, CA in '93. FPL Energy is the 
largest developer and operator of wind energy facilities in the 
Nation, with more than 1,500 megawatts out of a total of 2,500 
megawatts produced in the United States. They have plants, or 
at least wind energy facilities, in California, Iowa, 
Minnesota, Oregon, Texas, Washington and Wisconsin.
    We are delighted that he took time away from Jupiter, which 
some days I would rather be than in Washington, to visit with 
us today and obviously inform us of not only the productivity 
of wind energy, but the importance as we approach a balanced 
energy policy.
    Thank you, Mr. Chairman.
    Chairman McCrery. Thank you, Mr. Foley. Mr. Watkins.
    Mr. Watkins. Thank you, Mr. Chairman, and Members of the 
Committee.
    I am really honored. I just want to say to all of you that 
it is a real privilege today to have a fellow that I've known 
for a long, long time. He hails from Seminole, OK. Dan Wallace 
is the owner of Columbus Oil Co. from Seminole.
    To put some importance on it, Mr. Chairman, in Seminole 
County, at one time, I think the early twenties, they produced 
one-third of the oil in the world. I say in the world. Dan 
Wallace, as we speak right now, as he's here testifying, he is 
drilling a 4,400 foot well--I think you're down to about 3,600 
feet, somewhere close to that. So he's a live, wildcatter, risk 
taker, who is a domestic producer out there. He knows that tax 
incentives are things that help make the production go out 
there, and people like him. So I am glad that Dan Wallace has 
come from Seminole, OK to be here today.
    Thank you, Mr. Chairman.
    Chairman McCrery. Thank you, Mr. Watkins. Mr. Williams, we 
will begin with you.

     STATEMENT OF STEVEN R. WILLIAMS, PRESIDENT, PETROLEUM 
       DEVELOPMENT CORPORATION, BRIDGEPORT, WEST VIRGINIA

    Mr. Williams. Thank you very much.
    Mr. Chairman, Members of the Subcommittee, my name is Steve 
Williams and I'm the President of Petroleum Development Corp. 
of Bridgeport, West Virginia. I appreciate the opportunity to 
be here today to talk to you about the possibility of an 
extension of the section 29 tax credit for producing fuel from 
non-conventional resources.
    I can speak from personal experience about section 29, 
which was created in 1980 in a situation not too different from 
what we find ourselves in right now, with shortages of natural 
gas and concern over imported oil levels. I have been in the 
business of producing non-conventional gas since 1982, when I 
joined Petroleum Development Corporation. We currently operate 
over 2,000 oil and gas wells in seven States--in the 
Appalachian Basin, Michigan, and in the Rocky Mountain region--
and virtually all of our production is, in fact, from non-
conventional sources.
    When congress created the section 29 credit in 1980, the 
goal was to encourage U.S. production from deposits which were 
difficult and expensive to produce. In fact, much of our 
remaining on-shore resource fits just exactly that description. 
Congress then felt that non-conventional resources were needed 
to provide consumers with the energy that they wanted at a 
reasonable price.
    I think one of the really attractive features of the 
credit, from the standpoint of the taxpayer and consumer, is 
that it's awarded only for success. It is a production credit 
that you earn by producing gas from non-conventional sources, 
and if we don't produce gas, then we get nothing for the risks 
we take in drilling the wells.
    In fact, I think the question was asked earlier whether 
section 29 was successful in generating the desired result. I 
think the evidence is very clear that it has been. It has 
resulted in a significant increase in the amount of production 
from these difficult-to-produce sources. In addition, it has 
driven the development of new technologies which have made more 
resources economic, more resources available, throughout the 
country. But the section 29 credit is expiring. In fact, it 
expired for new wells back in 1992, but the credit for the 
wells that did qualify before that will be expiring or is 
scheduled to expire at the end of 2002.
    I can't speak for every producer, but I do know some of the 
impacts that expiration will have on my company. First of all, 
there are wells with remaining reserves that are too expensive 
to produce absent the credit. Maybe with five dollar gas prices 
they would be profitable, but I suspect that price won't be 
around for too long, and maybe we'll be back in a two dollar 
gas price scenario again.
    Once we plug those wells, as has been pointed out, it is 
really uneconomical to go back and reopen them and put them 
back into production, so we will lose whatever remaining 
resource is in those wells when we plug them.
    In the case of my company, we plan no further wells in the 
Appalachian Basin, where we started from and where we drilled 
exclusively for almost the first 30 years of our existence. We 
just can't justify the economic return given the uncertainty of 
the results of those wells, so we're not drilling there. Many 
others aren't as well, and we are losing the ability to drill 
wells in that area as the infrastructure dries up and goes 
away.
    Finally, our availability of capital for drilling wells, 
whether from non-conventional sources or conventional sources, 
will be reduced with the loss of the credit.
    We know that section 29 has worked historically, and the 
question also should be asked as to whether it will continue to 
work in the future. You don't have to take my word for that. 
Attached to my testimony today is a summary of a study that was 
prepared by the Gas Technology Institute, which has been 
analyzing non-conventional fuel issues for 20 years, and Energy 
and Environmental Analysis, Inc., which was the lead contractor 
in the 1999 National Petroleum Council study of natural gas 
supply.
    The conclusion of that study is that an extension of 
section 29 could have a significant impact on consumer prices 
in the short term as well as in the long term. The study used 
the NPC study as a base case and examined the impact of a 
section 29 extension and allowing new wells to qualify for the 
credit. Several of the key results of that study:
    First of all, over the next 15 years, production of non-
conventional gas resources must double again if the United 
States is to meet its demand needs. Also, if we fail to do 
that, it will result in further increases in the import of oil 
to fill in that gap, or imports of natural gas from other 
places to fill that gap.
    The study projects that the extension of the section 29 
credit could result in an increase in the annual supply of 
natural gas from non-conventional sources of two trillion cubic 
feet by 2015, and a total increase in supply of over 15 
trillion cubic feet over the same period. And, I think perhaps 
most importantly, the study projects that the extension of 
section 29 could result in savings to consumers of more than 
$100 billion for the cost of the gas that they buy for their 
needs.
    Finally, the study concludes that among the competing 
sources of additional gas that are out there, section 29 gas is 
one of the quickest and most effective ways to provide 
additional supplies because the infrastructure needed to 
deliver it is already in place.
    In conclusion, I would say to you today that there is no 
single energy supply solution, but we think that section 29 
could play an important role in helping to reduce natural gas 
costs for consumers over the next 15 years, reducing our 
dependence on imported energy, helping to keep our environment 
as clean as possible, while providing the energy that we want 
and in spurring additional technological innovation over the 
coming years.
    In addition to that, it also has direct impacts on the 
communities where we live, because in order to achieve that 
increase in production, we will need to drill another $15 
billion worth of wells using services and employment in the 
communities where we live, all important things to those of us 
in this room.
    I thank you very much, gentlemen, for allowing me to come 
and speak to you today, and I would certainly be happy to 
answer any questions I can.
    [The prepared statement of Mr. Williams follows:]

   Statement of Steven R. Williams, President, Petroleum Development 
                 Corporation, Bridgeport, West Virginia

    Mr. Chairman and Members of the Subcommittee, my name is 
Steve Williams, and I'm President of Petroleum Development 
Corporation, of Bridgeport, West Virginia. I appreciate the 
opportunity to appear before you today, to talk about the 
importance of an extension of the Section 29 tax credit for 
producing fuel from non-conventional sources.
    I can speak from experience about the history of Section 
29, since I have been in the business of producing hard-to-get 
natural gas since 1982, soon after the Section 29 tax credit 
was created in the wake of the widespread energy shortages and 
deep concern about American dependence on imported oil. My 
company, PDC, operates 2050 oil and gas wells in seven states--
in the Appalachian Basin, Michigan and the Rocky Mountain 
region--and most of our production is non-conventional.
    When Congress created Section 29 in 1980, the goal was to 
encourage U. S. production from deposits that are unusually 
difficult and expensive to develop and produce, like the 
Devonian shale and tight formation wells that PDC drilled and 
now operates. An important feature is that the credit applies 
only to actual production - the consumer's tax dollar is spent 
only after the producer has taken the risk and achieved 
success.
    I know from my years of experience in non-conventional 
resource development that Section 29 did indeed result in a 
significant expansion of production from difficult sources, and 
it helped to drive new advances in production technology. 
Today, however, the credit applies only to production from 
wells completed before Dec. 31, 1992, and even for these 
qualifying wells it is scheduled to expire on Dec. 31, 2002. I 
know, too, what it will mean for PDC if Section 29 is not 
extended. Some wells will be shut in, and we will not be doing 
any further drilling in the Appalachian Basin because the 
economic return on wells in that region is too uncertain.
    Study says that Section 29 could save gas consumers $100 
Billion.
    I am not asking you to rely on my experience of Section 29, 
and its impact on natural gas supply, and, of course, on 
consumer gas prices. Rather, I would like to draw your 
attention to a recent study undertaken by the Gas Technology 
Institute, which has been analyzing issues related to non-
conventional production for 20 years, and Energy and 
Environmental Analysis, Inc., which was the lead contractor in 
the landmark 1999 study of natural gas supply undertaken by the 
National Petroleum Council.
    The GTI/EEA Study, a summary of which is attached to my 
remarks, makes it clear that an extension of Section 29 could 
have a significant impact on consumer prices by quickly 
increasing supply. Using NPC research as the base case, the 
Study examined the impact of the Section 29 credit on the U.S. 
gas market, and concluded that:
     Passage of Section 29 in 1980 made it possible for 
production of non-conventional gas to more than double, and led 
to innovation in drilling and completion technology.
     Production of non-conventional gas must double, 
once again, if the U.S. is to meet growing demand. The U.S. now 
imports 56% of its oil, and that figure is projected to rise to 
65% within 15 years.
     Extension of Section 29 to wells drilled through 
2010 could increase U.S. gas supply by about 2 trillion cubic 
feet (Tcf) annually, for a total of more than 15 Tcf by 2015. 
This increase in supply would translate into lower gas prices, 
and consumer savings of more that $100 billion in the next 15 
years. (And consumers will continue to benefit from expanded 
supply and technological innovation even after the term 
projected by the study.)
     Extending the credit will have a significant near-
term impact on prices, since Section 29 gas can reach the 
market more quickly than other major incremental supplies.
    There's no single energy supply solution, but Section 29 
could play a key role According to the Study, extension of the 
Section 29 credit offers these important benefits:
     Reduced natural gas costs for consumers, and 
timely increases in consumer gas supplies.
     Less dependence on imported energy.
     A cleaner environment.
     Technological innovation, at a time when natural 
gas R&D is otherwise slowing.
     A positive impact on the U.S. economy, including 
new jobs and demand for $15 billion in materials and services 
resulting from reliance on U.S. production. And
     Increased state and local severance taxes in 19 
states.
    The U.S. has large natural gas reserves, but the Section 29 
credit is needed to unlock supplies of gas that are currently 
too expensive or uncertain to develop. While we all know that 
gas prices are high today, producers--and our bankers and 
investors--have learned the hard way about price volatility. 
Without the protection provided by Section 29, we simply cannot 
make the massive investments needed to produce gas from 
difficult sources. An extension of Section 29 will play a vital 
role in encouraging domestic supply, and assuring the 
availability of natural gas for home heating, high quality 
power generation, and a growing list of other consumer needs.
    I appreciate the opportunity to comment today about the 
Section 29 tax credit for actual production from challenging 
formations, and about the importance of Section 29 to the 
nation's supply of natural gas.

                              F


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    Chairman McCrery. Thank you, Mr. Williams. Mr. Morrison.

   STATEMENT OF ROBERT MORRISON, VICE PRESIDENT OF BUSINESS 
       DEVELOPMENT, FPL ENERGY, LLC, JUNO BEACH, FLORIDA

    Mr. Morrison. I would like to thank Mr. Foley for 
introducing me.
    Chairman McCrery, Members of the Subcommittee, as Mr. Foley 
mentioned, my name is Robert Morrison. I am Vice President of 
Business Development for FPL Energy. FPL Energy is a subsidiary 
of FPL Group, one of the largest electric utility holding 
companies in the United States. Our sister company is Florida 
Power & Light. It serves south and eastern Florida as a 
regulated investor-owned electric utility.
    I want to thank the chairman and the Members of the 
Subcommittee for inviting me to testify on behalf of FPL Energy 
about the importance of extending the wind energy production 
tax credit. FPL Energy is the largest developer, owner and 
operator of wind-powered electric generating facilities in the 
United States. We have more than 1,500 megawatts of wind 
turbines in operation or under construction in seven States. By 
the end of 2001, wind-powered generating projects will 
represent 30 percent of FPL Energy's total generating 
portfolio. I think we have a map over here that demonstrates 
where FPL Energy currently owns or is constructing wind 
projects.
    FPL Energy is committed to clean energy sources and 
strongly believes that, among all the renewable energy 
technologies, wind energy is the most economically viable and 
has the best potential to quickly add significant new and clean 
sources of electric power generation across a broad range of 
geographic areas in the United States.
    I want to commend Representatives Foley, Weller, Matsui, 
and Thurman for their leadership in introducing H.R. 876 to 
extend the production tax credit. I also want to thank you, Mr. 
Chairman, and full Committee Chairman Bill Thomas for your 
strong support of wind energy.
    As I think everyone knows, the PTC provides an inflation 
adjusted 1.5 cents per kilowatt hour Federal tax credit for 
electricity produced with new wind turbines for the first 10 
years of each turbine's operation. The PTC stimulates new wind 
projects by assisting the industry in competing with fossil 
fuels used for electricity generation. We strongly believe that 
Congress should extend the PTC at the end of this year, as 
proposed by H.R. 876.
    The PTC has proven to be an excellent legislative 
investment and is a shining example of a Federal policy 
initiative that has successfully achieved many of its original 
goals. The PTC has served as a catalyst, stimulating 
development of many large utility scale wind projects across 
the United States. With the support of the PTC, the wind 
industry expects its costs will continue to decline as turbine 
technology improves and the wind industry is able to realize 
economies of scale, both in turbine size and manufacturing 
volumes.
    The turbine technology of the 1980s was an infant 
technology, and the cost of electricity from wind energy during 
that period of time often exceeded 25 cents per kilowatt hour. 
In the intervening 20 years, a relatively short period of time 
in the power generation business, the industry has reduced its 
costs by a remarkable 80 percent, to a current cost of around 
4.5 cents per kilowatt hour, not including the effects of the 
production tax credit. With increasingly sophisticated turbine 
designs and manufacturing efficiencies, the wind industry 
expects the cost of wind energy will continue to decline, until 
such time in the relatively near future when it can compete 
directly with fossil fuels without any incentives.
    The severe shortage of electricity in the Western United 
States points to the critical need for the development of new 
alternative energy sources. Throughout the West, power 
shortages have led authorities to call for the construction of 
new power plants. Even with the fastest construction schedules, 
conventional fossil fuel plants can take several years to bring 
online. In contrast, environmentally benign new wind plants can 
often start producing energy in only a matter of months.
    In California, for example, if PTC is available, FPL Energy 
sees the potential to develop new wind projects over the next 
18 months in that State which could serve in excess of 400,000 
homes, thus alleviating some of the electric supply problems in 
California.
    Nationwide, wind power projects currently represent about 
2,500 megawatts of capacity, enough power to meet the electric 
energy requirements of about 700,000 homes. As shown on the 
next map here, there are also vast parts of the country that 
are very suitable for the development of wind projects with an 
excellent wind resource, and many other parts of the country 
that have not yet even been explored for the potential to build 
wind projects in the future.
    Also, most of America's farming and ranching regions have 
promising wind resources. Since wind projects displace only a 
tiny amount of crop or ranchland, in terms of roads and 
foundations and the like, lease payments from wind projects 
serve as a valuable and additional source of diversified and 
stable income for ranchers, farmers, and other rural 
landowners. Also, wind projects bring new economic 
opportunities to the rural areas where they're located, 
including local tax bases, new manufacturing opportunities, and 
new construction and operations jobs.
    Domestic wind development also provides economic benefits 
to other sectors of the economy. FPL Energy has components of 
its wind turbines and wind projects manufactured throughout the 
United States, including a variety of States--California, 
Louisiana, Illinois, Wisconsin and Texas, just to name a few.
    Since the PTC is directly linked to energy production, the 
credit is inextricably tied to the financing, permitting and 
construction of new facilities. With the credit due to expire 
in only a few months, it is very difficult to adequately plan 
for anything but the most immediate projects. Longer-term plans 
are simply prevented by the budgeting, permitting and project 
construction cycles, all of which are at least 12-18 months 
long. The immediate extension of the PTC is critical to the 
continued development of wind power in the United States.
    This concludes my hearing testimony. Again, I would like to 
thank you for the opportunity to provide FPL Energy's 
testimony.
    Thank you very much.
    [The prepared statement of Mr. Morrison follows:]
 Statement of Robert Morrison, Vice President of Business Development, 
                  FPL Energy, LLC, Juno Beach, Florida
I. Introduction
    Chairman McCrery, Congressman McNulty, and members of the 
Subcommittee, my name is Robert Morrison. I am Vice President of 
Business Development at FPL Energy, LLC. I thank you for providing me 
the opportunity to appear before you today on behalf of FPL Energy, LLC 
to talk about the importance of extending the wind energy production 
tax credit (PTC).
    FPL Energy, LLC is the largest developer and operator of wind 
energy facilities in the nation with more than 1,500 megawatts of wind 
turbines in operation or under construction in seven states: 
California, Iowa, Minnesota, Oregon, Texas, Washington and 
Wisconsin.\1\ FPL Energy is a subsidiary of the FPL Group Inc., which 
is also the parent of Florida Power & Light Company, an investor-owned 
electric utility that serves approximately 3.8 million customers in 
Florida.
---------------------------------------------------------------------------
    \1\ A map showing the location of FPL Energy's Facilities is 
attached.
---------------------------------------------------------------------------
    FPL Energy is committed to clean energy sources and strongly 
believes that, among all of the renewable energy technologies, wind 
energy is the most economically viable and has the greatest potential 
to add significant new, clean electrical power across a broad range of 
geographic regions in the United States.
    I want to commend Representatives Mark Foley (R-FL), Jerry Weller 
(R-IL), Bob Matsui (D-CA) and Karen Thurman (D-FL) for their commitment 
to wind power and their leadership in introducing H.R. 876 to extend 
the wind energy PTC. I also want to thank you, Mr. Chairman, and full 
Committee Chairman Bill Thomas for your long-term support of the wind 
industry.
    Wind energy is a bipartisan issue that has the broad support of 
both Republicans and Democrats. In addition to having significant 
bipartisan support in the House, the PTC has strong support in the 
Senate under the bipartisan leadership of Finance Committee Chairman 
Charles Grassley (R-IA) and Senator Kent Conrad (D-ND), and in the 
White House which included an extension of the PTC in President Bush's 
FY 2002 Budget.
    It is important to note that the current PTC will expire at the end 
of this year. I hope the House of Representatives will take swift 
action to extend the PTC by enacting the provisions of H.R. 876. It is 
FPL Energy's belief that without an extension of the PTC, little or no 
new utility scale wind power will be developed in the United States 
past 2001.
II. Background on the Wind Energy PTC
    The wind energy PTC, enacted as part of the Energy Policy Act of 
1992, provides an inflation-adjusted 1.5 cents/kilowatt-hour (kWh) 
credit for electricity produced with wind equipment for the first ten 
years of a project's life. The credit is only available if the wind 
equipment is located in the United States and electricity is generated 
and sold in the marketplace. The credit applies to electricity produced 
by a qualified wind energy facility placed in service after December 3, 
1993, and before January 1, 2002.
III. Why We Need a Wind Energy PTC
            A. The Wind Energy PTC stimulates new wind development by 
                    helping drive down costs, making wind energy an 
                    economical source of clean, renewable power
    The cost competitiveness of wind generated electric energy has 
increased dramatically since the inception of the industry in the early 
1980s. The wind turbine technology of the 1980s was in its infancy and 
the cost of wind energy during this time period exceeded 25 cents/kWh. 
Since that time, however, the wind industry has succeeded in reducing 
its production costs by a remarkable 80% to the current cost of 
approximately 4.5 cents/kWh. The 1.5 cent/kWh PTC stimulates new wind 
power development by assisting the industry in competing with fossil 
fuel generating sources, which based on historical averages cost around 
3.0 cents/kWh.
    With the continued support of the PTC, the wind industry expects 
that its costs will continue to decline as wind turbine technology 
continues to improve and the industry is able to realize more efficient 
manufacturing economies of scale. Through further turbine development 
and manufacturing efficiencies, the wind energy industry anticipates 
that the cost of wind energy will continue to be reduced until wind can 
compete head-to-head with fossil fuels without the need for any 
incentives.
    The most significant factor contributing to the dramatic reduction 
in U.S. wind energy production costs over the last two decades has been 
the dramatic improvement in turbine efficiency. Since the 1980s, the 
industry has developed four generations of new and improved turbines, 
with each generation improving upon its predecessor. As a result, 
better blade designs, improved computer controls, and extended machine 
component lives have been achieved, which in turn have reduced the 
life-cycle costs of energy generated by wind turbines. Proven machine 
technology has evolved from the 50kWh machines of twenty years ago to 
the 1,500kWh machines of today that have the capacity to satisfy the 
energy demands of as many as 525 homes.\2\ Moreover, new turbines in 
the range of 2,000 to 3,000 kWh are currently under testing and 
development, which will further improve the technology's efficiency and 
reduce wind power costs.
---------------------------------------------------------------------------
    \2\ One megawatt (MW) (or 1,000 kWhs) of current technology 
installed wind capacity servces approximaely 300 to 350 homes.
---------------------------------------------------------------------------
    With the support of the PTC, the wind industry anticipates that 
research and development will continue and turbine costs will continue 
to decline. We are confident that future generations of wind turbines, 
along with improved efficiencies in manufacturing economies of scale, 
will sufficiently lower costs to allow the industry to directly compete 
with fossil fuel generated power. An extension of the PTC will help the 
wind industry bridge the gap as it moves closer to direct competition 
with fossil fuels.
            B. The Wind Energy PTC is Helping Develop an Important 
                    Alternative Clean Energy Source with Significant 
                    Potential to Add New Electrical Generating Capacity
    The severe shortage of electricity currently being experienced in 
the Western United States graphically points to the critical need for 
Congress to support the development of alternative energy sources in 
the United States such as wind power. Throughout the West, severe 
shortages of electricity have led authorities to call for stepped up 
construction of new power plants. But, even the speediest construction 
of conventional fossil fuel plants takes years to bring on-line. By 
contrast, new wind plants can often be brought on-line in months.
    For example, in California, where the electricity shortage is the 
most acute, FPL Energy has identified 525 megawatts (MW) of new wind 
power potential that it believes could be developed in California over 
the next twelve months. In addition, FPL Energy estimates it could 
repower another 100MW at its existing wind plants in California over 
the next 12 months. Finally, FPL Energy believes there is the potential 
of at least another 500MW of new wind power at other sites in 
California that could be developed over the next 18 months. In other 
words, FPL Energy believes that, if the PTC continues to be available, 
there is the potential to develop new wind power capacity in California 
of at least 1,125MW over the next 18 months. This is enough new power 
to serve approximately 400,000 homes.\3\
---------------------------------------------------------------------------
    \3\ FPL's estimates contained herein are based on its most current 
research of new wind development potential in California over the next 
18 months. The ability to develop this potential could be significantly 
impacted by economic and regulatory restrictions and/or difficulties, 
including but not limited to the availability of the wind energy PTC, 
access to transmission and the ability of power producers to get paid.
---------------------------------------------------------------------------
    Also, along the Washington-Oregon border near Walla Walla, 
Washington, FPL Energy is currently constructing and expects to have 
on-line by year-end what will be the world's single largest wind plant. 
At a capacity of 300MW, FPL Energy's new Stateline Wind Generating 
Project will produce enough electricity to serve the needs of some 
70,000 homes, enough energy to serve about one-third of the residential 
customers in Portland, Oregon.
            C. Wind Power is Green Power That Can Contribute to the 
                    Reduction of Greenhouse emissions
    Wind-generated electricity is an environmentally friendly form of 
renewable energy that produces no greenhouse gas emissions or ground 
water pollution. In fact, a single 750KW wind turbine can displace, by 
replacing the combustion of fossil fuels, up to 1,500 tons of CO2 
emissions per year.
    Significant reductions of greenhouse gas emissions in the United 
States can only be achieved through the combined use of many new, 
energy-efficient technologies, including those used for the production 
of renewable energy. The extension of the PTC will assure the continued 
availability of wind power as a clean, renewable energy source.
            D. Wind Power has Significant Economic Growth Potential
            1. Domestic
    As stated, wind energy has the potential to play a meaningful role 
in meeting the growing electricity demand in the United States. Wind 
power projects currently operating across the country generate 
approximately 2,500MW of electric power--enough energy to serve as many 
as 700,000 homes--in states as geographically diverse as the following: 
Alaska, California, Colorado, Hawaii, Iowa, Kansas, Michigan, 
Minnesota, Nebraska, New Mexico, New York, North Dakota, Oregon, 
Pennsylvania, Texas, Vermont, Wisconsin, and Wyoming. With the 
appropriate commitment of resources to wind energy projects, the 
American Wind Energy Association estimates that wind energy could 
generate power to as many as 10 million homes by the end of the next 
decade.
    The domestic wind energy market has significant potential for 
future growth because, as the sophistication of wind energy technology 
continues to improve, new geographic regions in the United States 
become suitable forwind energy production. The top twenty states for 
future wind energy potential include:\4\
---------------------------------------------------------------------------
    \4\ Source: An Assessment of the Available Windy Land Area and Wind 
Energy Potential in he Contiguous United States, Pacific Northwest 
Laboratory, 1991. A map showing wind energy resources in the U.S. is 
attached.
---------------------------------------------------------------------------
STATE
                                                                    kWhs
                                                           (in billions)
    1. North Dakota...........................................     1,210
    2. Texas..................................................     1,190
    3. Kansas.................................................     1,070
    4. South Dakota...........................................     1,030
    5. Montana................................................     1,020
    6. Nebraska...............................................       868
    7. Wyoming................................................       747
    8. Oklahoma...............................................       725
    9. Minnesota..............................................       657
    10. Iowa..................................................       551
    11. Colorado..............................................       481
    12. New Mexico............................................       435
    13. Idaho.................................................        73
    14. Michigan..............................................        65
    15. New York..............................................        62
    16. Illinois..............................................        61
    17. California............................................        59
    18. Wisconsin.............................................        58
    19. Maine.................................................        56
    20. Missouri..............................................        52
            a. Wind Power Projects Can Serve as a Valuable Source of 
                    Supplemental Income for Farmers and Ranchers And 
                    New Economic Growth Opportunities For Rural Areas
    Some of America's most productive farming and ranching regions are 
also some of the most promising areas for wind development. Since wind 
projects and farming and ranching are fully compatible--wind plants can 
operate will little or no displacement of crops or livestock--lease 
payments made by wind developers can serve as a valuable source of 
stable, additional income for ranchers and farmers. In Iowa, for 
example, existing wind farms are currently paying $640,000/year in 
rent.
    Also, importantly, wind projects bring valuable new economic 
opportunities to areas, often rural, where wind projects are located, 
including increased local tax bases, new manufacturing opportunities 
and construction and ongoing operational and maintenance jobs. FPL 
Energy estimates its new Stateline project will add millions of dollars 
in revenue to the local Walla Walla, Washington economy, and will 
create an average of 150 new construction jobs with a peak need of 350 
workers, and for on-going operations provide 8 to 15 new full-time jobs 
and 4 to 7 new part-time jobs.
            b. Continued Growth of Domestic Wind Industry will provide 
                    economic benefits to other sectors of the U.S. 
                    economy
    In addition to the benefits cited above which wind plants provide 
for farmers, ranchers and the rural communities where wind farms are 
sited, the U.S. wind industry provides many economic benefits to other 
sectors of the U.S. economy. For example, FPL Energy has its steel wind 
towers manufactured in Louisiana, Texas, Utah and North Dakota; wind 
turbines manufactured in Texas, Illinois and California; transformers 
manufactured in Wisconsin, Pennsylvania and Missouri; and wind turbine 
components manufactured in Georgia, Washington, Iowa and Colorado.
            2. International
    The global wind energy market has been growing at a remarkable rate 
over the last several years and is the world's fastest growing energy 
technology. The growth of the market offers significant export 
opportunities for United States wind turbine and component 
manufacturers. The World Energy Council has estimated that new wind 
capacity worldwide will amount to $150 to $400 billion worth of new 
business over the next twenty years. The current worldwide market for 
wind turbines is approximately $4 billion per annum, and growing 
rapidly. Unfortunately, most of this manufacturing capacity, and its 
attendant job creation, is currently located in Denmark. Experts 
estimate that as many as 157,000 new jobs could be created if United 
States wind energy equipment manufacturers are able to capture just 25% 
of the global wind equipment market over the next ten years. Only by 
the continued support of its domestic wind energy production through 
the extension of the wind energy PTC can the United States hope to 
develop the technology and capability to effectively compete in this 
growing international market.
            E. The Immediate Extension of the Wind Energy PTC is 
                    Critical
    Since the wind energy PTC is a production credit available only for 
energy actually produced from new facilities, the credit is 
inextricably tied to the financing, permitting and construction of new 
facilities. With the credit due to expire in less than seven months, 
January 1, 2002, it is very difficult for wind energy developers plan 
for new wind power projects post-2001. The immediate extension of the 
wind energy PTC is therefore critical to the continued development of 
wind power in the United States.
IV. Conclusion
    We strongly believe Congress should extend the PTC as proposed in 
H.R. 876. Since its inception in 1992, the PTC has proven itself to be 
an excellent investment by the Congress. It has served as a catalyst 
that has stimulated significant development across the United States of 
the most viable renewable source of energy: wind power. We believe the 
extension of the PTC will ensure that FPL Energy and other U.S. energy 
companies continue to make the investments necessary to ensure the 
long-term role of wind energy in our national energy mix.
    Thank you for providing FPL Energy LLC with this opportunity to 
appear before you today.

                                


[GRAPHIC] [TIFF OMITTED] T4221A.049

[GRAPHIC] [TIFF OMITTED] T4221A.048

                                


    Chairman McCRERY. Thank you, Mr. Morrison. Mr. Carlson.

 STATEMENT OF WILLIAM H. CARLSON, VICE PRESIDENT AND ALTERNATE 
   ENERGY GROUP GENERAL MANAGER, WHEELABRATOR ENVIRONMENTAL 
 SYSTEMS, INC., ANDERSON, CALIFORNIA, ON BEHALF OF USA BIOMASS 
                    POWER PRODUCERS ALLIANCE

    Mr. Carlson. Mr. Chairman, members of the Subcommittee, the 
USA Biomass Power Producers Alliance, whom I represent today, 
appreciates the opportunity to testify today in support of 
President Bush's inclusion in the 2002 budget of a provision 
allowing existing biomass plants to qualify for the section 45 
tax credit. We intend to show why this represents good public 
policy and how it will be used to increase generation of 
renewable power from existing biomass plants.
    The Alliance represents most of the 100 small biomass power 
plants spread across 30 States, from California to Maine, and 
New York to Florida. We dispose of over 22 million tons 
annually of waste wood from the Nation's agricultural, 
forestry, and urban wood waste streams, while producing one-
half of 1 percent of the Nation's electricity. We combust rice 
hulls in Louisiana, sugar cane waste in Florida, orchard 
prunings in California, untreated urban wood in New York and 
Massachusetts, and forestry waste materials in Michigan, Maine, 
and the West. In the process, we lower air emissions by 96 
percent versus open field burning, free up valuable landfill 
space, and assist public forest land managers in removing 
excess fuels to lower fire risks.
    Our plants are typically located in rural areas, where we 
may be both the largest private employer and the largest 
property taxpayer.
    Since 1992, the section 45 tax credit for wind and biomass 
has provided an inflation-adjusted 1.5 cent per kilowatt hour 
tax credit. Due to excessively narrow drafting, no biomass 
plant has even claimed one cent of credit. The existing credit 
simply does not work for our industry.
    The credit applies only to closed-loop biomass, which are 
agricultural products grown exclusively to produce power. Not 
one plant has been built utilizing this material as the 
economics simply will not support the concept. On the other 
hand, well over 100 open-loop plants were built using clean 
waste wood and selling to utilities under the auspices of PURPA 
contracts.
    These contracts typically contain ten or more years of 
known rates based on the utility's own costs, but most of these 
plants are now beyond that point and struggling to survive in a 
deregulated market which values price only. As a consequence, 
nearly 30 percent of the industry has closed its doors since 
1994. Already, farmers have resumed open-field burning, wood is 
going back to landfills, and excess fuel removal in western 
forests has virtually halted.
    So why should the President and this Congress care about 
saving this small renewable industry, whose electrical output 
could easily be replaced by a handful of new gas-fired plants? 
The answer is found in a November, 1999 study by the Department 
of Energy that sets out to put a dollar value on the 
environmental benefits of the biomass power industry. The study 
looked at the alternative fates of waste materials were they 
not to be combusted in a biomass plant. The conclusion is that 
the nonelectric environmental benefits of reduced air 
emissions, landfill avoidance, and improved forest health 
totaled the equivalent of 11.4 cents per kilowatt hour of 
biomass power produced. Clearly, the 1.5 cent per kilowatt hour 
tax credit applied to this technology is a wise investment of 
public funds with an exceptional return.
    The Clinton and Bush administrations clearly recognized 
these values when they included in the 2001 and 2002 budgets, 
respectively, the definitional changes that would allow the 
types of open-loop plants that we operate to qualify for the 
credit.
    Mr. Herger and Mr. Matsui introduced this week a 
comprehensive bipartisan biomass bill that provides further 
definition to the President's budget bill. On the Senate side, 
Senator Grassley has introduced S. 756, a bill virtually 
identical to the Herger/Matsui bill. Both Republican and 
Democratic energy bills include the definitional change to 
biomass and make it available to existing facilities. Clearly, 
this is a bipartisan issue with broad support.
    This tax credit is the appropriate mechanism to stabilize 
the industry and incentivize additional production. It is only 
through maximum production from existing plants that the Nation 
captures the full range of environmental and energy benefits. 
In current energy markets, most biomass plants operate only a 
fraction of the time at full capacity, due to the low value of 
power during off-peak times and the rising cost of fuel with 
additional production.
    The current credit is at the right level of allow virtually 
all plants to cost-effectively operate at maximum capacity at 
all times. A lower credit would not accomplish this same level 
of operation. Quite simply, if you run and produce the 
environmental benefits for the public, you get the credit.
    The current tax credit includes a provision whereby the 
credit goes away during periods of high power prices. We 
support that protection against windfall profits and suggest no 
change.
    We ask once again for your support of the President's 
expansion of the section 45 biomass tax credit, as modified and 
clarified by the Herger/Matsui bill. We advocate that this 
expanded credit represents good public policy and is a textbook 
example of how tax credits can be judiciously used to cost-
effectively and simultaneously accomplish the Nation's energy 
and environmental objectives.
    We thank you for this opportunity to testify and welcome 
your questions.
    [The prepared statement of Mr. Carlson follows:]
 Statement of William H. Carlson, Vice President and Alternate Energy 
    Group General Manager, Wheelabrator Environmental Systems Inc., 
Anderson, California, on behalf of USA Biomass Power Producers Alliance
    The USA Biomass Power Producers Alliance (USABPPA) applauds the 
leadership of this subcommittee in holding this hearing and supports 
the inclusion in President Bush's budget of an expanded definition of 
biomass that allows existing power plants to qualify for the existing 
IRC Section 45 tax credit.
    The USABPPA represents most of the 90 to 100 small biomass power 
plants spread across 30 states from California to Maine and New York to 
Florida. While these plants, in aggregate, provide only about 1/2 of 1% 
of the nation's electrical energy, they along with other renewables, 
are central to increasing energy self-reliance and they are integral to 
proper disposal of the nation's wood waste materials and to achieving 
our air quality goals and commitments. These plants dispose of over 
22,000,000 tons of waste each year from the nation's forestry and 
agricultural activities and from untreated wood separated from the 
municipal waste stream. We combust everything from rice hulls in 
Louisiana, to sugar cane waste in Florida, to orchard prunings in 
California, to urban wood in New York and Massachusetts, to forestry 
waste materials in Maine, Michigan and California. In the process we 
lower air emissions by 96% versus open field burning, provide 
substantial levels of rural employment, free up valuable landfill space 
and assist with reducing the massive fire hazard in choked western 
forests by removal of brush and small trees.
    Since 1992 a tax credit has been on the books in Section 45 of the 
Tax Code that grants an inflation adjusted 1.5 cents/kWh tax credit to 
wind and biomass facilities. Due to excessively narrow drafting, no 
biomass plant has claim for one cent of credit under this provision. In 
other words, the current credit simply does not work for or industry.
    The problem is that the credit applies only to ``closed loop 
biomass'', which are agricultural products grown exclusively for 
combustion in a power plant. There has not been a commercially viable 
undertaking in the U.S. in the nine year life of the credit, as 
economics simply will not support it, even with the credit. Conversely, 
since the passage of the Public Utility Regulatory Policy Act (PURPA) 
in 1978, we have seen the growth of a substantial biomass power 
industry fueled by the waste products of the nation's agricultural, 
forestry and urban wood streams.
    Initially encouraged by utility contracts featuring 10 years or 
more of reasonably high rates based on the utility's own costs, and 
thus not needing a tax credit, the plants are now struggling to survive 
in a deregulated market where all supply decisions are based purely on 
price. As a consequence, nearly 30% of the industry has closed its' 
doors since 1994. With that loss has come the resumption of open field 
burning of ag wastes, a halt in much needed thinning of overstocked 
forests and the return of clean urban wood to the landfills. Without 
this tax credit that erosion will continue. If this happens, tighter 
air quality controls on industry and the public will be necessary to 
make up for the improvements provided by the biomass industry.
    There have been price blips across the nation that have stayed the 
decline temporarily, but the trend continues down. California plants, 
for example, currently see high prices all around them in the open 
market, but see only a modest bump in their prices since most are still 
under contract to the utilities, and those utilities have not paid them 
for deliveries from December through March. Maine plants saw a price 
rise for a few months due to power shortages, but those have since 
disappeared as large gas-fired plants have come on line, and margins 
have narrowed as fuel costs have increased.
    The question then is why should the President, this Congress and 
this Subcommittee care about saving this small renewable industry when 
the whole industry's electrical output could easily be displaced by 
gas-fired merchant plants that you could count on one hand? The answer 
is found in a study released in November 1999 by the Department of 
Energy that set out to put a value on the environmental benefits of the 
industry. This study (Attachment 1) conducted by the Green Power 
Institute of Berkeley, California, looked at the alternative fate of 
waste materials were they not to be used as fuel for a biomass plant. 
The conclusion reached was that the non-electric environmental benefits 
of reduced air emissions, landfill avoidance and improved forest health 
totaled the equivalent of 11.4 cents/kWh of biomass power produced. 
This striking public benefit is in addition to the domestic energy 
security, avoidance of fossil fuel use and rural employment benefits 
shared with other renewable technologies. Interestingly, the ``open 
loop'' plants burning waste materials actually have much greater 
environmental benefits than the ``closed loop'' concept that has had 
the tax credit since 1992. The DOE study clearly indicates that the tax 
credit is not a form of corporate welfare but a wise investment with a 
substantial return.
    The Clinton and Bush Administrations clearly recognized these 
values when they included in the 2001 and 2002 Budgets, respectively, 
the definitional changes that would allow the types of ``open loop'' 
biomass plants that we currently operate to qualify for the credit.
    Fellow members of the House Ways & Means Committee, Mr. Herger and 
Mr. Matsui introduced, just this week, a comprehensive bipartisan 
biomass bill, that provides further definition to the President's 
budget proposal. On the Senate side, Senator Grassley, Chairman of the 
Senate Finance Committee, has introduced S.756, a bill virtually 
identical to the Herger/Matsui bill. Senators Collins and Boxer also 
introduced S.188, another bipartisan biomass bill. This truly is a 
bipartisan issue, as the comprehensive Senate energy bills of both the 
Republicans and Democrats have included the same change in definition 
of biomass and made the credit available to existing facilities.
    The Section 45 Wind and Biomass Tax Credit truly is the appropriate 
mechanism to stabilize the industry and incentivize additional 
production. It is only through maximum production from existing and 
currently closed facilities that the nation captures the full range of 
environmental and energy benefits. In the current energy markets, most 
biomass plants operate only a fraction of the time at full capacity due 
to the low value of power during off-peak periods and the rising cost 
of fuel with additional production. The current credit is at just the 
right value to allow virtually all plants to operate at full capacity 
at all times. A lower credit, as has been advocated by some, would not 
accomplish the objective of maximizing the environmental benefits of 
the industry. Attachment 2 is our attempt to capture this relationship 
between marginal fuel cost, electric power value, and impact of tax 
credit level. Simply, you produce and generate multiple times the 
environmental benefits; you receive this credit. You don't produce; you 
receive no credit.
    The current Section 45 credit wisely includes a provision whereby 
the credit disappears during times of high power prices. This would 
avoid the appearance of windfall profits under certain situations, 
something we also wish to avoid given the current round of 
investigations and incriminations against power producers in 
California. We support the continuance of this safeguard.
    We close by asking for your support of the President's expansion of 
the Section 45 Biomass Tax Credit as modified and clarified by the 
Herger/Matsui bill. We believe that this expanded credit represents 
good public policy and is a textbook example of how tax credits can be 
judiciously used to cost effectively and simultaneously accomplish the 
nation's energy and environmental goals. On a personal note, as an 
operator of five of these plants, I look forward to a day, perhaps late 
in 2001, when I can tell my employees that their plants and their jobs 
will have a long-term future.

                                


    Chairman McCrery. Thank you, Mr. Carlson. Mr. Wallace.

STATEMENT OF DAN WALLACE, OWNER, COLUMBUS OIL COMPANY, SEMINOLE, 
        OKLAHOMA

    Mr. Wallace. Mr. Chairman and Members of the Committee, 
after that introduction by Congressman Watkins, I feel 
compelled to tell you I am not J.R. Ewing. [Laughter.]
    But I am a blue jean-wearing, boot-wearing, pickup-driving 
``oily'' from Seminole, OK. When invited here, I was invited 
here to represent that segment of the oil and gas industry 
known as the independent producer, operating marginal stripper 
production.
    I heard the young lady earlier today testify that we 
produce about 50 percent of domestic crude barrels, and I 
suggest to you we probably produce about 70 percent.
    I assume we all know what a marginal or a stripper 
production well is here today. I assume that we're acquainted 
with Congressman Watkins' introduction of the 100 percent net 
income tax limitation suspension back in '97, and I assume that 
we all know what happened to the price of oil in 1998 and '99, 
after the introduction of the suspension. I would suggest to 
you that if it was important enough in 1977 and 1997, it's 
probably more important to you today.
    If the question were asked, should we continue the 100 
percent net income limitation, the answer should be yes. If one 
would ask why, the answer should be to encourage the 
exploration and production of the domestic barrel. If not to 
increase production, at the least slow the decline curve.
    If one was to ask how we would do that, my follow-up to the 
question would be I think there needs to be a partnership 
between the government, the private sector, the industry, to 
encourage the investment of risk capital in the production of 
the American barrel.
    Tax incentives can and will help find the domestic barrel 
and the domestic natural gas. These efforts will not only help 
the independent producer, but also will help develop America's 
reserves. Businessmen and women that make legitimate business 
decisions must be made on knowns, not hypotheticals, not 
projections.
    In the independent business, we have to live in the real 
world. We have to get up every morning and put our clothes on 
and go to work with what is going on in the real world today. 
What is the price of the commodity? What are the percentages of 
the investment dollars? Are the rules going to get changed? Is 
the price going to get changed? That's what we get up and go to 
work with most every day.
    I would suggest to you there are 1,440 minutes in a day, 7 
days in a week, and these wells run every day of every week of 
every year. This is a seven-day-a-week business. The 
consumption is a 7-day-a-week business. The supply side is the 
same.
    You ask how does the suspension of the 100 percent net 
income limitation work, how does it affect my bottom line? As 
Wes said earlier, I'm currently, as of six o'clock this 
morning, about 3,600 foot deep on a 4,400 foot well. The 
estimated cost, about $220,000. I got up this morning watching 
CNBC, and the price of oil drops 4 percent yesterday.
    I can assure you, that means something to me. It does not 
drop my cost. I don't have to explain that to you fellows. I'm 
sure you've all been there and done that before, like myself. 
But that's the world that we independents live in.
    I own about 50 percent of this well, and four of my other 
buddies own the other 50 percent. My backing is my bank. My 
collateral at my bank is my stripper and marginal production. 
That's what they hold the mortgage on, for me to get the money. 
In case I can't come up with the money, at least I can go 
borrow the money and pay my 50 percent of this well. The other 
four guys, I can tell you, are the same way. If not this well, 
it will be the next well.
    I can also tell you for a fact that this is the first well 
that I have drilled in about 12 years. One would ask, well, why 
is that? I suppose you're going to get around to asking that 
later on. Pretty simple logic is the answer to where the 
independent is.
    I would also suggest to you that, in the past 15 years--and 
people are going to talk about the infrastructure, and I've 
heard some of the speakers today talk about it. Let me tell you 
one of the most important things. The infrastructure that's 
being lost in this country is about 70 percent of the 
independent producers who have either bellied up, gone broke, 
got out of the business, second generation, let's sell out and 
quit fighting it, take what we can get safe, and let's go on 
down the road and retire.
    That's all the knowledge, all the experience. There is not 
a university in this country that can teach the things that the 
independent producer must know before he takes his risk 
dollars, or maybe somebody else's risk dollars, and puts them 
to work. There is not a book in any library. That's the 
infrastructure that's being lost, the independent producer.
    I would suggest to you that behind me the generation will 
skip. There won't be an aggressive, risk-taking, gambling 
generation in numbers behind my particular generation in the 
independent sector.
    My particular well that I just alluded to represents about 
four independent producers. If you would take the thousands of 
independent producers across the country and divide four into 
it, I think you will find there are literally hundreds of wells 
being drilled by the independent today. I can also tell you 
that only in the last 3 years this country has lost another 10 
percent of its daily pipe-line runs. That's the infrastructure.
    If you want to fix the problem in this country, from the 
people that do things--we're not much as talkers, although I 
have sat here and talked quite a bit. But I think we are the 
doers. That's the consensus of the independent producer.
    Thank you.
    [The prepared statement of Mr. Wallace follows:]

   Statement of Dan Wallace, Owner, Columbus Oil Company, Seminole, 
                                Oklahoma

    My name is Dan Wallace, owner of Columbus Oil Company, 
located in Seminole, Oklahoma. I am an Independent Oil 
Producer. And I am here to represent the segment of the oil and 
gas industry known as the Independent Producer. I have been 
invited to testify today to the impact of the federal tax laws 
on the production and supply of oil and gas from marginal 
wells.
    The term marginal production means domestic oil or gas 
production during any taxable year. This includes stripper well 
properties that are defined as: ``The average daily production 
of oil or gas from producing wells on a property that is 
equivalent to 15 barrels or less per well per taxable year.''
    In 1997, Congressman Wes Watkins added language in the tax 
bill that suspended the 100% net income limitation for marginal 
properties. And, this year, President Bush included the 
extension of this suspension in his budget proposal to 
Congress.
    This suspension provides needed incentive to invest risk 
capital dollars in the business. If the question is ``Do we 
continue the suspension of the 100% Net Income Limitation?''
    The answer should be YES.
    The question now becomes ``Why should the suspension of the 
100% Net Income Limitation be continued?''
    One of the answers to this question should be ``so the 
government can encourage the oil and gas industry to increase 
domestic production in order to stop or slow the decline 
curve.'' In turn reducing this country's reliance on foreign 
imports.
    The follow-up question to why should be ``how do we support 
extending the suspension of the 100% Net Income Limitation?''
    The answer to how should be ``so government can work 
effectively with the private sector to achieve positive 
results.'' By offering a variety of incentives to the 
Independent Producer to return those risk dollars to slow or 
stop the steep decline curve of not only oil and gas, but the 
even steeper decline of the Independents Producers active in 
America today. Thousands of Independent Producers across 
America have been forced out of business over the past decade 
due to declining or non-existing profits.
    Tax incentives can and will help create an environment that 
will offer the possibility of a profit through the spending of 
risk capital.
    These efforts will not only be for the Independent 
Producer's benefit but for the opportunity to develop America's 
oil and gas reserves as well. The opportunity will be created 
out of need for these energy-producing commodities. Businessmen 
and women can make better decisions based on knowns with a 
strong message from our government that there is a future with 
some stability in the energy business.
    Tax incentives must be part of a long-term plan by our 
government if we are to reverse the current trend of inadequate 
energy supplies.
    Let us not forget all wells become marginal at some point. 
Marginal production is the foundation the Independent Producer 
works from to finance their operations.If you ask ``How does 
the suspension of the 100% Net Income Limitation affect my 
bottom line today?''
    My answer is. ``Today I am currently drilling a 4400, well 
in Hughes County, Oklahoma. It is located on the Oliphant Ranch 
twenty miles from my office in proven oil and gas country. The 
estimated cost of this drilling project is $220,000.00. 
Marginal and Stripper production is the collateral used at a 
local bank to fund my 50% of this project. Local independent 
producers in this joint venture fund the remaining 50% from 
their Marginal and Stripper production.I suggest you multiply 
this well times a few thousand other Independent Producers and 
you will find hundreds of wells being drilled as I speak.
    What is currently being done is working to keep this 
industry active and there is your proof.
    Government and industry together can make a difference.
    I urge you EXTEND THE SUSPENSION of the 100% Net Income 
Limitation.
    Thank you for your time and this opportunity to speak on 
behalf of other Independent Producers.

                                


    Chairman McCrery. Thank you, Mr. Wallace.
    Mr. Wallace, with respect to the suspension of the 100 
percent net income provision, did that suspension allow you to 
keep open some wells that you otherwise might have capped?
    Mr. Wallace. No question about it. No question about it. I 
can't say enough about that, and I can't say enough about any 
tax incentive that is offered in this particular industry.
    Seriously, you must be dealing with some knowns. The 
incentives offered us, if not taken away, are the knowns. 
Whenever we create the budget in which we're going to try to 
operate on with the forthcoming year, it's a very volatile 
market and we don't know what the price of the commodity is 
going to be.
    Chairman McCrery. If you had capped those wells rather than 
keeping them in production, would you have been able to just go 
back out in the field and open them up when the prices got back 
up?
    Mr. Wallace. No, sir. I heard somebody testify earlier, 
something about the capping of wells, the plugging of wells. 
That's a serious problem. That is not going to fix this problem 
today, but that is a problem that needs some consideration down 
the road.
    I would suggest there be some technology looked into on how 
to plug a well. Maybe not the old conventional method that 
we've used for the last 50 years. Maybe that's not the best. 
That's in the event you want to go back.
    Chairman McCrery. Now that prices have rebounded, what role 
does the suspension of the net income limitation play in 
developing capital and directing that to new production?
    Mr. Wallace. An excellent question. It provides the 
opportunity to take some profits from some profitable leases, 
wells, properties, and go back and rework those stripper wells, 
to try to improve them from possibly a three-barrels a day well 
to a five- or six-barrels a day well. That's the opportunity it 
offers you, the incentive to put those dollars at risk back 
into the business.
    Chairman McCrery. Do you do your own taxes, Mr. Wallace?
    Mr. Wallace. No, sir. I'm fortunate enough to have a CPA in 
my office, who's been with me for 20-some years.
    Chairman McCrery. Do you talk with your CPA about your 
taxes?
    Mr. Wallace. I think my CPA runs the business, rather than 
me, sometimes.
    Chairman McCrery. Have you ever talked with your CPA about 
the effects of the alternative minimum tax----
    Mr. Wallace. I'm sorry?
    Chairman McCrery. Have you ever talked with your CPA about 
the effects of the alternative minimum tax on your business?
    Mr. Wallace. Yes.
    Chairman McCrery. And what does he tell you?
    Mr. Wallace. He doesn't much care for it.
    Chairman McCrery. He doesn't much care for it. Have you 
gotten into any of the detail as to why he doesn't care for it?
    Mr. Wallace. Well, again--not in detail. I'm not an 
accountant and, after 20-some years--We have a lot of one-on-
one conversations, I can assure you.
    Chairman McCrery. I'm sure you do.
    Mr. Wallace. I don't try to tell him how to run the Tax 
Code, and he doesn't tell me how to run an oil well. But we 
have discussions. As far as me being well-versed, no.
    Chairman McCrery. Well, allow me to just say, gentlemen on 
the Subcommittee, we need to take a look at the AMT and the 
effect it has on independent producers, because it is a very 
serious impediment to independent producers having reliable 
income. In fact, it's a very perverse influence on the 
production of oil by independents because, in bad times, it 
punishes them. If they're having bad years, income-wise, the 
alternative minimum tax actually punishes those independent 
producers at the worst possible time, driving some of them out 
of business and certainly preventing them from reinvesting in 
the ground, so to speak. So that may be something we'll have to 
get into in another hearing.
    Mr. Williams, according to a study by the Gas Technology 
Institute that you referenced, non-conventional gas production 
tripled in the past 20 years, growing from about 1.5 trillion 
cubic feet per year in 1980 to about 4.6 trillion cubic feet 
currently.
    Can you offer us any insight on the role that the section 
29 credit played in this increase?
    Mr. Williams. Certainly. I'm pretty intimately involved 
with it, and have been for a number of years. I think it 
absolutely played a key role in that increase.
    I think maybe you could look at coalbed methane as the best 
example. In 1980, there was no effective coalbed methane 
production in the United States. In fact, through most of the 
eighties, it remained at relatively low levels. It was in 
direct response to the section 29 credit that people were 
willing to go out and take the additional risk to attempt to 
produce a formation that had never been produced before, 
effectively and economically.
    That same kind of risk taking also applied to tight 
formation gas and Devonian shale, because of the additional 
incentive and security provided by the credit. Wells were 
drilled that wouldn't have been drilled; new techniques for 
drilling wells and producing wells, were developed that made 
wells that would not have been economic even with the credit 20 
years ago very economic today, or much more economic.
    I see that as a possibility for the future. I absolutely 
think that reinstating the credit would encourage our industry 
to take those kind of chances again. You know, over the last 10 
years, we've been living on our past laurels, going back in, 
completing the drilling of fields that were started before 
that, and doing less and less exploratory work. These kind of 
incentives help to take away some level of the risk. Basically, 
they help to ameliorate the price risk to some degree. It just 
reduces the number of risks that you have got to deal with 
before you decide to put your money in the ground.
    Chairman McCrery. Thank you. Mr. McNulty.
    Mr. McNulty. Thank you, Mr. Chairman. I want to thank Mr. 
Williams, Mr. Morrison, Mr. Carlson and Mr. Wallace for their 
assistance today. I'm just going to ask one question of Mr. 
Morrison.
    In my opinion, there is tremendous merit in pursuing 
alternative sources of energy, particularly wind power. I noted 
in your testimony that you had some estimates about how much 
production could be increased given the proper resources. I 
want to get a handle on what you really mean by that and what 
would you consider to be the proper resources necessary in 
order to fulfill the vision that you have for wind power in the 
future, and if you could quantify what that actually would be 
in the end, if you could give some kind of a guess of your 
vision of what percentage of our energy supply could eventually 
come from wind power.
    Mr. Morrison. Sure. With respect to what is required to 
facilitate wind becoming a significant source of energy in the 
United States, I think the credit for the next few years is of 
essential importance.
    As I alluded to in my testimony, the price of this energy 
has decreased dramatically, and we are now approaching the 
point where wind is (with the PTC) directly competitive with 
fossil fuels. I think the cost of the technology will continue 
to decrease as turbine sizes continue to get larger, which 
makes them more efficient because there's less steel, less 
copper, etc., per kilowatt hour that comes out of the turbines.
    Additionally, most of the manufacturing of these machines 
currently occurs in Denmark. I am sure that, if there is a 
stable, long-term American market, that manufacturing will 
shift to the United States. There will be factories built in 
the United States and components will be sourced in the United 
States, gear-boxes, generators, and so on, which are currently 
manufactured in European factories. So with a stable, long-term 
American market, I think we will have tremendous growth and 
tremendous efficiencies and increasingly reduced costs in this 
business to the point where wind will be directly competitive 
with fossil resources.
    With respect to what my guess is--and it's nothing more 
than a guess--as to what this technology could eventually 
provide in the way of electricity generation in the United 
States, west of the Mississippi is probably where most of the 
resource is. It is also where the land usage patterns are 
amenable to large-scale utility wind farms. Also, it just has 
population densities that are favorable for wind.
    In that respect, I think it's interesting to draw a 
parallel to Denmark, where this technology has been around for 
a similar amount of time as it's been in the United States, but 
in Denmark it has benefited from a stable, long-term policy. 
The Danes currently provide about 15 percent of their national 
electricity from wind, and they're targeting a third by, I 
believe, the year 2012.
    West of the Mississippi, I think this technology could 
easily provide 10 percent of the electricity consumed in that 
region. With favorable public policies and some luck on the 
technology side, it would be upward of 15 percent. In the East 
it would be slightly less because the population densities are 
higher.
    Wind will be a small percentage piece of the puzzle in 
solving the Nation's environmental and energy problems, but 
nevertheless, 10 percent of the electric energy consumed west 
of the Mississippi is an enormous absolute quantity of energy. 
In particular, as a marginal percentage of new capacity added, 
wind would be substantially greater than that.
    This technology is not going to generate 40 percent of the 
energy in this country. Nevertheless, it's an important piece 
of the puzzle.
    Mr. McNulty. Thank you very much. I thank all the 
panelists, and thank you, Mr. Chairman.
    Chairman McCrery. Mr. Weller.
    Mr. Weller. Thank you, Mr. Chairman. This has been as good 
panel.
    I would comment to Mr. Wallace that your Representative in 
Congress, my friend Wes Watkins, has been talking about these 
little guys and gals that are independent oil people back home, 
and it's nice to have you before the Committee today. Wes does 
a good job of speaking out for you, and it is nice to see, 
West, that you brought one of them. You brought a live one here 
and we appreciate Mr. Wallace being a part of this today.
    There are a couple of questions I would like to direct 
first to Mr. Williams. You were talking about the section 29 
tax credit and the role it plays, particularly in addressing 
the additional cost of non-conventional fuels, making that a 
competitive solution as we look for ways to increase domestic 
sources of energy.
    According to the statistics that the chairman pointed out, 
about the increase in non-conventional gas production tripling 
over the last 20 years, do you feel today that we have reached 
the peak? Do you feel that we have an adequate supply of non-
conventional fuels, or do you feel there's an opportunity to 
continually increase the amount of non-conventional fuels that 
could be made available as a result of the section 29 tax 
credit?
    Mr. Williams. Certainly, I do think there's a great 
opportunity to continue to increase the supplies of non-
conventional sources. In fact, I think it's essential that 
supplies of non-conventional sources continue to be increased. 
I have not seen any long-term supply model that doesn't have 
them playing a significant part in the future supplies.
    The reality is that the amount of conventional resources 
available domestically is declining. We have developed more of 
our conventional resources because they're more economic and 
easier to develop. So more and more, what's left is non-
conventional. If you want to have an adequate supply, that's 
where it's going to have to come from. But I certainly think we 
have developed some of the technologies to develop what's 
there, but there is certainly room for improvement over the 
coming years.
    Mr. Weller. What do you see as additional barriers to 
increasing non-conventional fuels that we need to address in 
the Congress? When you look at the Tax Code, not with just 
section 29, are there any other provisions in the Tax Code that 
have an impact on the production of non-conventional fuels?
    Mr. Williams. The net income limitation is an issue, and 
the alternative minimum tax is very much an issue. I would 
point out that the chairman is absolutely correct, that when 
prices are low and our profits are lowest the alternative 
minimum tax has the most adverse impact. When profits are high, 
we tend to be not under the alternative minimum tax umbrella. 
Certainly that's been the experience with my company, and 
myself personally, with my own investments in the wells that we 
drill.
    But I think, even beyond the Tax Code, one of the big 
issues is access. The more we cut off potential areas of 
development around the country from access for oil and gas 
development, the less resources will be available.
    My company recently had an experience with denied access in 
Utah. We leased some land on a Federal lease and started to 
work putting together the permits for it. Initially we were 
delayed waiting for eagle nesting season to end. By the time 
that was done, the former President's roadless initiative had 
taken effect, or had been proposed, and we're sort of sitting 
and waiting to see whether we will even be able to get access 
to the land that we've already leased. I think that's a major 
issue for our industry.
    Generally, I think there are a number of provisions in the 
Tax Code that are very helpful in the formation of capital. 
Capital formation is absolutely essential to our industry. 
Whether it's the small wells, one well that you're drilling for 
yourself, or a company like mine that goes out and accesses 
capital through public markets, in addition to our own money, 
having a project that has a reasonable level of risk and an 
acceptable rate of return is essential. With the price 
volatility that we've seen in the last decade, it becomes very 
difficult to do.
    Mr. Weller. Thank you, Mr. Williams.
    Mr. Morrison, the wind energy tax credit, of course, I'm 
one of those who believes very strongly that it needs to be 
extended and that it's a key incentive as we look for 
alternative ways of generating electricity, something that's in 
shortage in California and elsewhere in this country. Of 
course, green power is a good thing.
    You indicated--I believe the statistic you used was about 
700,000 homes today are essentially provided electricity as a 
result of wind power, and there's a potential for continued 
growth, but it's not the ultimate solution.
    A similar question as I asked Mr. Williams. Besides 
extension of the wind energy tax credit, are there other 
provisions in the Tax Code which have an impact on wind energy 
that we should be taking a look at?
    Mr. Morrison. Wind currently qualifies for the 5-year 
Modified Accelerated Cost Recovery (MACRS) makers treatment, 
and that clearly enhances the economics of wind projects, so I 
think that's an important attribute.
    Other than that, I think the PTC to-date have facilitated 
the development of many of these wind projects which have been 
quite successful. I think that all we are asking for is time to 
allow us to have the technology further mature so that we don't 
need these incentives any more. That's basically what you heard 
in some of my testimony.
    Mr. Weller. Thank you, Mr. Morrison. I see my time has 
expired, Mr. Chairman. Thank you.
    Chairman McCrery. Thank you, Mr. Weller. Mr. Neal.
    Mr. Neal. Thank you, Mr. Chairman. I have a question for 
Mr. Carlson.
    Could you give me a range of items that would be covered by 
the proposal to extend the biomass credit to open-loop 
businesses, particularly in the northeast?
    Mr. Carlson. Yes, Mr. Neal. I will do that.
    The definitional changes that we seek are something that we 
have worked on now for about 3 years, and involved a wide range 
of parties, including environmental groups, Treasury officials, 
others here in Washington, D.C., to try to get these 
definitional changes as narrow as possible in order to keep the 
cost to the Treasury down but broad enough to encompass the 
materials that we use.
    Basically, they fall into three categories, and all of 
these are somewhat applicable to the northeast. The first is 
forestry waste materials. These are things like sawmill 
residues and the brush that is removed from thinning a lot of 
the overstocked woods that we find now that we have, 
particularly in the western States, but specifically it limits 
the materials from, for instance, old growth timber, which is 
not included in the definition.
    Second, in the agricultural arena, all of the by-products 
of agriculture, such as shells and pits and stems and stocks of 
agricultural products, would be included within the 
definitional change that we seek.
    Thirdly would be materials out of the urban wood stream, 
which would probably be most applicable to the more heavily 
populated areas of the northeast. This would be things like 
pallets and dunnage, tree trimmings, those kinds of materials, 
but specifically excluding, because of the parties that we have 
collaborated with, any treated or painted materials that might 
have some hazardous substances associated with them, and 
excluding paper materials that would typically be available for 
recycling.
    So we're trying to find that slice of the market where 
there are materials that could be put to good use, that would 
have no other use, but would not usurp materials that would 
have a higher use somewhere else in the recycling realm.
    Mr. Neal. Well, given the rising price of electricity, what 
is the value to the public of extending this credit to the open 
loop biomass plants?
    Mr. Carlson. The rise in electricity, as you referred to, 
is probably primarily referring to the California market again, 
because that's the market that has seen the most rise recently. 
In that market, for instance--and there are numerous biomass 
plants in California, actually the largest location for these 
plants--virtually none of those plants have seen that rise in 
electricity. They are still under contract to utilities.
    In fact, the problems that have been engendered by the high 
prices in California are actually more of a problem to the 
biomass producers there than they are an opportunity, because 
they haven't been paid for their December 2000 through March 
2001 production.
    What you will find is that in other areas of the country 
there has been no price rise. In fact, the next largest 
concentration of plants is in Maine, and the prices in Maine 
are very low, to the point where the plants there are suffering 
greatly.
    The nice thing about the section 45 credit, as it's 
currently written, is that it has this provision that it phases 
out as electricity prices go up, so there is not the potential 
for windfall profits. In fact, when it reaches a fairly high 
level, the credit is gone altogether. So it really has a self-
limiting mechanism that is very appropriate for this type of a 
credit.
    Mr. Neal. Thanks for your testimony, Mr. Carlson. I agree 
with you. Thank you, Mr. Chairman.
    Chairman McCrery. Thank you, Mr. Neal.
    Mr. Morrison, as you pointed out, I have supported the wind 
credit in the past. However, this is a question that we have to 
ask, I think, and I'm going to give you an opportunity to 
answer it.
    Because we are seeing a rise in the price of electricity, I 
think it's intuitive to conclude that, if the price gets so 
high, then you guys don't need a credit. How do you answer that 
right now?
    Mr. Morrison. We have a couple of charts that I think would 
be illustrative here. We have made some comparisons with the 
price of natural gas rather than a direct comparison with 
market prices of electricity because electricity markets are 
fractured and somewhat difficult to make direct comparisons to. 
So we regard the marginal competitor for wind-generated energy 
as being natural gas, as the gas gets transformed through a 
combined cycle generating plant into electricity.
    The chart on the left provides some historical and 
forecasted data for the price of natural gas. I think it's 
rather similar to some of the charts that the people from DOE 
presented today. I don't think there is anything particularly 
different from what we're showing from what was earlier 
presented.
    On the left, in blue, is the historical price of natural 
gas on an inflation-adjusted basis at Henry Hub, based on the 
NYMEX contract. On the right in red is a similar forecasted 
Henry Hub price, which represents an average of forecasts from 
five nationally recognized energy forecasting firms.
    I think what is clearly most conspicuous about the graph is 
that, if one considers historical trends and future forecasts--
admittedly, they're just forecasts--we're in the middle of what 
appears to be an unprecedented spike in the price of natural 
gas.
    Similarly, the chart on the right-hand side, which is all 
historical data over a much shorter time period, from May of 
2000 through May of 2001, which is actual traded prices for the 
NYMEX contract for Henry Hub deliveries for natural gas, again 
we reached a tremendous spike in January, where we got to $10 
per mm Btu, but immediately after that, we have seen the price 
of natural gas come down.
    I think it is our belief, and I think it's generally the 
belief of most people in the energy business today, that prices 
we see today, while they may be good for producers and also 
good for generators of wind energy, they're not going to last, 
that supply will, expand to meet increased demand and that 
prices will decline in the future. Wind still needs a bit of 
time yet, with incentives, to perfect its technology to the 
point where it can compete on the basis of the sorts of 
forecasted prices for natural gas that we see here.
    Chairman McCrery. Thank you for that explanation.
    You also mentioned in your testimony that you foresee a day 
when wind energy could be competitive in the market without the 
tax incentive. Do you have any idea when that might occur?
    Mr. Morrison. It is certainly not in our business plan to 
come up here and get an extension every 3 years. Again, it's a 
bit of a guess, but in my conversations with turbine 
manufacturers and other people who are technically savvy in the 
business, I think the general expectation is that five to seven 
years is the sort of timeframe that we need before we can be 
directly competitive.
    The turbine manufacturers that I know have internal targets 
where, on a year-by-year basis, they target reductions in the 
cost of turbines, from manufacturing efficiencies, and supply 
chain efficiencies, on the order of five percent per annum.
    In addition, every time a new turbine model is introduced, 
which occurs about once every 18 months or 2 years, they target 
a 10-percent reduction in the cost of the turbines. Turbine 
costs are about 75 percent of the total cost of a wind 
generation facility, so a 5 percent per annum decrease, in 
addition to a 10 percent per new model decrease, pretty rapidly 
leads to some significant price decreases in the cost of the 
equipment and, therefore, the cost of the energy coming out of 
the equipment.
    Chairman McCrery. Thank you. Mr. Watkins.
    Mr. Watkins. Thank you, Mr. Chairman.
    You know, we talk about national energy policy. That has a 
different meaning for different people, I know. We see a lot of 
the peaks and valleys in the price of energy, and we yell out 
in the oil patch when it gets so low, and when it gets too 
high, the consumers are yelling, saying we have to do 
something. So, in my opinion, we need to try to stabilize a 
pricing system, stabilize it so that it can become more 
predictable.
    Again, I'm excited, because I think we have some people who 
understand at the White House the need for this, and also may 
have some knowledge about how to do that.
    Mr. Chairman, this has been a very informative panel, and I 
would like to have each one to state what tax provision--if you 
could just wave a magic wand, what tax provision in a national 
energy policy would each of you like to see, like the top one 
or two tax provisions that would allow you to increase 
production, stabilize and move forward?
    Mr. Williams, we'll start with you and then move to Mr. 
Wallace.
    Mr. Williams. I can't speak to wind power since I know 
nothing about it, so I will stick to oil and gas, if that's OK 
with you.
    Mr. Watkins. You stick to each of your industries. I figure 
that's why you're in that business.
    Mr. Williams. Choosing just two measures that make a lot of 
sense in the oil and gas industry--certainly, I would have to 
put section 29 in there. I do think it focuses on the 
resources, the high cost resources, and helps pull them into 
the mix where they might not be there otherwise.
    Another measure that I think makes a lot of sense would be 
a marginal well tax credit, because it reaches out and helps 
keep the wells that might otherwise be abandoned and a resource 
that would be lost permanently available in the mix going down 
the road. I think those would be my top two choices.
    Mr. Watkins. Thank you. Mr. Morrison.
    Mr. Morrison. I think for the wind industry, what we would 
most like would be a long-term extension--and by that I mean a 
five- to 7-year extension--of the section 45 credits. That's 
all.
    Mr. Watkins. That would probably do it for the wind 
industry. All right. Mr. Carlson.
    Mr. Carlson. Mr. Watkins, I would certainly second what Mr. 
Morrison just said. We are actually excited to be here today, 
because for the first time our industry is being included in 
section 45 in the President's budget, where we have been 
excluded because of definition before. This is virtually the 
perfect credit to incentivize our industry, because we are 
fairly unique, in that the more we run, the more expensive our 
fuel source becomes, because it needs to be hauled further 
distances to arrive at the plant for proper disposal.
    This credit, as a production tax credit, really allows us 
to take what is a relatively low-cost power market for many 
hours of the week--even though we may get high prices, for 
instance, during a hot day in the summer time--and for months 
on end in the fall and the spring, and particularly when prices 
are extremely low--this credit will build a floor under the 
industry so that we can still be incentivized to go procure the 
fuel that we need to run these plants at full capacity.
    So this is the type of incentive that our industry needs, 
the section 45 tax credit included in the President's budget, 
because as I mentioned, it has this self-limiting mechanism 
whereby don't get it when the prices are high, but when you 
need it the most, it's there for you so that you can procure 
the fuel that you need.
    Mr. Watkins. To help stabilize that, a little more 
predictable, right?
    Mr. Carlson. Absolutely.
    Mr. Watkins. Mr. Wallace, my friend from the oil patch.
    Mr. Wallace. Wes, if I wanted to approach this problem from 
a tax angle, I would probably do it on some sort of a sliding 
scale, tied to the price of oil, what is the lifting cost. 
Everybody wants to talk about the price of oil, but nobody 
wants to talk about what it costs to produce it, the lifting 
cost. That's the key to domestic production, the lifting cost.
    I would tie it to some sort of a sliding scale. If you're 
making a profit and you don't plow part of it back into the 
production of America's oil and gas, I would probably tax you 
pretty good. I would just take a good, common sense approach, 
and the boys out there making obscene profits, we're going to 
tax you or you're going to go get us another barrel. That's 
probably what I would come up with.
    The State of Oklahoma, 9- or 10 dollar oil, I was involved 
a little bit in that a couple of years ago. They removed all 
their tax to save the wells. We all know the gross production 
tax helped pay the bills in the State of Oklahoma. That's how 
serious it got with them, and that's the serious attitude they 
took.
    If I were these people, I would declare war on them. I 
would roll up my shirt sleeves and go to work.
    Mr. Watkins. That's an excellent point. I think, for the 
consumer as well as the producer, over and over--I've been out 
in the oil patches and have visited with friends. All they are 
looking for is some kind of predictability, some stability, so 
that they can go borrow that money and know if they may have a 
shot at paying it back.
    Mr. Wallace. That's the key.
    Mr. Watkins. That's the sliding scale on tax credits, 
another bill that I've introduced along the way--and I noticed, 
Mr. Carlson, biomass is getting quite a bit of interest in some 
of the farm land around the country. But I think it's just 
exactly that in the oil patch.
    Most of the people love it, they're working at it, but it 
is shocking when you realize we've lost 70 percent of the 
producers, independent producers, and that's not counting the 
skilled workers, that infrastructure that we've lost out in the 
oil patch, where today I would predict it would be difficult to 
get geared back up to increase that production that we have to 
have in order to get there.
    If I'm hearing what they're saying to me, as I make the 
rounds and have a chance to visit along the way, I know it 
seems that way in our neck of the woods.
    I want to thank all of you for being here, but I want to 
especially thank my friend, Dan Wallace, who is just exactly 
what he described. He's out there, he may have that CPA, but 
I'll tell you, I'll bet he's keeping an eye on that bottom 
line. But he's out there making sure that rig is running, 
making it work, and like this morning, calling and finding that 
it's down to 3,600 feet and he has still got about 600 feet or 
more to go before that well is complete. Dan, we wish you much 
success on that well.
    Mr. Wallace. Thank you, Wes.
    Mr. Watkins. Let me just ask, how many wells do you have 
overall?
    Mr. Wallace. We're probably operating right at 50 wells 
today, a carryover from '98 and '99--let me just share this 
with you. I don't care if you're an independent or a major. You 
take the calendar years of '98 and '99, your gross, $19.60 a 
barrel, less taxes, less royalty, you operated for 24 months at 
$14.60 a barrel. Now, start trying to pay your bills, take care 
of your family, and look for a barrel of oil on $14? It's not 
going to happen.
    If you take the next calendar year, 2000, add it to that, 
you've got the same thing. We have operated for over 3 years 
out there at cost. No question.
    Mr. Watkins. No question about it. Thank you, Mr. Chairman. 
It was a very, very valuable meeting.
    Chairman McCrery. Thank you, Mr. Watkins. Mr. McNulty.
    Mr. McNulty. Thank you, Mr. Chairman. I just want to 
express my gratitude to all of those who gave testimony today, 
to thank you for calling this very important hearing. I noted 
that every single Member of the Subcommittee participated in 
the hearing, and that's an indication of how important this 
subject is.
    Finally, Mr. Chairman, I look forward to our next hearing, 
which will also be on this subject, and at that hearing I 
intend to steal a play from Wes Watkins' playbook and bring a 
couple of my constituents to talk about fuel cell technology.
    Thank you, Mr. Chairman.
    Mr. Watkins. We look forward to that.
    Chairman McCrery. Thank you, gentlemen, for your testimony 
today. We appreciate it very much. And to all of you who 
participated in today's hearing, thank you for coming and being 
such a polite audience. We look forward to our next hearing.
    [Whereupon, at 1:05 p.m., the hearing was adjourned.]
    [Submissions for the record follow:]
  Statement of Charles Fritts, Vice President, Government Relations, 
                        American Gas Association
I. Introduction
    The American Gas Association (``AGA'') appreciates the opportunity 
to present its views on the role of federal tax law in addressing the 
energy situation currently faced by the nation. AGA represents 185 
local natural gas distribution companies, which deliver natural gas to 
approximately 60 million customers throughout the United States. AGA 
member companies serve more than 90 percent of America's gas consumers, 
and AGA member companies are located in every one of the United States.
II. Executive Summary
    Events of the last year have made clear the importance to consumers 
and the economy of adequate and reliable supplies of reasonably priced 
natural gas. Providing the natural gas that the American economy 
demands will require providing incentives to bring the plentiful 
reserves of North American natural gas to production and to deliver 
that gas to end-use consumers. To that end, AGA believes that federal 
tax legislation should:
     Provide incentives for the investment of $150 billion that 
will be necessary to ensure the infrastructure required to serve this 
natural gas market, including:
     Seven-year depreciation for new natural gas infrastructure
     Expensing of natural gas storage facilities
     Repeal of the tax on Contributions in Aid of Construction
     Provide incentives to produce the vast, untapped reserves 
of natural gas, particularly those reserves that might not otherwise be 
produced, that will be necessary to serve a market that will consume in 
excess of 30 Trillion cubic feet per year. AGA particularly endorses 
proposals to extend the tax credit provided under Section 29 of the 
Internal Revenue Code for certain ``nontraditional'' sources of natural 
gas.
     Provide incentives for new energy technologies such as 
distributed generation, combined heat and power, and natural gas 
cooling.
III. Tax Incentives Are Necessary to Ensure Required Gas Infrastructure
    As AGA will explain in further detail below, events in energy 
markets over the last year have strongly underscored the need for a 
comprehensive national energy policy that will ensure that sufficient 
gas supplies are brought forth to meet the projected growing demand for 
this clean and readily available fuel. Producing gas from the ground 
is, however, only the beginning of providing the energy that consumers 
require. In most instances the gas must then be moved hundreds or 
thousands of miles through large-diameter, high-pressure transmission 
lines. It is often stored underground during the off-season to be 
delivered in the peak season. After delivery by the interstate pipeline 
company, the pressure of the gas is reduced, and it is transported 
through miles of local distribution lines. Often local distribution 
companies will own underground gas storage to meet the needs of their 
temperature-sensitive customers.
    AGA's members are engaged in the local distribution of natural gas. 
They have an interest, as will also be explained below, in making 
certain that adequate supplies of natural gas are available for 
consumers. But their most direct interest is in ensuring that adequate 
infrastructure is in the ground to serve their end-use customers. 
Secondarily, they have an interest in making sure that sufficient 
interstate pipeline infrastructure exists to transmit the requisite 
volumes of gas from the producing areas to the market areas.
    Adequate natural gas is in the ground; it is simply necessary to 
assure that it is produced to meet the needs of our growing economy. 
Natural gas supply is, however, only half of the solution. Once natural 
gas is produced, it is necessary, as discussed previously, to have 
adequate infrastructure (typically in the ground) to deliver it to 
residential, commercial and industrial customers. Should overall 
natural gas demand in the years ahead reach the 30 to 35 Tcf level, 
significant capital investment will be required. The recent Fueling the 
Future study by the American Gas Foundation, as well as a study by the 
National Petroleum Council, project that $150 billion in natural gas 
infrastructure will have to be constructed to deliver those supplies of 
gas to consumers. Roughly $100 billion in infrastructure will be 
required for local distribution company service and $50 billion will be 
required for interstate pipeline companies. Without this investment in 
infrastructure the projected market demand for natural gas may not be 
served.
    Tax incentives for infrastructure can provide natural gas pipelines 
and distributors with the additional incentive to place these necessary 
facilities in the ground. They can also provide the spur for investors 
to invest in the federal- and state-regulated utilities that provide 
the vast majority of natural gas service in the United States. These 
utilities are generally regulated as to the rates they can charge. As 
such they tend not to secure the types of entrepreneurial returns that 
readily attract capital. Yet it is clear that significant amounts of 
capital must be secured to serve the natural gas market that most 
forecasters expect to materialize.
    To this end, AGA supports seven-year accelerated depreciation for 
new natural gas infrastructure. This would include gas transmission, 
gas storage, and gas distribution facilities. On average over the past 
15 years, local gas distribution infrastructure investment has been $3 
to $5 billion per year. This pace will simply be inadequate to provide 
the infrastructure that AGA believes will be necessary to support 
projected consumer demand for natural gas. More rapid tax depreciation 
for these needed new facilities will provide the necessary impetus for 
investment in this infrastructure.
    AGA also supports proposals to permit expensing natural gas storage 
costs. Natural gas storage has been increasingly important over the 
last ten years in permitting local distribution companies to acquire 
gas during periods of low prices and deliver the gas to their customers 
during higher-priced periods. Such facilities are, during conditions 
such as those that have existed recently, even more important tools in 
dampening retail price volatility for consumers. Providing full 
expensing of natural gas storage facilities will give the critical 
impetus necessary to bring more such facilities online, with 
concomitant consumer benefits in the form of lower delivered gas prices 
overall. This approach is particularly important if competing fuels are 
accorded such tax treatment so that tax law does not artificially skew 
the choice among fuels.
    Another area for tax reform that will benefit energy consumers is 
correcting the tax treatment of contributions in aid of construction 
(CIAC). At present a new customer (either residential or a residential 
developer) that seeks to connect to the natural gas system is often 
required to pay a hookup fee that the utility uses as an offset to the 
costs of making the connection. Under present law local distribution 
companies are taxed on these contributions. In fairness, they should be 
treated as contributions of capital to the natural gas system. This 
CIAC tax works as a disincentive to new gas connections. As a result it 
discourages additional gas usage, even though that fuel is the most 
environmentally benign fuel available, is usually the most economic 
fuel, and is almost always procured from North American sources.
    AGA urges Congress to take constructive action to ensure that the 
needs of America's gas consumers are met by providing tax incentives 
for needed new energy infrastructure.
IV. America's Current Energy Situation
    Ample, reliable energy supplies at affordable prices are critical 
to providing economic and national security for America and its 
citizens. Energy is consumed in every sector of our economy. There is 
virtually no business entity in the United States that does not rely 
upon energy in order to operate. Our economy cannot grow, and, indeed, 
cannot maintain its present vitality, without assurances of adequate, 
reliable, and reasonably priced supplies of energy. Continued economic 
stability and growth are inexorably tied to the nation's energy supply. 
Economic stability and growth are, in turn, keys to continued full 
employment, growth in national wealth, and the important state and 
federal tax revenues that are so essential to funding important 
government social, public safety, and defense programs.
    The intermittent California electric blackouts this year have 
dramatically raised public awareness of these issues. Additionally, 
energy costs in most areas of the country have risen significantly, 
including gasoline, electricity, and natural gas. These events have 
caused both businesses and consumers increasingly to realize that 
reliable and reasonably priced energy are required to support our 
economic vitality as well as the many comforts and necessities that 
Americans have come both to enjoy and to expect in the postwar era. 
Energy is more in the public mind now than it has been at any time in 
the last twenty years.
    The Federal Government occupies a critical position in the current 
energy situation. By conceiving, enacting, and implementing a 
comprehensive national energy policy, the government presently has a 
unique opportunity to ensure that America will enjoy reliable and 
reasonably priced energy for many years to come. A sound energy policy 
will lead to continued prosperity and employment for America's 
citizens. Although a comprehensive national energy policy will have 
many elements, a key component will be a prudent, measured tax policy. 
Sound tax policy will play a critical role in driving a national energy 
policy.
    America has significant reserves of domestic energy. The events of 
the last year, however, make plain that we must do more to bring these 
ample energy supplies to production and to expand the infrastructure 
that is necessary to deliver that energy to the places that demand it. 
Not much more than a year ago the price of natural gas was 
approximately $2.50 per million British Thermal Units (``Btu'') at 
Henry Hub in Louisiana. In the last several months the Henry Hub price 
has been about $5.00 per million Btus. At the height of the winter the 
price reached $10 per million Btus. This price movement indicates the 
tightness in the marketplace and it reflects the sensitivity to changes 
in production and consumption levels. As a result, most American 
natural gas consumers experienced significant, unwelcome increases in 
the natural gas bills over this past year.
    The increase in natural gas prices resulted from supply, demand, 
and weather. Drilling for natural gas declined in 1998 and 1999 in 
response to extremely low prices. Demand for natural gas continued to 
grow with the robust condition of the economy as well as the public's 
recognition of the economic and environmental benefits of natural gas. 
As a result, natural gas prices began to rise in the spring of 2000. In 
November and December of 2000 record cold weather hit many parts of the 
country. All of these factors together led to very high natural gas 
bills for most consumers in America.
V. The Future Energy Supply and Demand
    The United States has enormous untapped reserves of natural gas. It 
is widely believed that in excess of 1200 Trillion Cubic Feet (Tcf) of 
natural gas--or a 60-year supply at current levels of production--are 
available in North America. Current proved reserves are approximately 
170 Tcf. At present the United States consumes approximately 23 Tcf 
annually. Virtually all projections suggest that over the coming 
decades U.S. consumption will top 30 Tcf.
    The experience of the past year makes plain that available natural 
gas production and current natural gas demand are closely matched. The 
behavior of natural gas prices over the last twelve months strongly 
suggests that very little incremental supply of gas is presently 
available in the market place. In other words, the ``gas bubble'' of 
the last ten or more years is a thing of the past.
    Recent gas prices have spurred record new drilling for natural gas, 
and some of those supplies are already coming on line. Yet there is 
reason to be concerned whether there will be production of the volumes 
of natural gas that most commentators believe the market will require 
in the coming decade and beyond. Should natural gas production not keep 
up with growing demand, the result will be significant price volatility 
and generally higher prices. The trajectory of the last year in terms 
of prices and supplies could well accelerate if supplies do not keep 
pace.
    A comprehensive national energy policy must ensure that adequate 
supplies of natural gas are produced and that adequate infrastructure 
is in place to deliver that gas to consumers. Federal tax law can 
perform an important function in ensuring that the energy needs of 
consumers and businesses are met in the years ahead.
VI. Reasonable Tax Incentives Are Necessary to Ensure Adequate Supplies 
        of Gas
    AGA member companies distribute natural gas to America's 
residential, commercial, and industrial consumers. That natural gas is 
usually purchased from others, most often natural gas producers or 
energy marketers. AGA member companies do not make a profit on the sale 
of gas to consumers; rather they earn their revenues from distributing 
that gas to end users. Accordingly, AGA member companies do not have an 
economic stake in gas production or gas prices. Rather, their interest, 
like that of their customers, is in ensuring that ample supplies of gas 
are reliably available and at reasonable prices.
    AGA believes strongly that the Federal Government, including the 
Congress, must take affirmative steps to assure adequate future gas 
supplies to meet consumer needs. AGA defers, however, to those most 
directly involved in this end of the business--natural gas producers. 
AGA traditionally has left it to that segment of the industry to make 
the specific legislative and regulatory proposals that are necessary to 
ensure adequate gas supplies. Notwithstanding this fact, AGA supports 
legislative initiatives to promote sufficient gas supplies.
    AGA generally supports a number of proposals made by the producer 
community to spur increased gas production. For example, AGA supports 
those who urge that Section 29 of the Internal Revenue Code, providing 
incentives for ``nontraditional'' gas production, be extended. The 
history of Section 29 makes clear that it has brought forth major 
volumes of natural gas that would not, in all likelihood, have been 
produced otherwise. (It is interesting to speculate as to prices this 
past winter had Section 29 never been enacted.) Similarly, AGA endorses 
tax incentives for production from marginal wells. Such incentives will 
bring to market volumes of gas that might otherwise remain forever in 
the ground.
    A very large volume of the United States gas consumption is 
produced by smaller independent gas producers. These producers do not 
enjoy access to New York, London, and Hong Kong capital markets. 
Rather, they are dependent for their activities upon convincing local 
and regional banks to extend them financing or, more likely, their own 
cash flow. Modest tax incentives for these types of producers can 
provide important benefits for the nation. For example, proposals to 
expense (rather than capitalize) geological and geophysical costs and 
shut-in royalty payments can provide producers with significantly 
increased cash flow. Similarly, proposals to permit ten-year carryback 
for percentage depletion can be of major assistance, particularly to 
small independent producers.
    AGA generally supports reasonable and well considered tax 
incentives of this sort that will have a genuine impact in bringing to 
market more of America's significant natural gas resources.
VII. Tax Incentives Are Necessary to Encourage New Energy Technologies
    AGA also supports tax incentives for new energy technologies such 
as distributed generation, combined heat and power, and gas cooling. 
Distributed generation in particular warrants close Congressional 
attention. Onsite power generation has many benefits. It removes load 
from the electric transmission and distribution grid, averting 
congestion and additional construction of new transmission facilities. 
It also obviates the need to build new central station power plants. 
Moreover, it tends to draw on the natural gas transmission system at 
offpeak times, providing additional natural gas load without the need 
for additional gas facilities, thus leading to lower unit costs for all 
gas customers.
VIII. Conclusion
    Natural gas is the right fuel at the right time to solve many of 
the nation's energy problems. AGA believes that the federal government 
should take whatever steps it can to bring this fuel to America's 
consumers right now. It can do so by encouraging the construction of 
the natural gas infrastructure that will be necessary to meet projected 
natural gas demand by consumers. It can do so by encouraging the 
production of natural gas, particularly from sources that might not 
otherwise be produced. It can do so by supporting new technologies that 
utilize natural gas in new and efficient means. Tax incentives should 
be adopted to promote all of these ends.

                                


     Statement of the Electric Vehicle Association of the Americas
Introduction
    This testimony is presented on behalf of the Electric Vehicle 
Association of the Americas (EVAA), a national non-profit organization 
of electric and other energy providers, vehicle manufacturers and 
suppliers, state and local governments and other entities that have 
joined together to advocate greater use of electricity as a 
transportation fuel. A complete membership list is attached. A 
principal activity of the association is to advocate the adoption of 
incentive-based policies and programs to facilitate the development and 
use of electric modes of transportation.
The Role of Electricity in the National Transportation System
    The Association believes that use of electricity as a fuel offers 
significant advantages in transportation applications. Electricity is 
inexpensive, stable and generated from a variety of domestic fuels. 
Electric transportation technologies present our nation with an 
important means for reducing our dependency on foreign petroleum and 
increasing the diversity of fuels relied upon in the transportation 
sector. During the last energy crisis in 1973, only 36 percent of oil 
used in the U.S. was imported. Today, the U.S. imports 19.1 million 
barrels of foreign oil per day and the U.S. Department of Energy 
reports that net imports of petroleum in the year 2001 will account for 
54 percent of total U.S. petroleum demand--an increase of 18 percentage 
points from 1973. And in the next twenty years, the Energy Information 
Administration (EIA) predicts that this nation's demand for oil will 
increase by an additional 33 percent. EIA also predicts that gasoline 
prices--already at $2.00 per gallon in some regions of the country--
could spike even higher during the summer peak-driving season.
    It is clear that the need for this country to transition to the use 
of alternative fuels is more critical than ever. A wide variety of 
transportation modes--individual passenger and light-duty vehicles--and 
heavy-duty vehicles, like buses and trolleys--can and should be powered 
by electricity--an abundant, clean, and domestically produced energy 
resource. All of the technologies mentioned above will reduce 
pollution, reduce our dependency on imported oil, and improve the 
quality of life in many of our cities and towns, while maintaining our 
high degree of mobility.
    In addition to diversifying sources of transportation ``fuels,'' 
air quality considerations also are requiring municipal transit 
operators to consider the use of alternative fuel technologies as a 
means to reduce emissions and achieve air quality goals. Nearly 100 
cities in the United States do not meet federally established air 
quality standards. For many urban areas, electric transportation may be 
a particularly important means to substantially reduce emissions of 
mobile source pollutants, including volatile organic compounds and 
oxides of nitrogen that are the precursors of smog. Electric cars and 
buses are truly ``zero emission'' transportation modes. They produce no 
tailpipe emissions and generate insignificant, ancillary emissions 
during operations. They also have the added benefit of mitigating noise 
pollution and improving efficiency.
The State of Electric Drive Technologies
    While each major automobile manufacturer, domestic and foreign, now 
has offered battery-electric vehicles (BEVs) for sale and/or lease on a 
limited basis, these products entered the market later than 
anticipated, and subsequently, the market has not developed as quickly 
as envisioned by industry and government. Since 1996, a total of 4,017 
BEVs have been leased and/or sold in the United States. Additionally, 
there are approximately 200 battery electric buses in operation 
throughout the United States. Some automakers also have begun to 
develop and market small, neighborhood electric vehicles (NEVs) that 
have applications in planned communities, college campuses, in station 
car applications, and other urban settings where space and travel 
distances are limited. Finally, there is growing use of non-road and 
industrial EVs, especially at airports located in urban areas.
    Hybrid electric vehicles (HEVs) also are making inroads in the 
marketplace. To date, Honda and Toyota have leased and/or sold over 
12,480 HEVs in the United States and other automobile manufacturers 
have announced plans to introduce hybrids into the marketplace in the 
next two to three years. There also is an interest among 
environmentalists, regulators, the electric utility industry and others 
to pursue development of grid-connected hybrid technologies as a means 
to improve the environmental performance of such technologies.
    Fuel cell electric vehicles (FCEVs), which harness the chemical 
energy of hydrogen and oxygen to generate electricity, have the 
potential to change the way we think about energy and transportation. 
Fuel cells are more efficient than other technologies that rely on 
direct combustion, and they produce zero, or near zero emissions. All 
of the major automakers are investing heavily to develop fuel cell 
technology and each has announced plans to offer fuel cell vehicles to 
the commercial marketplace by the end of the decade.
    Because EVs of all types are radically different from their 
internal combustion engine (ICE) counterparts, there are several 
challenges that must be overcome. Today, the challenges to the 
increased use of electric modes of transportation remain the cost of 
the vehicles, the limited availability of charging infrastructure, and 
consumer awareness and acceptance of the technology. For example, in 
order to achieve the range standard (100 miles per charge) that 
industry believes is necessary for BEVs to be commercially successful, 
the vehicles must use advanced batteries, such as nickel metal hydride, 
that are far more expensive and add to the incremental cost of the 
vehicle.
    Also, as is the case with BEVs and FCEVs, a new infrastructure 
system--whether it is electric chargers or hydrogen refueling 
stations--must be developed to support these technologies. There will 
be a significant cost associated with building a sufficient number of 
electric chargers and hydrogen refueling stations.
The Need for Federal Tax Incentives
    The Energy Policy Act of 1992 (P.L. 102-486 ``EPAct'') recognized 
the benefits that can be gained by using alternative fuels and electric 
modes of transportation by including modest, targeted tax credits for 
battery, fuel cell and certain hybrid-electric vehicles and supporting 
infrastructure. However, these tax credits are scheduled to begin 
phasing-out in 2002 and to expire in 2004. This timing will not provide 
the necessary incentives to support the introduction of these electric 
drive technologies.
    EVAA believes that targeted tax incentives can be the most 
effective means by which government could help assure that electric 
drive technologies are successfully introduced into the marketplace. 
While the Association believes that incentives should be limited in 
their scope and duration, they must be available, and sufficient now 
and in the immediate future, as these new and dramatically different 
technologies are being introduced to consumers. Without this critical, 
immediate assistance, it is unlikely that we will reap the full 
potential of environmental and energy benefits promised by widespread 
use of electric modes of transportation.
    Many Members of Congress--Republicans as well as Democrats--have 
recognized the role that limited and targeted tax incentives can play 
in overcoming the current market barriers to assure large-scale 
commercialization of electric drive technologies. EVAA applauds the 
leadership several members of this Committee--specifically 
Representatives Mac Collins (R-GA), John Lewis (D-GA), Dave Camp (R-
MI), and Sander Levin (D-MI)--have provided in years past to pursue 
legislation that provides the types of modest tax incentives necessary 
to make these advanced technology vehicles more affordable and 
acceptable in the marketplace.
    To date, three bills that seek to address this country's energy 
dilemma have been introduced in the Senate during the 107th Congress. 
Senator Frank Murkowski (R-AK), Chairman of the Senate Energy and 
Natural Resources Committee, has introduced the National Energy 
Security Act of 2001 (S. 389). Senator Jeff Bingaman (D-NM), Ranking 
Member of the Senate Energy and Natural Resources Committee, has 
introduced the Comprehensive and Balanced Energy Policy Act of 2001 (S. 
597). And, Senator Orrin Hatch (R-UT) has introduced the Clean 
Efficient Automobiles Resulting from Advanced Car Technologies Act of 
2001 (S. 760, the CLEAR Act). All three proposals include--in whole or 
in part--tax incentives to encourage the purchase and use of electric 
vehicles and other advanced transportation technologies and supporting 
infrastructure. (See attachment for a summary of the major provisions 
of these bills.)
    Comprehensive energy legislation also is being discussed in the 
House, and it is clear that policymakers are focusing on the important 
role that advanced transportation technologies can, and must, play in 
the development of a sound national energy policy. Just this week, the 
Democratic Caucus' Energy Task Force released its blueprint for 
addressing the nation's energy dilemma. Also, Representative David Camp 
(R-MI) introduced the Clean EfficientAutomobiles Resulting from 
Advanced Car Technologies Act of 2001 (H.R. 1864--the CLEAR Act), 
companion legislation identical to the bill introduced by Senator Hatch 
in the Senate.
    As gasoline prices continue to rise and Congress moves forward with 
energy legislation, EVAA urges you to look beyond the benefits gained 
by increasing supply, to the energy security and environmental benefits 
gained by supporting modest, consumer-based tax incentives for electric 
drive technologies.
    Attachments

      Electric Vehicle Association of the Americas--Membership List
                               May 1, 2001
------------------------------------------------------------------------

------------------------------------------------------------------------
Advanced Vehicle Systems               Hydro-Quebec
Air Products and Chemicals, Inc.       IMPCO Technologies Inc.
American Honda Motor Company,Inc.      International Lead Zinc Research
                                        Organization, Inc.
American MagLev Technologies, Inc.     Long Island Power Authority
Amercian Public Power Association      Massachusetts Division of Energy
                                        Resources
Avestor (Hydro Quebec)                 Maxwell Energy Products
Atlantic Center for the Environment    Mid-Del Lewis Eubanks AVTS
Ballard Power Systems                  National Rural Electric
                                        Cooperative Association
Carolina EV Coalition                  New York State Technology
                                        Enterprise Corporation
CEREVEH                                Nissan North America/Nissan R&D
Chattanooga Area Regional              Northeast Sustainable Energy
 Transportation Authority               Association (NESEA)
CITELEC                                NYSERDA
City of Atlanta/Bureau of Motor        PSA Peugeot-Citroen/USTR
 Transport Services
City of Burbank                        Sacramento Municipal Utility
                                        District
City of New York                       SAFT America, Inc.
Copper Development Association         Salt River Project
Curtis Instruments                     Saminco
Dynasty Motorcar Corporation           San Bernardino Associated
                                        Governments
Ecostar Electric Drive Systems         Solectria Corporation
Electricite de France                  Southern California Economic
                                        Partnership
Electric Vehicle Infrastructure        Southern California Edison
                                        Company
Electric Vehicle Association of        Southern Company/Georgia Power
 Canada                                 Company
Electric Vehicle Association of Great  Technologies M4
 Britain
Enova Systems                          Tennessee Valley Authority
ERIM                                   Texaco, Inc.
Florida Power and Light Company        3M
Ford Motor Company                     Tokyo Electric Power Company
Global Electric MotorCars, LLC         TotalEV
                                       Toyota Motor Corporation
                                       Toyota Motor Sales USA
                                       Unique Mobility, Inc.
                                       University of California, Davis/
                                        ITS
                                       University of South Florida
                                       US Department of Energy
                                       Volkswagen
                                       York Technical College
------------------------------------------------------------------------
Bold denotes EVAA Board member.


    [An additional attachment is being retained in the Committee 
files.]

                                


Statement of Rupert J. Fraser, Chief Executive Officer, Fibrowatt LLC, 
                         Yardley, Pennsylvania
    In 1999, Congress extended the Section 45 tax credit for 
electricity production from wind and other closed-loop biomass to 
include poultry waste, the manure and bedding materials also known as 
``poultry litter.'' This credit encouraged development of poultry 
litterfired power plants which could provide renewable electricity and 
an environmentally sensitive alternative to traditional land 
application of poultry litter, which is needed to address water and air 
pollution concerns. Currently, two poultry litterfired power plants are 
in planning stages but will not be in service by the December 31, 2001 
expiration date of the current Section 45 credit.
    We urge the Subcommittee to extend the Section 45 poultry waste 
production credit for five years, as provided in H.R. 1657 by 
Congressmen Herger and Matsui and S. 756 by Senator Grassley. Extension 
of the credit is needed to incentivize production of renewable energy 
from the estimated 20 million tons produced annually as an alternative 
to land application and address the increasing environmental issues 
associated with land application.
Poultry Production has Tripled
    The U.S. has the largest, most advanced poultry industry in the 
world. Since 1973, U.S. poultry production has tripled and continues to 
grow at about 5% per year.
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    In 2000, the U.S. produced 8.23 billion broilers and 270 million 
turkeys. The average American purchases about 98 pounds of poultry 
annually. Forty-two states produce chicken and turkey including 
Georgia, Arkansas, North Carolina, Mississippi, Texas, Minnesota, 
Alabama, Louisiana, Maryland, Delaware, Virginia, Oklahoma, and 
California.
[GRAPHIC] [TIFF OMITTED] T4221A.046

[GRAPHIC] [TIFF OMITTED] T4221A.047

Environmental Effects
    To increase production and gain economies of scale, feeding 
operations have concentrated in smaller geographic areas and have 
resulted in the generation of over 20 million tons of litter a year. 
Traditionally, poultry litter has been used as a fertilizer on farm 
fields. Although litter is a good fertilizer, certain lands have 
received too much manure and have become overloaded with nutrients such 
as phosphorus and nitrogen. When these nutrients mix with water runoff, 
they can cause water pollution problems such as algae blooms, 
pfiesteria, and eutrophication.
    Poultry producers throughout the U.S. are now facing increasingly 
stringent environmental regulation of manure utilization at federal, 
state and local levels. Poultry farmers are seeking out alternative, 
environmentally sensitive ways to use poultry litter to complement the 
use of manure as fertilizer.
Electricity Generation: A Proven Alternative
    Fibrowatt LLC is a U.S. developer of biomassfired power plants, 
based in Philadelphia, using technology pioneered by its shareholder 
Fibrowatt Ltd. Fibrowatt Ltd. has successfully built the world's first 
three power plants in the U.K. to use poultry litter and agricultural 
biomass as fuel, burning over 850,000 tons a year to generate a total 
of 65MW--enough electricity for over 150,000 homes. Fibrowatt expects 
to start construction soon for its 50 MW plant in rural Minnesota, 
which plans to use about 500,000 tons of poultry litter and about 
150,000 tons of other biomass a year. The plant is anticipated to be 
operational by the end of 2002.
    The poultry industry nationwide has shown significant interest in 
using litter to generate electricity because this technology offers a 
long-term and reliable manure utilization option for farmers. 
Generation of electricity from poultry litter is a proven, large-volume 
alternative. When poultry litter and agricultural biomass are combusted 
to produce electricity, an ash is produced, the volume of which is 
around 10% of the original. This ash can be sold as a fertilizer and 
contains potassium, phosphorus and other essential minerals. Excessive 
and over-concentrated volumes of poultry litter are thus reduced in 
size to transportable proportions.
    Fibrowatt obtains poultry litter from surrounding farms and 
purchases other forms of biomass from local sources. Operations begin 
on the farm, where Fibrowatt and poultry farmers coordinate litter 
cleanout for barns. Then the litter is transported in tightly covered 
trucks to the plant's fuel hall, where it is kept at negative pressure 
to prevent the escape of odors. Inside, the furnace burns the litter 
and other biomass fuels at very high temperatures, heating water in a 
boiler to produce steam, which drives a turbine and generator.
The Need for Renewable Electricity
    Industry experts in several states are predicting a shortfall in 
future electrical supply. The production of renewable energy from 
poultry litter not only helps America to meet that shortfall but also 
offers diversification of fuel sources within the power market. This is 
important if the U.S. is to become less reliant on polluting fossil 
fuels and foreign oil supplies.
Benefits
    Like other renewable energy projects, poultry litter-fired power 
plants have greenhouse gas benefits because they recycle carbon dioxide 
and can reduce methane and nitrous oxide emissions to the atmosphere. 
For example, a 50 MW plant reduces carbon dioxide emissions by an 
amount equivalent to taking 500,000 cars off the road.
    In addition, use of poultry litter for electricity generation 
provides local sources of electricity while addressing environmental 
issues of concern to poultry growing areas of the U.S.
    The benefits of a large-volume alternative to land application 
include:
           reduction of water and air pollution resulting from 
        land spreading of manure,
           sustainable agriculture by enabling poultry growers 
        to maintain levels of production while complying with increased 
        regulation of land spreading of manure,
           skilled, reliable jobs for rural residents, as a 50 
        MW plants employs about 35 people and creates about 175 
        indirect jobs,
           local production of electricity,
           reduction of carbon dioxide and other greenhouse 
        gases,
           improvement of poultry biosecurity, and
           support for rural communities.
Conclusion
    The Section 45 tax credit is needed because, like other biomass 
plants, poultry litterfired plants cannot compete in price with 
traditional fossil fuel plants. This is because (a) fossil fuel plants 
have economies of scale not available to poultry litterfired plants, 
whose size is determined by the amount of locally available litter, (b) 
the capital costs of fossil fuel plants may be fully amortized, whereas 
the technologies and facilities to combust poultry litter are new and 
involve substantial capital investment, and (c) fossil fuel technology 
has had 100 years of government support and subsidy worldwide which has 
enabled it to come much further down the cost curve than any renewable 
power technology. The Section 45 tax credit is needed to level the 
playing field, particularly in those states where no renewable 
portfolio mandate has been enacted.
    Fibrowatt stands ready to invest in future plants to produce 
renewable electricity while providing a viable, reliable alternative to 
land application of poultry litter. For this to happen, extension of 
the expiring production tax credit for poultry waste is needed so that 
poultry litter generated electricity can compete in price with fossil 
fuel electricity. Thank you for your consideration.

                                


   Statement of John H. Skinner, Ph.D., Executive Director and Chief 
 Executive Officer, Solid Waste Association of North America (SWANA), 
                        Silver Spring, Maryland
    On behalf of the Solid Waste Association of North America (SWANA), 
I appreciate the opportunity to submit this written statement for the 
record of the Subcommittee's hearing on current tax incentives and 
their role in the nation's energy policy. SWANA would like to commend 
you, and the members of your Subcommittee, for holding this timely 
hearing in light of the critical efforts of the Bush Administration and 
this Congress to develop sound energy policies to allow our nation to 
maintain its economic vitality and self-sufficiency. The association 
urges the Subcommittee to support tax incentives, such as the I.R.C. 
Section 29 nonconventional fuel production credit or an amended I.R.C. 
Section 45 tax credit, that encourage the solid waste management 
industry to produce energy as an adjunct to its handling of the 
millions of tons of municipal solid waste (MSW) generated by the 
country's households and businesses.
SWANA and MSW as a Source of Energy
    SWANA, an association of over 6500 solid waste management 
professionals, companies and government agencies in the United States 
and Canada, has as its mission the advancement of environmentally and 
economically sound solid waste management practices. The association 
has long recognized that development of energy from municipal solid 
waste can be done reliably, while resulting in more efficient solid 
waste management, resource recovery, cleaner air quality, and reduced 
potential for global climate change. Accordingly, SWANA has advocated 
the two types of energy production that are identified with solid waste 
management: (i) projects at which MSW is directly combusted to produce 
electricity, also known as waste-to-energy (WTE) projects, and (ii) 
projects that collect landfill gas, naturally generated at a landfill 
as the waste decomposes, and utilize the gas as a fuel, either to 
produce electricity or to supplement local natural gas supplies, known 
as LFG-to-energy projects or simply ``LFG projects.''
    Currently, WTE projects and LFG projects provide energy to over 2 
million homes and businesses. Both result in an energy resource that is 
sustainable, diverse, environmentally positive and local. The multitude 
of benefits provided by the use of MSW to generate energy is unique 
among renewables. WTE and LFG projects together have the potential to 
generate a significant portion of the nation's electricity as further 
technological innovations are developed and public appreciation of 
their benefits grows. SWANA continues to believe that federal policies 
should be adopted to encourage our nation to diversify energy 
production against risks of an uncertain future and to continue to 
develop supplements to fossil fuel generation. Providing tax incentives 
for WTE and LFG project development should clearly be part of such 
federal policies.
Landfill Gas to Energy Projects and the Section 29 Tax Credit
           Benefits of LFG Projects
    A medium sized landfill can generate more than 300 billion BTUs of 
methane gas a year, which, if converted to electricity, could annually 
provide 3.0 MWs of capacity, enough to serve the yearly electrical 
needs of 3000 households. Projects at larger landfills have generated 
as much as 50 MWs of electric power. Typically, LFG-to-electricity 
projects are located in urban areas allowing them to serve as 
distributed power sources to help improve the reliability of the 
region's power grid. The methane gas could also be used directly as a 
supplement to natural gas supplies. Existing ``direct-use'' LFG 
projects are providing the gas for commercial heating, as boiler fuel 
at industrial installations, as an alternative fuel for various vehicle 
fleets, and, recently, as a hydrogen source for fuel cells. Many of the 
``direct-use'' LFG projects are dispersed in the urban centers of our 
nation and provide a viable back up to local natural gas supplies.
    LFG projects provide society with several ``external benefits'' in 
addition to the domestic energy supply. Specifically, if not controlled 
and flared, LFG can pose a fire hazard, is odorous, impairs local air 
quality, and would add, for each ton of methane emitted, an equivalent 
of 21 tons of CO2 into the global atmosphere. Consequently, 
each of these impacts is eliminated when a LFG project is constructed 
and operated.
           Section 29 Tax Credit
    The tax credit for the production of nonconventional fuels for 
provided under Section 29 has been the key impetus for the solid waste 
management industry constructing and operating more than 300 LFG 
projects around the country. Under Section 29, taxpayers that produce 
certain qualifying fuels from nonconventional sources, including ``gas 
from biomass,'' are eligible for a tax credit until 2008 (or 2003 if 
the project was installed before 1993) equal to $3 per barrel or 
barrel-of-oil equivalent (adjusted for inflation) as long as the gas is 
sold as a fuel to an unrelated party. The tax credit provided the 
incentive to make LFG projects economically feasible. However, since 
June 30, 1998, the deadline under Section 29 by which LFG projects must 
be ``placed in service'' to qualify for the credit, no new LFG projects 
have been planned and constructed.
    For reasons unrelated to LFG projects, Congress to date has not 
extended the Section 29 tax credit. Unfortunately, without the 
continued availability of the Section 29 tax credit, private investors 
have been reluctant to undertake development of LFG projects at more 
than 700 additional landfills identified by the Environmental 
Protection Agency as producing sufficient volumes of LFG. Consequently, 
the nation faces the real loss of valuable domestic and renewable 
energy resource the recovery of which is simple, proven and has no 
negative impact on the environment.
The Section 45 Tax Credit
    Section 45 currently provides a 1.5 cents/kw-hr tax credit for 
electricity generated by wind, closed-loop biomass (organic material 
from a plant that is planted exclusively for purposes of being used to 
generate electricity) or poultry waste. The tax credit is provided for 
the first 10 years of production if such electricity is sold to an 
unrelated party. In response to Congress' unwillingness to extend the 
Section 29 tax credit, the landfill gas industry has targeted Section 
45 as a possible substitute.
    Ironically, several pieces of legislation were introduced during 
the 105th and 106th Sessions of Congress amending Section 45 to add 
additional renewable energy sources as qualified fuels that expressly 
excluded MSW and LFG. SWANA strongly believes that any recommendation 
to include tax credits for encouraging renewable energy development as 
part of our nation's energy policy should ensure that tax incentives 
are provided on a ``renewable source neutral'' basis. A free market 
government should not pick winners and losers among renewable energy 
sources. Accordingly, landfill gas and waste to energy projects should 
not be placed at a disadvantage in the energy policy.
    The ``renewable source neutral'' approach has been embraced by 
Senator Frank Murkowski in his recently introduced S 389, the National 
Energy Security Act of 2001. That bill, among its many other 
provisions, expands the list of qualified fuels under Section 45 and 
extends operative dates to include all renewable energy sources, 
including LFG and MSW. In an attempt to duplicate the incentive 
provided by Section 29, under S 389 both LFG-to-electricity projects 
and LFG ``direct gas use'' projects are qualified facilities. In the 
case of these latter type of projects where the gas is sold for direct 
use, the 1.5 cents/kw-hr tax credit is applied to the ``kilowatt-hour 
equivalents'' contained in the particular volume of gas calculated on a 
10,000 BTU per kilowatt-hour basis. The Energy Security Tax Incentive 
Act of 2001, S 596, introduced by Senator Jeff Bingaman, also expands 
the list of qualified fuels in Section 45 to include landfill gas and 
MSW.
    In the House, Congressman Dave Camp will soon introduce legislation 
to duplicate the Section 45 provision for LFG projects contained in 
Senator Murkowski's bill. That legislation is intended to compliment 
bills introduced by other House Members each of who would add a 
specific renewable energy resource as a qualified fuel under Section 
45. SWANA urges the the Subcommittee to act on these bills and to do so 
in a ``renewable source neutral'' manner.
Conclusion
    The Subcommittee has an opportunity to significantly impact the 
development of a new energy policy for the nation. Use of the tax code 
to encourage energy-related private investment is justified by the 
compelling energy security, economic and environmental concerns facing 
our nation currently and in the foreseeable future. Specifically, a tax 
incentive for energy production through the combustion of MSW or the 
utilization of LFG would allow the nation to not only benefit from 
increased domestic energy supplies, but to also realize the many 
consequent environmental and resource conservation benefits. SWANA 
urges the Subcommittee to support extension of the Section 29 tax 
credit for LFG projects or, in the alternative, to add LFG projects 
producing electricity and LFG projects providing the gas for direct use 
as qualified facilities for purposes of the Section 45 tax credit. In 
addition, SWANA urges the Subcommittee to support adding waste-to-
energy projects that combust MSW to generate electricity as qualified 
facilities under Section 45. I appreciate very much this opportunity to 
present SWANA's views.