[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
SUBCOMMITTEE ON SELECT REVENUE MEASURES
COMMITTEE ON WAYS AND MEANS
HOUSE OF REPRESENTATIVES
ONE HUNDRED SEVENTH CONGRESS
MAY 3, 2001
Serial No. 107-19
Printed for the use of the Committee on Ways and Means
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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
C O N T E N T S
Advisory of April 26, 2001, announcing the hearing............... 2
U.S. Department of the Treasury, Joseph Mikrut, Tax Legislative
U.S. Department of Energy, Mary J. Hutzler, Director, Office of
Integrated Analysis and Forecasting, Energy Information
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
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,
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:]
FROM THE COMMITTEE ON WAYS AND MEANS
SUBCOMMITTEE ON SELECT REVENUE MEASURES
CONTACT: (202) 226-5911
FOR IMMEDIATE RELEASE
April 26, 2001
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.
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
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.
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
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but will be maintained in the Committee files for review and use by the
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
2. Copies of whole documents submitted as exhibit material will not
be accepted for printing. Instead, exhibit material should be
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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
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4. A supplemental sheet must accompany each statement listing the
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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
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
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
The Committee is in 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
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
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
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
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
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
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
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
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
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.
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
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
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
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
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
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.
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
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
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
\1\ All price references are to the spot price at the Henry Hub and
are in nominal dollars.
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
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.
\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
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\
\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.
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,
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.
\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)).
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.
\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
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\
\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
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\
\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
\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).
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
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\
\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
\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.
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\
\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.
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
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.
\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.
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
\17\ In the case of an integrated oil company, the credit base
includes those IDCs which the taxpayer is required to capitalize.
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
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
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
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
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
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
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
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.
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\
\19\ Analytical Perspectives, Budget of the United States
Government, Fiscal Year 2002, U.S. Government Printing Office,
Washington, DC, 2001, p. 63.
Electric and clean-fuel vehicles and clean-fuel vehicle refueling
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.
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.
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\
\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.
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
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
Chairman McCrery. Do you know if Vice President Cheney's
task force is going to include any tax proposals in their
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
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,
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
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
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
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
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
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
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
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
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
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
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
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
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
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
Mr. Mikrut. In some proposals, yes. I mean, there were
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
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
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
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-
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
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
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
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
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
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
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
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
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
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
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.
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
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
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
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.
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
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.
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 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
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
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.
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.
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
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
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
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
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
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
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
But prior to the 1997 period, when the States did not have
program to push renewables, tax incentives didn't add much
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
[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
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
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
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.
Ms. Hutzler. Of course, those issues are certainly holding
back the development, or the building or construction of new
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,
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
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
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
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
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
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
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
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
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,
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
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
Thank you, Mr. Chairman.
Chairman McCrery. Thank you, Mr. Foley. Mr. Watkins.
Mr. Watkins. Thank you, Mr. Chairman, and Members of the
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
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-
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
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
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
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
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
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
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
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
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.
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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
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
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
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
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
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
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
\1\ A map showing the location of FPL Energy's Facilities is
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
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
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
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
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
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
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
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
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.
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.
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
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.
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
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
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
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
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
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
[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
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,
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
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
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
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
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
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.
[The prepared statement of Mr. Wallace follows:]
Statement of Dan Wallace, Owner, Columbus Oil Company, Seminole,
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
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
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
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
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
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
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
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
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
Mr. Wallace. I think my CPA runs the business, rather than
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
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.
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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.
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
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
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
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
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
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
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
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
Provide incentives for new energy technologies such as
distributed generation, combined heat and power, and natural gas
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
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
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
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
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
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
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
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
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
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
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
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
American MagLev Technologies, Inc. Long Island Power Authority
Amercian Public Power Association Massachusetts Division of Energy
Avestor (Hydro Quebec) Maxwell Energy Products
Atlantic Center for the Environment Mid-Del Lewis Eubanks AVTS
Ballard Power Systems National Rural Electric
Carolina EV Coalition New York State Technology
CEREVEH Nissan North America/Nissan R&D
Chattanooga Area Regional Northeast Sustainable Energy
Transportation Authority Association (NESEA)
City of Atlanta/Bureau of Motor PSA Peugeot-Citroen/USTR
City of Burbank Sacramento Municipal Utility
City of New York SAFT America, Inc.
Copper Development Association Salt River Project
Curtis Instruments Saminco
Dynasty Motorcar Corporation San Bernardino Associated
Ecostar Electric Drive Systems Solectria Corporation
Electricite de France Southern California Economic
Electric Vehicle Infrastructure Southern California Edison
Electric Vehicle Association of Southern Company/Georgia Power
Electric Vehicle Association of Great Technologies M4
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/
University of South Florida
US Department of Energy
York Technical College
Bold denotes EVAA Board member.
[An additional attachment is being retained in the Committee
Statement of Rupert J. Fraser, Chief Executive Officer, Fibrowatt LLC,
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.
[GRAPHIC] [TIFF OMITTED] T4221A.045
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
[GRAPHIC] [TIFF OMITTED] T4221A.046
[GRAPHIC] [TIFF OMITTED] T4221A.047
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.
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
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
local production of electricity,
reduction of carbon dioxide and other greenhouse
improvement of poultry biosecurity, and
support for rural communities.
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
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
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
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.
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.