[House Hearing, 107 Congress]
[From the U.S. Government Printing Office]
ENERGY SUPPLY AND PRICES
SUBCOMMITTEE ON OVERSIGHT
COMMITTEE ON WAYS AND MEANS
HOUSE OF REPRESENTATIVES
ONE HUNDRED SEVENTH CONGRESS
MARCH 5, 2000
MAYVILLE, NEW YORK
Serial No. 107-8
Printed for the use of the Committee on Ways and Means
U.S. GOVERNMENT PRINTING OFFICE
74-211 WASHINGTON : 2001
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 OVERSIGHT
AMO HOUGHTON, New York, Chairman
ROB PORTMAN, Ohio WILLIAM J. COYNE, Pennsylvania
JERRY WELLER, Illinois MICHAEL R. McNULTY, New York
KENNY C. HULSHOF, Missouri JOHN LEWIS, Georgia
SCOTT McINNIS, Colorado KAREN L. THURMAN, Florida
MARK FOLEY, Florida EARL POMEROY, North Dakota
SAM JOHNSON, Texas
JENNIFER DUNN, Washington
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
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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 February 14, 2001, announcing the hearing............ 2
U.S. Department of the Treasury, Joseph Mikrut, Tax Legislative
U.S. Department of Energy, John S. Cook, Director, Petroleum
Division, Office of Oil and Gas, Energy Information
Chautauqua County, NY, Frederick A. Larson....................... 3
Independent Oil and Gas Association, Dennis Holbrook............. 44
Lindsley, Moira L., Sinclairville, NY............................ 38
National Fuel Gas Distribution Corporation, Bruce D. Heine....... 47
Sosinski, Caroline, Westfield, NY................................ 41
Universal Resources Holdings, Inc., John J. Nalbone, Jr.......... 55
Western New York Regional Council of Carpenters, Jeff Aiken...... 42
SUBMISSIONS FOR THE RECORD
Accurate Prices Program, and Redefining Progress, Oakland, CA,
Mark Glickman, and Kim Rodgers, joint statement................ 63
American Petroleum Institute, statement.......................... 67
Anchor Glass Container, Elmira, NY, Michael Sopp, statement and
Brown, Helen D., Bath, NY, letter and attachment................. 75
California Independent Petroleum Association, Sacramento, CA,
David S. Hall, letter and attachments.......................... 76
Coyne, Hon. William J., a Representative in Congress from the
State of Pennsylvania.......................................... 79
Dominion, Jane Lew, WV, Ben Hardesty, statement.................. 80
Eaton, Patricia, Bath, NY, letter and attachment................. 81
Edison Electric Institute, statement............................. 82
Hall, Mildred C., Bath, NY, letter............................... 88
Independent Petroleum Association of America, and National
Stripper Well Association, John Swords, joint statement and
Lubrizol Corporation, Wickliffe, OH, statement................... 96
National Energy Marketers Association, Craig G. Goodman,
New York State Assembly, Hon. Catharine M. Young, Assemblywoman,
Slaughter, Hon. Louise M., a Representative in Congress from the
State of New York, statement................................... 104
ENERGY SUPPLY AND PRICES
MONDAY, MARCH 5, 2001
House of Representatives,
Committee on Ways and Means,
Subcommittee on Oversight,
Mayville, New York
The Committee met, pursuant to notice, at 12:16 p.m., at
the Chautauqua County Legislative Chamber, Gerace County Office
Building, Mayville, New York, Hon. Amo Houghton (Chairman of
the Subcommittee) presiding.
[The advisory announcing the hearing follows:]
ADVISORY FROM THE COMMITTEE ON WAYS AND MEANS
SUBCOMMITTEE ON OVERSIGHT
CONTACT: (202) 225-7601
FOR IMMEDIATE RELEASE
February 14, 2001
Houghton Announces Hearing on
Energy Supply and Prices
Congressman Amo Houghton (R-NY), Chairman, Subcommittee on
Oversight of the Committee on Ways and Means, today announced that the
Subcommittee will hold a hearing on the impact of Federal tax laws on
the cost and supply of energy The hearing will take place on Monday,
March 5, 2001, in the Chautauqua County Legislative Chamber, Gerace
County Office Building, 2 North Erie Street, Mayville, New York,
beginning at 12:00 noon.
In view of the limited time available to hear witnesses, oral
testimony at this hearing will be from invited witnesses only.
Witnesses will include representatives of the U.S. Department of the
Treasury and the U.S. Department of Energy, local energy producers and
suppliers, manufacturers, a representative of organized labor, and
individual 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 domestic
production of oil and gas, including: (1) expensing of exploration and
development costs, (2) a special depletion deduction, and (3) a tax
credit for enchanced oil recovery costs. The tax code also encourages
energy conservation by allowing taxpayers to exclude from income energy
conservation measures (e.g., longer lasting light bulbs, rebates for
buying more efficient furnaces) provided by a utility company to
In announcing the hearing, Chairman Houghton stated: ``We held
hearings on incentives for oil and gas production two years ago. Since
then, the price of crude oil has increased three-fold. The price of
natural gas has increased four-fold--in fact, it has increased over
seven-fold in some parts of the country. The price of home heating oil
has nearly doubled. We simply can't have American families choosing
between heating their homes and buying food and medicine. We have to
find out where the tax code helps, where it causes problems, and
whether it needs to be changed.''
FOCUS OF THE HEARING:
The hearing will focus on (1) the adequacy of current tax
incentives for production and conservation, (2) the causes of current
shortages and high prices, and (3) the impact of shortages and high
prices on individual consumers and business.
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, Monday,
March 19, 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,
other than invited witnesses, wish to have their statements distributed
to the press and interested public at the hearing, they may deliver 50
additional copies for this purpose to the Office of the Honorable Amo
Houghton, Federal Building, Room 122, Jamestown, New York 14701, by the
close of business, Friday, March 2, 2001.
Each statement presented for printing to the Committee by a
witness, any written statement or exhibit submitted for the printed
record or any written comments in response to a request for written
comments must conform to the guidelines listed below. Any statement or
exhibit not in compliance with these guidelines will not be printed,
but will be maintained in the Committee files for review and use by the
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
referenced and quoted or paraphrased. All exhibit material not meeting
these specifications will be maintained in the Committee files for
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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
Committee,must include on his statement or submission a list of all
clients, persons, or organizations on whose behalf the witness appears.
4. A supplemental sheet must accompany each statement listing the
name, company, address, telephone and fax numbers where the witness or
the designated representative may be reached. This supplemental sheet
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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 advisories 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
Mr. Larson. I am Fred Larson. I am the Chautauqua County
Attorney, and more significantly today, I am the Acting County
Executive. And on behalf of our County Executive, Mark Thomas,
who is in Washington today, and on behalf of the 140,000 people
of Chautauqua County, it is a distinct honor and privilege for
me to welcome Congressman Houghton, Congressman English, and
Congresswoman Thurman here to Chautauqua County, New York.
It is appropriate that you are here. On the one hand,
Chautauqua County is the largest gas and oil producer in the
State of New York, and on the other hand, we obviously have a
very long heating season here in Chautauqua County. We have all
been shocked by the sudden, dramatic and largely unexplained
increase in the cost of heating our homes and businesses this
winter. We wish you the best in formulating thoughtful public
policy that will foster both the efficient use of energy and
the increased exploration and production of energy.
So on behalf of Mark Thomas and the people of Chautauqua
County, welcome to Mayville and Chautauqua County, New York.
Chairman Houghton. Well, thank you, Fred, very much. I
really appreciate it, and give Mark our best. Mark is in
Washington. We are here. It just seems that something is wrong.
But Fred, we are delighted and thank you for your gracious
Ladies and gentlemen, let me just try to explain a few
things before we begin our hearing. I have got this great
gavel. I will pound it in a minute.
First of all, thanks so much for being here. It really
means a lot, because it means a lot to us, and it means a lot
to the people, not only here in Chautauqua County, but also in
the United States. But we are dealing with a really important
issue. The concept of the hearing is that we listen to people
who know something about this issue, and can give us
information with which we then can make better decisions.
We are Members of the Ways and Means Committee, and the
Ways and Means Committee is primarily involved in taxation
because 100 percent of the revenues and 60 percent of the cost
go through our particular Committee.
The work of Congress is done by committees, and many times
the work of committees is done by subcommittees. And, we are
the oversight Subcommittee here dealing with this particular
issue on energy. We had a meeting a couple of years ago. Since
then, obviously, energy prices have escalated, and there has
been a lot of hurt around this country.
So what we are trying to do is take our hearing process out
into the country, hear what other people have to say, not only
experts in the field of energy conservation or production, but
also people who, locally, are being affected by this energy
So that is the whole concept here. We cannot drill for oil.
We cannot do a lot of different things that you would expect us
to do, maybe such as Spencer Abraham in the Department of
Energy might be able to do, but we can take a look at the
overall issues and see where Congress, particularly through the
Ways and Means Committee, can play its part. So that is what we
are trying to do.
Let me just say, also, that there are pieces of testimony
up here. Anybody that would like to pick up one of them, they
can. Also, if you would like to put your name on a piece of
paper--I don't know where that piece of paper is, Mac. If you
would like to get copies of the testimony, which is being
produced here today, we would be glad to send it to you. We
want you to be involved in this process, despite the fact that
you really are observers here and the panels and the
individuals are the ones who are going to be doing the
testimony. So I just wanted to explain that.
We will try to keep this thing moving right along, and I
hope it will be of interest to you. So now here goes, the
The hearing will come to order, ladies and gentlemen, and I
would like to deliver a few brief remarks. Then I would like to
turn the microphone over to Karen Thurman and Phil English.
Before I make my remarks, let me introduce these two
individuals. Karen Thurman is a dear, wonderful friend. She and
I have done a lot of things together. She is not only
representing herself and her own feelings, but also Bill Coyne,
who is the Ranking Member of this Subcommittee and hurt his
shoulder and could not be here today.
Bill could not get here from Pittsburgh, but Karen got here
from Florida. So I think we ought to give you a special
And the person on my right is Phil English, who I am very
close to. We have been involved in a variety of different
issues. Phil and I consider ourselves some of the middle of the
roaders in the Republican Party and feel that we try to
represent the best interests of northeastern United States,
both in Pennsylvania and in New York. So, Phil, thank you very
much for coming up here from Erie.
Now, I want to thank so many people. Also, I would like to
thank Mac McKenney, who is the head of the--he was head of the
staff of the--on the Republican side on the Ways and Means
Committee for the Oversight Subcommittee, and also Beth Vance,
who represents the Democratic side. Beth and I worked together
for a long time, particularly when I was the minority member,
when Jake Pickle of Texas, who was the Congressman--famous
Congressman who took over for Lyndon Johnson. So we have had a
long, long history together. So I want to thank them very much.
You may be knowledgeable about this; I was not. That in
1821 in Fredonia, there was a man called William A. Hart, who
drilled a 27-foot-deep well in an effort to get a larger flow
of gas from the seepage of natural gas. That was the first
well, if I understand it, intentionally drilled to obtain
natural gas in thecountry, and it was right here. So, this is
really an appropriate place and an appropriate start for our hearing.
We are here, basically, because of the crisis. Oil and gas
prices are too high, too high for people who are having trouble
paying their heating bills, and also too high for many of the
businesses that provide jobs in our community. There obviously
is a shortage.
So, the new Bush administration has created an interagency
task force--that is a task force amongst the departments
reporting to the President--to look at the Nation's energy
problems. It is being chaired by Vice President Dick Cheney,
and he will make recommendations soon. I think it will be a
serious report for a variety of reasons, and not the least of
which is the fact that, as you know, Governor Bush comes from
an energy--not only consuming, but producing--State, which is
In the meantime, the three of us here who serve on the
taxwriting Committee, and we are here to learn more, as I
mentioned earlier before, about the problem. Our particular
assignment within the Congress is to write tax law. So we need
to look at where our tax laws are going, and whether they are
making matters worse or making matters better, or can be
improved or help solve the problem.
There was great concern in Washington 2 years ago on
incentives for oil and gas production, and we had a hearing at
that particular time. Since then, things have gotten worse. The
price of crude oil has increased threefold. The price of
natural gas has gone up four times. In fact, it has increased
over sevenfold in some parts of the country. And, the price of
home heating oil has nearly doubled.
So it seems to us that we just cannot go along here and
accept this. We have got to take a look at what we can do. So
the people in the government can be working together. We cannot
have American families choosing between heating their homes and
buying food and medicine.
Now, our first witness today will be a representative of
the Treasury Department. He is also an old friend of the Ways
and Means Committee, and Mr. Mikrut, we are delighted to have
Then we are going to hear from the Energy Department, and
then Assemblywoman Cathy Young, who I hope is here, who will
tell us about the important work that is under way in
After that, we will hear from a number of men and women who
live and work here in the southern tier and, of course, they
are our most important witnesses today.
So I want to again say, I encourage anyone who is not
testifying today, who would like to submit a statement for the
record, to do so. And just make sure it reaches my office by
the close of business on March 19th. We have got a little
wiggle room there, but basically, we have some sort of
discipline on the date. That may seem like an arbitrary
deadline, but we have got to get our record printed so we can
get it back to you.
So now what I would like to do is turn this over to
Congresswoman Thurman for an opening statement.
[The opening statement of Chairman Houghton follows:]
Opening Statement of the Hon. Amo Houghton, M.C., New York, and
Chairman, Subcommittee on Oversight
Good afternoon. I want to begin by thanking the men and women who
have taken time to participate in this hearing today. People watching
hearings on television may not realize that the government does not
reimburse private citizens for their time or expenses when they testify
before a congressional hearing. They appear on their own nickel, and I
I would also like to thank my colleagues for being here today.
Bill Coyne, from neighboring Pennsylvania, is beginning his fifth
year as the ranking Democrat on the Oversight Subcommittee. He is not
only a partner in the legislative process--he is a friend.
Karen Thurman came from farther away than anyone else to join us
today. She represents a district in central Florida. If you're
wondering why a Floridian is interested in these issues, keep in mind
that central Florida experiences both the hottest and the coldest
weather in the State.
Phil English joins us from Erie, which we think of as a suburb of
Mayville. He has served previously on the Oversight Subcommittee, and I
am delighted that he is with us today.
Before calling on our first witness, I wanted to mention that in
1821 in neighboring Fredonia, William A. Hart drilled a 27-foot-deep
well in an effort to get a larger flow of gas from a surface seepage of
natural gas. This was the first well intentionally drilled to obtain
natural gas in the country.
So, this is an auspicious setting for our hearing.
We're here today because oil and gas prices are too high--too high
for people who are having trouble paying their heating bills--and too
high for many of the businesses that provide jobs in our community--and
there is a shortage.
The new Bush Administration has created an inter-agency task force
to look at our nation's energy problems. It is chaired by Vice
President Dick Cheney and will make recommendations soon.
In the meantime, the four of us serve on the tax-writing committee.
We're here first to learn more about the problem. We cannot regulate
energy prices, nor open up new refineries.
Our particular assignment within the Congress is to write tax law,
so we need to look at whether our tax laws are (1) making matters worse
or (2) making matters better or (3) can be improved to help solve the
We held a hearing in Washington two years ago on incentives for oil
and gas production. Since then, the price of crude oil has increased
three-fold. The price of natural gas has increased four-fold--in fact,
it has increased over seven-fold in some parts of the country. The
price of home heating oil has nearly doubled. We simply can't have
American families choosing between heating their homes and buying food
Our first witness today will be a representative of the Treasury
Department. He is also an old friend of the Ways and Means Committee.
Then we will hear from the Energy Department.
Then Assemblywoman Cathy Young will tell us about the important
work that is underway in Albany.
Saving the best for last, we will hear from a number of men and
women who live and work here in the Southern Tier. They are our most
important witnesses today.
I would encourage anyone who is not testifying today but would like
to submit a statement for the record to please do so. Just make sure it
reaches my office by the close of business on March 19th. That may seem
like an arbitrary deadline, but we want to get the printed record into
Mrs. Thurman. Thank you, Mr. Chairman. I actually will be
reading what Mr. Coyne would have said had he been able to be
here, since he is the ranking member. He, like Mr. English,
have worked together over the years to address the concerns of
Pennsylvania, which is where Mr. Coyne is from as well.
So I am not Mr. Coyne, but will read his statement in its
entirety. I know he does send his regrets. I guess sometimes we
get hurt and sometimes that happens.
``I am pleased to be here today to discuss an issue of
critical importance to Americans nationwide. My constituents in
Pittsburgh, Pennsylvania, know firsthand the impact of rising
energy costs on their lives.
Experts and government policymakers say that the reasons
for higher natural gas prices are varied and complex. This
winter, we had colder-than-average temperatures. This followed
two mild winters, which saw a drop in the demand for natural
gas. As a result, the price producers could charge was lower.
Gas producers had less incentive to drill new wells and
supplies dropped. Then, when demand rose dramatically with our
current cold weather, prices rose as well.
Many of us are beginning to face 50 to 100 percent
increases in our monthly heating bills. Apparently, the utility
companies are paying twice as much for the gas they deliver and
passing the cost on to their customers.
As a short-term measure, I have cosponsored H.R. 683, the
Emergency Energy Response Act of 2001. This legislation will
help consumers cope with high energy costs through increased
funding for the Low-Income Home Energy Assistance Program and
State energy programs.
In the long term, however, it is necessary that the
Subcommittee consider the role that the Tax Code plays in
providing adequate incentives for fuel production and
conservation. Tax incentives are being considered to assist the
home purchase of energy-efficient furnaces, air
conditioners''--which is where Florida would really be
interested--``and appliances, and for energy conservation
measures, such as improved residential insulation and
weatherization. Also, tax incentives are being discussed to
make marginal wells more profitable and to encourage
appropriate oil and gas exploration.
I want to personally thank Chairman Houghton for scheduling
today's hearing on this most important topic. I hope we can
continue with additional hearings in Washington, D.C., and move
forward with legislative recommendations on a bipartisan
I submit his written statement for the record.
Chairman Houghton. Thank you very much, Karen. Mr. English,
would you like to make a statement?
Mr. English. Thank you, Mr. Chairman. Just briefly. I want
to thank you for bringing the Subcommittee to the North Coast
to hear about the high energy costs that our constituents are
facing, and to look at ways that the Tax Code can blunt the
impact of those problems.
We know that we are going to consider an energy bill this
year, and clearly the new administration is committed to
putting in place a national energy policy. Given that, it is
most timely that you have decided to have this hearing to focus
on the effectiveness of some of the incentives built into the
Tax Code, whether they are incentives for increased production
or incentives for energy conservation.
This is one of the most important issues that we will
grapple with in Congress this year, and I want to congratulate
you particularly for being proactive and allowing a North Coast
perspective to be entered into this national debate.
I have come here with an open mind, curious to find out
what our role as Ways and Means can be in crafting this energy
bill. So I am looking forward to the testimony. I appreciate
the fact that we have had people to come in from Washington as
well as Florida to participate in this hearing. I look forward
to the comments of the witnesses, and, again, I thank you for
allowing me as a Ways and Means Committee member who is a
visitor to this Subcommittee to participate today.
Chairman Houghton. Well, thank you, Phil, and thank you,
Karen, very, very much. Now, I would like to introduce Mr.
Joseph Mikrut, who is a Tax Legislative Counsel for the United
States Department of the Treasury.
Joe, it is great to have you here. Thanks for making the
effort to come up.
STATEMENT OF JOSEPH MIKRUT, TAX LEGISLATIVE COUNSEL, U.S.
DEPARTMENT OF THE TREASURY
Mr. Mikrut. Thank you, sir. Thank you, Mr. Chairman, Mr.
English, Mrs. Thurman.
I am pleased to be here today to discuss with you the
impact of current tax law on the cost and supply of energy,
particularly oil, natural gas, and alternative fuels. As a
Chicago native, I particularly enjoyed being in a part of the
country today where people actually know how to drive in the
snow. It is a rare treat.
Mr. Chairman, as you said in your opening remarks, what a
difference 2 years makes. Treasury last testified before this
Subcommittee in February, 1999, on energy policy. At that time
the cost of a barrel of oil was approaching single-digit
dollars, gasoline costs were routinely under a dollar a gallon,
and home heating oil and natural gas supplies were relatively
Mr. Cook, the representative of the Energy Information
Agency, will later describe in detail the dilemmas caused by
current energy prices. It is easy to see that the current
prices have created crises both for individual consumers as
well as businesses.
This underscores the fact that energy, particularly oil, is
an internationally traded commodity, and the U.S. Price is set
by world supply and demand. Domestic exploration and production
for oil is affected by the world price.Domestic oil production
has been declining since the mid-1980s. From the late 1970s, to the
mid-1980s, oil consumption in the U.S. has also declined, but in the
last decade oil consumption has risen by 11 percent. The decline in oil
production and the increase in consumption has led to an increase in
oil imports. Net crude oil imports have risen from approximately 41
percent of consumption in 1988 to 55 percent in 1999.
The U.S. has large natural gas reserves and was,
essentially, self-sufficient in natural gas until the late
1980s. Since 1986, however, natural gas consumption has
increased by more than 30 percent, while production has
increased by only 17 percent. As a result, net imports as a
share of consumption more than tripled from 1986 to 1999,
rising from 4.2 percent to almost 16 percent.
The increases in energy prices over the past 2 years have
focused attention on the impact of shortages and higher prices
on individual consumers and businesses, and on the tax
treatment of oil and gas producers.
Mr. Chairman, in your statement announcing this hearing,
you have said, rightly, we have to find out where the Tax Code
helps, where it causes problems, and where it needs to be
Policymakers have long recognized the importance of
maintaining a strong domestic energy industry. To that end, the
Internal Revenue Code includes a variety of measures to
stimulate domestic exploration and production. The tax
incentives contained in present law address the drop in
domestic exploration that has occurred since the mid-1950s, and
the continuing loss of production from mature fields and
marginal properties. Current tax incentives are generally
justified on the grounds that they reduce U.S. vulnerability to
an oil supply disruption by stimulating increased exploration
and production in oil and gas and development of alternative
forms of energy.
Incentives for oil and gas production in the form of tax
expenditures are estimated to total almost $10 billion for
fiscal years 2002 through 2006. Over 40 percent of these
expenditures, or $4.4 billion, are represented by the enhanced
oil recovery credit. This is a 15 percent credit for costs
associated with qualifying tertiary recovery methods. These
methods generally involve injecting substances into an oil
reserve to increase production that would otherwise not occur.
The credit phases out at higher oil prices, but under current
prices is fully effective.
The next largest expenditures are for the nonconventional
fuel production credit, the section 29 credit, and the
percentage depletion deduction. The section 29 credit is
approximately $6 per barrel of oil equivalent for oil produced
from shale and tar sands, gas produced from geopressurized
brine, Devonian shale, coal seams, and biomass, fuel produced
from coal. There is a $3 credit for gas produced from tight
These credits are supplied so that oil and gas reserves
that would otherwise not be put into production are put in
production by way of a credit.
Percentage depletion allows independent producers to deduct
a percentage of their oil and gas revenue, even if the total
deductions for depletion have exceeded the cost of the revenue.
It is, in essence, a reduction of the applicable tax rate. In
most cases, the deduction is 15 percent of revenue, but
marginal wells; that is, those wells that produce less than 15
barrels a day or produce heavy oil, can qualify for a higher
rate up to 25 percent. This higher 25 percent rate, phases out
when oil prices fall below $20 a barrel.
Oil and gas producers are also allowed to expense their
intangible drilling and development costs, or IDCs. In general,
these are the costs associated with drilling and preparing
wells for the production of oil and gas, and normally would
have to be capitalized and recovered over time absent a special
In the case of independent producers, a 100 percent
deduction is allowed. Integrated major oil companies may deduct
70 percent of these expenditures up front and amortize the
remaining costs over a 5-year period. This tax expenditure is
estimated to cost $640 million over the 5-year period.
In addition, working interests in oil and gas production
are largely exempt from the passive loss limitations of present
law, and oil and gas activities have been largely eliminated
from the alternative minimum tax by amendments made in the
Energy Policy Act of 1992.
Incentives for energy efficiency and alternative energy
sources are also essential elements of our national energy
policy. The continuing strength of our economy over the past 2
years, despite oil price rises, underscores the dramatic
improvements in energy efficiency we have achieved in the past
quarter century. While the past oil shortages have taken
significant toll on the U.S. economy, the recent increases in
oil prices have not affected the economy to the same degree.
Increased energy efficiency in cars, homes, and
manufacturing have helped insulate the economy from the short-
term market fluctuations. For instance, in 1974, we consumed 15
barrels of oil for every $10,000 of gross domestic product.
Because of increased efficiency, today we only consume about 8
barrels of oil for the same amount of economic activity.
Tax incentives currently provide an important element of
support for these energy efficiency improvements and the
increased use of renewable and alternative forms of energy.
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 of fuel vehicles, credits for the production of
electricity produced from wind or biomass and for certain solar
energy property, and an exclusion from gross income for certain
energy conservation measures provided by public utilities to
The administration's fiscal budget for the year 2002 will
include additional tax incentives for renewable energy
resources. The proposal will extend the credit for electricity
produced from wind and biomass and expand eligible biomass
sources. The proposal will also provide a new 15 percent tax
credit for residential solar energy property, up to a maximum
credit of $2,000.
We are currently developing the details and the revenue
estimates for these proposals and will provide to Congress more
details when the administration presents its budget later this
Mr. Chairman, this concludes my brief remarks. I ask that
my entire statement be submitted for the record, and I would be
happy to answer any questions that you and the other Members of
the Subcommittee may have.
[The prepared statement of Mr. Mikrut follows:]
Statement of Joseph Mikrut, Tax Legislative Counsel, U.S. Department of
Mr. Chairman, Mr. Coyne, and Members of the Subcommittee:
I appreciate the opportunity to discuss with you today the current
tax incentives for the domestic production of oil and gas and for
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 prices
ranged from $14.91 to $23.59 in real 1992 dollars. In 1998, however,
oil prices at 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 $17.46 per barrel in
1999 and $30.92 per barrel in November 2000, the latest month for which
composite figures are available. The equivalent prices in 1992 dollars
are $15.31 per barrel in 1999 and $26.56 per barrel in November 2000.
Domestic oil production has been on the decline since the mid-
1980's. From 1978 to 1983 oil consumption in the United States also
declined, but increasing consumption since 1983 has more than erased
this decline. In 2000, domestic oil consumption was 15 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 51 percent in 1999.
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 has recently exceeded $10.00 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 more than tripled from 1986 to 1999, rising from
4.2 percent to 15.4 percent. Natural gas from Canada makes up nearly
all of the imports into the United States.
These increases in energy prices over the past two years have
focused attention on the impact of shortages and high prices on
individual consumers and businesses. In announcing this hearing, the
Chairman noted the three-fold increase in crude oil prices, the four-
to seven-fold increase in natural gas prices, and the near doubling of
the price of home heating oil. He also said we ``have to find out where
the tax code helps, where it causes problems, and whether it needs to
be changed.'' To assist the Subcommittee in this effort, I would now
like to discuss the current tax incentives for domestic oil and gas
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, and exploration and production capacity. The tax incentives
contained in present law address the drop in domestic exploratory
drilling that has occurred since the mid-1950s and the continuing loss
of production from mature fields and marginal properties.
Incentives for oil and gas production in the form of tax
expenditures are estimated to total $9.8 billion for fiscal years 2002
through 2006.\2\ They include the nonconventional fuels (i.e., oil
produced from shale and tar sands, gas produced from geopressured
brine, Devonian shale, coal seams, tight formations, or biomass, and
synthetic fuel produced from coal) production credit ($2.4 billion),
the enhanced oil recovery credit ($4.4 billion), the allowance of
percentage depletion for independent producers and royalty owners,
including increased percentage depletion for stripper wells ($2.3
billion), the exception from the passive loss limitation for working
interests in oil and gas properties ($100 million), and the expensing
of intangible drilling and development costs ($640 million). In
addition to those tax expenditures, oil and gas activities have largely
been eliminated from the alternative minimum tax. These provisions are
described in detail below.
\2\ Estimates prepared by the Office of Tax Analysis, Department of
the Treasury, for inclusion in Analytical Perspectives, Budget of the
United States Government, Fiscal Year 2002, U.S. Government Printing
Office, Washington, DC (publication expected in March 2001). 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 December
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 though 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 1999 taxable year was
2.0013. Therefore, the inflation-adjusted amount of the credit for that
year was $6.00 per barrel or barrel equivalent.
\15\ For 1999, the inflation adjusted threshold for onset of the
phaseout was $47.03 ($23.50 x 2.0013) and the average wellhead price
for that year was $15.56.
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.
This provision provides a significant tax incentive (currently
about $6 per barrel of oil equivalent or $1 per thousand cubic feet of
natural gas), over one quarter of the average wellhead price of gas in
2000. 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 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 and uneconomic at
current world oil prices. 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 IDCs 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.
IDCs related to oil and gas wells are generally not taken into
account in computing the excess IDCpreference 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. Individuals and
businesses do 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 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 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 technologies.
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 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 produced 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\ Estimates prepared by the Office of Tax Analysis, Department
of the Treasury, for inclusion in Analytical Perspectives, Budget of
the United States Government, Fiscal Year 2002, U.S. Government
Printing Office, Washington, DC (publication expected in March 2001).
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-
fuelvehicle 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 third party 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 will
include tax incentives for renewable energy resources. The proposals
would extend the credit for electricity produced from wind and biomass
and expand eligible biomass sources. The proposals also would provide a
new 15-percent tax credit for residential solar energy property, up to
a maximum credit of $2,000. We are developing the details of these
proposals and will provide a complete description when the
Administration presents its budget to Congress later this month.
Mr. Chairman, this concludes my prepared testimony. I will be
pleased to answer any questions you or other members of the
Subcommittee may have.
(British thermal unit) content of 5.8 million.
Chairman Houghton. Well, thanks very much, Mr. Mikrut. I
have just got a brief question. It is sort of a generic
question, and then I will turn it over to Mr. English and Mrs.
The problem I see is that one of the reasons we do not have
more energy available is because the prices have been so low.
Two years ago, it was something like $10 a barrel. I don't know
what it is now--if it is at $30.
So, you say to yourself, okay, so you give tax incentives
to producers and the price is higher. Therefore, they can
afford to invest. And that is good. But at the same time, what
it does, it bumps up the price to the individuals and the users
of this. So I see an almost incompatible scenario here. So that
is the question number one.
The other question is, if we took all your incentives, we
took all of the things that you were doing and put them
together, would it make a major dent in the energy crisis which
we face today?
Mr. Mikrut. Those are two very good questions, Mr.
Chairman. I wish I had two very good answers.
As my testimony points out, the price of oil is set on a
world market. So, there is very little one could do
domestically to affect that market. Any increased production in
the United States can be offset by decreased production
elsewhere in the world. Alternatively, should OPEC decide to
increase production and drive prices even further down, that
could discourage the production of U.S. Reserves.
As a result, what we saw 2 years ago when we testified
before you at a time of very low energy prices was a request by
domestic oil producers to have some sort of a floor or stopgap
measure, such that if they knew that should oil prices fall
below a certain floor, then credits would kick in to encourage
The rationale was that with respect to certain properties,
particularly marginal wells, that once prices drop and it
becomes too expensive to operate that well, then the producer
shuts down the well. That represents an almost permanent loss
of production, in that it may be very difficult, if not
impossible, to restart an oil well that has been capped or very
expensive to do so.
Your question points out the tension here. You want to
ensure a certain level of domestic production, and that is what
our current code attempts. It tries to provide an incentive for
current production, and yet you want to somehow ensure that
those benefits flow through to consumers so that oil producers
themselves are not the only ones benefited by the incentives,
and that is the part that is difficult to do.
And, again, as you mentioned, Vice President Cheney has a
task force that is developing a comprehensive energy policy
strategy for the United States, and it is in light of those
forthcoming recommendations that I think you will have to
reexamine the tax provisions.
This may not be a very satisfying answer to your original
questions, but again it is one that the tax policy writers have
been wrestling with for a long time along with the energy
Chairman Houghton. Okay. Thanks. Mrs. Thurman.
Mrs. Thurman. A lot of what you talked about was things
that are already happening today. And based on your answers to
the chairman, are you involved in putting together this policy
that the Vice President is working on? As far as from the tax
writing part of it and the implementation of what is going on
with the White House and with Treasury, are you all
communicating? And if so, what kinds of things are you offering
to an energy policy that you believe, if implemented, would
help this situation?
Mr. Mikrut. Mrs. Thurman, again, this is an interagency
task force. Treasury is and will be involved. I am not at
liberty to discuss the specific details at this time. I can
tell you what has already been decided, what will be in the
President's budget proposal with respect to energy incentives.
There would be a new 15 percent investment tax credit for
residential solar energy systems. Under current law, as you
know, businesses have a 10 percent solar credit and this credit
is proposed to be expanded for residential purposes.
There will be a proposal extension of the 1.5 percent per
kilowatt hour tax credit for the production of electricity from
wind and biomass, and a proposed expansion of the sources of
biomass. Under present law, the biomass that qualifies for the
credit only can be what is called ``closed loop biomass,''
which are crops grown and dedicated solely for burning. There
is going to be an expansion of the eligible biomass sources.
Mrs. Thurman. Like potentially hydrogen and some other
Mr. Mikrut. Potentially.
I think some of the expansions that have been mentioned in
the past have been mixing biomass sources with coal generation,
the use of wood chips and other waste wood products, items that
can be burned, which would otherwise go to waste, but now could
be burned and generate electricity.
Mrs. Thurman. And for folks out here, the issue involves a
fight that is kind of going on between coal producing States
and those who use coal, dealing with Tax Code section 29. I
have written a letter to Treasury Secretary Summers, and I feel
compelled to bring it up now, is any conversation going on
concerning section 29 that specifically looks at whether coal
dust can be reused for section 29 purposes in our area, like
some of our electric companies are doing? Do you see any help
coming from Treasury on this at all?
Mr. Mikrut. Certainly, Mrs. Thurman. And for a little
background for the members of the audience who are not as
familiar with the section 29 credit as you are: section 29
allows a credit, which is essentially equivalent to, I think,
$25 a ton for coal, for the production of synthetic fuels from
As you mentioned, in the past synthetic fuel producers have
used coal fines, which are waste coal products that otherwise
would be thrown out or thrown into settlement ponds, and
created an environmental hazard, in essence. And what producers
were able to do by way of the credit was to dredge out the coal
fines, reconstitute them, generally with an oil/petroleum based
product, to make a briquette, which can then be burned, and
generally for electricity generation. And the Service has ruled
favorably in a lot of those cases.
We have heard through Members of Congress, Governors of
States, and some of our trading partners, that certain
producers have taken steps away from a coal fine process where
they may be using run-of-the-mine coal, mixing it with oil, and
claiming the credit. We were asked to study this issue further.
So in late October, we announced that the IRS would not be
issuing any private letter rulings in this area, except for
those involving the use of coal fines, and that we would study
the issue. We asked for public comments. The comment period
ended right around Thanksgiving. Several groups have asked to
come in and speak to us further on this matter. All of this is
a matter of the public record. And what we hope to do is study
all the comments we have received and then develop a ruling
policy as to exactly what kind of coal production qualifies for
the section 29 credit and release that in the short term.
Mrs. Thurman. This is the last question, and then back to
the tax issues. I know that Mr. Matsui and I and some others
actually produced a piece of legislation last year on
alternative energy sources. Do you know if the proposals in the
bill are going to be a part of the dialogue that is going on
with the administration right now?
Mr. Mikrut. Yes, I believe----
Mrs. Thurman. I am not asking you to tell me exactly the
final answer. I just kind of want to know if a piece of this
bill is going forward.
Mr. Mikrut. Again, Mrs. Thurman, I think you have to see
how all the pieces fit together. What the administration is
trying to develop is a comprehensive energy policy, and I think
the tax portion will be one of the last pieces considered. You
may want to see exactly what proposals will be set forth with
respect to the Department of Energy, and some of the other
departments that are more directly involved in energy policy,
and then, just as the chairman is doing today, see how tax law
either inhibits or encourages those policies.
Chairman Houghton. Okay. Mr. English.
Mr. English. Thank you, Mr. Chairman. Mr. Mikrut, building
on that line of questioning, I was wondering, has Treasury
conducted any detailed studies of the efficiency, in general,
of tax incentives for production? And you understand what I
mean by efficiency. Does the tax policy provide the incentive
necessary for changes in production on the margin, necessary to
increase production? Are these tax policies efficient from a
tax standpoint or not?
Mr. Mikrut. We do that all the time, Mr. English. As you
know, many of the tax incentives in the Internal Revenue Code
are what are known as the ``expiring provisions.''
Mr. English. Right.
Mr. Mikrut. Like the section 29 credit, the percentage
limitation on percentage depletion, and some of the others. So
they expire from time to time and therefore the Congress and
the administration have to revisit those policies. Together we
have to make the determination on whether the policy is
following through on what it was intended to do.
Most of the policies, especially with respect to the tax
credits, are trying to provide an incentive for activity that
would otherwise not occur. In studying the section 29 credit,
as we have recently, what we have found is that there has been
a lot of research and development done with respect to the
production of coal into synthetic fuel that probably otherwise
would not have taken place without the credit.
And this research has given rise to benefits such as lower
ash content from burning, which is very important to
electricity generation as well as to the steel industry. There
is less coal dust, which is an environmental and a safety
hazard in factories. We have also seen that there may be less
pollution with some of these processes.
These are some of the things that we have found have
happened. The difficulty, though, and what faces policymakers
all the time, is how do you quantify those benefits versus how
you quantify from what you are giving on the tax side? And that
is the analysis that Congress and the administration follow up
on all the time in deciding whether or not to extend these
Mr. English. Particularly on that point, the part that we
are focusing on today, or one of the things we are focusing on
today, is the production. Is it Treasury's finding that tax
incentives have significantly increased production in the
context of an energy situation where, until recently, prices
were coming down? So the incentives coming from the marketplace
were not to expand production?
Mr. Mikrut. I think you have hit the nail on the head, Mr.
English. The thing that creates the greatest incentive for
production is price. Clearly, if someone knows that the
commodity is going to sell at a high price, they are going to
want to produce.
One of the problems in providing tax incentives, or
incentives for production through the Internal Revenue Code is
that generally producers do not pay very much tax when prices
fall. So it is very hard to give them a tax benefit. For
instance, when the Treasury last testified before the
Subcommittee on this matter, it found that in a period of, I
believe, relatively moderate prices, 75 percent or more of the
firms engaged in oil and gas production did not pay any income
tax because of the cost they had versus what they were
generating in revenues.So it is hard to give an industry that
pays little tax incentives through the Tax Code. You probably have to
do it elsewhere, and that is why the administration currently is trying
to develop a more comprehensive approach to energy policy to ensure
continued domestic policy.
Mr. English. That is a good point. If I might do a follow-
up question, Mr. Chairman.
Chairman Houghton. Yes.
Mr. English. This is particularly a useful point, because
the income from this particular industry has varied
considerably. You need to have significant income and revenue
in order to make full use of these tax credits.
On the other side, the tax breaks for conservation tend to
extend, in a sense, more broadly across the economy. Has
Treasury studied the relative efficiency of those tax breaks
Mr. Mikrut. Not in as great a detail, Mr. English. It is
much easier to gather data on a specific industry, which we
have for the oil and gas producing industry, or the coal
industry, or for industries involved in energy production or
distribution. The conservation measures are, as you said, much
broader and are of a more recent vintage. So it is much harder
to study those effects.
I do know, for instance, that the current law exclusion for
conservation measures that utilities to their customers, at one
time applied to both businesses and individuals. And the
Congress and the administration together decided, I believe in
1996, to repeal the exclusion that applied to businesses
because it was not as viewed as efficient as the provision that
applied solely to individuals.
So, again, this was an instance where current law was being
reevaluated on an ongoing basis and a policy decision was made.
Mr. English. If I could, Mr. Chairman, and thank you for
your tolerance, I have two other very quick questions. The
first being, you had raised, Mr. Mikrut, the fact that some of
these provisions are expiring provisions that were revived on
an annual basis. Has Treasury studied whether the incentive
effects of these provisions have been reduced because these are
temporary tax provisions?
Mr. Mikrut. In general.
Mr. English. And would making them permanent improve their
Mr. Mikrut. In general, Mr. English, what we try to do, and
what Congress has tried to do in designing these provisions, is
to say that they apply for a relatively extended period of
time. For instance, the extension of the section 29 credit
applied to property placed in service in 1998, and for 10
years. So that gave those producers trying to make that
investment decision a fairly wide window in order to make the
investment and be sure that the credit would be there for 10
I think, then, at the end of the 10-year period, it is
appropriate for Congress to say, well, you had a credit for 10
years. What have you done? What benefits have we seen and has
this industry stabilized to such an extent that it can go
forward without the credit?
So, with respect to the energy provisions, the credits have
been relatively long-lasting to give producers a sufficient
lead time to make their investment decisions. With respect to
some of the other credits that have been extended on an annual
basis; for instance, the research and the experimentation
credit mentioned before, taxpayers come to expect those to be
enacted on an ongoing basis, so that incentive effect may be
somewhat diluted. But, again, with respect to the energy
provisions, I think Congress has wisely given the producers a
long enough credit period so they can make those investments.
Mr. English. Thank you, Mr. Chairman.
Mrs. Thurman. I think Mr. English is exactly on target on
those issues. I found that continued incentives are important
to production, particularly the incentive for research and
development. The wind energy tax credit actually expired for
about 6 or 8 months before it was put into effect again. And so
we are finding that some of these energy sources have not been
able to fully develop because of the unavailability of
So as a kind of follow-up, have you looked at the impact of
having the research and development expire?
Mr. Mikrut. Again, not to the extent that we have on the
cost items, Mrs. Thurman. But when we looked at the section 29
credit, we heard about research capabilities. It also is an
issue that we have been exploring on an ongoing basis with
respect to the production of electric vehicles and clean fuel
technologies for automobiles.
As you know, as the years go on, we gather more and more
information on how credits and other tax incentives could be
more targeted to invigorate the next technology, as opposed to
giving tax benefits for the last technology, which is activity
that will be happening anyway. So those discussions have been
ongoing with industry and Treasury, yes.
Mrs. Thurman. Thank you.
Chairman Houghton. Well, thank you very much. I certainly
appreciate you being here.
Ladies and gentlemen, let me just explain, the key
relationship which the Ways and Means Committee has with the
administration is through the Treasury Department. We will be
talking to somebody from the Department of Energy. We can talk
to somebody from the Department of Justice or whatever the
issue is, but this is the key.
So you can see the issue that we are wrestling with here.
So, Mr. Mikrut, thank you very much for being here. You are a
great asset and a great citizen and a great American.
Mr. Mikrut. Thank you, Mr. Chairman. It has been a pleasure
to be here.
Chairman Houghton. Okay. Thank you. What I would like to do
is call John Cook. Mr. Cook is--is Mr. Cook here?
Mr. McCoy. Yes, he is here.
Chairman Houghton. Okay. Great, Mr. Cook is the Director of
the Petroleum Division of the Office of Oil and Gas, Energy
Information Administration in the U.S. Department of Energy.
So, Mr. Cook, we are delighted to have you here and you can
proceed with your testimony and can submit any other pieces of
information that you want outside your oral testimony.
Mr. Cook. Thank you, Mr. Chairman.
Chairman Houghton. You want to turn your microphone on?
Mr. Cook. Is that it?
Chairman Houghton. Yes.
STATEMENT OF JOHN S. COOK, DIRECTOR, PETROLEUM DIVISION, OFFICE
OF OIL AND GAS, ENERGY INFORMATION ADMINISTRATION, U.S.
DEPARTMENT OF ENERGY
Mr. Cook. Again, thank you, Mr. Chairman. I apologize for
being a bit tardy. My only excuse, a weak excuse, is that
United canceled both of its early flights this morning. That,
and some rental car problem. Do not ask me any other questions.
Anyway, I would like to thank the Committee for the
opportunity to testify today on behalf of the Energy
Information Administration. I will begin with an overview of
recent crude oil and natural gas trends and some of the factors
underlying those trends. I will then address our near-term
A combination of factors contributed to the sharp increases
in both oil and gas prices experienced in the past year or so.
On the demand side, strong economic growth through the first
half of last year lead to increased oil and gas consumption.
Additionally, the winter started out very cold, unlike the
previous three or four winters, which were much warmer than
normal. November and December were very cold in certain parts
of the country, requiring significantly more energy for home
heating than in recent winters.
On the other hand, supplies of both oil and natural gas in
2000 did not keep pace with demand growth, especially given the
need to rebound from low inventory levels. This left the market
situation ripe for higher prices. For natural gas, strong
demands in the residential sector combined with continued
growth in gas fired power generation occurred at the same time
that production stagnated.
Low oil and natural gas prices in 1998 and early 1999
sharply curtailed drilling and discouraged vigorous exploration
and development of natural gas. As a result, gas production
actually declined in 1998 and 1999 before rising by a modest 1
percent in 2000. With demand outpacing supply, natural gas
inventories dropped to low levels. For oil, supply been the
most significant factor. Although the cold winter, robust
economy, and some fuel switching from natural gas to oil, has
an impact on oil demand, it was action taken by OPEC that has
greatly elevated oil prices since early 1999.
OPEC dramatically reduced crude production in 1998 and
again early in 1999, so that even after the four increases seen
last year, inventories remained at extremely low levels. Scarce
crude supplies encourage high near-term prices relative to
those several months out. This situation is referred to as
backwardation, and it discourages maximum refinery production
and inventory holding. With low crude and product inventory,
there is little flexibility to adjust to market conditions, and
the stage is set for price volatility.
I would like to turn next to our short-term forecast,
beginning with crude oil. On January the 17th, OPEC reduced its
production quotas by approximately a million and a half barrels
a day effective at the beginning of last month. This decision
by OPEC is expected to maintain a tight balance between global
supply and demand, resulting in continued low inventory
worldwide, especially in the developed countries of the OECD.
You can see this in figure 2 in my testimony.
Given low stock, the EIA expects the price of OPEC's basket
of crude oils to remain toward the high end of the OPEC target
range of $22 to $28 a barrel at least for the remainder of this
year. You can see that in figure 1.
Given its higher quality, West Texas Intermediate, which is
the U.S. Benchmark crude oil, tends to run about $3 to $4 a
barrel higher than the OPEC price basket. This puts our
forecast for the remainder of this year for WTI at about $30
again this year, before easing several dollars by mid next
If we look at gasoline next, with crude oil prices
rebounding from their December 2000 lows, and with gasoline
stocks currently low and expected to be low ahead of the
summer, we look for gasoline prices to rise from the current
levels by at least a dime. And this is assuming that we see no
further disruptions this summer like those seen in California
and the Midwest last year. In other words, with low inventories
and everything flowing smoothly, we will see prices average
this summer about the same $1.50 that they did nationwide last
On the other hand, with low inventories, the stage is again
set for regional supply problems that could bring about price
spikes. The prospect of these regional problems is increased by
the differing regional gasoline product requirements, which
arise from Federal and State air quality programs which limit
the distribution system's flexibility.
Regional problems can also arise from temporary or
permanent losses in refining capacity and pipeline disruption.
Nevertheless, it is expected with a year's experience behind
them the refining industry's ability to make the new phase 2
reformulated gasoline, required for the first time last summer,
should be somewhat enhanced.
Turning to distillate fuel, with the heating season nearing
its end, it is likely that retail prices have peaked. Because
of relatively warm weather in the Northeast during the last
half of January and for stretches in February, coupled with
high distillate imports and high refinery production,
inventories did not decline in January and February like they
normally do. This means that for heating oil anyway, stocks
have now returned to their normal range.
Nevertheless, while retail heating oil prices have declined
some accordingly, they still remain relatively high on a
historical basis. Thus the average bill for the consumer
heating with oil in the Northeast this winter is expected to be
nearly $1,000, compared to $760 last winter and under $600 the
previous two winters.
Although consumers have not faced the price spike they saw
last winter, consumption is expected to be over 11 percent
higher due to colder weather and high natural gas prices,
sparking fuel switching. High consumption levels, lower initial
stock levels, and high crude prices have combined to push the
average price of heating oil up 18 percent this winter.
Together, these increases in consumption and price are expected
to raise the winter bill by over 31 percent.
Looking at natural gas, spot prices last summer averaged
more than $4 per thousand cubic feet during the normally low-
priced season. They remained above $5 per thousand cubic feet
last fall, and more than double the average the year earlier.
We see this in figure 3.
In January of 2001, the spot price averaged a record $9 per
thousand cubic feet as noted earlier. Such high prices are due
largely to demand out stripping domestic production, causing
very low volumes to be injected into storage as happened last
winter, figure 4.Looking ahead and assuming normal weather, we
project continued low storage, resulting in an average annual wellhead
price this year of about $5, an increase of well over $1.50 from last
year's already high average. On the positive side and in response to
these higher prices, drilling for natural gas in the 48 States
increased over 45 percent last year, and therefore we expect some
moderate growth in production to continue this year and next. See
Thus, by the summer of 2002, we expect storage to return to
the low end of the normal range. This should drive wellhead
prices back down under $5.
Finally, increased consumption and higher prices this
winter are expected to yield heating bills for homes using
natural gas in the Midwest, which is the region most dependent
on gas for heating also, of approximately $1,000. This
represents something like a 75 percent increase from last
winter. This sharp increase in prices has had particularly
severe impact on low-income consumers using gas to heat.
In recent months, 5 million consumers have applied for
Federal and State government assistance to pay their heating
bills, which is an increase of over 1 million from last year. A
short description of our forecast for electricity is included
in my written testimony. This concludes my remarks, and I will
be happy to answer any questions.
[The prepared statement of Mr. Cook follows:]
Statement of John S. Cook, Director, Petroleum Division, Office of Oil
and Gas, Energy Information Administration, U.S. Department of Energy
Mr. Chairman and Members of the Committee:
I appreciate the opportunity to appear before you today to discuss
the near-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
EIA produces both short-term and long-term energy projections. The
projections through 2002 in this testimony are from the Short-Term
Energy Outlook February 2001 (STEO). Each month, EIA updates its Short-
Term Energy Outlook, which contains quarterly projections through the
next 2 calendar years, taking into account the latest developments in
energy markets. The Annual Energy Outlook provides projections and
analysis of domestic energy consumption, supply, and prices through
2020. 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 and subject to many random events that
cannot be foreseen, such as weather, political disruptions, strikes,
and technological breakthroughs. In addition, long-term trends in
technology development, demographics, economic growth, and energy
resources may evolve along a different path than assumed in the Annual
Energy Outlook. Many of these uncertainties are explored through
The Outlook to 2002
Energy markets in the United States today are characterized by high
nominal prices for both petroleum and natural gas, due in large part to
a tight balance between supply and demand for both fuels. Reductions in
oil production by OPEC and weak production growth from several non-OPEC
petroleum-exporting nations have contributed to low oil stocks. It
should be noted, however, that current oil prices of around $30 per
barrel are far from the inflation-adjusted $70-per-barrel historical
high seen in 1981. It would seem then that rapid price changes may
impact consumers more initially than such absolute levels since
individuals and organizations generally budget and plan for small
changes from recent history.
Crude Oil. At its January 17 meeting, OPEC members agreed to reduce
production quotas effective February 1, 2001. This decision by OPEC 10
(OPEC, excluding Iraq) is expected to maintain the average U.S.
imported crude oil price within and toward the high end of OPEC's
target range of $22 to $28 per barrel in 2001 and 2002 (Figure 1).
Average imported prices may fall slightly from the estimated value of
$27.70 per barrel in 2000 to between $26 and $27 during the 2001 to
2002 period. These prices, as well as all other prices mentioned in
this testimony, will be in nominal dollars. EIA expects that oil stocks
in the OECD countries will continue to remain lower than normal,
preventing prices from falling significantly (Figure 2). Some OPEC
members have suggested that further cuts will be needed to maintain
world oil supply in balance with demand. Any additional quota
reductions will be discussed at the next OPEC ministerial meeting which
will be held on March 16, 2001.
Motor Gasoline. The average monthly retail price for regular
unleaded motor gasoline fell 11 cents per gallon from September to
December. However, with crude oil prices increasing from their December
lows combined with lower than normal stock levels, EIA projects that
prices at the pump will rise modestly as the 2001 driving season begins
in the spring. For the summer of 2001, we expect little difference from
the average price of $1.50 per gallon seen during the previous driving
season. The annual average retail price of regular motor gasoline is
projected to decline from $1.49 per gallon in 2000 to $1.46 per gallon
in 2001 to $1.42 per gallon in 2002. Gasoline inventories going into
the driving season are projected to be about the same or even less than
last year. Relatively low gasoline inventories could set the stage for
regional supply problems that once again could bring about significant
price volatility in gasoline markets. The prospect of regional supply
problems is increased by the differing regional gasoline product
requirements, arising from Federal and State air quality programs,
which limit the distribution system's flexibility. Regional problems
can also arise from temporary or permanent losses of refining capacity.
However, it is expected that with a year's experience behind them, the
refining industry's ability to make the new type of gasoline initially
required last summer should be improved, thus mitigating any problems
related to this latest change in gasoline specifications.
Distillate Fuel. The heating season of October through March is now
nearing its end, so it is likely that retail heating oil prices have
seen their seasonal peak provided no late seasonal surge in heating
demand occurs. Warm spells in January and declining crude oil prices in
December and January have helpedease heating oil prices. Spot heating
oil prices (New York Harbor) fell from $1.05 per gallon on December 6,
2000, to $0.73 per gallon on February 28, 2001. Because of the
relatively warm weather in the Northeast during the last half of
January and the extremely high level of distillate fuel imports and
refinery production so far in 2001, heating oil stock levels have not
weakened over the past month or two as would normally occur. Thus, for
the country as a whole, distillate stocks are now back within the
normal range after being well below normal for most of the winter.
However, although retail heating oil prices have come down some
recently, they have remained relatively high as demand has continued to
be strong. The national average price in December 2000 was about 40
cents per gallon above the December 1999 price. By February 2001, the
average price is expected to be about $1.34 per gallon, about 8 cents
per gallon less than the record high set in February 2000.
The average bill for a consumer heating with oil in the Northeast
States is expected to be nearly $1,000 this winter compared to $760
last winter and less than $600 the previous two winters (Table 1). Of
the 7.7 million households in the United States that use oil to heat
their homes, 5.3 million households, or roughly 69 percent reside in
the Northeast region, which includes New England and the Central
Atlantic States. Although consumers this winter have not faced the
price spike they saw last winter, consumption is expected to be 11
percent more than last year, because of colder weather and high natural
gas prices encouraging some customers to switch to distillate fuel oil.
Higher consumption levels and higher crude oil prices relative to last
winter have combined to push up the expected cost of a gallon of
heating oil by 18 percent this winter. Together the increases in
consumption and price are expected to raise winter oil heating bills by
TABLE 1.--WINTER HEATING OIL COSTS FOR AN AVERAGE NORTHEAST HOUSEHOLD HEATING WITH OIL
1997-1998 1998-1999 1999-2000 2000-2001
actual actual actual projected
Heating oil consumed (gallons).......................... 636 650 644 715
Heating oil price (dollars per gallon).................. 0.92 0.80 1.18 1.39
Heating oil cost (dollars).............................. 585 520 760 994
Natural Gas. Spot natural gas prices last summer averaged more than
$4 per thousand cubic feet during a normally low-priced season and
remained above $5 per thousand cubic feet in the fall, more than double
the average price a year earlier (Figure 3). In January 2001, the spot
price averaged a record $8.98 per thousand cubic feet. These sustained
high prices are largely due to high demand for natural gas in 2000,
which exceeded 1999 demand by almost 1 trillion cubic feet, according
to preliminary data, and was not matched by an increase in domestic
production. U.S. production of natural gas is estimated to have
increased by about 0.5 trillion cubic feet in 2000 over 1999 levels.
Strong growth in the economy during the first half of the year, cold
winter weather late in the year, and increased demand from natural gas-
fired power plants throughout the year are the main reasons for high
natural gas demand in 2000. Due to high demand for natural gas in the
summer of 2000, smaller quantities of natural gas than usual were
injected into storage for winter, which is the peak demand period for
natural gas (Figure 4).
Demand for natural gas for heating was eased by milder than normal
weather during the latter part of January in much of the Nation's gas-
consuming regions, which led to a reduction in spot prices to less than
$6 per thousand cubic feet. By February 2001, the average spot price
for natural gas was about $5.80 per thousand cubic feet. However, spot
prices and wellhead prices still remain high by historical standards.
EIA projects that winter wellhead natural gas prices will average about
$6.10 per thousand cubic feet, more than two and one half times the
price of the previous winter season. Assuming normal weather and
projected continued low underground storage levels, the annual average
wellhead price in 2001 is projected to be about $5 per thousand cubic
feet, an increase from the 2000 price of $3.60 per thousand cubic feet.
In 2002, we expect the storage situation to improve, leading to a
decrease in the average annual wellhead price to $4.50 per thousand
cubic feet. Domestic natural gas production for 2001 and 2002 is
expected to rise as production responds to the high rates of drilling
experienced over the past year. In 2000, drilling for natural gas in
the United States increased by 45 percent over the 1999 level of 10,500
wells, in response to a 66-percent increase in the average natural gas
wellhead price from 1999 to 2000 (Figure 5). Production is estimated to
have risen by 1.1 percent in 2000 and is projected to increase further
in 2001 and 2002 as higher natural gas prices are expected to encourage
a moderate growth in supply. In contrast, natural gas production
declined slightly from 1997 to 1998 and from 1998 to 1999.
Of the 101.5 million U.S. households, 53 percent use natural gas
for home heating. The highest concentration of households heating with
natural gas-83 percent-is located in the Midwest. The average natural
gas home heating bill in the Midwest is expected to approach $1,000
this winter (Table 2). Compared to last winter, colder weather is
expected to increase residential gas consumption by 18 percent in the
Midwest. Residential gas prices are projected to be 50 percent higher
than last winter because growing demand and lagging growth in supply
resulted in reduced natural gas storage levels at the beginning of the
heating season. Together, increased consumption and prices are expected
to yield winter heating bills that are 77 percent above last winter.
The sharp increase in natural gas and heating oil prices has a
particularly severe impact on low-income consumers that use natural gas
for heating. In recent months, 5 million consumers have applied for
Federal and State governmental assistance to pay their heating bills,
an increase of 1 million from last year.
TABLE 2.--WINTER NATURAL GAS COSTS FOR AN AVERAGE MIDWEST HOUSEHOLD HEATING WITH NATURAL GAS
1997-1998 1998-1999 1999-2000 2000-2001
actual actual actual projected
Natural gas consumed (thousand cubic feet).............. 82.4 84.5 81.7 96.7
Natural gas price (dollars per thousand cubic feet)..... 6.56 6.27 6.61 9.89
Natural gas cost (dollars).............................. 541 530 540 956
Electricity. Demand for electricity increased an estimated 3.6
percent from 1999 to 2000. Growth of 2.4 and 2.3 percent is projected
in 2001 and in 2002, respectively, slowing in part because of reduced
projected economic growth. Electricity demand for this winter is
expected to be 4.5 percent higher than the previous winter, due to
higher residential and commercial demand and the cold temperatures in
November and December. Natural gas deliverability problems in
California have helped to increase natural gas prices and have
frequently caused interruptible customers, including electricity
generators, to have service curtailed in that State. In California, and
in the West as a whole, capacity additions have not kept pace with
demand growth over the past ten years, contributing to the current low
electricity generation reserve margins. The current situation in
California is characterized by low natural gas storage, natural gas
pipeline bottlenecks, unexpected plant outages, low availability of
hydropower resources, and electricity demand in excess of available
supply. In addition, the San Onofre 3 nuclear unit is currently offline
due to a fire in early February and may not return to service for
several months. Typically California would export electricity in the
winter season but has required net electricity importsfrom neighboring
states this year. The average residential price of electricity in the
United States is projected to increase from 8.2 cents per kilowatthour
in 2000 to 8.3 and 8.4 cents per kilowatthour in 2001 and 2002,
In the near term, we expect crude oil and petroleum prices to
remain about the same as their current levels throughout this year with
natural gas prices declining further next year as production increases.
Stock levels of both petroleum and natural gas are likely to remain
low, and natural gas prices are projected to remain higher than normal
largely due to high demand in 2000. Home heating oil and natural gas
bills are expected to approach $1,000 this winter, substantially higher
than last winter.
Thank you, Mr. Chairman and members of the Subcommittee. I will be
happy to answer any questions you may have.
Figure 1. Crude Oil Prices, 1998-2002 (dollars per barrel)
[GRAPHIC] [TIFF OMITTED] T4211A.001
Figure 2. Total OECD Oil Stocks, Including Commercial and Government
Stocks, 1995-2002 (million barrels)
[GRAPHIC] [TIFF OMITTED] T4211A.002
Figure 3. Wellhead Natural Gas Prices, 1999-2002 (dollars per thousand
[GRAPHIC] [TIFF OMITTED] T4211A.003
Figure 4. Working Gas in Storage, 1998-2002 (billion cubic feet)
[GRAPHIC] [TIFF OMITTED] T4211A.004
Figure 5. Lower 48 Natural Gas Wells Drilled and Average Wellhead
[GRAPHIC] [TIFF OMITTED] T4211A.005
Chairman Houghton. All right. Thank you very much. That is
great. You know, it just seems to me that there is something
out of sync here. You say the consumption is up, expected to be
11 percent more than last year, and if you followed the law of
supply and demand, that maybe you can see the prices being up
11 percent or maybe 15 percent, but not two, three, four, five,
six, seven times. What is going on here?
Mr. Cook. Well, certainly those kinds of price increases we
are seeing in California in gas and power markets I don't
believe they are that high nationwide. The data that we have
show gas prices approximately 50 percent higher, and the bill
maybe double. But certainly in the West where supplies have
been very constrained with the disruption in the El Paso
pipeline into California, and combined with a very strong
economy out there, certainly that balance is very tight. And
when the market is resolving a situation like that, prices do
not rise proportionately. They tend to rise to whatever will
clear the market. Then the individual who just has to have
Chairman Houghton. You mean whatever people will pay? In
other words, will be forced to pay; is that right?
Mr. Cook. Unfortunately, that is correct, sir. In
economics, back when I took the course 30 years ago, I think
the professor talked a little bit about the glass of water. How
much you would pay for it in the first hour you are in the
desert, which is not very much. As you walk farther and get
hotter and thirstier, then the amount you are willing to pay
for it, assuming you can, rises geometrically. I am not here to
offer excuses or apologies, or suggest, you know, solutions to
the problem. I can only tell you what has happened.
Chairman Houghton. Oh, no, and I understand that. And you
know, you are new, I assume, in theDepartment of Energy.
Mr. Cook. No. I have been there----
Chairman Houghton. You have been there what?
Mr. Cook. Longer than I want to remember.
Chairman Houghton. So we can lay it on you a little harder;
Mr. Cook. Give me your best shot.
Chairman Houghton. I don't want to give anybody a shot.
What I am trying to do is to understand what the dynamics are
here, and the--I mean, I think, you know, we live in a--we live
in a democracy. It is not only a political, but economic
democracy and we live by competition. And that is why our
economy is virgin. That is why it has grown so much faster than
other economies around the world.
At the same time, I do think there is a responsibility for
somebody, either doing on a voluntary basis or government, to
take a look at what are the discrepancies here. Could next year
the prices go up another seven times, or another seven times
after that? I mean, what responsibility do you think that we
have, as all Federal employees have, to be able to give the
best and fairest deal to the people who are consuming?
Mr. Cook. Well, again----
Chairman Houghton. That is my best shot.
Mr. Cook. You are pushing me into the policy arena, which
is not my agency's mission. You would have to talk to the
policy folks at the Department. EIA just does the forecasts,
and in this case, provides the unpleasant facts. And along
those lines, all I can say is that, although--well, I will give
you an example in the heating oil arena.
We had the spike in January of 2000, and as a result, lots
of heating oil imports flowed in from Russia and from Europe,
unfortunately too late to avoid paying the higher price for it,
but it did help stabilize the market some. With the continuing
relatively low inventories this summer into last fall, heating
oil prices were reasonably elevated compared to normal. But
they never spiked, even though the weather was colder and
stocks were low, unlike the year before when stock were normal
and the weather was warm, and yet prices spiked.
This year, there was enough concern early on in the market
that it brought in the imports early and prompted refiners to
produce at much higher rates than they normally do in the
wintertime. You could almost say the heating oil market was
flooded in January and February. It was very tight and very
high priced in November, for November. But that did bring in,
again, lots of imports from Russia and from Europe, and
refiners ran their refinery units at, at times, 500,000 to
800,000 barrels a day, higher levels than they had the year
To give maybe a little better example, inventories in
January and February usually drop between 10 and 15 million
barrels each month. They actually climbed, which means the
market was oversupplied by 30 million barrels during that
period. So it does work. It is just that sometimes, when it
gets out of balance, it can be very painful in the recovery
Our testimony is that the same situation is occurring in
the natural gas market. We have had real strong growth for 4 or
5 years. The low prices in 1998 and early 1999 curtailed
drilling. We are paying now for the very low prices and the
very low bills that we saw in 1997 and 1998, because that
dampened production just when gas demand was beginning to take
off, and yet you could not see it because the weather was so
warm when gas demand peaks in the wintertime.
So this year we get a little more normal weather and the
gas bill goes up. Part of it is just because the weather is
more like a typical winter and, in particular, because the
prices shoot up dramatically with the tight balance between
supply and demand, that all of a sudden it has been revealed in
the wintertime by the weather.
So we are going to have to have a lot more gas production;
and, fortunately, these high prices have shot drilling for
natural gas, exploring for natural gas, to record levels. We
are seeing just enormous amounts of drilling going on
scrambling, as I am sure you are aware, to consider the best
way to bring more in from Canada, maybe even Alaska.
So, you know, within a year or two, I think we will be back
out of the woods. But it is difficult now. All I can say is,
the winter is over, and if the LIHEAP program, which has been
funded additionally, can help the low-income families with
their bills, hopefully, we will not have to go through this
again next winter.
Chairman Houghton. Okay. Thanks very much. Mrs. Thurman.
Mrs. Thurman. Mr. Cook, is there any concern in your
internationally forecasting about production because of a
conversation going on in this country about the slowing down of
our economy? Will that have any effect on any of this over the
next couple of years?
Mr. Cook. Do I think our conversations about alternative
Mrs. Thurman. Or a slowing of our economy. Will less use
have any effect on future considerations by those that we are
Mr. Cook. Well, if you are referring to OPEC----
Mrs. Thurman. That is probably who, yes.
Mr. Cook. It is hard to say. OPEC probably does not know
what it is going to do at its meeting this month on the 16th.
They stated that they are going to watch the U.S. Economy
closely; and if it does look like it is sliding closer to
recession and that oil demand is slipping further, which, you
know, the data may show by then.
That is a tricky question, because half of that camp wants
to increase supply, or at least leave supplies where they are,
so that inventories can rebuild and prices can fall and help
stimulate demand. But the more hawkish element within OPEC
wants to keep cutting supply as demand falls to keep the price
higher, which just spirals the situation downward. I really do
not know which way they are going to go on this. I would hope
that we will see some signs of stabilization in the economy
that will convince them to leave supplies and prices where they
are, if not maybe bring inventories up some.
Mrs. Thurman. The other question is about how the different
States operate. I don't know what happens here or in
Pennsylvania, but obviously the big concern to the consumer is
the same. Are thecosts that get shifted to the consumer more
than needed and a way to make profit on the other end? Is there
conversation at all about this? I don't know if you can answer this
since you are not doing policy. In Florida, for example, we have a
Public Service Commission that sets rates. Sometimes the utility
companies come in and ask for rate increases. When we find out that
maybe they have had too much of a rate increase, we can actually reduce
the rate. We go through a hearing of some sort and actually the
consumer gets money back. Are we looking at those kinds of options at
the Federal level or just at the State level which, quite frankly, is
where it should probably be handled. I am just curious to know how
overall the State have worked and whether they been successful in
helping the consumer in what are really tough times for them?
Mr. Cook. I really can't comment on that. We not only skirt
that area, but we don't collect State-level data and work at
that level. National, regional to some extent, but certainly
not State level. I don't know that FERC, for example, has the
same role that you outlined for the States.
Mrs. Thurman. I just thought it might be interesting to
gather that forecasting information to see what is happening
individually in the States and to see if there is some over
charging in one part of the country because of high demand.
What has been happening in other parts of the country may kind
of even out the number a little bit, helping more consumers
Mr. Cook. Well, Okay. Indeed, those kinds of regional
disparities in supply and demand, again, we don't have the
resources to work the data at the State level, but it is our
responsibility to provide that kind of regional information to
the policy makers, so they can anticipate and promote better
production policies in those regions.
Mrs. Thurman. Okay. Thank you.
Chairman Houghton. Mr. English.
Mr. English. Briefly, Mr. Chairman.
Mr. Cook, the thing I find alarming about your testimony is
that you are predicting that there is no immediate way out of
this box. What you have suggested is that, for a substantial
period of time, we are going to continue to have shortages of
natural gas and that in the near future we can anticipate the
prices at the gas pump of petroleum are going to go up for
Now, I am particularly concerned, because I recently went
to a local steel company, McGuinness Steel in Erie,
Pennsylvania, and they showed me on a chart how their gas
prices for their forge have gone up 400 percent since
September. Do you feel that is an atypical impact, and does
that figure surprise you?
Mr. Cook. Again, I don't have data at that kind of a local
level, and the data that we have don't show 400 percent
increases. That is stunning, and there may be local conditions
causing that where that occurs.
Mr. English. So this may be, in part, a local supply
problem. It was particularly striking to me, because this
region is a gas-producing region, and I would have thought
there would be an opportunity for supplies of local gas that
could bring those costs down.
You identified the lack of refinery capacity correctly as
one of the sources of high gasoline prices last year, and our
refinery capacity has been contracting over the years. This is
wandering a little bit in the policy realm, but how much of
this side of the problem should we focus on in designing tax
incentives? If we can find a way of incentivizing investment
and refinery capacity, could that help address the problem?
Mr. Cook. Possibly, yes. Again, I would like to steer a
little clear of that area. Certainly refinery capacity right
now is part of the problem, especially in the summertime when,
again, it is run at virtually 100 percent in the Gulf Coast and
on the West Coast.
On the other hand, the rest of the year, refining capacity
utilization is not at its maximum like right now, and over the
last year or two, it has been more an economic problem. So even
if you have more capacity you probably wouldn't have a lot more
production than what we have had. The reason again for that is
tight crude oil supplies. It goes back to OPEC, crude oil cuts,
and crude oil high prices, and you have this causing
backwardation. Given this, refiners don't want to run their
plants at maximum levels. They want to supply just their known
contracted customers. They don't want to speculate on
independents showing up, demanding increased supplies, and
being able to sell this commodity on down the road a couple of
months to them, because they may not get their money back with
lower prices projected for the future. So it certainly would
help to have more refinery capacity.
Mr. English. But that is only a temporary problem typically
during a certain time of the year.
Mr. Cook. At the moment it is. On down the road 5, 6, 7
years, our projections show it continuing to get tighter and
tighter and the clean fuel rules exacerbating that trend.
Mr. English. Mrs. Thurman brought up the point, and I have
echoed it in my earlier questions about new technologies. Has
the Department studied the extent to which new technologies
like coal bed gas reclamation could create new supplies of
natural gas, and to what extent is this potentially part of the
new supply and part of the solution?
Mr. Cook. Yes. There has been work going on in that area.
In the short term, I wouldn't expect a whole lot to result from
Mr. English. A final question, and this is particularly
relevant because we are just outside of Westfield, New York,
which, of course, was the homestead of Governor Seward, who was
the Secretary of State that brought Alaska into the United
States. But to what extent does the Department estimate new
supplies in Alaska could be a significant addition to our
National energy supply?
Mr. Cook. Well, as you probably know, ANWR has been
estimated to--the median estimate is for about 10 billion
barrels, which would supply about 1.3 million barrels a day.
Mr. English. Relative to what is our known reserve
Mr. Cook. Well, I like to compare it as 1.3 million a day
to roughly what we import from Saudi Arabia.
Mr. English. Very good. Thank you.
Chairman Houghton. I just have one other question. We have
asked the Secretary of Energy--we asked Bill Richardson to come
up at one time, and now we have asked Spencer Abraham to come
up here. Now I am going to throw a tough question at you. If
they come, what is the key question we should ask them? And
this will not be a resignation speech on your part.
Mr. Cook. Well, let's see, with respect to Secretary
Richardson, since he is----
Chairman Houghton. No, he is out now.
Mr. Cook. He is out. I would be safe there. I guess one
might ask a tough question like what exactly is the Department
and Federal Government doing to ease in the short to midterm
the crude oil, in particular, and the natural gas supply
shortfalls? Aside from jawboning here and there and sending
people like me up here to sit in the hot seat, what are we
exactly doing here?
Chairman Houghton. All right. That is fair. That is a fair
I do have one other. I understand the whole conservation
issue is really not being explored appropriately. I don't know
what the numbers are, but somebody told me that if people just
tuned up their cars and blew up their tires, that it would save
an enormous amount of gasoline. Is that worthy of some action
on our part in terms of tax incentives?
Mr. Cook. I don't know how you would do it. Practically
speaking, it would probably be difficult to do that. Yes, it
certainly would help some. It would conserve some energy. I am
not an optimist that that is the way to do it. I think you need
more supply. You need to address both sides, the supply and the
demand side here. But just blowing up your tires is not going
to get you where you need to be.
Chairman Houghton. Thank you. You are very nice. I
appreciate it, and I hope United has a flight back for you.
Mr. Cook. They said they did, but they----
Chairman Houghton. I don't trust them. Find out.
Mr. Cook. When I get back, I am going to see if I can
switch to USAir.
Chairman Houghton. Okay. Thank you very much. We certainly
appreciate you being here.
Now, we were going to have Cathy Young, who is the
Assemblywoman from New York, and she can't be here. Neither can
Mike Sopp, who is General Manager of the Anchor Glass Container
Corporation in Elmira. But we do have other members of the
panel, and I hope that they will come up now, so they can
provide their testimony.
Moira Lindsley of Sinclairville; Caroline Sosinski of
Westfield; Jeff Aiken, Council Representative for Western New
York Regional Council of Carpenters, Randolph, New York; Dennis
Holbrook, who is a member of the Board of Directors,
Independent Oil and Gas Association out of Buffalo; Bruce
Heine, Assistant Vice President, National Fuel Gas in Buffalo;
and John Nalbone, President of Universal Resources Holdings of
Dunkirk, New York.
Ms. Lindsley, would you like to begin your testimony?
Thank you very much, all of you, for being here. You can go
STATEMENT OF MOIRA L. LINDSLEY, SINCLAIRVILLE, NEW YORK
Ms. Lindsley. Thank you for the opportunity to be here
today. I am a little nervous.
Chairman Houghton. Don't be nervous.
Ms. Lindsley. I am a single mother of a 14-year-old son;
and I am the head of the household, the only wage earner in my
family. I have a 94-year-old mother who is living with me--she
will be 94 in June--and a sister who is 72 diagnosed with Lou
I have two businesses at this time, and I also have a part-
time position at Jamestown Community College. My average
workweek is approximately 70 hours. My son is very active in
sports and in school activities, and I try, as a single parent,
to be there for hockey games and music programs. Obviously, it
doesn't leave many more hours in a day to put any more work
hours in. Also, both of my businesses require that I drive
considerably, approximately 700 miles a week. So I am affected
twofold. I am affected at home with my heating oil and also
with my gasoline.
My mother and sister were living together. My father passed
away approximately 5 years ago, and because of their age and
their handicap it was becoming very difficult for them to be
alone. I chose not to put them in a nursing home and not to
have them live with assistance. So my son and I brought them
into our home, and there is plenty of room there for them.
I heat with fuel oil, and I live in the country. Niagara
Mohawk is our power source. We sat down to do a budget before
they moved in to see what needs we had, and at that time we
felt comfortable with what we were earning to be able to
support the energy needs that we had.
They moved in in August 1999, and in September we needed to
purchase fuel oil for the first time. The first bill we had
was--we had averaged $150 a month for budgeting our first bill,
and the total was $300. Obviously, it put a real big nick in
our budgeting. We struggled through that winter. My mother now
has congestive heart failure, and her circulation is very poor.
So she needs to be warm. Seventy-eight to her is cold. We tried
to adjust with, you know, clothing and whatever. We did get
through last year, but it really put a crimp in the budgeting,
and I continued to work more hours, stressful, everything that
we are trying to do to keep going.
I have two alternatives. I could feed them and keep them
warm, or I could pay my mortgage. Obviously, the one that is
going is the mortgage; and mortgage companies don't want to
hear that. They really don't care about the energy problem.
I looked during the summer. We had a relatively cold
summer, also, so I had heat--normally, I wouldn't be heating
through the summer, but at times we had to have heat on for my
mother and for my sister. In the fall I had locked into $1.349
for fuel oil, and I received--again, October was our first
delivery. We had been averaging $600 a month from that point on
because of the cold winter and need for my mother to stay warm.
I went to several agencies to try to see what I could do. I
never had assistance. I have always been an entrepreneur. I
have had businesses in this area for many years, and it was
very difficult for me to go get assistance, but I had to do
something. One of the problems that I had was now getting any
response from agencies. I was put off from one to the other to
the other, and I thank Mr. Houghton's office for coming to my
rescue, so to speak.
I was told from one agency that I didn't qualify, Office of
the Aging. I was head of household, my mother wasn't, various
situations. I did apply for HEAP, and because of my income
being too high I didn't qualify, but we did look at a self-
employment worksheet to get the expenses to balance that. So I
am getting some assistance from HEAP, and again it is very
difficult for me. I am embarrassed to gothere, to ask for this
assistance. I have to keep my mother warm. There was no other
So we looked at sources, other sources that may be less
expensive, and we did put in a propane heater in her end of the
House. At that point, propane was less expensive. However,
after we put the equipment in, the propane increased, also. So
we are struggling with the cost of equipment, the cost of the
increase in the propane, and then the cost of increase in fuel
Right now I am not certain what we are going to do. We are
looking at a foreclosure on our house, so I might be not
worrying about any of these problems pretty soon. I hope not.
We are looking at reorganizing. What I saw as a consumer was
that no one seemed to be interested in the fact that we had
energy problems, that our prices were going up. I looked around
and, you know, what is the average person supposed to do? I
thought maybe it is just me who is suffering. After talking to
other organizations and people, I found out, no, it is not just
me. There are many people in my situation that have to make a
choice. Do we feed and keep our older people warm, or do we
make our mortgage payments? And we are making the choices that
we have to.
I thank you for your time.
[The prepared statement of Ms. Lindsley follows:]
Statement of Moira L. Lindsley, Sinclairville, New York
I am a 52 year old, single mother of a 14-year-old son. I am the
head of household, with my 94-year-old mother, and a sister, who is
diagnosed with Lou C. Gehrig's disease, living with me. I am the only
wage earner in the family.
Currently I am running two businesses and working part time to try
to stay financially afloat. My workweek averages approximately 70
hours. I maintain the home, prepare the meals do the shopping, laundry,
yard work etc. My son is also active in school and sport activities and
I try not to miss any of these events. I have no help coming from any
My mother and sister were living together after my father passed
away. Everyday responsibilities became difficult for them to handle
because of their ages and handicap. My son and I had room for them to
live with us and also felt it would be good for him to have family to
support him and be there when I needed to work. Also, financially, we
felt it would be to everyone's advantage. In August of 1999 they came
to live with us.
My home is heated with fuel oil and I am in the country and Niagara
Mohawk is our power source. In October of 1999 we needed to order our
first supply of fuel oil, what I anticipated to be approximately $150
was nearly $300. There is no room in the budget for these types of
increases. We struggled through the winter to pay these fuel costs and
hoped for any early spring and warm summer. Neither of these came and
costs kept rising. We weren't able to lock in to a price at this time
but were prepared to in the summer. In the fall of 2000 we were told of
additional costs in energy that we would be experiencing soon. We
already received our electric increases. I was suffering with all of
the long hours working and now the stress of dealing with anticipated
increases was taking a toll. What was I going to do? Where could I turn
for help? How could my pride deal with any of it? I was getting behind
in mortgage payments because it seemed more important to keep my mother
warm and comfortable. This was a dilemma I didn't know how to cope
My mother and sister have rooms that are separate from the rest of
the house and I began to look for optional ways to heat their area and
keep the heat in the main part of the house lower to conserve fuel. The
answer seemed to be propane and I converted my hot water tank, dryer
and added a propane wall heater to my mothers room. I am in an area of
an abundance of natural gas, which is less expensive. However, the cost
to put in gas lines to my house is prohibitive. The fall of 2000-turned
cold early and hard. My first month's fuel oil cost was $600. How are
we going to survive? With the costs incurred with the new equipment and
the first months supply of propane, which by the way, also increased
and additional fuel oil I was completely devastated. Everything else
was getting seriously behind. Gasoline prices are on the rise and with
my businesses I travel nearly 700 miles per week. It seemed like
everything I was earning was going into energy and not mine. I started
to ask anyone I knew for what help might be available. No one had any
answers. I started calling all of the emergency agencies and for one
reason or another was turned down and sent on to someone else who
continued the cycle. I finally turned to my local politicians to see
what they would do for me. The only one that responded was Amo
Houghton's office. I was referred to Independent Living Office and
found someone who seemed to care. I had tried applying for HEAP and was
told I had too much income. Other offices could assist me if my mother
was the head of household. It was put off after another. I had two
people on my side now that listened to my story and wanted to help. I
felt so desperate and now I am in jeopardy of losing my home through
foreclosure. I reapplied to HEAP with file right language, I need to
apply for a self-employment worksheet this would lower my income to
make me eligible for assistance. All of this was so humiliating because
I had never asked for any help before. I am able to receive some
benefits for only fuel oil now. However, my story is not over. I am
trying to refinance my house before it is sold in auction, probably in
May. I still owe Niagara Mohawk $1200 and my propane source $300.
The average person is not able to survive under the type of
increases we are experiencing. We are told we need to save for
retirement, our children's education and that proverbial ``rainy day''.
My rainy day is already here. Where is the concern for the effect on
the economy when people like me have to make a choice between keeping
warm, keeping food on the table, gas in their cars so they can continue
to work or making their mortgage payments?
My grandparents and my father were immigrants who believed in the
future and prosperity of this country. I wonder what they would feel
Chairman Houghton. Thank you so much. That was a wonderful,
What I thought we would do is just go through the panel,
and then we will have questions and general afterward. Ms.
STATEMENT OF CAROLINE SOSINSKI, WESTFIELD, NEW YORK
Ms. Sosinski. Thank you, Congressman Amo Houghton and
Members of the Ways and Means Committee, for coming to
Chautauqua County, and thank you for allowing me the
opportunity to speak to you on the energy crisis.
I live in a small mobile home, 12 by 82. I keep my
thermostat on 60 to 65. Still, my gas bill was $194 a month. On
the budget plan, I was paying $62 a month and was warm. Now I
pay $99 a month, and I am cold.
I cannot and will not pay such high prices. The raise we
received in Social Security doesn't begin to cover the fuel
raise. Then there are also all the other raises to consider,
medicine, food and doctor bills.
I am a volunteer with the county HEAP program, and I see
many of the seniors applying for HEAP who have to choose
whether to keep warm or eat well. Unfortunately, either choice
is not a healthy one. So many times I would suggest that they
go for food stamps, but they refuse that. They don't want to be
shamed. Medications for some can run over $200 a month, even
with a prescription plan. There are some who have to forgo
medicine they need in order to pay fuel bills.
The really hard part for me is when I have to deny someone
HEAP when I knew it was needed. If they are just a few pennies
over income guidelines, you have to deny them. They tell you
how much they have to pay for medication and other essentials,
but because of government rules it makes no difference. I
believe it should make a difference, and I believe you,
Congressman Houghton, and other congressmen here today do,
also, or you would not be here. But we need help now.
While doing volunteer work in January, a 90-year-old lady
was telling us she had an $800 gas bill. She didn't know how
she was going to pay it. What do we do in America about someone
like her? At her age, she needs to keep warm. Even some with
arthritis like me feels the cold more than others, and it
affects our health.
I honestly do not feel there is any justification for
raising prices so high. I may not understand business, but I
truly believe someone is making a big profit at our expense,
and it could be dangerous to some.
As my friend, Mac McCoy, who is a senior advocate in our
county, said to me, there are many older people who will need
the whole year to pay off this huge increase in their gas
heating bills, and it will set them back for a long time. But
they go without to pay their bills, because they are
responsible citizens. So many of these people receive no
assistance and are living on a restricted, fixed income.
All of us living here in Chautauqua County and throughout
our great country will continue to work hard to pay our bills.
I thank you for coming here today. I ask you to please let them
know in Washington that America needs to find a solution to
this problem. Tomorrow is already too late for so many of our
older citizens, and that is very sad.
[The prepared statement of Ms. Sosinski follows:]
Statement of Caroline Sosinski, Westfield, New York
Thank you Congressman Amo Houghton and Members of the Ways and
Means Committee for coming to Chautauqua County and thank you for
allowing me the opportunity to speak to you on the energy crisis.
I live in a small mobile home 12 x 82. I keep my thermostat on 60-
65. Still my gas bill was $194.00 a month. On the budget plan I was
paying $62.00 a month and was warm. Now I pay $99.00 a month and I am
cold. I can not and will not pay such high prices. The raise we
received in Social Security doesn't begin to cover the fuel raise. Then
there are also all the other raises to consider; medicine, food, and
I am a volunteer with the counties HEAP program and I see many of
the seniors applying for Heap who have to choose whether to keep warm
or eat well. Unfortunately either choice is not a healthy one. So many
times I would suggest that they go for food stamps but they refuse, as
they don't want to be shamed. Medications for some can run over $200.00
a month even with a prescription plan. There are some who have to forgo
medicine they need in order pay fuel bills.
The really hard part for me is when I had to deny some one HEAP
when I knew it was needed. If they are just a few pennies over income
guidelines you have to deny them. They tell you how much they have to
pay for medication and other essentials but because of government rules
it makes no difference. I believe it should make a difference and I
believe you Amo Houghton and the other Congressman here today do also
or you would not be here. But we need to help now.
While doing volunteer work in January a 90 year old lady was
telling us she had a $800.00 gas bill. She didn't know how she was
going to pay it. What do we do in America about someone like her? At
her age she needs to keep warm. Even some one with arthritis (like me)
feels the cold more than others and it affects our health.
I honestly do not feel there is any justification for raising
prices so high. I may not understand business but I truly believe some
one is making a big profit at our expense and it could be dangerous to
As my friend Mac McCoy, who is a senior advocate in our county said
to me, there are many older people who will need the whole year to pay
off this huge increase in their gas heating bills and it will set them
back for a long time. But they go without to pay their bills because
they are responsible citizens. So many of these people receive no
assistance and are living on a restrictive fixed income.
For all of us living here in Chautauqua County (and throughout our
great country) who continue to work hard to pay our bills, I thank you
for coming here today. I ask you to please let those in Washington know
that America needs to find a solution to this problem now. Tomorrow is
already too late for so many of our older citizens and that is very
Chairman Houghton. Thank you very much, Ms. Sosinski. Mr.
STATEMENT OF JEFF AIKEN, COUNCIL REPRESENTATIVE, WESTERN NEW
YORK REGIONAL COUNCIL OF CARPENTERS, RANDOLPH, NEW YORK
Mr. Aiken. Good afternoon.
Once again, like the rest of the panel, thank you for
having a labor representative here. I can't speak for labor
across the country, only on the local level that I deal with. I
also want it noted that whatever affects industry also affects
labor, and industry is feeling the pinch here.
We in southwestern New York live in what would be
classified as a rural area. There are several small cities and
municipalities within this area which have a reliable and
inexpensive although subsidized source of power. But, by and
large, most people live and work outside these areas; and the
majority of citizens, manufacturers and businesses cannot avail
themselves of the less expensive source of power. Not only do
they end up on an uneven playing field locally, but on a
national average we pay more for energy in this area than other
We are in a national and global market that is very
competitive, and in order to compete for their share of this
market, industry must find ways of cutting costs. Where does
industry begin? Usually the first place to start is cutting
workers' wages for producing the same product that is produced
in other parts of the country at a higher wage. By not offering
health insurance and pension benefits or not offering a package
that requires a monetary contribution on behalf of the
employees is another cost savings so the manufacturer can
better compete with industries in other parts of the country.
However, this creates another problem. When workers here
know that they can earn a better living for themselves and
their families elsewhere, they leave for greener pastures.
Consequently, and this is proven by census figures that show a
steady decline in population in western New York, it turns out
that this area's most valuable export is its workforce. We find
our best and brightest young people leaving the area to make
their homes and careers elsewhere.
As population declines, fewer working taxpayers are left to
support our economy, schools, and maintain our needed
infrastructures. Our residents are doing this with a dollar
that is already stretched too thin.
Previously, I mentioned the fact that this is basically a
rural area. This means that many workers travel great distances
to get to their place of employment. As you can see, I have an
attached chart. We are now paying at the pump a significantly
higher price for fuel than the national average. Plant
closings, layoffs and shutdowns require workers who once lived
close to their work to either travel long distances or go from
job to job in ever-increasing numbers.
In effect, if nothing is done, what the high cost of energy
has created for New York is a death spiral. Industries that
offer good-paying jobs leave the area. Our sons and daughters
leave the area seeking a better life. What we are left with is
an aging workforce that is being forced to do with less and
less while we sit back and watch the rest of the country
prosper. Far too many of the workers I talked to are forced to
forgo braces for their children, needed medical treatment, and
college savings plans because so much is spent on paying
utilities, taxes and getting to work.
Perhaps if energy rates in this area for both residential
and commercial entities were more in line with the rest of the
country, families and industry would find western New York an
attractive place in which to live and work. Thank you.
[The prepared statement of Mr. Aiken follows:]
Statement of Jeff Aiken, Council Representative, Western New York
Regional Council of Carpenters, Randolph, New York
I am speaking to you on behalf of labor and what I feel are our
specific problems. Also, I would like it to be noted that whatever
affects industry, directly affects labor.
We in southwestern New York live in what would be classified as a
rural area. There are several small cities or municipalities within
this area, which have a reliable and inexpensive (although subsidized)
source of power. But, by and large most people live and work outside
these areas and the majority of the citizens, manufacturers and
businesses cannot avail themselves of the less expensive source of
power. Not only do they end up on an uneven playing field locally but
also on the national average we pay more for energy in this area than
other areas. We are in a national and global market that is very
competitive and in order to compete for their share of this market,
industry must find ways of cutting costs. Where does industry begin?
Usually the first place to start is cutting workers wages for producing
the same product that is produced in other parts of the country for a
higher wage. By either not offering health insurance and pension
benefits or offering a package that requires a large monetary
contribution on the behalf of the employee is another cost savings to
the manufacturer. To cut, reduce or do away with benefits, the
manufacturer can better compete with industries in other parts of the
However, this creates another problem. When workers here know that
they can earn a better living for themselves and their families
elsewhere, they leave for greener pastures. Consequently, and this is
proven by census figures that show a steady decline in population in
Western New York, it turns out that this area's most valuable export is
its workforce. We find our best and brightest young people leaving the
area to make their homes and careers elsewhere.
As the population declines, fewer working taxpayers are left to
support our economy, schools and maintain needed infrastructures. Our
residents are doing this with a dollar that is already stretched to
Previously I mentioned the fact that this is basically a rural
area. This means that many workers travel great distances to get to
their place of employment. As you can see on the attached chart, we are
now paying (at the pump) a significantly higher price for our fuel than
the national average. Plant closings, layoffs and shutdowns require
workers who once lived close to their work to either travel long
distances or go from job to job in ever increasing numbers.
In effect, what the high cost of energy has created for Western New
York is a death spiral. Industries that offer good paying jobs and our
sons and daughters leave the area seeking a better life. What we are
left with is an aging workforce that is being forced to do with less
and less while we sit back and watch the rest of the country prosper.
Far too many of the workers I talk to are forced to forego braces for
their children, needed medical treatment and college savings plans
because so much is spent on paying taxes, utility bills and getting to
Perhaps if energy rates in this area for both residential and
commercial entities were in line with the rest of the country, families
and industry would find Western New York an attractive place in which
to live and work.
[The attachments are being retained in the Committee files.]
Chairman Houghton. Thank you very much, Mr. Aiken. Mr.
STATEMENT OF DENNIS HOLBROOK, MEMBER, BOARD OF DIRECTORS,
INDEPENDENT OIL AND GAS ASSOCIATION, BUFFALO, NEW YORK
Mr. Holbrook. Good afternoon, Mr. Chairman, Members of the
panel. On behalf of the Independent Oil and Gas Association of
New York, we appreciate this opportunity to come here today and
to hopefully provide some of the solution to the problem that
has been identified here today.
IOGA of New York has 130 Members. We represent the vast
majority of both the large and the small independent producers
operating in this State. Large by New York State standards is
clearly not large when you compare it with some of the majors
you would think elsewhere in the country or world, but we try
and do our part.
I personally bring many years of experience, dating back to
the early 1970s in the energy industry when I worked on the
staff of Senator Buckley from New York. At that time, Senator
Buckley was concerned that government policies were interfering
with proper market signals for energy development, particularly
for natural gas. Much has changed in the nearly 30 years since
that time, and yet in many ways the issues are the same.
Current policies of the Federal Energy Regulatory
Commission that was referred to earlier today, commencing with
order 636 the early part of the past decade, in the early
1900s, allowed interstate pipelines to charge nearly all of
their costs in the form of a demand charge. Basically, the
charge was assessed up front for the cost of transportation,
bringing gas from the southwest and bringing gas in from
western Canada. You couple that experience with the nearly 20-
year contract terms associated with most of those contracts
that the local distributors were engaged in, and it created a
tremendous hindrance on local gas development in this region.
If you compare the time period just prior to that FERC
order and the time period following that, you find a
significant difference. I mean, we are talking on an order of
magnitude of more than a 50 percent reduction in drilling
activity since that time period. What this region basically
lost was the geographic advantage they should have had
associated with being relatively close to the market.
The typical local distribution company pays, on average,
$1.50 per 1,000 cubic feet to bring gas in from western Canada
and the western part of the U.S. Our point is, it may seem like
a minor amount when we talk about relatively large dollars here
today, but even if one-third of that, just 50 cents, was
assured to the local producer on a consistent basis and the
other dollar returned to the consumer, we believe that that
would be a tremendous encouragement in terms of local drilling
Now, I appreciate that this panel's focus is on tax policy,
but the question posited for today's hearing and as recited by
Chairman Houghton at the beginning of this meeting was, why are
prices rising in the manner that you described, and what can we
do about it? So we point that out, that we believe there are
government policies, some of which you may have direct control
over, some of which you may not, that do have a significant
influence over the supply side of this business.
The current high prices, I will submit to you, are a
reflection of an inefficient marketplace where price signals
are not consistent. The current high prices are a reflection of
shortage. Shortage is a reflection of the lack of drilling
activity, and the lack of drilling activity is due to an
inability to accurately predict prices. The unusually low
prices that were alluded to earlier today associated with
recent mild winters discouraged drilling activity, and the high
prices we are seeing this winter are a reflection of that
The irony in all this is even today's high prices won't
necessarily support renewed drilling activity. Now, I know it
was mentioned earlier today that we saw an upsurge in drilling
activity. There is no question that people get excited on my
end of the business when prices get high, but what needs to be
appreciated is that there is a healthy degree of skepticism
associated with that activity as well, and all you need is to
see the downturns that we have experienced in recent years for
that drilling activity to dry up once again. Keep in mind that
the vast majority of natural gas wells drilled in this country
are drilled by independent producers.
Another point I think is worth mentioning is that while it
seems like there would be a windfall out there right now for
the producers associated with in some cases the tripling or
quadrupling in prices when compared with earlier years, many
producers, based upon their historic experience of having a
relatively flat or downturn in the market, went out and hedged.
They basically sold their product in advance when the price got
a little bit better because it was so much better than what
they had experienced in recent years.
As a result, much of what has now been the fly up in prices
is not being experienced by the producers that you are looking
to, to go out and help correct some of this problem by going
out and increasing the supply. Marketers, brokers, other
parties that are engaged in the energy industry are either
winners or losers depending on how they hedged and how they
But I think it is important to keep in mind that short-term
swings, such as what we are seeing now, while they are very
severe, and I appreciate what we are hearing here today on this
panel, in terms of the economic impact on individuals, they
don't always do much to encourage the very activity we are
looking for to ultimately correct the problem.
What I would suggest to you is that, given the lead time,
the significant lead time, that is needed with drilling
activity, the activity of going out, developing a prospect,
raising the money necessary to drill for that product, and then
to ultimately bring it to market, it is critically important
for energy producers to have a minimum threshold of what I call
You heard prices out here associated with upward of $10 per
thousand cubic feet that has been charged in the marketplace
last winter. Most producers that I am familiar with have
expressed the view that if they could consistently anticipate a
price, even in the middle $3 range, for what they could expect
for their product, they could go out, borrow money from the
bank, go out and raise the necessary funds to go out and drill
and provide a consistent product. It is this variance that
takes place that creates much of the inefficiency that I think
we are seeing here today.
I think clearly the fly up, and I am a consumer in the
Northeast and can fully appreciate having questions when my
bills showed up, and I was on a balanced billing program and
discovered that what I thought was more than sufficient to
cover it, it was not even close. The worst part is when you get
to the end of those balanced billing programs and you have a
true--up month. Then you find out what you owe. So I fully
appreciate what has been expressed here today.
Some of the things that as an association we would like to
at least encourage and to think about, turning back to the tax
law policy, are the opportunity to expense certain items such
as delay rentals that we experience as part of the contracting
for the right to go out and drill and the geological,
geophysic, and geoseismic type of expenses that are incurred to
go out and again develop prospects.
As you may know, those are allowed to be capitalized, but
that tends to be extending way out into the far future. The
opportunity to reflect the actual costs that are being incurred
to go out and develop theprospects, as you heard mentioned
earlier, section 29 tax credits, particularly in the area of tight
sands, which is typical of the formations that we deal with up in this
part of the country. As you may know, the actual wells that were
eligible for that as far as new well spuddings ended in 1994, and then
you simply had the opportunity to collect that credit on wells that
were producing after that point in time, I believe, through 2002.
I think a point of question that I heard mentioned, and I
believe it was by Mr. English and Mr. Houghton, and I believe
you may have mentioned this as well, all three of you,
Congresswoman Thurman as well, was the question about, do these
tinkerings with the Tax Code help the process ultimately
achieve the desired end, which is to get the product up in
supply and, therefore, reduce the cost. I think predictability
and reliability on a consistent policy is critically important,
and the fact that tax credits may have been allowed for new
drilling back in 1994 hasn't done much in this area since that
So, with that, I am going to conclude my initial comments.
Again, I appreciate the opportunity to speak here today. We are
happy to answer any questions when this panel is completed.
Chairman Houghton. Thank you very much, Mr. Holbrook. Mr.
STATEMENT OF BRUCE D. HEINE, ASSISTANT VICE PRESIDENT, NATIONAL
FUEL GAS DISTRIBUTION CORPORATION, BUFFALO, NEW YORK
Mr. Heine. Good afternoon.
Again, my name is Bruce Heine. I am an Assistant Vice
President with National Fuel Distribution. I am in charge of
the gas purchasing area. I would like to thank Members of the
Subcommittee and the chairman for the opportunity to
participate in this hearing. Today I am speaking on behalf of
National Fuel, a natural gas utility that serves approximately
700,000 commercial, industrial and residential customers in
both western New York and the western Pennsylvania area.
An unprecedented rise in the cost of natural gas, along
with colder than normal weather this past year has caused
consumer bills in our area to increase significantly over the
last year. Now, I am going to refer to a number of exhibits
that are attached to my testimony. It might be helpful to look
at those as we go.
Exhibit 1 shows the components of our average annual rates.
The increasing purple line represents the gas cost element----
Chairman Houghton. Let me just interrupt a minute. Are
these going to be available for everyone?
Mr. Heine. I believe there should be copies.
Chairman Houghton. Because it is hard to sort of follow it.
Mr. Heine. Okay.
Chairman Houghton. These exhibits and the testimony of Mr.
Heine. As with other testimony, they are going to be available
afterward. Thanks. Go ahead.
Mr. Heine. Okay. The purple line on Exhibit 1 represents
the gas cost element of a customer's bill.
Chairman Houghton. We don't have colored up here.
Mr. Heine. Oh, you don't? Okay.
Chairman Houghton. Just black and white.
Mr. Heine. All right.
Chairman Houghton. Is this Exhibit Number 1?
Mr. Heine. Exhibit Number 1.
Basically, what the exhibit is showing, the bottom line is
basically the utility cost of service. You can see that the
middle line, which is the gas cost, is rising significantly,
while the utility charge or utility cost of service is
decreasing slightly. So you can see the top line, which is the
total of the two, is clearly being influenced by the cost of
gas, as opposed to the utility charge.
So why are natural gas prices so much higher recently as
compared to previous years? This year follows, again, a period
of oversupply when drilling was down due to relatively low gas
prices. Supplies have been steadily declining, and even though
National Fuel's market requirements have been somewhat stable,
demand has grown elsewhere in the United States, especially if
natural gas is used for electric generation. Factors outside of
our control and outside our geographic region affect the
marketplace where we purchase the commodity.
The problem of high prices is not just a New York and
Pennsylvania issue. It is a problem that is being felt
nationwide. Exhibits 2 and 3 illustrate these factors.
Exhibit 2 shows the decline of natural gas deliverability
over the past 5 years. In 1996, the total deliverability from
the U.S. Was about 53 billion cubic feet a day. Today, it is
around 51.5 billion cubic feet a day. This represents a 3-
Meanwhile, Exhibit 3 shows how natural gas demand
nationwide has been on the increase. The economy and
deregulation has fueled the demand for natural gas. Most
forecasts now predict the demand for natural gas to reach 25
BCF per day.
Now that prices have risen in response to the supply and
demand shift, drilling activity has picked up again. Both large
producers and small independent drillers now have the incentive
to get the gas production back to the level where it can meet
the growing demand. Most experts believe the market price for
natural gas will level off as additional supplies come to
How is National Fuel affected by the rising cost of natural
gas? It is important to realize that National Fuel does not
benefit from higher natural gas costs. The price we pay is
passed along to the customer dollar for dollar without markup.
National Fuel has taken steps to manage gas costs while
ensuring reliability of supply. We balanced our purchasing
portfolio between storage gas, fixed price gas and gas
purchased under market priced mechanisms. Hedging strategies
such as this do not necessarily reduce prices but do soften the
effect of price volatility.
Exhibit 4 illustrates our winter commodity supply mix and
how it is balanced between storage withdrawals, fixed price and
market price gas.
Where does National Fuel's gas supply come from? We
purchase gas supplies from the southwestern United States and
Canada. Storage gas also makes up approximately one-third of
our supply during the winter months. The majority of gas
supplies for sale to customers of National Fuel are brought to
National Fuel by seven major upstream interstate pipelines that
traverse our market area.
In addition, local production or locally produced gas
accounts for around 30 percent of the total volume of gas moved
through our system. Although it is closer, local produced gas
is not necessarily cheaper than other sources of supply. Local
gas is sold at market prices and is usually purchased directly
by local industry.
How does National Fuel keep our natural gas purchase prices
as low as possible? We consistently evaluate different sources
of supplies, pipelines and storage contracts to make sure we
are using the very least cost reliable options. We work to make
sure that our pipeline supplier rates and services are
prudently priced and in our customers' best interest. State
regulatory commissions review all of our contracts and
purchases related to gas purchasing.
However, with gas prices rising, it is more difficult to
keep gas supplies at the low-cost level we have experienced in
the past. Market price of gas is out of our control. It is
really driven by supply and demand, and it is very difficult to
What will the future bring? Our customers need to know that
supplies of natural gas are adequate. Rising prices, while they
hurt in the short run, have encouraged greater exploration and
production for new gas supplies. There are more rigs drilling
for natural gas than ever before. Many experts believe these
new supplies will help moderate prices later in the year.
Exhibit 6 shows the number of drilling rigs active in the
U.S. And Canada. As you can see, it has gone from 800 rigs last
January to approximately 1,150 currently nationwide. This is
encouraging. Also on Exhibit 6 is the latest price forecast
from the Petroleum Industry Research Association, or PIRA. This
is somewhat encouraging, since it shows prices leveling off
around $4 to $4.50, which is a considerable break from the $10
we saw in January.
National Fuel has been serving northwestern Pennsylvania
and western New York for over 100 years. As an active part of
the community, and as gas customers ourselves, we are working
to keep costs down by strategically acquiring and managing our
natural gas supplies.
I would like to thank you for this opportunity to present
this information to the Committee.
[The prepared statement of Mr. Heine follows:]
Statement of Bruce D. Heine, Assistant Vice President, National Fuel
Gas Distribution Corporation, Buffalo, New York
My name is Bruce D. Heine and I am an Assistant Vice President with
National Fuel Gas Distribution Corporation (``National Fuel''). I would
like to thank the members of the Subcommittee for the opportunity to
participate in today's hearing. I am speaking today on behalf of
National Fuel, a natural gas utility that serves approximately 700,000
commercial, industrial and residential customers in New York and
An unprecedented rise in the cost of natural gas along with colder-
than-normal weather this past year has caused consumers' bills to
increase significantly over last year. Exhibit No. 1 shows the
components of our average annual rates. The increasing purple line
represents the gas cost element of a customer's bill while the slightly
decreasing red line represents the utility cost of service component.
The green line is the sum of these two components. This clearly shows
it is the cost of gas supplies driving the increase in rates.
Why are natural gas prices so much higher recently as compared to
Natural gas is a deregulated commodity and is traded on the NYMEX
Futures Exchange. The price is based on the value traders place on the
gas at a specific point in time and, in most recent months, such prices
have been at historically high levels with extreme price volatility.
This rise in commodity cost directly relates to the increase in
residential charges shown in Exhibit No. 1. This year follows a period
of oversupply when drilling was down due to relatively low gas prices.
Supplies have been steadily declining and even though National Fuel's
market requirements have been somewhat stable, demand has grown
elsewhere in the United States, especially as natural gas is used for
electric generation. Factors outside our control and outside our
geographic region affect the marketplace where we purchase the
commodity. The problem of high prices is not just a New York and
Pennsylvania issue, it is a problem that is being felt nationwide.
Exhibit Nos. 2 and 3 illustrate these factors. Exhibit No. 2 shows the
decline of natural gas deliverability over the past 5 years. In 1996
the total deliverability from the U.S. was 53 Bcf/day. Today it is
around 51.5 Bcf/day. This represents a 3% decline. Meanwhile, Exhibit
No. 3 shows how natural gas demand nationwide has been on the increase.
A healthy economy and deregulation has fueled the demand for natural
gas. Most forecasts now predict the demand for natural gas to reach 25
Tcf by 2005. Another factor that has had a significant influence on
prices this past winter is the national storage inventory level. Going
into the winter of 1999/2000 storage levels nationwide were higher (3.0
Tcf) compared to this past winter when they were at 2.7 Tcf. This is
most likely due to the increased electric generation load over the
summer. Now that prices have risen in response to the supply and demand
shifts, drilling activity has picked up again. Both large producers and
smaller independent drillers now have the incentive to get the gas
production back to the level where it can meet the growing demand. Most
experts believe the market price of natural gas will level off as
additional supplies come to market.
How is National Fuel affected by rising natural gas prices?
It is important to realize that National Fuel does not benefit from
higher natural gas costs. The price we pay is passed along to the
customer, dollar for dollar, without markup. National Fuel has taken
steps to manage gas costs while ensuring reliability of supply. We've
balanced our purchasing portfolio between storage gas, fixed price gas,
and market-priced mechanisms. Hedging strategies such as this do not
necessarily reduce prices but do soften the effect of price volatility.
National Fuel's storage contracts act as a natural hedge against rising
prices and also provide a very reliable source of gas because it is
stored directly in the market area. Exhibit No. 4 illustrates our
winter commodity supply mix and how it is balanced between storage
withdrawals, fixed price and market-priced gas that includes the index
term, local and spot gas. This type of diversification helps to
mitigate the effects of volatile prices.
Where does National Fuel's gas supply come from?
We purchase gas supplies from the southwestern United States and
Canada. Storage gas also makes up approximately a third of our supply
during the winter months. The majority of gas supplies for sale to
customers of National Fuel are brought to National Fuel by seven (7)
major upstream interstate pipelines that traverse our market area.
These pipelines are: Tennessee Gas Pipeline Company, Texas Eastern
Transmission Corporation, Transcontinental Gas Pipeline Corporation,
Dominion Transmission Inc., Columbia Gas Transmission Corporation,
Empire State Pipeline and National Fuel Gas Supply Corporation. Most of
these are shown on Exhibit No. 5. It is these pipelines that transport
the supplies we have under contracts in the production area. We always
prepare for a winter that is 10 % colder than normal, and maintain
enough gas in storage and through gas supply contracts to assure that
level of available gas supply. In addition, local production accounts
for around 30% of the total volume of gas moved through our system.
Although it is closer, locally produced gas is not cheaper than other
sources of supply. Local gas is also sold at market prices and is
usually purchased directly by local industry.
How does National Fuel keep our natural gas purchase prices as low as
National Fuel follows a least-cost gas purchasing strategy. We
constantly evaluate different sources of supplies, pipelines and
storage contracts to make sure we are using the very least-cost,
reliable options available. We work with the Company's Rates and
Regulatory Affairs Department to make sure our pipeline supplier rates
and services are prudently priced and in our customers' best interest.
State regulatory commissions review all of our contracts and purchases
related to gas purchasing. However, with gas prices rising, it is more
difficult to keep gas supplies at the low cost level we've experienced
in the past. As far as the commodity price is concerned, we can't
influence it--the market price is controlled by the forces of supply
and demand. Historically, our most important opportunity and unique
asset in keeping costs low and maintaining reliability is our storage,
which is physically located in National Fuel's service territory. This
allows us to purchase and store a significant amount of natural gas in
the summer when, prices have traditionally been lowest. Then we can
draw gas from storage in the winter, when demand and prices are
generally higher. We continue to evaluate new storage options as
opportunities arise. Because National Fuel relies heavily on storage,
upstream capacity is not sufficient to meet customer requirements on
cold days. For this reason, storage must be reserved through the early
part of the winter to retain a volume of gas in storage that is
sufficient to provide delivery of gas from storage necessary on the
design peak day. In addition it is also necessary to reserve sufficient
delivery from storage to meet cold days late in the winter period.
Since there are many changing variables such as weather, price
forecasts and market requirements, a linear program model is used on a
continuous basis to prescribe the least-cost mix of gas supplies from
pipeline and storage sources that should be utilized to meet National
Fuel market requirements.
What will the future bring?
Our customers need to know that supplies of natural gas are
adequate. Rising prices, while they hurt in the short run, have
encouraged greater exploration and production for new natural gas
resources. There are more rigs drilling for natural gas than ever
before, and many experts believe these new supplies will help moderate
prices later this year. Exhibit No. 6 shows the number of drilling rigs
active in the U.S. and Canada. As you can see, it has gone from 800
rigs last January to approximately 1,150 currently nationwide. This is
Also on Exhibit No. 6 is the latest price forecast from the
Petroleum Industry Research Association (``PIRA''). This is somewhat
encouraging since it shows prices leveling off between $4.00 and $4.50
per MMBtu, which is a considerable break from the $10.00 price we saw
National Fuel has been serving northwestern Pennsylvania and
western New York for over 100 years. As an active part of the
community--and as gas customers ourselves--we're working to keep costs
down by strategically acquiring and managing our natural gas supplies.
Though the colder winter weather and price increases are putting
pressure on all of us, we are committed to providing our customers with
the quality and service they have come to expect. Our mission is to
continue to provide a reliable source of gas at the most reasonable
I would like to thank you for the opportunity to present this
information to the Committee.
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Chairman Houghton. Thank you very much, Mr. Heine. Mr.
STATEMENT OF JOHN J. NALBONE, JR., PRESIDENT, UNIVERSAL
RESOURCES HOLDINGS, INC., DUNKIRK, NEW YORK
Mr. Nalbone. Thank you, Mr. Chairman.
I am the president of a local production firm, Universal
Resources Holdings. We operate in western Pennsylvania and
western and central New York. We were formed in the mid-
seventies. Our firm has drilled in that period of time about
660 wells, and most of them were all funded by organized
Our peak operational year was 1981 when we had drilled 141
wells. Prior to the Tax Reform Act 1986 and the oil price crash
of that year, we had drilled about 620 of those wells, but in
the 15 years since, we have not even drilled 40 wells, and no
wells since 1992 when the window of time expired for drilling
the section 29 tight gas sand wells.
Chairman Houghton. You might explain what section 29 is for
everybody out here.
Mr. Nalbone. That is the unconventional fuel production tax
credits which were given for the natural gas and coal industry
for hard-to-produce oil and gas, for what you call low-margin
or low-yield reservoirs. This particular region, western
Pennsylvania and western New York, is that type of region that
falls under that jurisdiction.
Chairman Houghton. Thank you.
Mr. Nalbone. So since 1986 the national oil and gas
industry has been devastated, with most of their experienced
skilled tradesmen leaving for other industries, due to massive
layoffs and inactivity.
The government impact on drilling/production since the Tax
Reform Act of 1986. During this time, our National production
has declined from about 9 million barrels a day to less than 6
million barrels a day. In 1981, the industry had over 4,100
rigs running; today, it is barely over 1,100.
The effect of the tax rate reduction from the top 70
percent bracket to the current 39 percent bracket, which might
be, hopefully, reduced to around 33 percent, coupled with the
elimination of several types of tax credits that were there
before the Tax Reform Act, plus the change in the passive loss
rules requiring passive losses to be offset only by passive
income, and the implementation of the alternative income tax
devastated the usual capital sources for most of the smaller
independents like us, who combined had accounted for over 50
percent of the national natural gas production in the early to
During this period when supplies were made plentiful, the
consumer prices were reasonable and the perception of a ``gas
bubble'' left little incentive for the lawmakers at that time
to develop long-term tax policies that would ensure the
continuation of ample supply.
How independent producers sell gas now.
Since 1986, and with the gas deregulation, we have seen the
coming of a much more complex and volatile pricing market with
the presence of numerous large gas marketing firms dominating
this market as middlemen and futures market speculators causing
the wild price swings on the spot market. To counteract the
loss of profit caused by deregulation, the local area
distribution companies have successfully prevailed upon their
respective State public service commissions to allow the
charging of what are excessive tariffs to transport gas across
their wholly depreciated pipeline distribution systems. Thus,
the consumer is bearing the brunt in the end of having to pay
these higher prices for excessive middlemen and gas
transportation markups and the supply shortages.
My suggestions for improving the supply and lowering
prices. I think we need better tax incentives for encouraging
the undertaking of risk for substantially more drilling today.
These necessary incentives should be significantly easier for
lawmakers to justify than the billions of dollars given to the
The recommendations, which I believe would turn the supply
problems around and result in lower consumer prices, are:
Restoration of several of the key tax provisions that
stimulated the drilling boom of the early 1980s that were taken
away from the industry with the Tax Reform Act 1986. Namely,
return to us at least this the following: the 10 percent
investment tax credit on recoverable tangible equipment. The
return to the passive loss rules that existed prior to 1986 so
that our traditional investors would have the incentives to
return to us within the limited partnership formats that
existed in the past.
Extend for us, for at least 10 more years, the section 29
program for the tight gas sands production,which is set to
expire at the end of the year 2002, for the existing wells that are
drilled and properly registered with FERC. Allow the extension of those
fields for new offset wells under the program. A great part of the
remaining national undeveloped reserves are in tight gas sands
reservoirs. This would have great benefit for the drilling play in the
Western New York and Western Pennsylvania areas.
Last, allow the elimination of the alternative minimum tax
for new oil and gas drilling investments, as the implementation
of this tax over the past 15 years was as much a detriment to
the investor incentives as the passive loss rules.
Thank you for allowing me to make the address here.
[The prepared statement of Mr. Nalbone follows:]
Statement of John J. Nalbone, Jr., President, Universal Resources
Holdings, Inc., Dunkirk, New York
Congressman Houghton, ladies and gentlemen thank you for inviting
me to testify at this hearing today.
I. Brief History of Universal Resources Holdings, Inc.
Formed in the mid seventies, our firm has operated in Western
Pennsylvania and Western and Central New York and has drilled over 600
gas wells and about 60 oil wells, most of which were drilled for
organized limited partnerships. Our peak operational year was 1981 when
we drilled 141 wells. Prior to the tax reform act of 1986, and the oil
price crash of 1986, we had drilled over 620 of these wells in our
first 10 years of operation, and less than 40 wells in the 15 years
since 1986. We have drilled no wells after 1992 when the last of the
local area tight gas sand drilling incentives for production tax
Since 1986 the national oil and gas industry has been devastated
with most of the experienced skilled tradesmen leaving for other
industries, due to massive layoffs and inactivity.
II. Government Impact on Drilling/Production Since the 1986 Tax Reforms
During this time our national oil production has declined from
about 9MM B/D to less than 6MM B/D. In 1981 the industry had over 4100
rigs running but today about 1100.
The effect of the tax rate reduction from the top 70% bracket to
the current 39% bracket (which will probably be reduced to around 33%)
coupled with the elimination of several types of tax credits--plus the
change in the passive loss rules requiring passive losses to be offset
only by passive income, and the implementation of the alternative
income tax devastated the usual capitol source for most of the small
independent producers who combined had accounted for over 50% of the
national natural gas production in the early to mid eighties.
During this period supplies were made plentiful, the consumer
prices were reasonable and the perception of a ``Gas Bubble'' left
little incentive for the lawmakers at that time to develop a long range
tax policy that would ensure the continuation of ample supply.
III. How Independent Producers Sell Gas Now
Since 1986 and with gas deregulation we've seen the coming of a
much more complex and volatile pricing market with the presence of
numerous large Gas Marketing firms dominating the market as middlemen
and futures market speculators causing wild price swings on the Spot
To counteract the loss of profit caused by deregulation, the local
area distribution companies have successfully prevailed upon their
Public Service Commissions to allow the charging of what are excessive
tariffs to transport gas across their wholly depreciated pipeline
Thus the consumer bears the brunt in the end in having to pay
higher prices for excessive middlemen and gas transportation markup and
the supply shortages.
IV. Suggestions On Improving Supply & Lowering Prices
The industry needs better tax incentives to fund the risk of
substantially more drilling today.
These necessary incentives should be significantly much easier for
the lawmakers to justify than the billions of dollars of subsidies
given to the farm industry.
The recommendations which I believe would turn the supply problems
around and result in lower consumer prices are:
1. Restoration of several of the key tax provisions that stimulated
the drilling ``boom'' of the early eighties that were taken away from
the industry with the tax reform act of 1986 as follows:
A. Return the 10% investment tax credit on recoverable tangible
B. Return to the passive loss rules that existed prior to 1986 so
that our traditional investors would have the incentives to return to
us within the Limited Partnership formats that existed in the past.
2. Extension for at least 10 years of the Section 29 Non-
conventional fuel tax credit program for tight gas sands production
which is set to expire at the end of 2002 for existing wells that were
properly registered with FERC when drilled and allow the extension of
these fields for new offset wells under this program. A great part of
the remaining National undeveloped reserves are in tight gas sands
reservoirs. This would have great benefit for the character of the
traditional drilling play that has been ongoing in Western New York for
the past 100 years and stimulate a lot of new activity.
3. Elimination of the alternative minimum tax for new oil and gas
drilling investments as the implementation of this tax over the past 15
years was as much a determent to investorincentive to participation in
drilling ventures as was the changing of the passive loss rules.
Thank you for allowing me to make this address.
Chairman Houghton. Thank you very much.
What I am going to do is turn to Ms. Thurman and ask her to
ask questions and then Mr. English. If there is any time left,
I will proceed. As I look out the window, we had better be
careful that we are not all stranded here overnight.
So, let us get on with this. If we are a little truncated
in our questions, it is not that we are not interested, but we
can follow up in other ways.
Go ahead, Ms. Thurman, please.
Mrs. Thurman. First, let me thank you for giving us ideas
of what you believe could help and comments on some acts that
actually exacerbated the problem earlier on.
Do you remember how much total those dollars were when they
were cut out of the budget?
Mr. Nalbone. No, I don't, ma'am.
Mrs. Thurman. Okay, because all of that would have to be,
from our perspective, scored for revenue costs and looked at. I
would just caution you not to play one industry off of another.
Some of us believe in our farmers and think food is a very
important issue, as well as our fuel costs.
Mr. Nalbone. Well, that subsidy is due to oversupply, and
this is different.
Mrs. Thurman. In some cases, but, nonetheless, we won't
argue that. I caution you not to do that, because remember that
the chairman of the Finance Committee on the Senate side is Mr.
Grassley, and he has interest in some of these other areas, as
well as alternative fuels. Just kind of a sidebar there. But we
would like you to be successful, because certainly we are here
to help the consumer.
But let me ask you this question: In one of your charts,
let me see if I can get this right, you mentioned the
residential rates have gone up about 30 percent. Your costs
have gone from 90 cents to $1.20. But, what we are hearing here
today from the consumer is much more dramatic than this. We
have heard from a consumer who thought that she was going to
have an increase, all of a sudden, from $150 to $600 per month.
I agree with what Mr. Holbrooke said about how we had a more
severe winter and there are some reasons for the increases. But
that certainly doesn't give us reasons for the total increases
people are facing.
So I am a little concerned about why this has happened.
With suggestions for drilling incentives, what are the
incentives to help people like them, other than just subsidies
from the Federal government?
Help me here. Whoever wants to answer that question, or who
would like to respond to me later with the answer to that
question, please do.
Mr. Heine. Well, I guess I can respond on what some of the
things we are looking at at National Fuel to try and reduce gas
costs even though we really don't have much influence on the
commodity. It is supply and demand that is causing that rise.
But one of the things we can do is look at other alternatives
of gas supply.
I mentioned, that the majority of our gas comes up through
the interstate pipelines. What we have done over the last year,
and we are continuing to look at, is storage alternatives where
you don't have to pay the pipeline supplier's year-round demand
charge just to have the gas delivered in the winter, because
our customers in western New York and Pennsylvania are heat-
What storage allows us to do is purchase gas more cheaply
in the summer and have it there in the winter without paying
the same high demand charges all year. You still may have the
problem of higher commodity cost even in the summer, but it is
one of the alternatives that we are looking at.
Mrs. Thurman. Sir, based on the tax cuts we are trying to
look at here, what incentives can we give you then to store it
at an earlier time? Is there anything that could be helpful? I
am sure that someone is going to require some kind of
additional storage tanks or whatever. Is there something either
already in the Tax Code or something that you have looked at
that would be to your benefit as a new tax incentive?
Mr. Heine. Well, the storage contracts that I am referring
to are usually regulated by the FERC. They are like interstate
pipelines. So, I am not sure. At least I can't think of
anything right now from a tax cost incentive that would
influence those, but I haven't really thought about it either.
Mrs. Thurman. Anybody else?
Mr. Holbrook. Yes. Just picking up on Mr. Heine's
observation of using less southwest deliverability, basically
what he is saying is using less of the long line pipeline
capacity that you are paying for, in some cases, 1,500 miles of
transportation pipeline. I believe I alluded earlier in my
presentation to the fact that we calculate that to work out to
be about $1.50 per every 1,000 cubic feet that are utilized by
the utility in this part of the world.
I believe our observation also was that even if the
producer here got a small fraction of that as an incentive to
go out and do more development, that could leave somewhere in
the nature of $1 per 1,000 cubic feet that could be available
as discount, as a reduction in the cost to consumers in this
region by spending a few more dollars here but a lot less
dollars in other parts of the country. So I think that is
something, at least from our perspective. It may not be a tax
issue, but it clearly is something, we think; and we would like
to see it encouraged in whatever manner you can encourage that
Mrs. Thurman. Ms. Lindsley and Ms. Sosinski, and other, we
really want you to know that we thank you for being here. I
can't even imagine what some have faced. I just lost my mother,
and I had her living with me in Washington. She had surgery and
had to be fed through a tube. Heating was very important
because she was cold and she was uncomfortable. I can really
say to both of you, you have my sympathy. Hopefully, with Amo,
we can help with your situations. I agree with you that one of
the issues of particular importance is the flexibility of the
programs that are available.
With high costs, particularly in situations like this, we
ought to have some ability to work with people that are having
problems, and not reject folks if they are a penny over the
income cap. There ought to be some sliding scale for costs and
income to really take into account, your good suggestion. We
appreciate your being so kind to give us these stories that we
can take back to our colleagues. Thank you very much.
Chairman Houghton. Thank you, Karen. Phil.
Mr. English. Just very briefly, Mr. Chairman. I would like
to thank all of the panelists for making a very substantial
contribution to our discussions and giving us concrete things
that we can take back to Washington.
Mr. Nalbone, I particularly appreciated your tax
suggestions. All of them make eminent sense to me.
The investment tax credit I think is something we ought to
revisit. Its elimination created a hole in our Tax Code that
has not been filled; and, obviously, this would benefit a far
broader range of industries than simply yours.
The passive loss rule and section 29 credit I do think
ought to be revisited as part of an energy bill.
Finally, you have hit on something that particularly rubs
my rhubarb, and that is the corporate AMT. The first bill I
introduced when I came to Congress was to repeal the corporate
AMT. I have reintroduced it every year. I do not feel it has
any justification in tax policy, and it clearly is a drag on
You have given me a fresh example of an area of the economy
which has been severely impacted by the corporate AMT, which is
a well-intentioned but nonsensical approach. I am particularly
grateful for your suggestion on how we could create an
exception to the corporate AMT, because, short of full repeal,
I am also committed to going in and knocking holes in the
So I thank you, and I thank all of you for taking the time
Mr. Chairman, I yield back the balance of my time.
Chairman Houghton. Thanks, Phil. I won't take very much
more of your time, but I want to ask a question.
Here you have the people who are responsible for the
sourcing, and here you have the consumers. We are not going to
be able as a panel, as Members of the Ways and Means Committee,
to rejigger the whole energy policy of this country. We can't
do that; and, even if we could, some of the critical issues
would be longer term things.
I think the thing that I am most interested in, and I hope
you join with me, is that we don't come back here next year at
this time and have the same situation. I hope we can soldier
through this winter.
But what specifically can we do now to be able to minimize
the impact of these different economic forces at work so that
you don't have the same situation with Ms. Sosinski; and, Jeff,
you were talking about the same thing. What do we do?
So I am going to ask all of you just to give us one
thought: What would you think that we as a group could do now
to be able to--not solve everything, but to do something which
would be able to help your cause and also everybody here?
Ms. Lindsley. I feel what you have done today, listening to
the consumer and hearing our needs and becoming aware of what
we need rather than the industry. The consumer, we are the ones
that pay their bills, and I think what you are doing right now
is what will help us in the long run, that you are hearing us,
that you are paying attention to what we are saying.
Chairman Houghton. All right, thank you very much. I hope
Ms. Sosinski. I realize that the government has guidelines
when they have their HEAP program, that there has to be a
cutoff, but I also feel that when you have these people that
have such high doctor bills, medical bills and prescription
bills, that somehow a certain percentage could be taken off
their income to help them be eligible for the HEAP program.
Chairman Houghton. All right. Yes, Jeff.
Mr. Aiken. From what I have seen, anytime there is an
industry that has been deregulated, I think the consumer ends
up picking up the great brunt of the burdens that are left, and
I think that maybe some regulations there to get away from this
vast deregulation thing that the governments have headed to for
so long--like I said, we have taken it pretty big time since
deregulations have started.
Chairman Houghton. Mr. Holbrook.
Mr. Holbrook. I think Mr. Aiken's observation is an
understandable one. I think if the market doesn't get an
opportunity to receive the proper signals, then I think it is
understandable to advocate the alternative, which is to have
government regulation. I mean, I think that is an
I would submit to you, this industry is capable of
operating in an efficient manner. It needs consistent signals
in terms of where it is valued. It needs a consistent energy
policy from the Federal Government in terms of where it wants
this energy industry to go.
As I said earlier, I think it is important that the tax
laws, your specific area of focus, show your interest in
encouraging increased drilling activity, increased supply,
because that increased supply won't bring the price down.
Chairman Houghton. Well, let me just follow up on this a
minute. You thought the consistency was more important than
almost anything else. Therefore, you said you used the $10
figure per 1,000 cubic feet versus $3. So you are suggesting
that the government, as it does in certain areas like the dairy
industry, put a floor?
Mr. Holbrook. I know that probably would be a reasonable
assumption, based upon my observation. I am fearful of the
government stepping in and trying to guesstimate where the
price should be. I think what we are suggesting is, for the
most part, that there be sort of consistent expectations of
where the prices have been.
If you look beyond this past year, they have been
relatively flat. I think it has been observed by a number of
parties and looked at by different studies as relatively flat
for a number of years.
What I am suggesting is just a few tinkerings where we are
talking here in terms of section 29 tax credits and allowing
just some of the expenses, some of the ongoing expense
associated with going out and exploring. I think just that
would be sufficient to send the signal that this government is
behind the industry.
I don't think there is a need to step in and establish even
a floor. I would be fearful of that, just as I would be fearful
of setting a ceiling. I think for the most part market sources
should work efficiently here, as I indicated earlier. I think
right now they just favor consistent management through tax
policy by reestablishing what you basically took out of favor
Chairman Houghton. Okay. Mr. Heine.
Mr. Heine. I think the focus of the New York State Public
Service Commission over the last 2 years has been deregulating
the merchant function in getting utilities out of merchant
function so that there is a free market. I think after this
winter the New York State Commission has sort of stepped back
and is taking another look. We don't have the same pressure to
get out merchant function.
The point I am making is that the drive that the New York
Commission had to get utilities out of merchant function I
think has been delayed by high costs. They don't seem to be
pushing as hard. The problem with us being caught in the middle
of knowing whether we are in the business or out of the
business, it was difficult to sign up for longer-term gas
For this next coming winter, we have received some
indications that it is okay to do longer-term pipeline deals
and gas supply deals. So, hopefully, with that change, we can
look at better alternatives next winter, like I mentioned
before, some storage contracts that are longer than a year-to-
year type deal. Hopefully, we can negotiate some good
Chairman Houghton. Rather than putting your hand in the
marketers, is what you are saying?
Mr. Heine. That is correct.
Chairman Houghton. Mr. Nalbone.
Mr. Nalbone. As I said, I would like to see the extension
of section 29; not only for the ongoing production but for new
drilling and offset wells and enact the laws that I suggested
as big changes. And try to establish them for the long term, so
we have a stable, long-range environment.
We have people that are not going into this field any more.
They would rather go into computer science, because they just
don't feel the industry will support their work, and with so
So we need long-term changes and whatever you can enact,
that we can rely on it for a long period of time.
Chairman Houghton. All right. Well, thank you very much. We
are all done.
[A member of the audience spoke out.]
Chairman Houghton. No comments. Please, sit down. Please
sit down. Officer, will you have this man sit down, please.
This is not the whole point of this.
I appreciate very much you doing this. We hope to get the
testimony out. If there is no further business, the meeting is
[Whereupon, at 2:20 p.m., the hearing was adjourned.]
[Submissions for the record follow:]
Statement of Mark Glickman, Director, Accurate Prices Program, and Kim
Rodgers, Research Associate, Redefining Progress, Oakland, California
Mr. Chairman and Members of the Subcommittee:
We welcome the opportunity to examine the role of Federal tax laws
in the energy sector. We could not agree more with the importance and
timeliness of these hearings. Americans are presented with the
opportunity to make critical choices about the future of our economy.
We can make sacrifices now, and channel our creative talents towards a
transition to sustainable energy use, or we can continue with the same
old policies that will lead us down the primrose path to recurring and
increasing energy shocks. Federal tax laws can continue to support
fossil fuels at the expense of sustainability, or they can help
Americans to make tough decisions that will benefit our future and the
future of our world.
We represent Redefining Progress, a nonprofit research and policy
organization based in Oakland, California. Redefining Progress develops
policies and tools that reorient the economy to care for all people and
nature first. The Accurate Prices program at RP advances market
mechanisms and incentives to internalize the economy's hidden social
and environmental costs.
Our priority is to encourage comprehensive, long-term policy
solutions that accomplish economic efficiency and equity. While the
policy discussion has so far emphasized increasing the supply of energy
by increasing fossil fuel production, a comprehensive energy policy
must encourage supply alternatives and equitable demand reduction. Oil
and gas production alone is a myopic lens with which to look at energy
The American economy depends heavily on fossil fuels, in part
because federal policy has kept them cheap and abundant. But fossil
fuels are finite, non-renewable resources, and their use causes
significant harm to the environment and to human health. At long last,
even the most skeptical admit the hard reality of climate change caused
by the burning of fossil fuels. Although technology has stretched
absolute supplies of oil and gas, the recognition that (1) world demand
will at some point outpace world supply capacity, and (2) absolute
supplies are ultimately finite, cannot be too far off.
Low-income, minority and tribal communities suffer disproportionate
health and ecological impacts from the energy industry and from energy
users, including coal and uranium mining, oil extraction and refining,
power plant sitings, dirty and unsafe industrial practices, and vehicle
pollution. Continued over-reliance on fossil fuel will
disproportionately impact the poor and communities of color, forcing
unacceptable trade-offs among basic necessities every time we hit
another price shock. Make no mistake about it, the longer we continue
down the fossil fuel path, the harsher and more widespread these
impacts will become.
Federal policy has long subordinated these costs to the priority of
keeping fossil fuel resources cheap and plentiful for Americans. The
government has done this through spending on research and development,
favorable tax treatment of fossil fuel industries, and allowing these
industries to use public lands, resources, and atmosphere cheaply.
Federal taxes should improve price signals reflecting scarcity and
environmental costs, not obfuscate them. In the case of energy, taxes
need to reflect the real scarcity of resources and the significant
social and environmental impacts of energy use. The numerous tax breaks
that subsidize fuel energy prices need to be phased out. Energy tax
laws should instead focus on leveling the playing field for renewable
sources of energy, reducing demand through conservation and efficiency
measures, and accounting for high health and environmental costs.
Consumers, our environment, and our economy will benefit from these
We offer several illustrative suggestions below. Our testimony is
organized around the three areas of focus as described in the
Subcommittee Hearing Advisory. We do not intend for this to be either
an exhaustive list of the possibilities or a complete analysis of the
impact of federal taxes on energy supply and demand, but rather a set
of forth principles and reforms that would move the American economy
onto a sustainable energy path for the future.
We have reason to believe that making this kind of turn in the
economy is possible. Europe is far ahead of us in making this
transition; most countries in the European Union have implemented
various forms of green tax reform that discourage fossil fuels. And
despite objections that Americans will not accept change, large
cultural shifts are clearly possible when Americans understand the need
and benefits of change--witness the sea change in attitudes towards
tobacco smoke and recycling.
1. Adequacy of Current Tax Incentives for Production and Conservation
Conventional economic theory holds that as oil becomes scarce,
rising prices will stimulate new, alternative resources to enter the
market. Federal taxes however, have played a significant role in
subverting market forces and have kept oil and gas prices artificially
low, at the expense of competing industries and the American consumer.
Conventional economic theory also argues that it is the task of
government to intervene when economic activities impose costs, or
``externalities'', on society that are not captured in the market, such
as pollution and global warming. Again, federal policy, including
federal tax laws, has failed to meet this task in the case of fossil
fuel energy. In short, current Federal tax laws encourage over-
production and over-use of fossil fuels.
Oil and gas industries have long enjoyed numerous tax breaks,
including accelerated depreciation of assets, tax credits for
production at marginal wells, and immediate expensing of intangible
drilling and development costs. It is difficult to think of another
American industry that is so heavily subsidized by our tax system.
These tax breaks are reinforced by the less obvious but equally
potent absence of taxes on health and environmental costs imposed by
the use of fossil fuels at no discernible cost to users and producers.
Instead these costs are passed on in the form of health problems and a
degraded environment (which create future health and cleanup costs),
and are paid most often by the least well-off in our society and around
the world. These costs will only continue to mount for future
generations unless we make hard decisions now.
Over the last decade Congress has instituted or broadened several
tax-based incentives for alternative energy sources. Although a
positive step, the approach has too piecemeal to induce the scale of
change required. Tax incentives to date have been small scale, only
partially targeted towards renewable energy, and continue to be
outpaced by tax breaks to oil and gas. The ``Section 29'' credit for
non-conventional fuels, for example, supports oil produced from shale
and tar sands, synthetic fuels produced from coal, and gas from biomass
while providing no benefits to wind or solar energy.
Last year, the Joint Committee on Taxation submitted testimony to
the Senate that examines the impact of federal taxes on energy policy.
It lists ten new tax breaks proposed for oil and gas production, as
compared to only five tax incentives for alternative fuels proposed in
the 106th Congress. All five alternative fuel proposals related to
alternative fuel vehicles. In other words all five proposals benefited
methanol, which requires almost as much fossil fuel to produce as it
replaces in end use, and which has been shown to reduce overall vehicle
Federal research and development spending has been equally stingy
when it comes to renewable energy. Only 11% of all federal R&D money
goes to renewable energy, less than half that spent on fossil fuels and
less than a fifth of the widely discredited nuclear power program.
Strikingly, energy efficiency, although receiving only 7% of research
dollars, generated the greatest return. The United States now uses 42%
less energy per unit of gross domestic product than in 1970.
For too long, these subsidies have allowed oil and gas companies to
maintain high profit margins. Subsidies have also kept retail prices
low enough to sap consumers' incentives to conserve energy and make it
difficult for renewable energy sources to enter the market. Tax
policies, by providing accurate signals regarding oil and gas, can play
a powerful role in stimulating change that places the consumer and the
economy as a whole ahead of the oil and gas industries.
Reduce and phase out tax breaks that benefit oil and gas
exploration and production, particularly at marginal wells and on
Reject new subsidies for so-called ``clean coal
technology'' and nuclear power, and eliminate existing subsidies.
Impose a market-based approach to impose charges on
emissions. This would be fairer, more efficient and more effective than
the structure of the currently proposed caps on NOX,
particulate matter from electric generation, CO2, and
Require that polluters pay for their greenhouse gas
emissions through either auctioned emissions permits or pollution
taxes. Redefining Progress strongly believes that the United States
should not give away rights to pollute the atmosphere. Revenues from
taxes or permits can be recycled into the economy in several ways that
improve economic efficiency and ensure distributional equity.
Provide additional tax incentives for renewable energy,
conservation and efficiency, such as:
Tax credits to individuals who buy clean and
efficient advanced-technology vehicles employing hybrid
Incentives for smart-growth development patterns
that conserve land, discourage sprawl, and reduce dependence on
The extension of the renewable energy production tax
credit, which encourages greater reliance on emerging renewable
energy sources;Incentives for advanced energy-efficient
buildings and appliances;
Expansion of credits to employers who provide public
Ensure that tax incentives favor renewable energy sources.
Current tax breaks, for example, provide benefits to ethanol fuel,
which requires almost as much fossil fuel in its production as it
replaces in end use.
Tax Provisions in the Proposed Senate Energy Bill
The tax provisions in the Energy Security Bill introduced
by Senator Frank Murkowski (R-Alaska) reinforce current tax bias in
favor of fossil fuels. The most recent versions of his bill include
continued tax credits for production from marginal oil and gas wells.
Royalties from offshore production would also be reduced when oil and
natural gas prices fall below a certain threshold level. These
provisions are economically inefficient, fail to move the U.S. economy
towards a rational energy policy, and provide large benefits to select
Senator Murkowski's bill currently includes provisions to
extend and expand the tax credit for renewable energy sources to wind
and closed-loop biomass. Tax credits for energy efficient hybrid
vehicles may also be included. These measures are a positive step, but
are not sufficient to rectify the imbalance of tax credits favoring oil
and gas. These should be the primary thrust of the legislation, rather
than an afterthought.
Causes of current shortages and high prices.
The bottom line is that oil and gas are finite resources in which
the United States has little domestic production capacity relative to
its demand. U.S. demand for oil has exceeded domestic production for
more than 30 years. Our relatively meager supply--total U.S. production
potential represents only about three percent of known world oil
reserves--means that no matter how much we step up drilling on federal
lands we are not going to come up with enough oil to actually influence
prices. We remain dependent on foreign oil powers, and subject to
unavoidable market fluctuations, as long as we remain dependent on oil,
whatever its source.
In addition, current forecasts estimate that world demand will
exceed worldwide production capacity within the next 2 to 17 years. The
world already consumes more than three times as much oil as is
discovered each year, and demand in Asia (which still uses dramatically
less energy per capita than the United States) is rising rapidly. The
critical point in energy markets is not when the world runs out of oil,
but the much more imminent point at which world demand exceeds supply
capacity. At that point, the costs of importing supplies and
maintaining world economic stability will increase exponentially.
Although certain policies such as the deregulation of electricity
generation in California have amplified world price volatility,
underlying price increases are a result of world events and policies
outside of our control. Our ability to avoid future price shocks
therefore depends largely on our ability to reduce our dependence on
Current power shortages in California have been blamed on
progressive health and environmental protections. This is a
smokescreen. The lack of generating capacity is a result of poor
planning and industry forecasts based on recession-level demand.
Uncertainty over the fate of deregulation legislation also contributed
to industry reluctance to invest in new generating capacity. Currently
there are nine approved power plants in the pipeline and a total of 12
new power plants have been approved within the last year.
California is just the tip of the iceberg. Virtually all Western
states have outgrown their electrical systems. According to the Los
Angeles Times, ``almost none of the West save Montana has increased its
power production at anything like the pace of its population growth
during the last decade. Despite the long economic boom of the 1990s,
which smiled especially on the West, several, such as Arizona, have
failed to complete a single new power plant.'' California's problems
have been blamed on a regulatory structure that stifles new plants, yet
its neighbors, some of them with much more lenient standards, find
themselves in the same boat.
Finally, transmission bottlenecks have exacerbated local supply
shortages. American power generation currently comes from a system of
large, centralized generators. Relying on a system of large
transmission lines carrying power over long distances introduces
another level of potential instability to power consumers.
The inequitable tax treatment of fossil fuels over
renewable energy sources undermines the beneficial market forces of
energy competition. Deregulation will only produce benefits if federal
tax laws are made to facilitate competition rather than thwart it.
A full and fair accounting, including social and
environmental costs, would likely reveal that states and localities are
better off developing local energy supplies, which most often means
renewable energy like wind and solar power. Tax policies should
explicitly encourage rather than hide the full accounting of energy and
Insurance against world energy supply shocks requires that
we reduce our demand for fossil fuels. Tax policies should encourage
conservation through direct financial incentives.
Impact of shortages and high prices on consumers and
In California, efficiency and conservation responses to shortages
and price increases have been impressive, but have been hindered by
retail price caps. Although the crisis has spurred new state-level
incentives for efficiency and conservation, the capping of retail
prices to consumers is undoubtedly slowing more widespread conservation
and efficiency responses.
The sudden, sharp nature of the price increases also makes it
difficult for consumers to adjust. In general, energy consumers are
more risk-averse to price volatility than to the absolute price of
power. Consumers are also less likely to believe that short-term shocks
reflect long-term price conditions and therefore have less incentive to
change their long-term consumption.
Repeated price shocks over the past thirty years reflect the
increasing fragility of a regulated system that tries to cover up
honest accounting of scarcity and environmental costs. Regulation,
however, did provide the benefit of protecting consumers from price
shocks, much as retail price caps are doing today. While competitive
prices should fluctuate to reflect scarcity, policies should aim to
equip consumers, particularly low-income consumers, and businesses with
the knowledge and choices they need to reduce energy demand and
insulate themselves from shocks.
As we have seen from anecdotal evidence of households unable to
afford sudden sharp rate increases, price volatility hits low-income
Americans particularly hard. Not only do low-income Americans suffer
disproportionate health impacts of fossil fuels, they also bear a
disproportionate amount of the financial risk associated with reliance
Assistance programs, such as the Low Income Heat and Energy
Assistance Program (LIHEAP), and block rate price structures, can help
low-income households deal with long-term energy price increases, but
these programs are less well-equipped to deal with the types of crises
we are now experiencing in both the West and Northeast.
Prices should be allowed to reflect scarcity and health
and environmental costs. It is possible for prices to more accurately
reflect condition of scarcity without forcing Americans to choose
between heat and food. Lifeline assistance to low-income households can
be provided through a block rate pricing structure--recently authorized
in California energy markets, and used in water markets. This structure
guarantees a base amount at a lower rate, insulates necessity level of
power usage, and implements higher prices above a base amount. Programs
such as LIHEAP can be expanded.
Energy conservation and the promotion of renewable energy
choices should become a high priority in electricity deregulation
efforts. Deregulation must also include measures that protect consumers
and businesses from extreme price volatility and that ensure access to
necessity level energy use.
Redefining Progress research shows that, combined with
reductions in other taxes, it is possible to raise fossil fuel energy
prices--through a carbon tax or auctioned permits, for example--with
little and possibly even positive impacts on economic growth and
Over 2,500 economists, eight Nobel Prize winners among
them, have stated that the United States can most effectively implement
climate policies through market-based mechanisms, such as carbon taxes
or the auction of emissions permits. The revenue generated from such
policies can be used to pay down interest on the deficit or to lower
existing taxes, and may in fact improve U.S. productivity in the longer
Mr. Chairman, and Members of the Committee, there are no easy
answers to the energy problems facing our nation today and in the
future. Tough choices need to be made, and we welcome the opportunity
to discuss the details of the recommendations we have made in the
Statement of the American Petroleum Institute
These comments are submitted by the American Petroleum Institute
(API) for inclusion in the record of the March 5, 2001 House Ways and
Means Subcommittee on Oversight hearing on the impact of federal tax
laws on the cost and supply of energy. API represents more than 400
member companies involved in all aspects of the oil and gas industry,
including exploration, production, transportation, refining, and
Over the past year, U.S. energy consumers have experienced sudden
increases in oil and gas prices, and extreme regional price volatility
in response to events such as unusual weather, and refinery and
transportation accidents. Such events have brought national energy
policy to the forefront of public debate, with a prominence not seen
for several decades. These events have also served as a vivid reminder
that oil and natural gas remain essential to fueling the growth of both
the U.S. and the world economies. Together, these products supply over
61 percent of the world's energy needs, and 62 percent of U.S. energy
needs, and their role in fueling future economic growth is expected
only to increase.
The Department of Energy's (DOE) most recent International Energy
Outlook estimates that by 2020, world energy demand will be more than
60 percent higher than in 1997. Three-quarters of that total energy
demand growth is expected to be for oil and gas, so that the share of
oil and gas in the global energy mix will rise to 66 percent by 2020.
An ever-increasing share of this growth, especially in the United
States, is expected to be for natural gas due to its comparative energy
efficiency, clean burning characteristics, and abundance of supplies in
From strictly a resource standpoint, there is no reason to doubt
that the resource base is adequate to satisfy expected growth in energy
demand for well beyond the next several decades. Global oil and gas
reserves are at or near all time highs. Global oil reserves have
reached 1.03 trillion barrels, over a third higher than a decade
earlier, and sufficient to last 42 years at current production rates.
Global gas reserves have reached 5278 trillion cubic feet (TCF), more
than 20 percent higher than a decade earlier. Furthermore, technology
has greatly increased industry's ability to pursue this development
without adverse environmental impact. Advanced seismic technology,
horizontal drilling, and a variety of new control technologies greatly
reduce the environmental footprint associated with oil and gas
Nevertheless, there are a number of challenges that potentially
stand in the way of realizing this potential. Generally, these problems
stem not from resource scarcity, but from self-imposed policy
restrictions on key remaining domestic supply prospects, an
insufficient U.S. downstream infrastructure, resurgence of OPEC market
power in global oil markets, and regulations that have diminished the
flexibility of the existing infrastructure to respond effectively to
unexpected events. In addition, the technology and increasingly
sophisticated production methods necessary to secure adequate supplies
of oil and natural gas are expensive and will require huge capital
investments by U.S. oil and gas companies. For example, DOE projects
that producers will have to invest some $650 billion through 2015 in
order to meet the anticipated growth in U.S. natural gas demand alone.
While the United States has a strong strategic and economic
interest in maintaining a vibrant domestic oil and gas industry, we
also need a wide diversity of international supplies. For over half a
century, the United States has relied to varying degrees on imports for
a portion of its oil needs. Over the last 30 years, imports as a
percentage of U.S. petroleum deliveries have risen from 23.3 percent to
55.6 percent. As our reliance on global oil markets has grown, we have
learned that this dependence carries both opportunities and risks. On
the one hand, it affords us access to energy supplies less costly than
could be produced domestically. On the other hand, it exposes us to two
inherent risks associated with that marketplace, namely the potential
for short-term supply interruptions, and the potential for long run
vulnerability to adverse actions by OPEC. But the experience of growing
dependence has also taught us a few important lessons about the
potential for U.S. policies to successfully manage these risks, and the
hazards of misguided policies that have aggravated them.
Recognizing that 90 percent of the world's proven oil reserves are
in the hands of foreign government-controlled oil companies (more than
two-thirds of those are in the Middle East), U.S. energy security is
best served by U.S. companies being competitive participants in the
international energy arena. If the U.S. oil and gas industry is not
provided the tools to economically compete overseas, those energy
resources located abroad will still be produced. However, they will be
produced without the security of supply that would be realized with
U.S. oil and gas companies producing the oil, without any benefit to
the U.S. economy, and without U.S. companies, their shareholders, or
American workers deriving any direct or indirect income from the
foreign production activity. The U.S. oil and gas industry already
possesses the experience and technical prowess that will ensure success
at finding and producing oil and gas from sources all over the world.
However, U.S. energy policies must support this necessary international
risk taking and encourage the tremendous capital investment that will
be needed to meet U.S. and global energy demand growth.
Currently, the ability of the U.S. oil and gas industry to compete
globally is hampered by the unintended consequences of two sets of U.S.
policies, namely the adverse tax treatment of foreign source income
earned by U.S. companies operating overseas, and the persistent
tendency of the United States to utilize unilateral economic sanctions
against oil producing countries as an instrument of foreign policy. The
U.S. international tax regime imposes a substantial economic burden on
U.S. multinational companies, and to an even greater degree on U.S. oil
and gas companies, by exposing them to potential double taxation, that
is, the payment of tax on foreign source income to both the host
country and the United States. In addition, the complexity of the U.S.
tax rules imposes significant compliance costs. As a result, U.S. oil
and gas companies are forced to forego foreign exploration and
development projects based on lower projected after-tax rates of
return, or they are preempted in bids for overseas investments by
global competition not subject to such complex rules. Congress can help
to stem further losses in the global competitive position of the U.S.
oil and gas industry by adopting tax measures that allow U.S. oil and
gas companies to compete more effectively both at home and in the
We cannot afford to constrain the development of oil and natural
gas supplies at home or abroad without regard to the potential
vulnerability threatened by such neglect in light of energy demand
growth projections. It must be remembered that oil and gas projects
require large amounts of capital and are high risk, long lead-time
ventures. The tax treatment of the financing and structuring of these
ventures is one of the essential elements of decisions whether to
proceed. If allowed to compete, our industry has the capability to
capture a significant share of the expected growth in demand, limiting
OPEC's marketshare and contributing to the diversity of global supply.
But barriers to supply expansion offer the threat of renewed
vulnerability. Given this prospect, recent events should serve as a
wakeup call for the United States to adopt a national energy policy,
which includes revised tax rules, that begins to tear down these
II. DOMESTIC TAX PROVISIONS
While most other countries encourage energy development, flawed
public policies--especially discriminatory tax provisions, excessive
restrictions on access to federal lands and unreasonably burdensome
regulations--continue to place substantial restrictions on the
exploration and production of oil and gas in this country. Moreover,
continued high corporate tax rates limit the capital available to U.S.
oil and gas companies at the very time huge investments in exploration
and production must be made to ensure the nation's energy future. The
most important thing Congress and the Administration can do is enact a
national energy plan that will change these policies to promote the
environmentally sound and economic recovery of domestic reserves, thus
helping reduce U.S. reliance on imported oil.
In 1999, a united oil and gas industry proposed a series of tax
changes designed to spur domestic oil and gas production. The need for
these changes has only intensified over the last couple of years as
OPEC has reestablished its ability to profoundly impact the available
supply of oil--and most importantly, the price paid by consumers.
While not the sole answer to ensuring adequate oil and gas supplies
for U.S. energy consumers, tax measures such as the expensing of
geological and geophysical (G&G) costs and delay rental payments, a
marginal domestic oil and natural gas well production credit,
eliminating limitations on use of percentage depletion of oil and gas
by independent producers, and Alternative Minimum Tax (AMT) relief will
promote greater U.S. exploration and production. Most of these items
were previously adopted by both the House of Representatives and the
Senate as part of the conference report to the Taxpayer Refund and
Relief Act of 1999 (H.R. 2488), which was ultimately vetoed by Former
President Clinton. Other provisions, including an expansion of the
enhanced oil recovery (EOR) credit to include certain nontertiary
recovery methods and a heavy oil production credit, would further
encourage increased domestic petroleum activity.
Geological and Geophysical Expenses
Oil and gas exploration companies incur huge up front capital
expenditures, including geological and geophysical (G&G) expenses, in
their search for new oil reserves. G&G expenses include costs incurred
for geologists, surveys, and certain drilling activities, which help
oil and gas companies locate and identify properties with the potential
to produce commercial quantities of oil and/or gas. Currently, these
costs must be capitalized, suspended and then amortized over a period
of years in the form of cost depletion after production begins. Forcing
oil and gas companies to capitalize G&G costs exacerbates the economic
burden imposed by these significant cash outlays that must be made
prior to or at the beginning of an exploration project. In order to
encourage the discovery of new domestic oil and gas reserves, and thus
increase overall supply, Congress should pass legislation to permit the
expensing of G&G costs.
In addition to having been included in the vetoed 1999 tax bill,
proposals to expense both G&G costs and delay rental payments were
included in S. 2265, introduced by Sen. Kay Bailey Hutchison in March
2000, and S. 2557, the National Energy Security Act of 2000, introduced
by Senate Majority Leader Trent Lott in May of last year. Even Former
President Clinton expressed support for these tax provisions in his
March 2000 proposal to ``strengthen America's energy security.''
Finally, these proposals are included in S. 389, the National Energy
Security Act of 2001, introduced in the Senate on February 26, 2001.
Delay rentals are paid by oil and gas exploration companies to
defer the commencement of exploration and production on leased property
without forfeiting the lease. Treasury regulations and case law clearly
support the option on the part of a lessee to expense or capitalize
delay rental payments, and until 1987, this right was essentially
uncontested. However, with the 1986 enactment of the Section 263A
uniform capitalization rules, the IRS began to challenge the
deductibility of delay rentals during audits. In 1997, the IRS
unequivocally adopted the position that for tax years beginning after
December 31, 1993, delay rentals had to be capitalized unless the
taxpayer could establish that the lease was acquired for some reason
other than development. This position ignores forty years of history
and long-established regulations. Congress should pass legislation that
clarifies and reaffirms the long-standing rule that has permitted delay
rentals to be expensed rather than capitalized. By decreasing the
economic burden of paying delay rentals, more capital will be available
for exploration and production.
Marginal Well Production Credit
A marginal well production credit of $3 per barrel for the first
three barrels of daily production from an existing marginal oil well,
and a 50 cent per thousand cubic feet (Mcf) tax credit for the first 18
Mcf of daily natural gas production from a marginal gas well, would
help producers ensure the economic viability and slow the shutting-in
of marginal wells. Like the proposed AMT relief, the credits would
phase in and out as oil and natural gas prices fall and rise between
specified levels providing the greatest benefit to producers when
prices are low. Finally, the credit should be allowed against both
regular and alternative minimum tax and to be carried back ten years.
This marginal oil and gas well production credit proposal is
included in S. 389, the National Energy Security Act of 2001.
Another way Congress could assist the domestic industry would be to
permit, by annual election, elimination of the 65 percent taxable
income limitation on percentage depletion, as well as elimination of
the 100 percent net income limitation. Independent producers and
royalty owners should be permitted to carry forward percentage
depletion deductions for ten years. These proposals also are included
in S. 389.
Alternative Minimum Tax
The Alternative Minimum Tax (AMT) was intended as an advance
payment of federal income tax, and therefore, AMT payments are
creditable in future years, though only against regular tax liability
and not the taxpayer's tentative minimum tax. However, companies within
the capital intensive petroleum industry often find themselves in a
position where they are consistently unable to use their AMT credits
because their regular tax liability in future years does not exceed
their tentative minimum tax for those years. For those companies, the
AMT constitutes a permanent tax increase and decreases the economic
viability of certain domestic operations.
Recently, the problems associated with the AMT have again been all
too real for many domestic oil and gas producers. Oil and gas drilling
activity has accelerated rapidly since 1999 in response to
thephenomenal growth in demand for oil and natural gas. However, a
portion of this activity had to be curtailed, not because of a lack of
product demand, but, rather, because the AMT preference item for
intangible drilling and development costs (IDCs) exposed those
producers to the AMT and rendered that additional drilling activity
uneconomic. In other cases, producers were not in an AMT position
because their regular tax liability exceeded their tentative minimum
tax. However, the ability of those producers to utilize accumulated AMT
credits was diminished due to a higher tentative minimum tax amount
resulting from the IDC preference item. In both instances, the AMT
served to restrict new oil and gas drilling activity at the very time
the nation was seeking to spur oil and natural gas production.
Many of the AMT's most discriminatory provisions are targeted at
the U.S. oil and natural gas industry. In order to reverse this
inequity and promote capital investment in the oil and gas sector,
Congress should, at a minimum, eliminate the preference for IDCs, fully
eliminate the depreciation adjustment for oil and gas assets, eliminate
the impact of IDCs and depreciation on oil and gas assets from the
Adjusted Current Earnings (ACE) adjustment, and permit the EOR and
Section 29 credits to reduce tentative minimum tax. This proposed AMT
relief would phase in and out as oil and natural gas prices fall and
rise between specified levels, thereby providing the greatest
assistance to producers in times of low prices.
Another non-industry specific way to mitigate the adverse impact of
the AMT would be to allow AMT credits to be applied against future
tentative minimum tax. This specific provision was included in the
vetoed 1999 tax bill.
The Enhanced Oil Recovery (EOR) credit provides a credit equal to
15 percent of costs attributable to qualified enhanced oil recovery
projects. Since the enactment of the EOR credit in 1990, new
technologies have greatly enhanced the ability of oil producers to
economically recover additional domestic reserves from existing wells
with minimal environmental impact. By extending the EOR credit to
certain nontertiary production methods such as horizontal drilling,
gravity drainage, cyclic gas injection, and water flooding, the
economic viability of these oil recovery methods would be greatly
enhanced. In turn, the up to 70 percent of an oil well's reserves that
otherwise would be left in the ground could be added to the nation's
available energy supply.
Heavy Oil Production Credit
So-called ``heavy oil'' is one source of domestic petroleum that is
significantly less economic, but represents a key component of the U.S.
energy base. Currently, heavy oil accounts for over 11 percent of U.S.
production. However, its potential is far more significant because the
measured U.S. heavy oil resource base is over 100 billion barrels.
Heavy crude oil is generally characterized by its high specific gravity
or weight, as well as its high viscosity or resistance to flow. Because
of these characteristics, heavy oil is substantially more difficult and
expensive to extract and refine than other types of oil. Additionally,
this oil is less valuable because a smaller percentage of high-value
petroleum products can be refined from a barrel of heavy oil than from
a barrel of higher quality crude oil. A heavy oil production tax credit
would help the nation maximize its domestic energy supply by making
that resource economic to produce.
III. RELIEF FROM DISCRIMINATORY INTERNATIONAL TAX RULES
In order to survive, the oil and gas industry must operate where it
has access to economically recoverable oil and gas reserves. Since the
opportunity for domestic reserve replacement has been substantially
restricted by federal and state government policies, the tax treatment
of international operations is critical to the industry's continued
ability to supply the nation's hydrocarbon energy needs.
With OPEC market share and influence once again on the rise, and up
to 90 percent of the world's proven oil reserves in the hands of
foreign government-controlled oil companies, a key concern of federal
policy should be that of maintaining the global supply diversity that
has been the keystone of improved energy security for the past two
decades. The principal tool for promotion of that diversity is active
participation by the U.S. oil and gas industry in the development of
these new frontiers. Therefore, while federal tax policy should promote
domestic oil and gas production, it should also seek to enhance the
competitiveness of U.S. companies operating abroad.
Tax measures that would enable U.S. companies operating overseas to
better compete in the global oil and gas business environment include:
reforming the foreign tax credit (FTC) rules, particularly the
proliferous FTC ``baskets,'' repealing the Section 907 foreign tax
credit limitations, extending carryback and carryforward periods for
foreign tax credits, accelerating repeal of separate limitation basket
requirement for dividends received from 10/50 companies (i.e., foreign
companies owned between 10 and 50 percent by U.S. owners), providing
look-through treatment for sales of partnership interests, providing
look-through treatment for interest and royalties from 10/50 companies,
allowing recapture of overall domestic losses, and modifying the
interest allocation rules to permit elective allocation on a world-wide
The Foreign Tax Credit Rules Need Reform
Since the beginning of federal income taxation, the U.S. has taxed
the worldwide income of U.S. citizens and residents, including U.S.
corporations. The FTC was intended to allow a dollar for dollar offset
against U.S. income taxes for taxes paid to foreign taxing
jurisdictions in order to avoid double taxation of that income earned
abroad. However, the many limitations on the FTC in our current rules
often results in U.S. taxpayers paying tax on the same items of income
in more than one jurisdiction.
The FTC is intended to offset only U.S. tax on foreign source
income. Thus, an overall limitation on currently usable FTCs is
computed by multiplying the tentative U.S. tax on worldwide income by
the ratio of foreign source income to worldwide taxable income. The
excess FTCs can be carried back two years and carried forward five
years, to be claimed as credits in those years within the same
respective overall limitations.
However, since enactment of the Tax Reform Act of 1986, the overall
limitation must be computed separately for not less than nine
``separate limitation categories'' or ``baskets.'' Some of the separate
limitations apply for income: (1) whose foreign source can be easily
changed; (2) which typically bears little or no foreign tax; or (3)
which often bears a rate of foreign tax that is abnormally high or in
excess of rates of other types of income. In these cases, a separate
limitation is designed to prevent the use of foreign taxes imposed on
one category to reduce U.S. tax on other categories of income. There
are other examples of normal active-business types of income that also
must be calculated separately. Examples of these normal business-types
of foreign source income include dividends received from 10/50
companies, gains on the sale of foreign partnership interests, and
payments of interest, rents and royalties from non-controlled foreign
corporations and partnerships.
Section 907: Foreign Oil and Gas Extraction Income and Foreign Oil
Under the separate basket rules, foreign oil and gas income falls
into the general limitation basket for purposes of computing the
overall FTC limitation. But before determining this limitation for
generaloperating income, U.S. oil and gas companies must first clear an
additional tax credit hurdle.
Internal Revenue Code Section 907 limits the utilization of foreign
income taxes on foreign oil and gas extraction income (FOGEI) to that
income multiplied by the current U.S. corporate income tax rate. The
excess credits may be carried back two years and carried forward five
years, with the creditability limitation of Section 907 being
applicable for each such year.
Congress intended for the FOGEI and foreign oil related income
(FORI) rules to purport to identify the tax component of payments made
by U.S. oil companies to foreign governments. The goal was to limit the
FTC to that amount of the foreign government's ``take'' which was
perceived to be a tax payment versus a royalty paid for the production
privilege. But even the so-identified creditable tax component of those
payments should not be used to shield the U.S. tax on certain low-taxed
other foreign income, such as that from shipping.
These concerns have been adequately addressed in subsequent
administrative rulemaking and legislation. In 1983, after several years
of discussion and drafting, Treasury completed the ``dual capacity
taxpayer rules'' of the FTC regulations, which set forth a methodology
for determining how much of an income tax payment to a foreign
government will not be creditable because it is a payment for a
specific economic benefit. Such a benefit could, of course, also be
derived from the grant of oil and gas exploration and development
rights. These regulations have worked well for both IRS and taxpayers
in various businesses (e.g., foreign government contractors), including
the oil and gas industry. In addition, the multiple separate basket
rules enacted in 1986 have restricted taxpayers from offsetting excess
FTCs from high-taxed income against taxes due on low-tax categories of
Since concerns underlying Section 907 have been adequately
addressed in subsequent legislation and rulemaking, that tax code
provision has been rendered obsolete. Furthermore, Section 907 has
raised little, if any, additional tax revenue because excess FOGEI
taxes would not have been needed to offset U.S. tax on other foreign
source income. Nevertheless, oil and gas companies continue to be
subject to burdensome compliance work. Each year, they must separate
FOGEI from FORI and the foreign taxes associated with each category.
These are time consuming and labor intensive analyses, which have to be
replicated on audit. Section 907 should be repealed as obsolete. This
would promote simplicity and efficiency of tax compliance and audit
with minimal loss of revenue to the government.
In fact, the House and Senate passed legislation that would have
repealed Section 907 during the 106th Congress. Unfortunately, Former
President Clinton vetoed that bill, H.R. 2488.
Foreign Tax Credit Carryover Rules
The inclusion of income taxes paid to foreign countries within a
taxpayer's FTC is limited to the U.S. tax owed on that taxpayer's
foreign source income. Thus, an overall limitation on currently usable
FTCs is computed by taking the ratio of foreign source income to
worldwide taxable income and multiplying this by the tentative U.S. tax
on worldwide income. As noted above, excess FTCs can be carried back to
the two preceding taxable years, or to the five succeeding taxable
years, subject in each of those years to the same overall limitation.
If the credits are not used within this time frame, they expire.
Excess credit positions are frequent because of the ever-increasing
limitations on the use of FTCs, coupled with the differences in income
recognition between foreign and U.S. tax rules. Many of these
differences occur as a result of timing variations resulting from
different depreciation methods and useful lives. The present law's
short seven-year total utilization (two-year carryback and five-year
carryforward) period causes credits to be lost, most likely resulting
in double taxation.
Strict adherence to the long-standing U.S. policy of not taxing the
same income twice would seem to dictate that all carryover periods be
eliminated in order to ensure that foreign source income is never
exposed to double taxation. However, a practical alternative proposal
to reduce the existing risk of double taxation would permit five-year
carryback and 15-year carryforward periods for excess FTCs. At the very
least, a two-year carryback and 20-year carryforward period would
provide greater consistency within the tax code by aligning the FTC
carryover periods to those provided for net operating losses.
Dividends Received From 10/50 Companies
The 1997 Tax Act repealed the separate basket rules for dividends
received from 10/50 companies, effective after the year 2002. A
separate FTC basket will be required for post-2002 dividends received
from pre-2003 earnings. Because of these limitations, U.S. companies
operating overseas will continue to forego foreign projects through
noncontrolled 10/50 corporations. When fully implemented, the repeal
will remove significant complexity and compliance costs for taxpayers
and foster their global competitiveness.
The repeal of the separate limitation basket requirement with
respect to dividends received from 10/50 companies therefore should be
accelerated. This provision was included in the last few Clinton
Administration budget proposals, as well as in the vetoed 1999 tax
bill, H.R. 2488. In addition, H.R. 2488 appropriately would have
eliminated the requirement of maintaining a separate limitation basket
for dividends received from earnings and profits accumulated before the
Look-Through Treatment for Sales of Partnerships
The distributive share of an at least 10 percent U.S. partner of a
foreign partnership follows the partnership's income FTC basket
classification. On the other hand, no such look-through applies to the
gain on the sale of a 10 percent or more partnership interest in a
foreign partnership. U.S. tax rules treat the gain as separate basket
passive income, thereby limiting the opportunity of FTC utilization.
Economically, any gain on the sale of the partnership interest is
attributable to unrealized or undistributed income. It is not only
inequitable but also counterintuitive for the legal form of the value
realization to control the FTC basket characterization. Accordingly,
for a 10 percent or greater partnership interest, look-through
treatment should apply to the gain in the same way that it applies to
the distributive share of partnership income.
Look-Through Treatment for Interest, Rents, and Royalties with Respect
to Non-Controlled Foreign Corporations and Partnerships
U.S. oil and gas companies are often unable, due to government
restrictions or operational considerations, to acquire controlling
interests in foreign corporate joint ventures. Look-through treatment
for interest, rents and royalties received from foreign joint ventures
should be available, as it is in the case of distributions from a
controlled foreign corporation (CFC).
Current tax rules also require that payments of interest, rents and
royalties from noncontrolled foreign partnerships (i.e., foreign
partnerships owned between 10 percent and 50 percent by U.S. owners)
must be treated as separate basket income to the joint venture
partners. Again, as in the case of corporate joint ventures, look-
through treatment should be extended to these business entities. This
would abolish distinctions in treatment of distributions that are based
on participation percentages that may be beyond the control of the U.S.
Recapture of Overall Domestic Losses
When foreign source losses reduce U.S. source income (overall
foreign loss or OFL) in a tax year, the perceived tax benefit has to be
``recaptured'' by resourcing foreign source income in a subsequent tax
year as domestic source income. Of course, this re-characterization
reduces the ratio of foreign source income to total income, which in
turn reduces the ratio of tentative U.S. tax that can be offset against
foreign taxes. However, if foreign source income is reduced by U.S.
source losses, there is no parallel system of ``recapture.'' Taxpayers
are not allowed to recover or recapture foreign source income that was
lost due to a domestic loss, resulting in the double taxation of such
income. The U.S. losses thus can give rise to excess FTCs, which, due
to the FTC carryover restrictions, may expire unused. Only a
corresponding re-characterization of future domestic income as foreign
source income will reduce the risk that FTC carryovers do not expire
Allocation of Interest Expense
Current law requires the interest expense of all U.S. members of an
affiliated group to be apportioned to all domestic and foreign income,
based on assets. However, the current rules deny U.S. multinationals
the full U.S. tax benefit from the interest incurred to finance their
U.S. operations. For example, if a domestically operating member of a
U.S. tax consolidation with foreign operations incurs interest to
finance the acquisition of new environmental protection equipment, a
portion of the interest will be allocated against foreign source income
of the group and therefore become ineffective in reducing U.S. tax. A
U.S. subsidiary of a foreign corporation (or a U.S. corporation--or
affiliated group--without foreign operations) would not suffer a
In addition, unless allocation based on fair market value of assets
is elected, allocation of interest expense according to the adjusted
tax bases of assets generally assigns too much interest to foreign
assets. For U.S. tax purposes, foreign assets generally have higher
adjusted bases than similar domestic assets because domestic assets are
eligible for accelerated depreciation while foreign-sited assets are
assigned a longer life and limited to straight-line depreciation. For
purposes of the allocation, the earnings and profits (E&P) of a CFC is
added to the stock basis. Since the E&P reflect the slower
depreciation, the interest allocated against foreign source income is
Rules similar to the Senate version of interest allocation in the
Tax Reform Act of 1986, as well as those included in the vetoed 1999
tax bill, would help to alleviate these current anti-competitive
results. The allocation group would then include all companies that
otherwise would be eligible for U.S. tax consolidation, but for their
being foreign corporations. Additionally, ``stand alone'' subsidiaries
could then elect to allocate interest on certain qualifying debt on a
mini-group basis, i.e., looking only to the assets of that subsidiary,
At the very least, taxpayers should be allowed to elect to use the
E&P bases of assets, rather than the adjusted tax bases, for purposes
of allocating interest expense. Use of E&P basis would produce a fairer
result because the E&P rules are similar to the rules now in effect for
determining the tax bases of foreign assets.
Our industry strongly supports tax law changes designed to
encourage increased domestic petroleum activity, which, in turn, will
help to expand overall product supply in the United States. Expansion
of available supply is critical to meeting DOE projections of a 33
percent increase in U.S. petroleum demand and a 62 percent increase in
U.S. natural gas demand by 2020. Existing oil and gas industry tax
incentives, while helpful, do not begin to address how this nation will
encourage the massive capital investment needed to meet this demand
growth. Positive tax changes will help promote the use of new
technologies for exploration, development and production, and help
maintain the economic viability of mature production sites.
Notwithstanding the benefits these new tax provisions would provide,
their potential to help increase and sustain domestic petroleum
production will be limited unless Congress also acts to reduce
restrictions on access to federal lands and to rationalize the
increasingly burdensome regulatory apparatus. Moreover, it must be
recognized that expected growth in U.S. demand for oil and natural gas
cannot be met merely through increased U.S. production. While U.S.
reliance on imported oil can be reduced, restoring the global
competitive position of the U.S. oil and gas industry through changes
in U.S. international tax policy will be crucial to ensuring that U.S.
consumers continue to enjoy adequate and cost-competitive supplies of
our industry's major products.
Statement of Michael Sopp, Anchor Glass Container, Elmira, New York
Mr. Chairman, members of the Committee:
Thank you for the opportunity to tell you what runaway energy
prices are doing to our business, our employees, our customers, and our
region. I'll be brief.
Who We Are
My name is Michael Sopp, and I am the general manager of the Anchor
Glass Container plant in Elmira, New York not far from here, in Chemung
County. A total of 365 of us work at the plant, where we make glass
containers for customers who produce soups, sauces, juices, beer, soft
drinks and other foods and beverages. We manufacture 540 million glass
containers a year in Elmira. Our business has been growing
incrementally and, unlike so many of the trendier dot.coms, it has
grown through a combination of quality production, sound capital
investment, and good old-fashioned sales work.
The Anchor Glass Container plant in Elmira has an annual payroll of
over $19 million. The annual economic impact to the greater Chemung
County area is over $90 million. Over all, glass manufacturing
represents hundreds of millions of dollars to the economy of the
Anchor Glass is, in many ways, representative of many businesses in
this region that manufacture a variety glass products, from fiber
optics to crystal vases. Manufacturing glass containers is an old
business, and an important one to the region, providing a good living
for generations of families along New York's Southern Tier. However,
because the business has been around a long time and because there are
so many competitors, our profit margins are naturally low.
Now, Mr. Chairman, consider the fact that the manufacturing of
glass is also an energy intensive business. Our manufacturing process
uses high heat in large furnaces to turn sand and soda ash, common
elements from the earth, into glass. The energy we use in those
furnaces represents about 13 percent of the cost of making a ketchup
bottle, a pickle jar or a jug for cranberry juice. That's a very high
percentage of our cost, compared to many other manufacturers. So you
can see why we have to manage energy costs very carefully. And we do.
By necessity, we have become sophisticated and experienced buyers
of energy--overwhelmingly naturalgas. We have people at corporate
headquarters who constantly monitor energy prices, plan ahead, work to
manage our risk and get the best energy prices. But even our experience
and care cannot protect us in the current environment.
Mr. Chairman--the current cost of natural gas is literally killing
our business and threatening our entire region with severe economic
consequences--and I am not even speaking of the heating bills that
every employee at our plant has to face when she or he goes home. Allow
me to refer to the attached charts in the way of an illustration.
In 2000, natural gas prices were 73% greater than the five-year
average for the period 1995 through 1999 (see Appendix 1).
For the first quarter of 2001, natural gas prices were an
astounding189% greater than the five year average for the first quarter
periods 1996 through 2000 (see Appendix 2).
Increases of this magnitude cannot be passed through to our
customers. As a result, much needed dollars that should be used for
capital up-keep and production improvements must be spent to pay our
gas bill. This, is turn, limits our ability to continue to contain the
costs associated with the manufacturing process that will allow us to
maintain our market share and remain competitive in the global market.
Anchor Glass Container Corporation operates a family of sixteen
glass container manufacturing facilities across the U.S. and Canada,
all of which are faced with the same issues of sky-rocketing energy
costs associated with the market price for natural gas. However, the
Elmira plant is faced with the additional inequity of excessive
intrastate transportation and distribution rates from the Local
Distribution Company (LDC). In fact, much of the year, the cost to
transport natural gas from the production area of Texas to the city
gate of our LDC in New York is less than the distribution rate to get
the gas from the LDC to our plant. This further hinders our ability to
compete with our sister plants for production that can be placed at any
number of plants across North America.
Effect on Our Business and Employees
The increase in energy costs has affected our profitability of
operations and can inevitably lead to production cutbacks. Capital
equipment rebuilds will be delayed, plans for new expansion become
questionable and a downward cycle begins to take hold. The result of
high energy costs will translate into lost wages and jeopardize
continued economic growth and prosperity for the Chemung County region.
This is a trend that must not be allowed to continue. Collectively and
individually the manufacturers and other businesses in the Chemung
County regions have worked very hard to grow the industrial base of the
Southern Tier economy.
Effect on Our Customers
While our customers have been understanding of the burden of
increasing energy costs and partnered with us through participation in
a temporary energy surcharge, the offset from the surcharge is only a
fraction of the total cost. Much like the glass container industry,
many of our customers simply can not pass through higher prices in the
form of price increase without jeopardizing their market position. And
so the cycle of rising energy prices begins to affect an economic
downturn much larger than just the glass container industry.
We do not know whether the resolution of this crisis, if there is
one, lies in tax policy, energy policy, energy conservation programs, a
combination of these, or some entirely different combination. But we do
know that all of us at the Elmira plant of Anchor Glass Container
Corporation--if not all of us in this region and this industry--need
relief, and we need it now. The Elmira Plant has weathered many storms
over the past 88 years but none have proven to be as potentially
devastating to the long term feasibility of our business as the current
increase in energy prices.
We commend your leadership on this important issue, and wish to
offer you an open invitation to tour our Elmira facility so that we can
share with you, first hand, the pride that we take in each stage of our
manufacturing and distribution process.
[Attachments are being retained in the Committee files.]
Bath, New York 14810
March 19, 2001
Congressman Amory Houghton,
Dear Sir: I am a tenant at Lake Country Estates Mobile home park in
Bath, New York, owned by Paul Wilson III.
I heat my home with gas which comes from Bath Municipal Utilities
There are 113 gas heated units in the park; 99% of these people are
senior citizens living on a fixed income.
Recently we received notice from the owner of the Park Paul Wilson
III that there would be an increase of $55.00 per month. Some units are
increased to $60.00 per month. This appears not fair that one should be
charged a different rate.
Heating units are not individually metered. We would be paying
$110.00 per month for heat and expected to pay this for 12 months.
As tenants with no meters we are penalized when applying for HEAP
program. The amount allowed is only $50.00 per year due to not being
metered. We have no way to tell how much gas we are using.
It would be greatly appreciated if you could offer some help.
I am enclosing a copy of my letter which I received concerning this
Helen D. Brown
Lake Country Estates, Inc.
East Washington Street
Bath, NY 14810
February 13, 2001
Lake Country Estates
Bath, NY 14810
Reference: NINETY DAY NOTICE OF ASSESSMENT/RENTAL FEES FOR LAKE COUNTRY
ESTATES MANUFACTURED HOUSING COMMUNITY.
We are sorry to inform you, that effective June 1, 2001 the
Assessment/Rental Fee for 30 ASH, will have a increase of $55. Your
rent will be $323.06 for June. (June will still be under STAR) July
rent will be with the increase $339.77.
The increase is due to the excessive increase in heating cost.
Anyone heating with gas this winter has been aware of the rising cost
around us. Unfortunately, we here at Lake Country Estates have not been
immune to the increase. The rising cost has not passed us by. Lake
Country Estates, has enjoyed the low affordable prices of BEG&W for
sometime. This apparently is all in the past. BEG&W has said the price
may still yet increase. If this is so, we would like you to be prepared
for yet another increase in January 2002, or sooner. Maybe we will be
lucky and the prices will stabilize and drop off. If this is so, maybe
we also will be able to have a drop off in price. The gas prices have
doubled in cost per unit used since last year. The only way to regulate
each homes heating cost would be to have individual meters installed.
Management has asked for individual metering. At this time the utility
company does not feel they can do this. Call or write, to BEG&W,
express your concern for the need of individual meters for your gas.
This is the only way for you to regulate your own individual heating,
cost and usage.
Rent received in the office prior to 4:00 P.M. on the 5th of the
month is eligible for a $10.00 discount. Rent must be paid IN THE
CORRECT AMOUNT to be eligible for the discount. Rent that is mailed,
should be post marked by the 3rd to take advantage of the discount.
After the 15th of the month your gross rent is subject to a 5% late
Paul J. Wilson III
California Independent Petroleum Association
Sacramento, California 95814
March 16, 2001
Mr. Chairman and Members of the Subcommittee:
For the record my name is David S. Hall, I am the Chairman of the
Economic Policy and Taxation Committee for the California Independent
Petroleum Association. I thank you for the opportunity to address this
Committee on behalf of our association.
Who is CIPA
California Independent Petroleum Association, also known as
``CIPA,'' is a non-profit, non-partisan trade association representing
approximately 450 independent producers, royalty owners, service and
supply companies operating in California. We are the little guys, the
``energy farmers'' of America, who are independent, non-integrated
companies that receives nearly all of our revenues from oil and gas
production at the wellhead. We are exclusively in the exploration and
production segment of the industry with no retail outlets, marketing or
refining operations. As independents, we are ``price-takers'', with
little or no control over the price we receive for our product at the
wellhead. In most cases, we operate the smaller oil fields the majors
oil companies have abandoned for higher rates of return, or passed over
because it did not meet their investment criteria. In either case, the
independent oil producers play an important role in developing our
existing oil field reserves and reducing our dependence on foreign oil
California Industry Highlights
California produced approximately 841,000 barrels of oil per day in
2000 or approximately 14.4% of the total U.S. production. Twenty-nine
California counties produce some oil or gas. More oil is produced in
Kern County (560,000+ bpd) than in all of Oklahoma, the fifth largest
producing state. Annual state and local revenues from petroleum
production in California total over $500 million. Direct and indirect
employment in the petroleum exploration and production industry in
California totals approximately 70,000. California's petroleum reserves
are predominantly ``heavy oil'' (See Chart A), which requires a large,
long-term capital investment to produce. California has approximately
45,000 producing oil and natural gas wells. California produces
approximately 16% of its daily natural gas needs and approximately 40%
of its daily oil needs. The upstream petroleum industry is highly
regulated with some 28 federal, state, regional and local agencies with
review and oversight responsibilities. Thirty-five major federal and
state regulatory statutes, and many more local and regional ordinances
and rules, govern industry activities in California.
In keeping with the focus of this Subcommittee, CIPA has attempted
to address the concerns of this committee by addressing adequacy of
current tax incentives for production and conservation.
Enhanced Oil Recovery Credit (EOR)
As previously stated, over two-thirds of California's oil
production is from marginal heavy oil.\1\ For example most of Kern
County's oil is 13 gravity oil, which in layman's terms is thicker than
molasses. This is the most marginal oil production in the United
States. Because of viscosity of the oil it requires much more effort
and costs to remove the oil from the ground. To remove the oil from the
sands of the reservoir requires steam to heat the oil so that it will
flow to the well head. Chart B shows that approximately 64% of heavy
oil is thermally treated. There are two methods commonly used to
produce the necessary steam. First method is a conventional steam
generator, which is the most costly. The second method is a co-
generation facility, which produces both steam and electricity as a by-
product. Selling the electricity offsets the costs of producing the
steam. Either method used to produce the steam requires considerable
capital investments. After the oil is produced, the steam (in the form
of water) must be separated from the oil. This also requires
considerable capital investment to separate, recycle the water back
into steam, and to dispose of the excess water. For every barrel of
marginal heavy oil removed we also remove between three to one hundred
barrels of water as well.
\1\ IRC Sec. 613A(c)(6)(F) HEAVY OIL.--For purposes of this
paragraph, the term ``heavy oil'' means domestic crude oil produced
from any property if such crude oil had a weighted average gravity of
20 degrees API or less (corrected to 60 degrees Fahrenheit).
Marginal heavy oil is used primarily in the production of gasoline.
California refineries are complex and have been configured to handle
our heavy oil. Because gasoline is the most sought after product, the
California refinery must perform a secondary step on heavy crude oil in
order to extract the most from a barrel of crude oil. The value of our
marginal heavy oil becomes worth less than lighter oil to the
refineries because of the extra steps involved. This is proven in our
Chart C which reflects the price differential between WTI-Nymex and
California Heavy 13 (crude oil). The average ``Basis Differential''
between the two types of crude oil has been between $5.00 and $7.50.
Since the passage of EOR Credit in 1990, approximately 16,500 \2\
new wells have been drilled. CIPA is aware that most producers
calculate their return on investment including the benefits of the EOR
Credit. The EOR Credit has become an important part of the production
of marginal heavy oil.
\2\ From Statistics gathered from the California Department of
Conservation, Division of Oil, Gas and Geothermal Resources and IPAA's
1998-1999 Oil & Gas Producing Industry In Your State, Hart Publication.
In summary, EOR Credit has served to help independent producers
producing marginal heavy oil, which requires large capital investments
in steam costs, drilling, and facilities infrastructures. CIPA believes
that EOR Credit should be offset against Alternative Minimum Tax (AMT)
in the same manner as Foreign Tax Credit is. Without the EOR Credit
some of California's marginal heavy oil would be uneconomically. CIPA
further believes that EOR Credit could improved by including produced
water disposal costs, recycling water costs, and environmental costs.
Without the EOR Credit, CIPA strongly believes that California marginal
heavy oil production would decline dramatically causing tankering of
foreign crude oil to California and CIPA believes that gasoline prices
would increase. In addition, electrical generation of oil field related
co-generation may become uneconomical.
Other current tax incentives currently allowed by the Internal
Revenue Code (IRC), which are critical to independent producers, are
percentage depletion on their marginal oil production, intangible
drilling costs, steam costs under IRC Sec. 193, capital recovery
through depreciation. CIPA believes that these tax incentives are
adequate in most cases but should be improved to help continue the
development of our domestic marginal oil and gas production and thereby
holding down our costs. Listed below are CIPA's suggestions for
improving current tax incentives.
Congress has provided for the temporary repeal of 65% percent net
income limit for percentage depletion of oil and gas wells operated by
independent producers. CIPA believes that the temporary repeal should
be made permanent. In addition CIPA believes the repeal of the current
50% net income limit on percentage depletion of oil and gas wells
should also be made. We believe that these limitations provide an
accounting handicap to the independent producers and create an
accounting nightmare tracking the small marginal oil fields. We also
believe that the amounts of tax dollars involved are minimal. For these
reasons CIPA support the repeal of the net income limitations on
percentage depletion for independent producers.
Independent oil and gas producers are allowed a percentage
depletion deduction based upon 1,000 \3\ barrels per day or gas
equivalent. Since the introduction of this limitation in 1975, the
number of independent producers has greatly diminished due to
consolidations and efficiencies of the market. CIPA believes that the
removal of the artificial, extremely low, and ineffective barrel
limitation would spur development of our domestic reserves. We further
believe that this could be supported by statistic if an economic study
were done. At minimum we believe that the limitation should be
increased to 25,000 barrels per day. CIPA supports the repeal of
tentative quantity limitation under Sec. 613A.
\3\ IRC Sec. 613A(c)(3)(B).
While the focus of this hearing is three fold: (1) the adequacy of
current tax incentives for production and conservation, (2) the causes
of current shortages and high prices, and (3) impact of shortages and
high prices on individual consumers and business, CIPA believes that
there are obstacles in the Internal Revenue Code (IRC) which could be
eliminated, removed or reduced to help the development of our natural
resources. Listed below are some of the major obstacles facing our
industry and CIPA's suggestions for removing those obstacles. In all
cases, AMT is the biggest obstacle an independent producer has in
converting his tax incentives into cash. Without cash, the independent
producers are unable to explore new fields, exploit and develop
existing fields, and maximize existing production for domestic use.
Alternative Minimum Tax (AMT)
Probably the biggest obstacle outside of depressed oil prices to
prevent producers from spending more on a drilling program (capital
budget) is the alternative minimum tax. This section of the Internal
Revenue Code prevents producers from converting their tax benefits into
cash and thereby prevents producers from spending more on drilling and
developing of America's oil and gas reserves. Consideration should be
given to eliminating the tax preference items in the AMT calculation
for producers. This would provide the small energy farmers the
necessary capital to continue drilling and developing our oil and gas
reserves. CIPA supports the removal of the alternative minimum tax on
Our industry is a very capital-intensive industry, which requires
large cash investments before any oil or gas wells are drilled. Once a
discovery is found additional cash is required to develop. Should the
well be economical to produce, more cash is needed to develop the
infrastructure to bring the oil and gas to the market. Sometimes this
cycle will take years to complete the first well and produce a product
for the consumer. CIPA believes that our current capital recovery
methods coupled with AMT are obstacles to the further development of
our industry. Reducing these obstacles through shorter depreciable
lives would spur new investors into the industry, which will ultimately
benefit the consumer through increased production of oil and gas.
Geological and Geophysical Expenditures
These costs were deductible until 1943 when the IRS ruled that the
costs should be capital. Today geological and geophysical (G&G)
expenditures are not deductible as ordinary and necessary business
expenses but are capital expenditures recovered through cost depletion
over the life of the field unless the prospects are abandoned then the
costs are deductible. These costs are an important and integral part of
exploration and production for oil and natural gas and have become a
necessary cost of doing business. As our domestic reserves are
developed G&G studies become more important in finding new ``stranded''
or by-passed domestic oil and gas reserves. G&G expenditures include
the costs incurred for geologists, seismic surveys, and the drilling of
core samples. These surveys increasingly use 4-D (time) and 3-D
technology rather the older conventional 2-D technology. Because
technological advances have been made the cost of 4-D, and 3-D have
dropped to a level where independent oil or gas producers can now
afford to use this technology to develop more reserves. CIPA supports
G&G expenditures as ordinary and necessary business expenses.
Mr. Chairman and members of the Subcommittee this concludes my
remarks. I thank you for allowing me to submit my written testimony to
David S. Hal
Chairman, Economic Policy and Taxation Committee
[Attachments are being retained in the Committee files.]
Statement of the Hon. William J. Coyne, a Representative in Congress
from the State of Pennsylvania
I am pleased to be here today to discuss an issue of critical
importance to Americans nationwide. My constituents in Pittsburgh,
Pennsylvania know first-hand the impact of rising energy costs on their
Experts and government policy-makers say that the reasons for
higher natural gas prices are varied and complex. This winter we had
colder-than-average temperatures. This followed two mild winters which
saw a drop in the demand for natural gas. As a result, the price
producers could charge was lower. Gas producers had less incentive to
drill new wells and supplies dropped. Then, when demand rose
dramatically with our current cold weather, prices rose as well.
Many of us are beginning to face 50 to 100% increases in our
monthly heating bills. Apparently, the utility companies are paying
twice as much for the gas they deliver and passing the cost on to their
As a short-term measure, I have cosponsored H.R. 683, the Emergency
Energy Response Act of 2001. This legislation will help consumers cope
with high energy costs through increased funding for the Low-Income
Home Energy Assistance Program (LIHEAP) and state energy programs.
In the long term, however, it is necessary that the Subcommittee
consider the role the tax code plays in providing adequate incentives
for fuel production and conservation. Tax incentives are being
considered to assist in the home purchase of energy-efficient furnaces,
air conditioners, and appliances, and for energy conservation measures
such as improved residential insulation and weatherization. Also, tax
incentives are being discussed to make marginal wells more profitable
and to encourage appropriate oil and gas exploration.
I want to personally thank Chairman Houghton for scheduling today's
hearing on this most importanttopic. I hope we can continue with
additional hearings in Washington, D.C. and move forward with
legislative recommendations on a bipartisan basis.
Statement of Ben Hardesty, General Manager, Northeast Gas Basin
Exploration and Production Company, Dominion, Jane Lew,
Dominion appreciates the opportunity to submit these comments
urging extension of the I.R.C. Section 29 credit for producing fuel
from non-conventional sources.
Dominion is a leading provider of electricity, natural gas and
related services to customers in the energy-intensive Midwest, Mid-
Atlantic and Northeast regions--a market where 40% of the nation's
energy is consumed. In addition to serving about 4 million retail
electric and gas customers, Dominion operates 7,600 miles of
transmission pipeline and 2.8 trillion cubic feet of reserves. Dominion
Exploration and Production's operations are primarily in the Gulf of
Mexico, South Texas, the Rocky Mountains and the Appalachian Basin, and
in New York State we have about 43,000 acres under lease.
Dominion has a long history serving retail customers, but we became
active in exploration and production after the energy shocks of the
1970s brought home the need for secure domestic supplies. At about the
same time, in the wake of the widespread energy shortages and deep
concern about American dependence on imported oil, Congress enacted the
Section 29 non-conventional fuels tax credit.
The goal was to encourage U.S. production of oil and natural gas
from ``nonconventional'' sources, such as Devonian shale, tight rock
formations, coalbeds, geopressurized brine, and biomass. The credit was
needed because these deposits are unusually expensive to locate and/or
produce. An important feature was that the credit applied only to
actual production--the consumer's tax dollar was spent only after the
producer had taken the risk and achieved success.
Section 29 did result in a significant expansion of production from
difficult sources, and it helped to drive new advances in production
technology. According to the Gas Technology Institute, during 1986 to
1996, 70% of the increase in lower-48 non-associated gas production
came from ``nonconventional'' sources. 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.
The U.S. now imports 56% of its oil, and that figure is projected
to rise to 65% within 15 years. At the same time, the availability of
domestic natural gas is more important than ever, in part because of
its growing role in the nation's electric power infrastructure. The
National Petroleum Council projects gas demand to rise to 31 Tcf by
2015, with about half of that increase related to electric generation.
However, unless something is done, supply will lag demand. The NPC
predicts that gas production will rise to only 27 Tcf by 2015. In order
to meet demand, the NPC says, the total number of oil and gas wells
drilled per year would have to double to 48,000.
Aside from the increasing importance of natural gas in the electric
sector, new gas technologies translate into additional ways to assist
in meeting the nation's twin goals of lowering emissions and reducing
dependence on foreign oil. For example, today's natural gas vehicles
meet the most stringent standards applicable to internal combustion
engine vehicles, and natural gas air conditioning, when operated as
part of an integrated cooling system, can play a critical role on
easing reliance on electric systems that are overstressed.
The U.S. has substantial gas reserves found in the kinds of hard-
to-reach formations addressed by Section 29. Production from these
formations continues to be very expensive, however, and expiration of
Section 29 could result in the plugging and abandonment of many of the
qualifying wells. On the other hand, as history demonstrates, an
extension of the credit to new wells could encourage the production of
vital new gas supply.
The Section 29 credit is needed to unlock marginal supplies of
natural gas. While gas prices are high today, producers--and their
bankers--have learned the hard way about price volatility. Without
Section 29 to protect them, they are not going to 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 high quality power
generation, for home heating, and for a growing list of other uses.
We appreciate the opportunity to comment today about the Section 29
tax credit for actual production from challenging formations, and about
of the importance Section 29 to the nation's supply of natural gas.
Bath, New York 14810
March 7, 2001
Congressman Amory Houghton
Allison Giles, Chief of Staff
Committee of Ways and Means
U.S. House of Representatives
1102 Longworth House Office Building
Washington, D.C. 20515
Re: Mobile Home Gas Heat Assessment Increase
Dear Congressman Amory Houghton:
Referencing your 03/03/01 article in ``The Leader'' captioned
``Amos's hearing seeks ways to ease heat woes,'' we submit the
following for your consideration.
In Lake Country Estates Mobile Home community in Bath, N.Y. there
are 113 units heated by Bath Municipal Utilities Natural Gas. 99% of
these occupants are senior citizens on fixed incomes. These units are
not individually metered, but the owner of the mobile home community
assesses gas. The heat assessment is as follows:
Prior to 2001: $45.00/month annually;
January 2001 increase: $5.00/month annually;
Commencing 07/01/01 increase: $60.00/month annually;
Total: $110.00/month annually;
Annual Total: $1,320.00/unit regardless of square footage.
Many of the tenants living in the 113 gas heated units have applied
for HEAP and again have been penalized for not being metered. The
maximum HEAP benefit allowed because of this is $50.00/yearper unit. As
tenants we all own our units and rent the space only.
Attached is a copy of the letter we recently received from the
owner of Lake Country Estates.
We, the tenants anticipated an increase but feel this increased
assessment to be excessive and inequitable. We would appreciate ANY
help you could give us.
Lake Country Estates, Inc.
East Washington Street
Bath, NY 14810
February 13, 2001
Lake Country Estates
Bath, NY 14810
Reference: NINETY DAY NOTICE OF ASSESSMENT. RENTAL FEES FOR LAKE
COUNTRY ESTATES MANUFACTURERED HOUSING COMMUNITY
We are sorry to inform you, that effective June 1, 2001 the
Assessment/Rental Fee for 17 BIRCH will have a increase of $60. Your
rent will be $328.06 for June. (June will still be under STAR) July
rent will be with the increase $344.77.
The increase is due to the excessive increase in heating cost.
Anyone heating with gas this winter has been aware of the rising cost
around us. Unfortunately, we here at Lake Country Estates have not been
immune to the increase. The rising cost has not passed us by. Lake
Country Estates, has enjoyed the low affordable prices of BEG&W for
sometime. This apparently is all in the past. BEG&W has said the price
may still yet increase. If this is so, We would like you to prepared
for yet another increase in January or sooner. Maybe we will be lucky
and the prices will stabilize and drop off. If this is so, maybe we
also will be able to have a drop off in price. The gas prices have
doubled in cost per unit used since last near. The only way to regulate
each homes heating cost would be to have individual meters installed.
Management has asked for individual metering. At this time the utility
company does not feel they can do this. Call or write, to BEG&W,
express your concern for the need of individual meters for your gas.
This is the only way for you to regulate your own individual heating
cost and usage.
Rent received in the office prior to 4:00 P.M. on the 5th of the
month is eligible for a $10.00 discount. Rent trust be paid IN THE
CORRECT AMOUNT to be eligible for the discount. Rent that is mailed.
should be post marked by the 3rd to take advantage of the discount.
After the 15th of the month your gross rent is subject to a 5% late
Paul J. Wilson III
Statement of Edison Electric Institute
The Edison Electric Institute (EEI) is pleased to provide comments
for the Record on the Ways and Means Subcommittee on Oversight's
hearing on the impact of Federal tax laws on the cost and supply of
energy. EEI is the association of U.S. shareholder-owned electric
companies, international affiliates and industry associates worldwide.
Our U.S. members serve over 90 percent of all customers served by the
shareholder-owned segment of the industry. They generate approximately
three-quarters of all the electricity generated by electric companies
in the country and service about 70 percent of all ultimate customers
in the nation.
The electric utility industry is the most capital-intensive
industry in the nation. We strongly advocate sound economic,
environmental and energy policies. There is an urgent need for new
electric generation and transmission facilities to power a sound
efficient economy. Therefore, we have specific tax recommendations for
Congress to consider to ensure an affordable, reliable and efficient
supply of electricity in an emerging competitive marketplace.
Given the uncertainty in power markets across the country,
especially in California and Western states, we believe that Congress
needs to address several federal tax problems in order to facilitate
efficient regional electric markets and ameliorate the energy supply
The problems facing electric utilities under the federal tax code
are immediate, and they are the direct result of federal and state
energy policy changes that have occurred over the past several years.
Excessive electricity price volatility, concerns about power shortages,
and harmful consequences for the regional economy in the West are all
related to inadequate generation and transmission capacity in and
around California. Moreover, the energy crisis in California and
neighboring states has demonstrated the importance of developing
generation and transmission facilities to ensure that electricity
supplies are widely available at reasonable prices and to sustain a
competitive wholesale electric market. But capacity shortages are not
just an issue in the West, and addressing these tax code problems is
critical to helping avoid similar problems from developing in other
regions of the country.
The explosive growth in electronic equipment, computers,
telecommunications, and bandwidth content has produced a dramatic
increase in the demand for electricity. The Internet is a major reason
for the accelerated growth in electricity usage. Wireless Internet and
telecommunications applications are growing at an even faster rate than
basic Internet growth. According to an August 2000 study by the
Lawrence Berkeley National Laboratory (LBNL), office and Internet
network equipment use approximately 74 Tera Watt-hours (TWh) per year,
or about 2% of the total U.S. electric consumption. Scientists from
LBNL have estimated that Internet data centers alone will increase
their electricity usage from 9TWh in 2000 to 22 TWh in 2005, which
corresponds to a 244% increase in 5 years.
In a study prepared by Eric Hirst, Ph.D. in August 2000,
``Expanding U.S. Transmission Capacity,'' he noted that: ``the
uncertainties associated with an industry that is partly regulated and
partly competitive make it difficult to invest in needed
infrastructure, particularly transmission. The amount of
transmissioncapacity per unit of consumer demand declined during the
past two decades and, unless government policies change, is expected to
drop further in the next decade. Representatives from all sectors of
the electricity industry reach the same conclusion from these data and
projections--we need to build more transmission capacity.''
Updating the tax code should be done now, so that the effects of
the tax code will help--not hinder--the development of needed electric
infrastructure and the maintenance of an adequate and reliable electric
system. Congress should consider the following tax law changes:
To encourage new investments in generation, depreciable
lives should be reduced from their current cost recovery period of 15
or 20 years to 7 years. The current electric industry depreciable lives
are longer than those of any manufacturing segment.
To assure upgrading and building of adequate transmission
capacity, transmission depreciable lives should have a cost recovery
period of 7 years.
To help ensure additional transmission capacity and
further diminish tax barriers to wholesale and retail competition, tax
relief should be provided for the sale or spin-off of transmission
facilities to participants in independent Federal Energy Regulatory
Commission (FERC) approved regional transmission organizations (RTOs).
To facilitate new generation, transmission and
distribution facilities the tax penalty (contributions in aid of
construction) for connecting new generation to the grid should be
removed, including upgrades by developers to transmission and
To facilitate the transfer of nuclear facilities to new
owners in compliance with state and federal directives, the tax
treatment of nuclear decommissioning costs has to be updated, including
allowing the owners of nuclear power plants no longer subject to cost-
of service ratemaking to continue to make tax-deductible contributions
to decommissioning trust funds.
To facilitate public power participation in regional
transmission organizations, current ``private use'' restrictions need
to be modified.
To encourage energy efficiency, tax credits for energy
efficient homes, refrigerators and other appliances, and alternative
fueled vehicles should be enacted. To maintain fuel diversity and
develop alternative energy sources, tax credits for new and enhanced
technologies should be enacted.
GENERATION: GROWTH LAGGING BEHIND DEMAND
America's booming technology-reliant economy of the 1990s spurred a
demand for more electricity. However, that increase in demand was not
met by building new generation. In the 1970s and 1980s, America had
power surpluses. As a result, state regulators, trying to keep consumer
rates down, often disallowed the costs of some excess capacity and did
not allow utilities to recover in rates all of their costs for building
power plants. In many cases, utilities were required by their
regulatory commissions to buy power from other suppliers rather than
build their own plants. That, and the advent of competition, engendered
a cautious attitude toward investment costs that might not be
recoverable. The result was a construction lag, while demand for power
increased by about 2 percent per year.
Nevertheless, between 1978 and 1992, America's utilities had
reserve margins that averaged between 25 percent and 30 percent to meet
emergency demand situations. Since 1992, the reserve margin has dropped
significantly--to less than 15 percent, nationwide.
In 1990, the North American Electric Reliability Council (NERC)
estimated that national demand for power would grow about 1.8 percent
annually; in actuality, the rate has been between 2 percent and 3
percent. Some parts of the country are growing faster. In its most
recent assessment, NERC estimates that more than 10,000 megawatts (MW)
of capacity nationally will have to be added each year between now and
2008 to keep up with even a 1.8 percent growth rate. However, since
1990, actual capacity additions have been averaging only about 7,000
Meanwhile, the Energy Information Administration (EIA), in its
Annual Energy Outlook 2001, raised its own projections of electricity
demand for the next 20 years because of projected increases in economic
growth and the growth in electricity use for a variety of residential
and commercial applications. To meet demand growth, EIA projects that
1,310 new plants--with a total of 393 gigawatts of capacity--will need
to be built by 2020. The 393 gigawatts represents nearly a 47% increase
over current installed capacity, or the ability to serve approximately
60 million additional customers.
To foster adequate generation and reliability, Congress should
enact the provisions of H.R. 4959, legislation introduced by
Representative Bill Thomas (R-CA), and others, last year. Similar
language is included in legislation (S. 389) introduced by Senator
Murkowski (R-AK), and others, on February 26, 2001, the ``National
Energy Security Act of 2001.'' These bills would reduce depreciable
lives for new generation assets from their current 15 and 20 year cost
recovery periods to 7-year depreciable lives (consistent with other
industries' lives). EEI testified before this Subcommittee in support
of this legislation on September 26, 2000.
The current tax law profoundly impacts a generator's bottom line,
making it difficult to compete, and discourages the formation of much
needed capital investment. The price spikes and major power outages in
recent years, most notably in California, have brought this issue home
to millions of people. By way of example, no significant new generation
has been built in California in more than a decade, despite higher-
than-expected growth in the demand for power.
Nationwide, the structure of the electric industry is rapidly
changing from vertically-integrated, regulated monopolies to unbundled
and fully competitive generation services--independent transmission
companies and local distribution companies. Currently, 24 states and
the District of Columbia, encompassing some 70% of the Nation's
population, have either passed electric industry restructuring
legislation or enacted regulatory orders to implement unbundling and
competitive customer choice. In addition, FERC is promoting wholesale
competition and the formation of regional transmission organizations.
Because of the introduction of competition, previously applicable rules
regarding the cost recovery of capital simply do not apply any longer.
There also is no regulatory certainty in a deregulated electricity
market. In a competitive electricity environment investors demand a
higher return on their investments to reflect the vastly increased
risks of an unregulated environment. Shorter capital recovery periods
are a key element in attracting these investors.
TRANSMISSION CAPACITY RAPIDLY NEARING ITS LIMITS
Utilities originally built transmission lines to move power from
their generating plants to their customers. Over the years, the role of
utility transmission systems expanded. As regions of the countrygrew,
utilities interconnected their transmission systems to enhance
reliability by allowing companies to share power during emergencies.
Following that, transmission was used to exchange economical power
among neighboring utilities. The newest role, fostered by competition,
is to use transmission systems as the means of carrying power across
greater distances to customers in competitive markets. Beginning in
1996, to promote fair and open electric competition, FERC issued a
series of orders allowing all companies wishing to sell power to have
open access to transmission lines to deliver electric power to their
Today, more suppliers are trying to put more power on transmission
lines, challenging the limits of transmission capacity. However, most
transmission systems were not designed to be electrical
``superhighways'' for delivering large amounts of power over long
distances or for supporting the ever-expanding competitive trade of
wholesale power (i.e., the sale of power from one utility or power
provider to another for resale to an end-use customer). The result is
that transmission capacity is becoming an increasingly scarce resource
in certain parts of the country. For example, in 1995, there were
25,000 transactions where electricity was sold from one region to
another. Last year, the number hit 2 million. In a growing number of
areas, the transmission lines are carrying all of the power they can.
The effect of this congestion is that consumers may not have easy
access to low-priced power, and reliability may become threatened.
In the Eric Hirst study, ``Expanding U.S. Transmission Capacity,''
Charles Falcone, former executive of American Electric Power,
specifically noted: ``There has been very little construction of new
transmission for a dozen years or more. America's transmission
paralysis is also due to economic factors. Present owners have no
incentive to build. Not only does a utility become a pariah in local
political circles when it tries to build a high voltage transmission
line, but it exposes itself to regulatory risks that dwarf any possible
economic benefit. At best, under FERC pricing policy, a utility will
earn a modest return on its new transmission investment, possibly after
a multiyear lag. At worst, a utility may be unable to get any increase
in rates at all.''
The ultimate solution is to build new transmission lines and to
upgrade existing ones. Legislation that would shorten the depreciable
lives of transmission assets from 20 to 7 years is included in
legislation (S.389), the ``National Energy Security Act of 2001.''
Enactment of this provision would greatly enhance the ability of the
transmission system to supply increasing electricity demands in the
PROMOTE FORMATION OF INDEPENDENT REGIONAL TRANSMISSION COMPANIES FOR
COMPETITIVE ELECTRICITY MARKETS
Under Order No. 2000 (Order 2000), issued by FERC in December 1999,
transmission-owning electric companies, subject to FERC jurisdiction,
are ``encouraged'' to join RTOs, which must be operating by December
15, 2001. RTOs would operate the combined transmission systems of most
or all of the electric utilities in a region. Order 2000 also provides
that an RTO must not be controlled by any of the companies that
comprise the RTO or use its transmission facilities. Companies that
comprise RTOs and other market participants may initially own up to 5
percent of an RTO, but ownership by a class of participants is limited
to 15 percent. Companies that comprise RTOs and other market
participants may have unlimited passive ownership.
RTOs may take different forms. An independent system operator (ISO)
is independent from transmission owners and other market participants.
But, ISOs do not own the facilities they operate. They are transmission
management entities that separate ownership from operations. By
contrast, transmission companies (Transcos) are independent, for-profit
entities that own and operate their facilities.
Under current tax laws, utilities that sell or spin-off their
transmission assets to form RTOs would incur a substantial federal
income tax liability. Utilities can avoid the tax consequences if they
form an ISO and become passive owners of transmission facilities by
relinquishing control of their facilities to others. However, passively
separating ownership from control undermines efficient transmission
operations and provides no incentive for owners to invest in new
facilities. Passive ownership is a poor substitute for true
independence. It requires complex and inefficient corporate structures.
Recent experience shows that the value of assets will decline, and
operating costs will increase under such structures. In addition,
because passive owners would have little incentive to invest in
upgrading transmission facilities, our ability to invest in needed
improvements could be harmed. Thus, resorting to passive control does
not solve our need to expand the transmission infrastructure. While
ISOs and RTOs ensure independence from other market participants, the
ISO is a transition mechanism that is being used to help form RTOs.
RTOs are needed to grow and expand the country's transmission systems.
Public policy should ensure that neither the utilities which comply
with Order 2000, nor the customers who do business with new RTOs,
suffer economically from the imposition of federal income taxes on
compliance transactions. This can be accomplished by amending two
sections of the tax code. Section 1033 should be amended to permit
sales of transmission assets on a tax-deferred basis if these sales
occur in conformance with Order 2000, providing that the proceeds of
the sales are reinvested in certain utility assets. Similarly, Section
355(e) should be amended to allow for a tax-free spin-off of
transmission assets, even if they are to be combined with neighboring
transmission assets in conformance with Order 2000. Legislation
incorporating these changes is included in S.389, the ``National Energy
Security Act of 2001.'' The same language is included in legislation
introduced last year by Representative Hayworth (R-AZ), and others
(H.R. 4971) and Senator Murkowski (R-AK), and others (S.2967), the
``Electric Power Industry Tax Modernization Act.''
Increasing electricity supply to meet growing demands for power and
delivering it to where it is needed are essential if electricity price
volatility and supply shortages are to be averted.
AMEND THE NUCLEAR DECOMMISSIONING TAX LAW TO ADAPT IT TO A COMPETITIVE
Owners of nuclear power plants make contributions to external trust
funds to ensure that monies are available to decommission plants when
they are retired. Congress added Section 468A to the tax code in 1984
to permit owners of nuclear power plants to currently deduct
contributions that are made to these external funds. Section 468A, when
enacted, was designed to operate within the structure of regulated
rates. It depends on public service commissions authorizing
specifically identified costs (i.e, decommissioning costs) that an
electric utility can charge its customers.
As a result of the Energy Policy Act of 1992, deregulation laws in
almost half of the states, and FERC policies, the electric utility
industry is in the process of restructuring. In the future, an electric
utility may not be in a situation where decommissioning costs are
included in its regulated and recoverable costs of service. Rather,
such costs could be left to the plant owner to provide through revenues
from market-based or competitive prices.
As now structured, Section 468A requires that deductible
contributions be determined by the amount of decommissioning costs
included in a company's cost of service. If the law is not changed,
taxpayers who sell power based on market rates may be unable to deduct
amounts identified as future decommissioning costs. Therefore, funds
collected for decommissioning may be depleted needlessly by income
taxes that would be incurred under current tax law because of the
failure to meet the connection required by Section 468A to traditional
cost-of-service ratemaking. Section 468A of the tax code should be
adapted to the structure of competitive electricity markets by
permitting taxpayers to continue to receive taxdeductions for
accumulating properly identified nuclear decommissioning costs in
external trusts independent of cost-of-service ratemaking and for
accelerated funding of nuclear decommissioning costs, where required,
in connection with the transfer of a nuclear power plant.
Stand-alone legislation making these changes was introduced in the
last Congress by Representative Weller (R-IL) (H.R. 2038) and Senator
Murkowski (R-AK) (S. 1308). It also is included in S. 389, the
``National Energy Security Act of 2001.''
PROMOTE ELECTRIC RELIABILITY AND INCREASE ENERGY SUPPLY
Under Section 118(b) of the tax code, the costs of building new
transmission and distribution facilities for new generating plants,
homes, commercial properties, and industrial sites--indeed, any kind of
property where connection costs are paid by a developer or
interconnecting third party to a utility--are treated as contributions
in aid of construction (CIACs) and are considered as taxable income to
the utility. Furthermore, the Internal Revenue Service (IRS) has
reversed its long-standing position of issuing rulings that payments
made by independent generators to utilities to interconnect their
plants to the utility are not taxable to the utility. The IRS refusal
to consider these ruling requests comes at a very difficult time when
new sources of energy are needed to satisfy increased demand. The tax
law should be clarified so that such reimbursements of costs needed to
interconnect suppliers with their customers do not result in an
unnecessary tax burden. Eliminating the tax on CIACs would help improve
reliability by lowering the costs of enhancing distribution and
transmission systems and providing new sources of electric generation
by reducing the costs of interconnections.
This tax law treatment makes it less costly to interconnect
generation facilities and provide electric services. This would help
increase the supply of power and improve electric reliability. It also
would help to eliminate any barriers to the construction of new
distribution facilities on behalf of third parties, such as developers
of housing and commercial and industrial projects. Legislation
incorporating these changes is included in S. 389.
ALLOW COMMUNITY-OWNED UTILITIES TO PARTICIPATE IN THE COMPETITIVE
Community-owned utilities (such as those owned by municipal
governments) currently face outdated federal tax law barriers which
prevent their full participation in the rapidly changing electricity
marketplace. Existing federal tax rules (``private use'' rules) limit
the ability of public power systems to continue to provide electricity
to consumers in a restructured electricity market, where flexibility is
the key to survival.
Current private use rules inhibit community-owned utilities from
joining RTOs, which will hamper critical transmission grid and system
reliability. The U.S. Treasury Department re-issued temporary
regulations in January, 2001 to address some of these problems.
However, Congress must enact statutory changes to provide a complete
and permanent solution. In order to allow community-owned utilities the
ability to fully participate in the emerging competitive electricity
marketplace, industry stakeholders--both public and private systems--
have agreed that some following modifications to the private use rules
are warranted. Legislation incorporating these changes is included in
ENACT TAX POLICIES THAT ENCOURAGE FUEL DIVERSITY AND DEVELOP
ALTERNATIVE ENERGY SOURCES
The mix of fuels used to generate electricity has shifted
dramatically over the past 20 years. Changes in government policies and
regulatory practices have influenced many of these shifts. For example,
in the late-1970's--during the midst of a worldwide oil embargo--new
utility plants were prohibited from using natural gas or petroleum
products to generate electricity. Instead, to meet demand, decisions
were made to build more coal-based plants. Today, natural gas is re-
emerging as the fuel of choice for new electricity generation.
Recent events--such as electricity price spikes, volatile foreign
crude oil prices, higher gasoline prices, and rising natural gas and
home heating oil prices--underscore that America is facing yet another
energy challenge. As a result, changes in government policies are again
No individual fuel is capable of providing the energy required to
meet all of our nation's electricity demands. Rather, a variety of
fuels--as well as increasingly more cost-effective and efficient ways
to use, and conserve, energy--are needed. Indeed, different regions of
our country rely upon different generation mixes, depending upon the
availability and costs of fuels within those regions. For example,
hydropower use is prevalent in the Pacific Norwest, natural gas in the
Southwest, and coal in the Midwest. By maintaining these fuel options,
consumers are provided with affordable and reliable supplies of
Maintaining a diversity of supply options is key to affordable and
reliable electricity. Policymakers and regulators should work together
to reconcile conflicting energy, environmental, or other public policy
goals. They should promote initiatives that capitalize on all of our
nation's abundant natural resources. They should address challenges
that limit the development and viability of fuel sources. They should
implement a national energy program that maximizes the diversity of
fuels and technology options available for the generation of
There are many alternative technologies that can add to this
diversity: wind turbines, biomass co-firing boilers, and others.
However, the cost of energy from these sources is often still higher
than current sources. Needed tax changes that could promote fuel
diversity and alternative energy sources include:
Tax credits for investment in qualifying clean coal
technology for existing power plants and for production of electricity
from a power plant converted to clean coal technology.
Tax credits for investment towards the construction of a
new power plant using qualifying advanced clean coal technology or the
retrofitting and repowering of an existing conventional power plant
with clean coal technology.
Extend tax credits for incremental increases and
efficiency increases for nuclear generation, as this is clean non-
emitting generation and reduces U.S. dependence on foreign oil.
Extending the existing Section 45 tax credit for
production of electricity from renewable resources to include almost
all biomass and agricultural waste, wood waste, municipal solid waste,
landfill gas, geothermal, and incremental hydropower, and extending the
credit for qualified resources (including wind) to 2011.
Extending the existing Section 29 tax credit for
production of non-conventional fuels to projects placed in service
between 2001 and 2010. In addition, the Subcommittee should be aware
that since last summer, the IRS has not issued any private letter
rulings related to whether synthetic fuels constitute ``solid synthetic
fuel produced from coal'' qualifying for Section 29 tax credits. More
than 30 private letter rulings are pending. The last Administration
issued a revenue procedure at the end of last year. Despite numerous
letters of support, the IRS proceeded with areview of Section 29, but
has not finalized the review. This Administration has inherited this
unresolved issue and we urge an immediate resolution to stabilize
market disruptions and give taxpayers certainty regarding Section 29
investments made in accordance with the law.
Many of these tax proposals are included in S. 389, although some
of the proposals in S. 389 have been modified to allow all generating
plants, rather than solely existing coal plants, to be able to qualify
for the clean coal incentives.
TAX POLICIES TO PROMOTE ENERGY EFFICIENCY
The United States has become more energy efficient over the last 30
years. However, there are still areas that could be improved,
especially in public sector facilities. There are proven technologies
and techniques available that can provide cost-effective energy
efficiency for buildings and processes in the residential, commercial,
industrial, agricultural and transportation sectors of the economy.
Encouraging these activities will contribute to ensuring an affordable,
reliable and efficient supply of electricity. The chief challenge is to
develop technologies, policies, and incentives to provide consumers
with accurate pricing information and the opportunity to use it. While
EEI supports fuel neutral tax credits for more efficient homes (H.R.
1358) as introduced by Representative Bill Thomas (R-CA) in the last
Congress, we specifically recommend the following tax changes that will
promote increases in energy efficiency:
Extend the existing tax credit for electric vehicles
($4,000) through 2008 and provide various additional incentives for
more advanced electric vehicles.
Provide a tax credit, up to $30,000, for EV charging
systems and extend the existing $100,000 tax deduction for clean-fuel
refueling property until 2008.
Make electric buses and heavy-duty electric vehicles
eligible for the $50,000 tax deduction already in place for all other
alternatively fueled buses and heavy-duty equipment.
The Edison Electric Institute appreciates the opportunity to
comment on federal tax law changes to lower the cost, increase the
supply, and increase the efficiency of energy in the United States. The
electric power industry is in the midst of fundamental change as a
result of action taken at both the Federal and state levels. We look
forward to working with the Members of the Committee on Ways and Means
on tax incentives that will increase the supply and reliability of the
nation's electric system.
Bath, New York 14810
Dear Mr. Houghton: I am a tenant in Lake Country Estates mobile
home park in Bath, New York, owned by Paul Wilson III. I heat my home
with gas, which comes from Bath Municiple Utilities Corp. There are 113
gas-heated units in the park and 99% of these people are senior
citizens living on a fixed income. Recently we received notice from the
owner of the park, Paul Wilson III, that there would be an increase of
$60.00 per month per unit. This increase would mean we would be paying
$110.00 per month for heat and expected to pay this 12 months per year.
The gas-heated units are not individually metered! We do not know how
Mr. Wilson arrived at this $60.00 figure and does he have the right to
sell gas at any price?
As a senior citizen on a fixed income, I anticipated an increase in
gas heat, but I feel this is excessive and I cannot afford it!
As tenants with NO meters we are penalized when applying for the
HEAP program. The amount allowed is only $50.00 per year due to not
I am a senior citizen and I need your HELP!
Mildred C. Hall
Tenant & Senior Citizen
Statement of John Swords, Independent Petroleum Association of America,
and the National Stripper Well Association
Mr. Chairman, members of the committee, I am John Swords, Chairman
of the Independent Petroleum Association of America (IPAA) Tax
Committee. This testimony is submitted on behalf of the IPAA, the
National Stripper Well Association (NSWA), and 33 cooperating state and
regional oil and gas associations. These organizations represent
independent petroleum and gas producers, the segment of the industry
that is damaged the most by the lack of a domestic energy policy that
recognizes the importance of our own national resources. NSWA
represents the small business operators in the petroleum and natural
gas industry, producers with ``stripper'' or marginal wells.
Today's hearing is examining a critical issue confronting domestic
petroleum and natural gas production--the role of the tax code with
regard to the enhancement or deterioration of domestic exploration and
production of natural gas and petroleum. To put this issue in a clear
perspective all we have to do is look to the 1999 National Petroleum
Council Natural Gas study. This study concluded that U.S. demand for
natural gas would increase by over 30 percent during the next ten
years. It also identified four general areas that must be addressed to
assure that this clean burning fuel will be adequately supplied to
America's consumers. These are: access to capital, access to the
national resource base, access to technology, and access to human
resources. The federal government is a significant--if not pivotal--
factor in two of them: access to the resource base and access to
capital. The federal tax code plays an integral part in providing
access to the capital essential to develop domestic resources--both
natural gas and petroleum.
Federal tax policy has historically played a substantial role in
developing America's natural gas and petroleum. Early on, after the
creation of the federal income tax, the treatment of costs associated
with the exploration and development of this critical national resource
helped attract capital and retain it in this inherently capital
intensive and risky business. Allowing the expensing of geological and
geophysical costs and percentage depletion rates of 27.5 percent are
examples of such policy decisions that resulted in the United States
extensive development of its petroleum.
But, the converse is equally true. By 1969, the depletion rate was
reduced and later eliminated for all producers except independents.
However, even for independents, the rate was dropped to 15 percent and
allowed for only the first 1000 barrels per day of petroleum (or
equivalent natural gas) produced. A higher rate is allowed for marginal
wells, which increases as the petroleum price drops, but even this is
constrained--in the underlying code--by net income limitations and net
taxable income limits. In theWindfall Profits Tax, federal tax policy
extracted some $44 billion from the industry that could have otherwise
been invested in more production. Then, in 1986 as the industry was
trying to recover from the last long petroleum price drop before the
1998-99 crisis, federal tax policy was changed to create the
Alternative Minimum Tax that sucked millions more dollars from the
exploration and production of petroleum and natural gas. These changes
have discouraged capital from flowing toward this industry. And,
without capital the ultimate result is lower production. Since 1986,
domestic petroleum production has dropped by over 2.5 million barrels
Now, independent producers are recovering from the low prices of
1998-99 that starved the industry of funds to maintain existing
production and to explore and generate new production--production of
both petroleum and natural gas. Today, we look at a world where
petroleum production is perilously close to petroleum demand--where all
but three or four producing countries are at full production. Today, we
look at natural gas supply struggling to meet demand in the United
States primarily because of the loss of capital when petroleum prices
fell. Today, we have a domestic industry ready to find and produce
energy for the nation's consumers, but this inherently risky industry
must compete for funds against other more appealing investments and the
lure of lower costs to produce foreign oil.
Hearings throughout Congress have echoed with the statements of
members from producing and consuming states alike that more must be
done to increase domestic production. The question is how. Much of that
answer lies within this Committee.
Near Term Actions
In the near term there are a number of actions that can be taken.
In fact, there has been wide agreement on these actions between
Republicans and Democrats. Numerous bills have been introduced in the
House and Senate with substantial sponsorship during the 106th Congress
and now in the 107th Congress. In the House, H.R. 805 has been
introduced with a number of exploration and production provisions and
in the Senate S. 389--the comprehensive energy bill--includes a tax
title with key provisions.
First, action should be taken to clearly allow expensing of
geological and geophysical costs and of delay rental payments. Congress
has passed these changes. These changes would clearly aid the
development of new wells and they reflect historic practice in treating
these costs. (IPAA Fact Sheets detailing these issues follow this
Second, there is wide support for a countercyclical marginal well
tax credit. This approach was recommended by the National Petroleum
Council in its 1994 Marginal Wells study. This tax credit today can be
crafted with a negligible impact on the federal budget, but at the same
time create an important safety net for the most vulnerable American
producing wells--wells that produce petroleum roughly equivalent to
imports from Saudi Arabia--wells that are the nation's true strategic
petroleum reserve. (An IPAA Fact Sheet detailing this issue follows
Third, Congress has suspended the property taxable income
limitation on percentage depletion for marginal wells through 2001. The
tax bill passed by the 106th Congress would have suspended this
provision through 2004. The suspension that was in place in 1998 and
1999 saved many marginal wells during the price crisis. This provision
should be permanently eliminated to provide domestic producers of these
wells an incentive not to plug the wells during a low price cycle. Once
the well is plugged, the potential to produce the remaining reserves is
lost forever. (An IPAA Fact Sheet detailing this issue follows this
Fourth, the 106th Congress' tax bill also suspended through 2004
the 65 percent net overall taxable income limit on percentage
depletion. This constraint on independent producers limits the amount
of capital that can be retained for reinvestment into existing and new
production. In an industry that typically reinvests 100 percent of its
profits back into the industry, this constraint means less domestic
petroleum and natural gas. It too should be eliminated. (An IPAA Fact
Sheet detailing this issue follows this testimony.)
Fifth, the 106th Congress' tax bill extended the net operating loss
carryback period for independent producers to five years. This approach
or one that would allow for the carryback of carried over percentage
depletion that was limited by the 65 percent net taxable income limit
both have been introduced in the 107th Congress. Taken together with
the changes passed regarding percentage depletion, millions of dollars
would be made available based on costs and losses already incurred to
enhance domestic production.
Collectively, these provisions have wide support. They would be of
significant national value. They should be enacted now. Equally
important, they must be crafted in such a manner to assure that the
Alternative Minimum Tax does not nullify the benefits that they would
create. The mistake of 1986 should not be repeated. When the industry
is in desperate need of capital, it should not be stripped away.
For the future, the country needs to look toward tax policies to
encourage domestic production of its petroleum and natural gas. The AMT
remains a constriction. While the AMT was modified to exclude
percentage depletion from the calculation of the alternative minimum
taxable income (AMTI), independent producers remain subject to the AMT
with regard to intangible drilling costs (IDCs). Specifically, if
``excess intangible drilling costs'' exceed 65 percent of net income
from all oil and gas production, these costs are ``potential preference
items''. AMTI cannot be reduced by more than 40 percent of the AMTI
that would otherwise be determined if the producer was subject to the
IDC preference. This 40 percent rule forces many independent
producers--particularly smaller ones--to curtail drilling once the
expenditures become subject to the AMT. Now is a time when drilling
needs to increase significantly. The 1999 NPC Natural Gas study
estimates that the number of wells drilled needs to double over the
next fifteen years. Independent producers drill 85 percent of domestic
oil and gas wells. It makes no sense for the federal tax code to be a
barrier to this effort.
Some of the future focus also needs to be directed to getting more
out of existing resources. For example, while the Enhanced Oil Recovery
tax credit exists, it is based on technologies that are twenty or more
years old. This provision should be restructured and updated. (An IPAA
Fact Sheet detailing this issue follows this testimony.)
Equally significant, policies need to address encouraging more new
development. Proposals to encourage domestic exploration and production
should be created. A number of concepts are already in play and need to
be more fully evaluated.
For example, the Section 29 tax credit for unconventional fuels
proved to be a strong inducement to developing those resources. It
applies to wells drilled prior to 1993 and uphole completions
thereafter. Just last July, the Federal Energy Regulatory Commission
acted to reinstate its certification process to address many wells that
would otherwise qualify for the Section 29 tax credit. But, the
existing credit expires in 2003 and provides no incentive for current
development since the qualifying wells had to have been drilled before
1993. S. 389 extends the existing credit and creates a second drilling
window that also applies to heavy oil.
Fundamentally, the question facing the nation is how to marshal the
capital to develop its domestic resources. The 1999 NPC Natural Gas
study estimates that an additional $10 billion over and above the
current expenditure level will need to be invested annually in domestic
production over the next fifteen years to meet the expected demand. To
date this target has not been met. At issue is how to obtain capital
for domestic development. One source is the capital markets and some of
this amount will come from there, but it has significant drawbacks.
First, the capital markets have yet to show a strong interest in the
oil and gas exploration and production industry despite the recent high
prices of both commodities. Second, where the capital markets are
likely to focus their attention will be on large companies. So, while
some large independents may derive some of their capital from these
markets, it will only be a portion and smaller independents will need
to look elsewhere. Third, there is no guarantee that such capital will
go into domestic production because even with regard to investment in
exploration and production activities, capital must compete against
other projects including international ones.
The next source of capital will be from the revenues generated by
higher production and higher prices. First, the magnitude of this
capital may be overstated because just as prices for oil and natural
gas have increased, prices for drilling rigs and other costs are also
increasing which will squeeze the capital that is available. Second,
this capital will also be directed to the most promising projects, so
there is no guarantee that it will be invested domestically. Third,
this revenue will be significantly reduced by taxes.
The challenge, then, is to create a mechanism to direct the capital
to domestic production. One such approach would be to create a
``plowback'' incentive that would apply to expenditures for domestic
oil and natural gas exploration and production. This type of proposal
would encourage capital formation and development of domestic wells
provided it was immediately beneficial. Therefore, it would have to be
creditable against both regular and AMT taxes and any excess available
for carryback and carryforward. It would address the compelling need to
improve natural gas supply as well as reduce the growing dependency on
foreign oil. It must, in fact, apply to both oil and natural gas
because they are inherently intertwined--often found together.
Moreover, because of their inherent link, a healthy domestic natural
gas exploration and production industry cannot exist without a healthy
comparable oil industry. (An IPAA Fact Sheet detailing this issue
follows this testimony.)
If Congress wants to see more domestic petroleum and natural gas
production, it must recognize that federal tax policy plays a critical
role in whether capital will flow toward this industry and the
production of this resource. That has always been the case and it will
continue to be. Domestic producers have always been ``risk takers''.
During these times of plentiful investment opportunities, they need
some assistance in attracting capital (or retaining it for use
internally) and directing it towards domestic projects. There are
immediate actions that can and should be taken. The time is right. The
nation is seeking a more stable energy supply. Congress should act.
Geological and Geophysical Costs
Geological and geophysical (G&G) surveys are used to locate and
identify properties with the potential to produce commercial quantities
of oil and natural gas, as well as to determine the optimal location
for exploratory and developmental wells.
Allow current expensing of geological and geophysical costs
incurred domestically including the Outer Continental Shelf.
G&G expenses include the costs incurred for geologists, seismic
surveys, and the drilling of core holes. These surveys increasingly use
3-D technology rather than the conventional 2-D technology used for
most of the last seven decades. Previously only very large companies
were able to utilize this state-of-the-art, computer-intensive, 3-D
technology because of its high cost and the considerable technical
expertise it requires. However, as the costs of computer technology
have declined, more and more domestic independent producers are making
use of this technology. Still, while 3-D seismic provides a vastly
superior tool for exploration, it is far more expensive than 2-D
technology. 3-D seismic surveys usually cost between five or six times
more per square mile onshore than the older technology and, in some
instances can account for two-thirds of the costs of some wells.
Encouraging use of this technology has many benefits:
More detailed information. Conventional 2-D seismic is
only able to identify large structural traps while 3-D seismic is able
to pinpoint complex formations and stratigraphic plays.
Improved finding rates. Producers are reporting 50-85%
improvements in their finding rate. In prior years a producer might
have to drill three to eight wells in order to find commercially viable
Reduced environmental impact. Because the use of advanced
seismic technology significantly improves the odds of drilling a
commercially viable well on the first try, this reduces the number of
wells that are drilled and, thus, reducing the footprint of the
industry on the environment.
Investment capital. Many investors are requiring producers
to provide 3-D seismic surveys of potential development before
committing their capital to the project in order to minimize their
Current law treatment
G&G costs are not deductible as ordinary and necessary business
expenses but are treated as capital expenditures recovered through cost
depletion over the life of the field. G&G expenditures allocated to
abandoned prospects are deducted upon such abandonment.
Reasons for change
These costs are an important and integral part of exploration and
production for oil and natural gas. They affect the ability of domestic
producers to engage in the exploration and development of our national
petroleum reserves. Thus, they are more in the nature of an ordinary
and necessary cost of doing business.
These costs are similar to research and development costs for other
industries. For those industries such costs are not only deductible but
a tax credit is available.
Crude oil imports are at an all-time high, which makes the U.S.
vulnerable to sharp oil price increases or supply disruptions. The
National Petroleum Council Natural Gas study concluded that natural gas
supplies need to increase by over 30 percent by 2010 to meet demand.
Domestic exploration and production must be encouraged now to offset
this potential threat to national security, to meet future needs, and
to enhance our economy. Allowing the deduction of G&G costs would
increase capital available for domestic exploration and production
The technical ``infrastructure'' of the oil services industry,
which includes geologists and engineers, has been moving into other
industries due to reduced domestic exploration and production.
Stimulating exploration and development activities would help rebuild
the critical oil services industry.
Encouraging the industry to use the best technology available and
to reduce its environmental footprint are important public policy
reasons to clarify that these ordinary and necessary business expenses
for the oil and gas industry should be expensed.
The Taxpayer Refund And Relief Act Of 1999 included a provision to
allow expensing of G&G costs, but the bill was vetoed. Congress needs
to pass legislation now to implement this common objective to enhance
and preserve domestic oil and natural gas production.
Tax Treatment of Delay Rentals
Delay rental payments are made by producers to an oil and gas
lessor prior to drilling or production. Unlike bonus payments (made by
the producer in consideration for the grant of the lease) which
generally are treated as an advance royalty and thus capitalized,
producers have historically been allowed to elect to deduct delay
rental payments under Treasury Regulations 1.612-3(c). However, in
September 1997, the IRS issued a coordinated issues paper stating that
such payments are preproduction costs subject to capitalization under
Section 263A of the Internal Revenue Code. The legislative history of
Section 263A is unclear and subject to varying interpretation.
Clarify that delay rental payments are deductible, at the election
of the taxpayer, as ordinary and necessary business expenses.
Reasons for change
In passing the Section 263A uniform capitalization rules, Congress
broadly intended to only affect the ``unwarranted deferral of taxes.''
Congress did not intend to grant the IRS the authority to repeal the
well-settled industry practice of deducting ``delay rentals'' as
ordinary and necessary business expenses.
Treas. Reg. 1.612-3(c) states that, ``a delay rental is an amount
paid for the privilege of deferring development of the property and
which could have been avoided by abandonment of the lease, or by
commencement of development operations, or by obtaining production.''
Such payments represent ordinary and necessary business expenses, not
an ``unwarranted deferral of taxes.'' Given the clear disagreement over
the legislative history and the likelihood of costly and unnecessary
litigation to resolve the issue, clarification would eliminate
administrative and compliance burdens on taxpayers and the IRS.
The Taxpayer Refund And Relief Act Of 1999 included a provision to
clarify that delay rental payments could be expensed, but the bill was
vetoed. Congress needs to enact legislation to implement this common
position if the Administration is unwilling to correct the current
confusing interpretation of the tax code.
Marginal Well Tax Credit
Summary of Legislation
The Marginal Well Production Tax Credit amendment to the Internal
Revenue code will establish a tax credit for existing marginal wells.
Marginal oil wells are those with average production of not more than
15 barrels per day, those producing heavy oil, or those wells producing
not less than 95 percent water with average production of not more than
25 barrels per day of oil. Marginal gas wells are those producing not
more than 90 Mcf a day. The amendment will allow a $3 a barrel tax
credit for the first 3 barrels of daily production from an existing
marginal oil well and a $0.50 per Mcf tax credit for the first 18 Mcf
of daily natural gas production from a marginal well.
The tax credit would be phased in and out in equal increments as
prices for oil and natural gas fall and rise. Prices triggering the tax
credit are based on the annual average wellhead price for all domestic
crude oil and the annual average wellhead price per 1,000 cubic feet
for all domestic natural gas. The credit for the current taxable year
is based on the average price from the previous year. The phase in/out
prices are as follows:
OIL--phase in/out between $15 and $18;
GAS--phase in/out between $1.67 and $2.00.
The amendment would allow the tax credit to be offset against
regular and the alternative minimum tax (AMT). In addition, for
producers without taxable income for the current tax year, the
amendment would provide a 10-year carryback provision allowing
producers to claim the credit on taxes paid in those years. The
carryback credit may be used to offset regular tax and AMT.
Reasons For Change
The 1994 National Petroleum Council's Marginal Wells report
Preserving marginal wells is central to our energy security.
Neither government nor the industry can set the global market
price of crude oil. Therefore, the nation's internal cost
structure must be relied upon for preserving marginal well
Marginal wells account for approximately 20 percent of domestic oil
production, amount roughly equivalent to imports from Saudi Arabia.
Producing an average of 2.2 barrels per day, these roughly 400,000
wells are the nation's true strategic petroleum reserve. They are,
however, particularly at risk during periods of low prices. Therefore,
a principal recommendation of the Marginal Wells report wasthe creation
of a countercyclical marginal well tax credit.\1\ The Dept. of Energy
has evaluated the benefits of a tax credit and believes that it could
prevent the loss of 140,000 barrels per day of production if fully
employed during times of low oil prices like those of 1998 and 1999.
\1\ It also recommended expanding the Enhanced Oil Recovery tax
credit, an inactive well recovery tax credit, and expensing of capital
expenditures associated with marginal wells.
As the 107th Congress begins, legislation has been introduced in
both the House and Senate to create a tax credit. If enacted now, this
countercyclical credit would establish a safety net of support for
these critical wells. As Congress addresses energy policy issues, IPAA
believes a marginal wells tax credit should be an essential component.
Eliminate the Net Income Limitation on Percentage Depletion
The net income limitation severely restricts the ability of
independent producers to use percentage depletion, particularly with
respect to marginal wells. Percentage depletion is already subject to
many limitations. First, the percentage depletion allowance may only be
taken by independent producers and royalty owners and not by integrated
oil companies. Second, depletion may only be claimed up to specific
daily production levels of 1,000 barrels of oil or 6,000 Mcf of natural
gas. Third, depletion is limited to the net income from the property.
Fourth, the deduction is limited to 65% of net taxable income. These
limitations apply both for regular and alternative minimum tax
The net income limitation requires percentage depletion to be
calculated on a property-by-property basis. It prohibits percentage
depletion to the extent it exceeds the net income from a particular
property. The typical independent producer can have numerous oil and
gas properties, many of which could be marginal properties with high
operating costs and low production yields. During periods of low
prices, the producer may not have net income from a particular
property, especially from marginal properties. When domestic production
is most susceptible to being plugged, the net income limitation
discourages producers from investing income to maintain marginal wells.
Eliminate the net income limitation on percentage depletion.
Reasons for change
Marginal oil wells--those producing on average 15 barrels per day
or less or producing heavy oil--account for approximately 20 percent of
domestic oil production, an amount roughly equivalent to imports from
Saudi Arabia. The U.S. is the only country with significant production
from marginal wells. Once wells are plugged, access to the remaining
resource is often lost forever. Eliminating the net income limitation
on percentage depletion would encourage producers to keep marginally
economic wells in production and enhance optimum oil and natural gas
The current requirement creates a paperwork and compliance
nightmare for taxpayers and the Internal Revenue Service. Eliminating
the net income limitation on percentage depletion would simplify
recordkeeping and reduce the administrative and compliance burden for
taxpayers and the IRS.
The Taxpayer Relief Act of 1997 created a two-year suspension of
the net income limitation on percentage depletion; this suspension has
been extended through 2001. However, it is time to make this suspension
permanent. If the country learned anything from the high oil and
natural gas prices of 2000, it is that America needs to maintain and
enhance its domestic oil and natural gas production. This tax reform
allows more capital to be retained by producers where it can do the
most good--producing more domestic oil and natural gas.
Legislation has been introduced to eliminate or further suspend the
net income limitation provision for marginal wells. It should be
enacted prior to 2002 when the current suspension ends.
Percentage Depletion Expansion and Carryback Proposal
Current tax law limits the use of percentage depletion of oil and
gas in several ways. First, the percentage depletion allowance may only
be taken by independent producers and royalty owners and not by
integrated oil companies. Second, depletion may only be claimed up to
specific daily production levels of 1,000 barrels of oil or 6,000 Mcf
of natural gas. Third, the net income limitation requires percentage
depletion to be calculated on a property-by-property basis.\2\ It
prohibits percentage depletion to the extent it exceeds the net income
from a particular property. Fourth, the deduction is limited to 65% of
net taxable income. These limitations apply both for regular and
alternative minimum tax purposes.
\2\ The net income limitation for marginal wells is suspended
Percentage depletion in excess of the 65 percent limit may be
carried over to future years until it is fully utilized. Many
independent producers have been limited in the past because they have
spent their income on continuing development of their properties,
thereby reducing their taxable income. When oil prices dropped to
historically low levels independent producers were unreasonably
constrained by these tax provisions limiting their cash flow. They
cannot use these carried over deductions. Now, when capital to develop
oil and natural gas should be maximized, producers can be constrained
due to the alternative minimum tax (AMT). Even if they could use the
deductions, they may not benefit to the fullest extent possible from
actual tax savings. This proposal would alleviate these limits by
implementing the following changes:
By annual election, the 65 percent taxable income
limitation would be reduced or eliminated for current and future tax
Carried over percentage depletion could be carried back
for ten years subject to the same annual election on taxable income
Legislation has been introduced in the 107th Congress to
eliminate or suspend the 65 percent net taxable income limit and to
provide for carryback of carried over deductions.
Congress needs to include such provisions in future tax reform
bills and the Administration needs tosupport such provisions to enhance
and preserve domestic oil and natural gas production.
Enhanced Oil Recovery
Section 43 of the Internal Revenue Code provides an enhanced oil
recovery (EOR) credit equal to 15 percent of the qualified enhanced oil
recovery costs incurred in a tax year. Existing Treasury guidelines for
the section 43 tax credit are very narrow, generally including only
expensive EOR processes--many of which are no longer in use. It
excludes, however, many EOR processes that are the result of
technological advances now considered common in the industry.
The Petroleum Technology Transfer Council (PTTC) in March 1997
compiled a list of EOR methods that should be included under section
43. This study was part of an industry effort to expand the EOR
definition to include technologies that have proven potential for
mitigating well abandonment and increasing oil production and resource
Have the IRS review and expand the definition of methods qualifying
for the EOR tax credit.
Reason for Change
The existing Treasury guidelines are based on 1979-vintage
technology. This list has not kept pace with technology. A second
rationale is the incentive generated by allowing domestic producers to
position themselves to glean existing reservoirs in order to maximize
production of existing reserves.
Two additional categories to the EOR list are proposed. Those
categories include Enhanced Gravity Drainage (EGD) and Marginally
Economic Reservoir Repressurization (MERR). Included under EGD would be
horizontal drilling, multilateral well bores and large diameter lateral
well bores. Included in MERR would be natural gas injection and
waterflooding. Certain qualifiers and limiting factors include economic
criteria for approved projects and incremental production limitations
on each project.
By redefining the definition of EOR projects to include both EGD
and MERR technologies, the EOR tax credit will encourage conservation
measures to expand recovery of existing crude oil reservoirs and
promote new drilling activity. This will enable the industry to recover
more than 238 billion barrels of oil currently defined by the
Department of Energy as ``immobile.''
Congress needs to enact legislation to implement these definitional
changes if the Administration is unwilling to correct the current
constrained interpretation of the tax code.
Fundamentally, the question facing the nation is how to marshal the
capital to develop its domestic resources. The 1999 NPC Natural Gas
study estimates that an additional $10 billion over and above the
current expenditure level will need to be invested annually in domestic
production over the next fifteen years to meet the expected demand. To
date this target has not been met. At issue is how to obtain capital
for domestic development. Independent producers are risk takers who
will invest capital if it is available to find and produce more oil and
natural gas. To encourage additional investment a method needs to be
created to ``plow back'' as much of the revenue from oil and natural
gas sales as possible to develop new production. Structuring the
federal tax code to allow greater revenues to be retained by energy
producers who reinvest those revenues into new exploration and
production can enhance domestic investment.
A 10% tax credit, based on the total drilling and
development costs for wells drilled after the date of enactment. These
costs would include all Intangible Drilling Costs, Geological &
Geophysical costs, equipment and related costs. It would also include
costs of drilling contractors' drilling equipment used for the purpose
of finding petroleum and natural gas in the United States. The credit
would apply against both the regular tax and the Alternative Minimum
Tax. It could be carried back and carried forward. In order to obtain
the credit, the taxpayer must be able to demonstrate that he has
expended a like amount on similar development activity within 12 months
following the end of the tax year to which the credit applies.
An exemption from federal income taxes of 50% of the
amount of drilling and development costs (as described above) from
gross income from wells drilled after the date of enactment. In the
event of a dry hole, this amount would be carried forward to the next
productive well drilled by the taxpayer. In the case of a drilling
contractor, the exemption would be from the first revenues generated
from the drilling equipment from which the applicable costs were
derived. The exemption is from gross income and would not reduce the
costs or deductions generated by the expenditures themselves.
Reason for Change
The challenge is to create a mechanism to direct the capital to
domestic production. One such approach would be to create a
``plowback'' incentive that would apply to expenditures for domestic
oil and natural gas exploration and production. This type of proposal
would encourage capital formation and development of domestic wells
provided it was immediately beneficial. It would address the compelling
need to improve natural gas supply as well as reduce the growing
dependency on foreign oil. It must, in fact, apply to both oil and
natural gas because they are inherently intertwined--often found
together. Moreover, because of their inherent link, a healthy domestic
natural gas exploration and production industry cannot exist without a
healthy comparable oil industry.
Statement of John Swords for the Independent Petroleum Association of
America and the National Stripper Well Association and
California Independent Petroleum Michigan Oil & Gas Association
Colorado Oil & Gas Association..... Mississippi Independent Producers &
East Texas Producers & Royalty Montana Oil & Gas Association
Eastern Kansas Oil & Gas National Association of Royalty
Florida Independent Petroleum Nebraska Independent Oil & Gas
Illinois Oil & Gas Association..... New Mexico Oil & Gas Association
Independent Oil & Gas Association New York State Oil Producers
of New York. Association
Independent Oil & Gas Association Ohio Oil & Gas Association
Independent Oil & Gas Association Oklahoma Independent Petroleum
of West Virginia. Association
Independent Oil Producers Panhandle Producers & Royalty
Association Tri-State. Owners Association
Independent Petroleum Association Pennsylvania Oil & Gas Association
of Mountain States.
Independent Petroleum Association Permian Basin Petroleum Association
of New Mexico.
Indiana Oil & Gas Association...... Tennessee Oil & Gas Association
Kansas Independent Oil & Gas Texas Alliance of Energy Producers
Kentucky Oil & Gas Association..... Texas Independent Producers &
Royalty Owners Association
Louisiana Independent Oil & Gas Wyoming Independent Producers
Statement of Lubrizol Corporation, Wickliffe, Ohio
The Lubrizol Corporation of Wickliffe, Ohio, hereby submits the
following comments requesting a change in the Federal excise tax
imposed on certain diesel fuel formulations. Such a change would
provide equitable tax treatment for a more environmentally-sound fuel
Diesel fuel is the primary fuel used by trucks and buses. It is an
efficient fuel, but one that emits air pollutants--nitrogen oxides
(``NOX'') and particulate matter (``PM''). The Federal
excise tax on diesel fuel is 24.4 cents per gallon. To reduce tailpipe
emissions of NOX and PM, some marketers are beginning to mix
commercial, on-highway diesel fuel with a significant amount of water
and a small amount of additive to produce water-diesel fuel emulsions.
Taxation of such emulsions at the diesel fuel rate places their
users at a competitive disadvantage and discourages the use of this
environmental-enhancing fuel. Congress should redress this inequity.
II. Water-Diesel Fuel Emulsions
Chemical engineers for years have been able to mix water and diesel
fuel. However, creating a stable emulsion is difficult because the
water and the diesel fuel never combine chemically: the two fluids
separate, and the water sinks to the bottom. Recently, chemical
additives have been developed that can maintain emulsions of water and
diesel fuel for several months, even though the fluids do not combine.
Water-diesel fuel emulsions generally contain approximately 77
percent diesel fuel by weight, 3 percent additives and 20 percent
water.\1\ The diesel fuel and the additive (80 percent by weight of the
emulsion) are the energy-generating components of the fuel. Water
provides no energy and, of course, cannot propel a vehicle. It is
estimated that a gallon of a water-diesel fuel emulsion has about 80
percent of the energy content of a gallon of diesel fuel.
\1\ These quantities vary slightly in winter formulations designed
to address cold weather operation.
B. PuriNOXTM Water-Diesel Fuel
Under one such technology, PuriNOXTM, the
water, diesel and a small amount of chemical additive are placed in a
special unit that elongates the water molecules and breaks them into
very small droplets. The chemical additive then attaches to the
droplets. It prevents the water from coming in contact with any metal
components of a vehicle's engine--avoiding corrosion, and it inhibits
the droplets from coalescing and forming larger drops that would
eventually settle out of the emulsion. Without further processing, the
water droplets remain suspended in the diesel fuel. Adding water to
diesel fuel has significant environmental benefits. It: (1) lowers the
combustion temperature of the fuel, thereby reducing NOx emissions by
up to 30 percent, and (2) delays combustion of the fuel, thereby
reducing PM emissions by up to 50 percent.
The PuriNOXTM emulsion can be dispensed and
burned in both old and new trucks and buses just as conventional diesel
fuel. It does not require engine modification or complex maintenance of
the fuel in storage.
III. Unfair Tax Treatment
A. Tax ``Above the Terminal Rack''
The water displaces approximately 20 percent by weight of the fuel
in a water-diesel fuel emulsion without supplying 20 percent of the
energy value. Users of the lower-energy content water-diesel fuel
emulsion must purchase more gallons to drive the same number of miles.
Thus, if water-diesel fuel emulsions are taxed at the diesel rate of
24.4 cents per gallon, users would unfairly pay 20 percent more tax
than users of conventional diesel fuel.
The Federal excise tax is dedicated to the Highway Trust Fund. A
basic principle of highway taxes is that users of the highway system
should be taxed in relation to their use of that system. Thus, the tax
rate should be reduced on water-diesel emulsions by 20 percent to
reflect their energy equivalence. Users of conventional diesel fuel and
users of water-diesel fuel emulsions would then pay the same amount of
tax to travel the same distance. There is ample precedent for such
action.\2\ In 1997, Congress reduced the tax rates on several special
fuels including propane, liquefied natural gas, and methanol derived
from natural gas, to reflect the energy content of those fuels relative
to gasoline. Those fuels had been taxed at the same rate as gasoline, a
fuel with which they compete. Users of those special fuels were also
paying more tax to travel the same number of miles.
\2\ See section 4041(a)(2) of the Internal Revenue Code of 1986, as
amended by P.L. 105-34, Sec. 907(a)(1) (reducing the rates of taxation
on propane, liquified natural gas, and methanol dervied from natural
The principle that tax rates should be reduced on water-diesel fuel
emulsions to reflect their energy equivalence also has been recognized
abroad. There is special tax treatment for water-diesel fuel emulsions
in the U.K., France, Switzerland, the Netherlands and Italy. The
European Union has authorized its Member States to impose their Federal
excise tax only on the percentage of the emulsion that is diesel fuel;
the percentage that is water is exempt. This action is based on a
recognition that the water component has no energy content. It also
recognizes that the emulsion provides significant environmental
B. Tax ``Below the Terminal Rack''
At times, petroleum distributors may wish to add water to diesel
fuel and create a water-diesel fuel emulsion after the diesel fuel has
been taxed at the terminal rack. Again, addition of the water adds no
BTU content and does not propel the vehicle. Thus, there should be no
difference in tax treatment regardless of whether the emulsion is
created ``above'' or ``below'' the terminal rack because in either case
the full amount of taxable diesel fuel will have been subject to
taxation. ``Above the rack,'' the tax should be set at a rate to
reflect the emulsion's BTU content; ``below the rack,'' there should be
no additional tax imposed on the water. A new subsection 4041(a)(1)(D)
could be added to clarify that ``liquid other than gasoline,'' which is
subject to tax under Section 4041(a)(1), does not include water added
to diesel fuel to form an emulsion. Such an amendment would ensure
consistent treatment throughout the Tax Code.
Accordingly, the Congress should, consistent with its prior action
on taxes for special fuels, make the following amendments:
For removals or sales ``above the rack'':
1. Reduce the tax rate by 20 percent (from 24.4 to 19.5 cents per
gallon) to account for the 20 percent water content in water-diesel
fuel emulsions by amending Section 4081(a)(2)(A); and
For sales ``below the rack'':
2. Add new subsection 4041(a)(1)(D) stating that the ``liquid other
than gasoline'' that is subject to taxation under section 4041(a)(1)
will not include any water added to diesel fuel after the diesel fuel
has been taxed at the point of collection.
These proposals would thus eliminate an inequity within the Tax
Statement of Craig G. Goodman, National Energy Marketers Association
My name is Craig G. Goodman. I am submitting this testimony as
President of the National Energy Marketers Association (NEM). NEM is a
national, non-profit trade association representing a regionally
diverse cross-section of both wholesale and retail marketers of energy
and energy-related products, services, information and technology
throughout the United States. NEM members include: small regional
marketers; large international wholesale and retail energy suppliers;
energy consumers; billing firms, metering firms, Internet energy
providers, energy-related software developers, risk managers, energy
brokerage firms, customer service and information technology providers.
Affiliated and independent marketers have come together under the NEM
auspices to forge consensus and to help eliminate as many issues as
possible that would delay competition. NEM supports the implementation
of laws, regulations, standards of conduct, rates, tariffs and
operating procedures: (a) that provide all customers meaningful choice;
(b) that implement open, efficient, liquid and price-competitive energy
markets, and (c) that encourage the development of new, and innovative
energy services and technologies, at the earliest possible date.
As a national trade organization, NEM brings a wide range of
experiences, as well as broad perspectives to its testimony in this
proceeding that should aide the United States House Subcommittee on
Oversight and enhance the quality of the record to be developed here.
NEM currently participates in more than 50 restructuring proceedings
around the country and at the FERC. The testimony and recommendations
presented here represent major issues and barriers to price competition
that are most often confronted in proceedings around the country.
Price competition is the goal of deregulation, whether it is for
airfares, long distance telephone rates or energy prices. Meaningful
choice and true price competition are always the best consumer
protection laws possible. When laws and regulations set prices,
restrict access to consumers, establish barriers to entry, mandate
sales of assets coupled with spot purchases of volatile commodities,
markets get distorted and everyone loses, consumers, taxpayers,
utilities, governments and suppliers. Real competition always works.
Deregulation is not a failure. California Style Deregulation, however,
is a failure.
California was first and could have established a model for other
states to follow. Unfortunately, a number of political compromises made
supply shortages and price spikes inevitable. In the face of strong and
growing demand for power, no new power plants were built. Price cuts
were legislated at the same time that tens of billions of dollars in
stranded costs were allowed into rates. Energy sellers and buyers were
prohibited from doing business with each other and all energy purchases
and sales were mandated through a state run monopoly. Simultaneously,
utilities sold most of their generating assets at values higher than
book value and purchased energy supplies in the spot market. All this
occurred at a time when no new power plant construction made future
shortages and price spikes foreseeable and ownership of existing plants
excellent investments. Financially, the utilities were selling
electricity short without generation to deliver as a hedge against
price increases. Predictably, wholesale prices grew to meet demand yet,
at the same time, retail prices were capped. This is a recipe for
disaster in any market.
California is one of the world's largest economies, the epicenter
of a worldwide technology revolution, and built around an electricity
system that is in need of significant new investments to deliver
``digital power quality.'' The direct and indirect impact to
California, the western United States and the global economy of local
decisions that stalled construction of needed supplies is potentially
astronomical. Meaningful choice and true price competition can only
occur when consumers are assured that new supplies will be available to
meet their growing demand. This has not happened in California.
Now, California is in a cycle of stage 3 energy emergencies with
rolling blackouts, major utilities are having cash flow and credit/
confidence crises, taxpayers and consumers are revolting against both
high prices and utility bailouts, new generation and construction is
stalled, and politicians have actually threatened to expropriate
private generating assets that utilities sold when values were high and
shortages were foreseeable. New proposals would also call for the
government to take over transmission lines.
While California-style deregulation is unique, the impact of the
California energy crisis is not contained within the borders of the
state, and will be felt throughout the region and could affect the
national and global economies. The impact of California's energy and
environmental choices is now being passed on to ratepayers throughout
the Northwest. Ironically, in order to allay short-term blackouts,
older, coal-burning facilities that could have been replaced with newer
cleaner plants will be running overtime for the foreseeable future.
Importantly, every state has a legitimate interest in protecting
in-state consumers from increasing energy prices. However, the current
60-year old system of federal and state laws and regulations were
designed around a local franchise monopoly paradigm. To deliver the
lowest possible prices to consumers, new laws and regulations are
needed immediately so that competitive suppliers can super-aggregate
energy demand and deliver national economies of scale to even the
smallest consumers. Competitive energy suppliers cannot succeed unless
they can offer consumers lower prices than the local franchise
There are a number of actions that federal and state governments
need to take to ensure the proper restructuring of the electric
industry. Members of NEM spent hundreds of man-days forging consensus
on the proper role of the federal, state and local governments in the
implementation of electric restructuring. NEM members operate in
virtually every market that has opened for competition, and their broad
base of experience was the basis for the attached document entitled,
``National Guidelines for Restructuring the Electric Generation,
Transmission and Distribution Industries.'' Since this document was
released, the California model for deregulation has produced empirical
evidence as to how the failure of one state's deregulation program can
have significant economic and environmental impacts on other states as
well as the national and global economies.
Accordingly, NEM urges the Congress to consider a number of
important actions to bring meaningful choice and true price competition
to all U.S. consumers of energy at the earliest possible date.
Generally speaking these actions would: (a) encourage the development
of national economies of scale through more uniform rules, operating
procedures, tariff structures, scheduling coordination and technology
platforms, (b) limit utility services to pure monopoly functions
(transmission and distribution) and provide current monopoly cost-base
prices to consumers as ``shopping credits'' to procure competitive
services, and (c) expand existing energy and environmental tax credits
to include Qualified Restructuring Investments such as advanced
metering, computer system upgrades, distributed generation and provide
tax and performance based regulatory incentives for infrastructure
upgrades, congestion management, maintenance and streamlined
A. National Economies of Scale are Critical to Lower Energy Prices.
True price competition and lower energy prices require competitive
suppliers to achieve national, or at least, regional economies of
scale. Competitive suppliers can only succeed in winning customers away
from incumbent utilities if they can offer lower prices, better
services, more novel products, services and technologies or all three.
Currently, there are 50 different states with different rules in
multiple utility service territories, different data protocols and
transaction sets, different operating rules, different switching,
scheduling andcustomer protection rules, even different units of
measurements. As long as market participants are forced to divert
scarce resources to customize computer systems, billing, back-office,
and customer care facilities, and to develop and maintain non-
standardized information protocols or develop specialized knowledge of
different business rules in each jurisdiction, it drives energy prices
higher nationwide. Add to this the fact that one marked failure like
California can have a devastating impact on consumers, taxpayers,
financial markets and regional ecosystems.
Energy is the lifeblood of the world economy. It is time to
coordinate and implement relative uniformity among the states, in
rules, processes, procedures, scheduling delivery, and even information
technologies.\1\ There are a significant number of business rules,\2\
consumer protection laws, technology platforms and comparable operating
rules and scheduling processes which, if established fairly,
efficiently, and uniformly across the country could bring significant
cost savings and have a profound impact on the country and the
reliability of energy supplies.
\1\ National Energy Technology Policy (October 30, 2000). Available
on the NEM website at: http://www.energymarketers.com/documents/
\2\ Uniform Business Practices for the Retail Energy Market,
Sponsored by EEI, NEM, CUBR and EPSA. Accessible at www.eei.org.
B. Utilities Should Exit the Merchant Function and Consumers Should
Be Provided Shopping Credits Equal to Current Monopoly Prices to Shop
for Competitive Services. Utilities should be encouraged to ``exit''
competitive businesses and focus all ratepayer dollars on performing
services that can only be performed by a natural monopoly. In the
process, consumers should be given ``shopping credits'' on their
utility bills equal to the utility's fully embedded costs of providing
competitive services that have been historically bundled with
traditional monopoly services. Currently, captive utility customers pay
monopoly prices for a bundle of services that include many products and
services that can and should be provided by competitive suppliers at
competitive prices. Failure to give consumers credits that reflect the
full costs historically associated with these services will send
erroneous pricing signals to consumers and cause consumers to pay twice
for the same services. Shopping credits which ``back out'' the proper
amounts from utility rates will permit consumers to shop for
competitive services, encourage price competition among suppliers,
improve efficiency and stimulate innovation. Until consumers are given
the full monopoly prices they are currently paying for competitive
services to shop for alternative energy services, price competition and
lower energy costs will be difficult to achieve.
C. Federal and State Tax and Regulatory Incentives are Needed
Immediately for Investments in New Energy Supplies, Conservation,
Technology, and Infrastructure Immediately. The United States has
entered the digital age with an energy infrastructure constructed for
the industrial revolution. The United States is operating on a level of
reliability that cannot support digital power quality needs. A flicker
of the lights in Silicon Valley has global impacts.
One of the lowest cost, highest yield policy solutions is to create
targeted tax incentives to encourage all forms of new energy supply,
technology and conservation investments. This includes investments in
new pipes and wires to reduce congestion, advanced metering systems,
new computer systems, new energy supplies as well as distributed
generation. Both the state and federal governments have powerful and
effective tools to encourage new investments in energy supply and
conservation. The federal tax code already contains a myriad of
targeted energy, environmental and efficiency tax credits that should
be updated to increase the supply of electricity and natural gas and
reduce consumption. Either or both the existing energy tax credits
contained in Section 48 of the Internal Revenue Code (IRC), or the
existing credit for research contained in Section 41 of the IRC, could
be expanded to include ``qualified energy restructuring investments.''
NEM recommends that the definition of ``qualified restructuring
investments'' include, at a minimum, expenses incurred to modernize and
upgrade computer and information systems, metering systems, billing
systems and customer care facilities to facilitate competitive
restructuring. The credit should be available to both regulated and
unregulated entities. To ensure that restructuring tax credits and
regulatory incentives are targeted and effective, investments that are
not ``qualified'' should also not qualify for stranded cost recovery.
The market structure and added supplies necessary for deregulation
to succeed in California were not in place, and the failure of
California style deregulation was therefore predictable. In order to
prevent similar crises, permit meaningful choice and true price
competition and ensure the reliability of a digital quality U.S. energy
infrastructure, (a) far greater uniformity is necessary among the
states to achieve national economies of scale, (b) utilities must be
incented to exit the merchant function while consumers are given
adequate shopping credits to shop for competitive supplies, and (c)
existing tax and regulatory incentives must be expanded to encourage
new investments in energy supply, technology and conservation.
If both federal and state laws are written in a manner that ensures
meaningful price competition for the smallest retail consumer, the
country will benefit from lower energy costs, greater efficiency and
improved competitiveness internationally. Higher energy costs operate
like a regressive tax on low-income individuals and small businesses.
Conversely, laws and policies that help to lower energy prices have a
disproportionately greater benefit for lower income individuals and
those on a fixed monthly income. NEM experts are available to work with
Committee staff to draft appropriate language to implement these
Statement of New York State Assemblywoman Catharine M. Young (R-Olean),
Mr. Chairman, panelists, distinguished guests, allow me to thank
you on behalf of the residents of the Southern Tier of New York, and
indeed all of New York, for conducting this hearing.
The high national cost of energy has had a potentially chilling
effect on the recovering economy of the Northeastern United States, as
you well know. What you may be less familiar with is the very personal
and historic relationship this current challenge has with the district
I represent in the State Legislature.
The small towns and villages of the Southern Tier were among the
first places in the New World where oil was discovered and produced.
These first wells gave rise to a series of bustling communities,
emerging industries and a network of railroads. The communities of my
district are mostly quiet now. Much of the oil still lies beneath the
hills, but the expenses and regulations of production have made the
industry non-sustainable. This bleak scenario has been the case for
some time now.
Today my district faces an even graver challenge to its potential
prosperity --senior citizens who cannot afford the energy needed to
heat their homes, farmers grappling with the high cost of motor fuel
required to run their machines, and employers unable to grow because of
the rising electric and natural gas costs.Simply put, energy costs too
Chairman, you know the people of the Southern Tier. They, like all
other Americans, are hard working, stubbornly determined and possessed
of an optimism that cannot be found anywhere else in the world.
Unfortunately that optimism is being eroded. The people of our
small towns still work hard and still are oddly determined to make a
better life for themselves, but many are discouraged. They are
discouraged because they often do not see the fruits of their labor.
They are losing their optimism because they are now unsure if their
children will have a better life than they did.
The pursuit of the American Dream made this land a great one. It
attracted faces and families from around the globe. Heroic men and
women tamed this vast land and made it home. With their own blood and
sweat they built a booming economy with enough prosperity to be had by
all who would claim it with the work of their own hands.
The American Dream has faced many challenges. Wars and natural
disasters have never defeated the spirit of our people. The challenge
faced today is that of excessive--nearly punitive--taxation.
The taxes on energy threaten to destroy our ability to grow, to
produce, and to improve. The taxes on energy threaten to destroy more
than a reasonable share of family budgets.
Make no mistake about it. New York State itself has hurt its own
residents with incomprehensible and burdensome taxes and regulations.
In the state capital we are working diligently to right that wrong. New
York now needs the national capital to rollback its unfair policies.
Home Heating Oil
In Western New York and much of the Southern Tier, home heating oil
prices were $.78 per gallon in January 1999. By January 2001 that price
had ballooned to nearly $1.51 per gallon. That increase is
approximately 93 percent in a two year span, according to the New York
State Energy Research and Development Authority. Compare that to a 78
percent increase statewide, and the problem we are facing in western
New York becomes very clear.
In the same report NYSERDA also outlines that the Mid-Atlantic
regional inventory for home heating oil increased from January 2000 to
January 2001 by over 40 percent. The regional oil inventory stands at
17.8 million barrels.
A free market system that encourages entrepreneurialism would allow
greater industrial competition to meet consumer demands. As a
businessman yourself, you know that an unmet consumer demand is the
perfect opportunity for growth and the perfect remedy for economic
malaise. We must allow American business to do what it does best.
Much of New York, as well as much of America, is still very rural.
People need to travel moderate distances to find work, to see family,
to buy goods and to get adequate medical attention. They need
affordable gasoline for everyday living.
Farmers who already are operating too close to the solvency margin
must purchase motor fuel to run their tractors, and other machinery.
Commercial and industrial employers must ship materials and goods over
great distances to meet supply and demand. Expensive gasoline is a cost
of business, and is passed on to the consumer.
A report from the New York State Energy Research and Development
Authority (NYSERDA) shows that statewide gasoline prices climbed from
nearly $1.05 in January 1999 to nearly $1.55 in January 2001. In
upstate New York this trend has been even more debilitating as prices
climbed from $1.01 in January 1999 to $1.54 in January 2001. That
increase totals 52 percent in 24 months.
As elected officials we can discuss the tightening of supply from
the Organization of Petroleum Exporting Countries (OPEC), and debate
the need for environmental regulation and infrastructure maintenance.
However, we must acknowledge a startling problem. Taxes are too high.
According to price data obtained from the Energy Information
Administration of the United States Department of Energy, taxes
directly account for about 28 percent of what a consumer pays for a
gallon of gas at the pump.
Altogether, Americans for Tax Reform has counted 43 different
direct and indirect taxes on the production and distribution of
gasoline. Through this lens we see that the total tax burden amounts
to--on average--about 54 percent of the price of a gallon of gas.
Furthermore, the National Taxpayers Union reported that from 1990
to 1999 the pre-tax pump price of gasoline barely changed. Actually it
decreased from 88 cents per gallon to 86 cents per gallon in adjusted
dollars. However, over that same period gasoline taxes rose by more
By cutting taxes we--federal, state and local government--can drop
the price of gasoline back down to around a dollar a gallon. This
positive action is something we can do to jumpstart our economy and
save an average family nearly $1,000 per year.
Sound gas tax cuts can be achieved without disrupting the funding
needed to support our national highway infrastructure. In March 2000,
the United States House of Representatives Committee on Transportation
and Infrastructure reported that a proposed repeal of a 4.3 cent per
gallon gas tax would result in a revenue loss of $20.5 billion in
fiscal years 2001-2003. However, at the same time, the Office of
Management and Budget showed the Highway Trust Fund was running at a
surplus of more than $29 billion. The OMB report expected that the
aforementioned surplus would grow to over $34 billion by fiscal year
2003. It is very clear that there is, and has been enough money to
enact common sense, and overdue, tax relief.
Electricity and Natural Gas
From 1989 to 1994, during the five years before Governor George E.
Pataki assumed office, the cost of electricity in New York increased by
According to the New York State Business Council and the United
States Department of Energy, New Yorkers pay nearly 37% above the
national average for natural gas. Part of the problem is again
taxation, we tax our citizens too much. The Public Policy Institute of
New York State shows that the per capita cost of taxes on utilities is
172.7% above the national average.
A larger problem is siting regulations and the permitting process.
It takes too long, and does not allow industry to attempt to meet
consumer demand. It is further complicated by narrow special interest
groups who use scare tactics and a disregard for the broader economic
need of society by opposing all newattempts to meet increased demand
The New York Power Authority is moving to install eleven small
generating plants downstate. This plan is a small step in the right
direction. The continued effort to improve operating efficiency and
establish new facilities will enable New York to grow its energy
market, thus allowing us to reap the benefits of the competition that
true deregulation will bring.
New York needs to develop new generating capacity. We have not
constructed a major plant since 1994.
Right now, our state's generating capacity is 35,000 megawatts. Our
best estimates for peak summer use indicate that New York will need
about 30,600 megawatts. That leaves us with a surplus for now, but only
Businesses in New York City are asking for an increase of 2,000 to
3,000 megawatts of generating capacity locally. Since 1998 more than 60
large power plants have been proposed. Only 2 have been approved, and
both will be situated upstate. This is a good start, but it will not be
enough long term. To promote our long term growth and viability more
needs to be done.
Competition is the answer. The current California crisis is a
result of deregulation--or so we are told by the nightly news. But let
there be no misunderstanding about it. California may call it
deregulation, but their actions are more appropriately termed over-
The California government is acting to centrally manipulate the
market place. Consumer rates have been regulated, and attempts to build
new generating facilities have been denied by Sacramento.
Ten years ago in a policy analysis of U.S. energy markets, the Cato
Institute and the Institute for Energy Research in Houston, Texas
warned of the impending problems with the marketplace.
Prophetically they indicated that our country would grow and come
to a crossroads in energy. The options were described as a return to
free market entrepreneurialism, a reduction in taxation and regulation,
and increased domestic generation or an adoption of price and
allocation regulations, government manipulation of reserves and
California chose the latter path. On behalf of New York I urge you
to return to Washington with the message that our nation must return to
the free market practices. It is not yet too late.
Here in New York State I have been working with Governor Pataki and
many of my colleagues to improve the availability of energy. Together
we have cut the Gross Receipts Tax on utilities, and are working to
spare residential ratepayers from its burden.
The Governors Office of Regulatory Reform is examining ways to cut
the red tape that binds business and manufacturers, and the Public
Service Commission is aggressively reviewing generating facility
Later this week I will be introducing legislation to eliminate the
state sales tax on motor fuel. This action alone would save New York
consumers $361 million annually and spur our economy--particularly the
agricultural regions of the Southern Tier.
New York needs the federal government to be a partner in these
actions. I am hopeful that a new Administration with its commitment to
economic growth, and a sound energy policy will provide the compass
needed to guide the country towards a full prosperity.
The rules of supply and demand govern price in a market economy.
Unfortunately, today the cost of energy is determined under what could
be described as a command economy, one comprised of the pressures of
supply, demand and government. As it stands now consumers pay too heavy
a price, generators are unable to compete for revenue fairly, and
government is receiving a windfall of new tax ``profits.''
Cutting taxes will in no doubt increase demand. Free of undue
regulation and stifling corporate taxes, the employers of this country
and state will increase supply. America is a land of plentiful
resources and unparalleled ingenuity. It is time for the American
government to unfetter the drive and ability of its people by lessening
the weight of government.
I urge you to help get government out of the equation. Fair market
forces will act to overcome obstacles set forth by the government,
supply will increase, demand will rise and our economy and people will
Statement of Hon. Louise M. Slaughter, a Representative in Congress
from the State of New York
Mr. Chairman and Members of the Committee, I appreciate the
opportunity to highlight my concern with the high heating prices my
constituents are paying right now to stay warm. As we know, the price
of natural gas has risen 40 percent to 70 percent over the past year.
Last winter, we had a heating oil crisis in the Northeast region.
In response to the spike in home heating oil prices, I introduced
bipartisan legislation last year that would have given homeowners tax
credits to convert from heating oil to natural oil or renewable energy.
While that was aimed to address our nation's dependence on foreign oil,
the current prices consumers are paying for natural gas indicate that
more vision is needed to solve our country's energy crisis.
What is the solution? Spring is right around the corner, and
hopefully the warm weather will accompany lower energy bills. But for
how long? Citizens in California are expected to face power outages
again this summer due to people using their air conditioners.
One thing this committee can do within its jurisdiction is to
permanently extend renewable tax credits. For example, the Energy Tax
Act of 1978 (P.L. 95-618) created residential solar credits and the
residential and business credits for wind energy installations, but it
expired on December 31, 1985. This law should be renewed.
I appreciate your time and consideration. I look forward to working
with this committee in the future on these issues.