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74–211 2001

ENERGY SUPPLY AND PRICES

HEARING

BEFORE THE

SUBCOMMITTEE ON OVERSIGHT

OF THE

COMMITTEE ON WAYS AND MEANS

HOUSE OF REPRESENTATIVES

ONE HUNDRED SEVENTH CONGRESS

FIRST SESSION

MARCH 5, 2000

MAYVILLE, NEW YORK

Serial No. 107–8

Printed for the use of the Committee on Ways and Means

(

ii

COMMITTEE ON WAYS AND MEANS

BILL THOMAS, California, Chairman

PHILIP M. CRANE, Illinois

E. CLAY SHAW, JR., Florida

NANCY L. JOHNSON, Connecticut

AMO HOUGHTON, New York

WALLY HERGER, California

JIM MCCRERY, Louisiana

DAVE CAMP, Michigan

JIM RAMSTAD, Minnesota

JIM NUSSLE, Iowa

SAM JOHNSON, Texas

JENNIFER DUNN, Washington

MAC COLLINS, Georgia

ROB PORTMAN, Ohio

PHIL ENGLISH, Pennsylvania

WES WATKINS, Oklahoma

J.D. HAYWORTH, Arizona

JERRY WELLER, Illinois

KENNY C. HULSHOF, Missouri

SCOTT MCINNIS, Colorado

RON LEWIS, Kentucky

MARK FOLEY, Florida

KEVIN BRADY, Texas

PAUL RYAN, Wisconsin

CHARLES B. RANGEL, New York

FORTNEY PETE STARK, California

ROBERT T. MATSUI, California

WILLIAM J. COYNE, Pennsylvania

SANDER M. LEVIN, Michigan

BENJAMIN L. CARDIN, Maryland

JIM MCDERMOTT, Washington

GERALD D. KLECZKA, Wisconsin

JOHN LEWIS, Georgia

RICHARD E. NEAL, Massachusetts

MICHAEL R. MCNULTY, New York

WILLIAM J. JEFFERSON, Louisiana

JOHN S. TANNER, Tennessee

XAVIER BECERRA, California

KAREN L. THURMAN, Florida

LLOYD DOGGETT, Texas

EARL POMEROY, North Dakota

ALLISON GILES, Chief of Staff

JANICE MAYS, Minority Chief Counsel

SUBCOMMITTEE ON OVERSIGHT

AMO HOUGHTON, New York, Chairman

ROB PORTMAN, Ohio

JERRY WELLER, Illinois

KENNY C. HULSHOF, Missouri

SCOTT MCINNIS, Colorado

MARK FOLEY, Florida

SAM JOHNSON, Texas

JENNIFER DUNN, Washington

WILLIAM J. COYNE, Pennsylvania

MICHAEL R. MCNULTY, New York

JOHN LEWIS, Georgia

KAREN L. THURMAN, Florida

EARL POMEROY, North Dakota

Pursuant to clause 2(e)(4) of Rule XI of the Rules of the House, public hearing records

of the Committee on Ways and Means are also published in electronic form. The printed

hearing record remains the official version. Because electronic submissions are used to

prepare both printed and electronic versions of the hearing record, the process of converting

between various electronic formats may introduce unintentional errors or omissions. Such occurrences are inherent in the current publication process and should diminish as the process

is further refined.

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C O N T E N T S

Page

Advisory of February 14, 2001, announcing the hearing ..................................... 2

WITNESSES

U.S. Department of the Treasury, Joseph Mikrut, Tax Legislative Counsel ..... 8

U.S. Department of Energy, John S. Cook, Director, Petroleum Division,

Office of Oil and Gas, Energy Information Administration .............................. 24

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 attachments ..................................................................................................................... 74

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 attachments ........................... 88

Lubrizol Corporation, Wickliffe, OH, statement ................................................... 96

National Energy Marketers Association, Craig G. Goodman, statement ........... 98

New York State Assembly, Hon. Catharine M. Young, Assemblywoman, statement ...................................................................................................................... 101

Slaughter, Hon. Louise M., a Representative in Congress from the State

of New York, statement ....................................................................................... 104

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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:]

2

ADVISORY

FROM THE COMMITTEE ON WAYS AND MEANS

SUBCOMMITTEE ON OVERSIGHT

FOR IMMEDIATE RELEASE CONTACT: (202) 225–7601

February 14, 2001

No. OV–1

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.

BACKGROUND:

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 consumers.

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,

3

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.

FORMATTING REQUIREMENTS:

Each statement presented for printing to the Committee by a witness, any written statement

or exhibit submitted for the printed record or any written comments in response to a request

for written comments must conform to the guidelines listed below. Any statement or exhibit not

in compliance with these guidelines will not be printed, but will be maintained in the Committee

files for review and use by the Committee.

1. All statements and any accompanying exhibits for printing must be submitted on an IBM

compatible 3.5-inch diskette in WordPerfect or MS Word format, typed in single space and may

not exceed a total of 10 pages including attachments. Witnesses are advised that the Committee will rely on electronic submissions for printing the official hearing record.

2. Copies of whole documents submitted as exhibit material will not be accepted for printing.

Instead, exhibit material should be referenced and quoted or paraphrased. All exhibit material

not meeting these specifications will be maintained in the Committee files for review and use

by the Committee.

3. A witness appearing at a public hearing, or submitting a statement for the record of a public hearing, or submitting written comments in response to a published request for comments

by the Committee, must include on his statement or submission a list of all clients, persons, or organizations on whose behalf the witness appears.

4. A supplemental sheet must accompany each statement listing the name, company, address,

telephone and fax numbers where the witness or the designated representative may be reached.

This supplemental sheet will not be included in the printed record.

The above restrictions and limitations apply only to material being submitted for printing.

Statements and exhibits or supplementary material submitted solely for distribution to the

Members, the press, and the public during the course of a public hearing may be submitted in

other forms.

NOTE: All Committee 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 Comtorney, and more significantly today, I am the Acting County Execmittee as noted above.

Mr. LARSON. I am Fred Larson. I am the Chautauqua County Atf utive. 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

4

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.

Thank you.

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 words.

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 crisis.

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 gavel.

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.

5

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 Chautauqua welcome.

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 the country, 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 Texas.

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

6

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 you

here.

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 Allegheny.

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 appreciate it.

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.

7

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 problem.

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

and medicine.

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

reading what Mr. Coyne would have said had he been able to be

we want to get the printed record into production.

Mrs. THURMAN. Thank you, Mr. Chairman. I actually will be

f 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,

8

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 basis.’’ 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

9

costs were routinely under a dollar a gallon, and home heating oil

and natural gas supplies were relatively plentiful.

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 mid1980s, 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 changed.

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

10

biomass, fuel produced from coal. There is a $3 credit for gas produced from tight formations.

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 rule.

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

their customers.

The administration’s fiscal budget for the year 2002 will include

additional tax incentives for renewable energy resources. The proVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00014 Fmt 6633 Sfmt 6602 E:\HR\OC\A211.XXX pfrm01 PsN: A211
11

1 All price references are to the spot price at the Henry Hub and are in nominal dollars.

posal 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 month.

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

the Treasury

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 energy conservation.

Increasing Domestic Oil and Gas Production

Before I turn to my discussion of the present tax treatment of oil and gas activities, I would like to provide a brief overview of this sector.

Overview

Oil is an internationally traded commodity with its domestic price set by world

supply and demand. Domestic exploration and production activity is affected by the

world price of crude oil. Historically, world oil prices have fluctuated substantially.

From 1970 to the early 1980s, there was a fivefold increase in real oil prices. World

oil prices fell sharply in 1986 and were relatively more stable from 1986 through

1997. During that period, average refiner acquisition 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 MMBtu.1

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

12

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. 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.

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 production.

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.

Percentage depletion

Certain costs incurred prior to drilling an oil- or gas-producing property are recovered through the depletion deduction. These include costs of acquiring the lease or

other interest in the property, and geological and geophysical costs (in advance of

actual drilling). Any taxpayer having an economic interest in a producing property

may use the cost depletion method. Under this method, the basis recovery for a taxable year is proportional to the exhaustion of the property during the year. The cost

depletion method does not permit cost recovery deductions that exceed the taxpayer’s basis in the property or that are allowable on an accelerated basis. Thus,

the deduction for cost depletion is not generally viewed as a tax incentive.

Independent producers and royalty owners (as contrasted to integrated oil companies) 3 may qualify for percentage depletion. A qualifying taxpayer determines the

depletion deduction for each oil or gas property under both the percentage depletion

method and the cost depletion method and deducts the larger of the two amounts.

Under the percentage depletion method, generally 15 percent of the taxpayer’s gross

income from an oil- or gas-producing property is allowed as a deduction in each taxable year. The amount deducted may not exceed 100 percent of the net income from

that property in any year (the ‘‘net-income limitation’’).4 Additionally, the percentage depletion deduction for all oil and gas properties may not exceed 65 percent of

13

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. 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)).

the taxpayer’s overall taxable income (determined before such deduction and adjusted for certain loss carrybacks and trust distributions).5

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 31, 2002.

Marginal production is defined for this purpose as domestic crude oil or domestic

natural gas which is produced during any taxable year from a property which (1)

is a stripper well property for the calendar year in which the taxable year begins,

or (2) is a property substantially all of the production from which during such calendar year is heavy oil (i.e., oil that has a weighted average gravity of 20 degrees

API or less corrected to 60 degrees Fahrenheit). A stripper well property is any oil

or gas property for which daily average production per producing oil or gas well is

not more than 15 barrel equivalents in the calendar year during which the taxpayer’s taxable year begins.6 A property qualifies as a stripper well property for a

calendar year only if the wells on such property were producing during that period

at their maximum efficient rate of flow.

If a taxpayer’s property consists of a partial interest in one or more oil- or gasproducing 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.

14

7 IDCs include all expenditures made by an operator for wages, fuel, repairs, hauling, supplies,

etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas. In addition, IDCs include the cost to operators of any drilling or development work (excluding amounts payable only out of production or gross or net proceeds from production, if the amounts are depletable income to the recipient, and amounts properly allocable

to the cost of depreciable property) done by contractors under any form of contract (including

a turnkey contract). Such work includes labor, fuel, repairs, hauling, and supplies which are

used in the drilling, shooting, and cleaning of wells; in such clearing of ground, draining, road

making, surveying, and geological works as are necessary in preparation for the drilling of wells;

and in the construction of such derricks, tanks, pipelines, and other physical structures as are

necessary for the drilling of wells and the preparation of wells for the production of oil and gas.

Generally, IDCs do not include expenses for items which have a salvage value (such as pipes

and casings) or items which are part of the acquisition price of an interest in the property. 8The IRS has ruled that if an integrated oil company ceases to be an integrated oil company,

it may not immediately write off the unamortized portion of the IDCs capitalized under this

rule, but instead must continue to amortize those IDCs over the 60-month amortization period. 9 In the case of IDCs paid or incurred with respect to an oil or gas well located outside of

the United States, the costs, at the election of the taxpayer, are either (1) included in adjusted

basis for purposes of computing the amount of any deduction allowable for cost depletion or (2)

capitalized and amortized ratably over a 10-year period beginning with the taxable year such

costs were paid or incurred. 10The 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). 11 A barrel-of-oil equivalent generally means that amount of the qualifying fuel which has a

Btu (British thermal unit) content of 5.8 million. 12 A facility that produces gas from biomass or produces liquid, gaseous, or solid synthetic

fuels from coal (including lignite) generally will be treated as being placed in service before January 1, 1993, if it is placed in service by the taxpayer before July 1, 1998, pursuant to a written

binding contract in effect before January 1, 1997. In the case of a facility that produces coke

or coke gas, however, this provision applies only if the original use of the facility commences

with the taxpayer. Also, the IRS has ruled that production from certain post-1992 ‘‘recompletions’’ of wells that were originally drilled prior to the expiration date of the credit would qualify

for the section 29 credit.

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.

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

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

Intangible drilling costs are a major portion of the costs necessary to locate and

develop oil and gas reserves. Because the benefits obtained from these expenditures

are of value throughout the life of the project, these costs would be capitalized and

recovered over the period of production under generally applicable accounting principles. The acceleration of the deduction for IDCs is viewed as a tax expenditure.

Nonconventional fuels production credit

Taxpayers that produce certain qualifying fuels from nonconventional sources are

eligible for a tax credit (‘‘the section 29 credit’’) equal to $3 per barrel or barrel-ofoil 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

15

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. 14The inflation adjustment factor for the 1999 taxable year was 2.0013. Therefore, the infla- tion-adjusted amount of the credit for that year was $6.00 per barrel or barrel equivalent. 15For 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. 16The average per-barrel price of crude oil for this purpose is determined in the same manner

as for purposes of the section 29 credit. 17 In the case of an integrated oil company, the credit base includes those IDCs which the taxpayer is required to capitalize.

The section 29 credit generally is available for qualified fuels sold to unrelated persons before January 1, 2003.13

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

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 taxable years.

The enhanced oil recovery credit for a taxable year is equal to 15 percent of certain costs attributable to qualified enhanced oil recovery (‘‘EOR’’) projects undertaken by the taxpayer in the United States during the taxable year. To the extent

that a credit is allowed for such costs, the taxpayer must reduce the amount otherwise deductible or required to be capitalized and recovered through depreciation, depletion, or amortization, as appropriate, with respect to the costs. A taxpayer may

elect not to have the enhanced oil recovery credit apply for a taxable year.

The amount of the enhanced oil recovery credit is reduced in a taxable year following a calendar year during which the annual average unregulated wellhead price

per barrel of domestic crude oil exceeds $28 (adjusted for inflation since 1990).16 In

such a case, the credit would be reduced ratably over a $6 phaseout range.

For purposes of the credit, qualified enhanced oil recovery costs include the following costs which are paid or incurred with respect to a qualified EOR project: (1)

the cost of tangible property which is an integral part of the project and with respect to which depreciation or amortization is allowable; (2) IDCs that the taxpayer

may elect to deduct; 17 and (3) the cost of tertiary injectants with respect to which

a deduction is allowable, whether or not chargeable to capital account.

16

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 nonhydrocarbon gas displacement generally is considered a qualifying tertiary recovery

method, even if the gas injected is not carbon dioxide.

A project is not considered a qualified EOR project unless the project’s operator

submits to the IRS a certification from a petroleum engineer that the project meets

the requirements set forth in the preceding paragraph.

The enhanced oil recovery credit is effective for taxable years beginning after December 31, 1990, with respect to costs paid or incurred in EOR projects begun or

significantly expanded after that date.

Conventional oil recovery methods do not recover all of a well’s oil. Some of the

remaining oil can be extracted by unconventional methods, but these methods are

generally more costly 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 items.

As a general rule, percentage depletion deductions claimed in excess of the basis

of the depletable property constitute an item of tax preference in determining the

AMT. In addition, the AMTI of a corporation is increased by an amount equal to

75 percent of the amount by which adjusted current earnings (‘‘ACE’’) of the corporation exceed AMTI (as determined before this adjustment). In general, ACE

means AMTI with additional adjustments that generally follow the rules presently

applicable to corporations in computing their earnings and profits. As a general rule

a corporation must use the cost depletion method in computing its ACE adjustment.

Thus, the difference between a corporation’s percentage depletion deduction (if any)

claimed for regular tax purposes and its allowable deduction determined under the

cost depletion method is factored into its overall ACE adjustment.

Excess percentage depletion deductions related to crude oil and natural gas production are not items of tax preference for AMT purposes. In addition, corporations

that are independent oil and gas producers and royalty owners may determine depletion deductions using the percentage depletion method in computing their ACE

adjustments.

The difference between the amount of a taxpayer’s IDC deductions and the

amount which would have been currently deductible had 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 IDC preference of taxpayers that are not integrated oil companies.

This treatment does not apply, however, to the extent it would reduce the amount

17

18This provision applies to individuals, estates, trusts, personal service corporations, and

closely held C corporations.

of the taxpayer’s AMTI by more than 40 percent of the amount that the taxpayer’s

AMTI would have been if those IDCs had been taken into account.

In addition, for corporations other than integrated oil companies, there is no ACE

adjustment for IDCs with respect to oil and gas wells. That is, such a taxpayer is

permitted to use its regular tax method of writing off those IDCs for purposes of

computing its adjusted current earnings.

Absent these rules, the incentive effect of the special provisions for oil and gas

would be reduced for firms subject to the AMT. These rules, however, effectively

eliminate AMT concerns for independent producers.

Passive activity loss and credit rules

A taxpayer’s deductions from passive trade or business activities, to the extent

they exceed income from all such passive activities of the taxpayer (exclusive of

portfolio income), generally may not be deducted against other income.18 Thus, for

example, an individual taxpayer may not deduct losses from a passive activity

against income from wages. Losses suspended under this ‘‘passive activity loss’’ limitation are carried forward and treated as deductions from passive activities in the

following year, and thus may offset any income from passive activities generated in

that later year. Losses from a passive activity may be deducted in full when the

taxpayer disposes of its entire interest in that activity to an unrelated party in a

transaction in which all realized gain or loss is recognized.

An activity generally is treated as passive if the taxpayer does not materially participate in it. A taxpayer is treated as materially participating in an activity only

if the taxpayer is involved in the operations of the activity on a basis which is regular, continuous, and substantial.

A working interest in an oil or gas property generally is not treated as a passive

activity, whether or not the taxpayer materially participates in the activities related

to that property. This exception from the passive activity rules does not apply if the

taxpayer holds the working interest through an entity which limits the liability of

the taxpayer with respect to the interest. In addition, if a taxpayer has any loss for

any taxable year from a working interest in an oil or gas property which is treated

pursuant to this working interest exception as a loss which is not from a passive

activity, then any net income from such property (or any property the basis of which

is determined in whole or in part by reference to the basis of such property) for any

succeeding taxable year is treated as income of the taxpayer which is not from a

passive activity.

Similar limitations apply to the utilization of tax credits attributable to passive

activities. Thus, for example, the passive activity rules (and, consequently, the oil

and gas working interest exception to those rules) apply to the nonconventional

fuels production credit and the enhanced oil recovery credit. However, if a taxpayer

has net income from a working interest in an oil and gas property which is treated

as not arising from a passive activity, then any tax credits attributable to the interest in that property would be treated as credits not from a passive activity (and,

thus, not subject to the passive activity credit limitation) to the extent that the

amount of the credits does not exceed the regular tax liability which is allocable to

such net income.

As a result of this exception from the passive loss limitations, owners of working

interests in oil and gas properties may use losses from such interests to offset income from other sources.

Tertiary injectants

Taxpayers are allowed to deduct the cost of qualified tertiary injectant expenses

for the taxable year. Qualified tertiary injectant expenses are amounts paid or incurred for any tertiary injectant (other than recoverable hydrocarbon injectants)

which is used as a part of a tertiary recovery method.

The provision allowing the deduction for qualified tertiary injectant expenses resolves a disagreement between taxpayers (who considered such costs to be IDCs or

operating expenses) and the IRS (which considered such costs to be subject to capitalization).

Energy Efficiency and Alternative Energy Sources

Incentives for energy efficiency and alternative energy sources are also essential

elements of national energy policy. Individuals and businesses do not invest in energy-saving and alternative energy technologies at a level that reflects the benefits

18

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).

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 aftertax cost. The increase in private return encourages additional investment in energysaving 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 shortterm 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

Electric and clean-fuel vehicles and clean-fuel vehicle refueling property

A 10-percent tax credit is provided for the cost of a qualified electric vehicle, up

to a maximum credit of $4,000. A qualified electric vehicle is a motor vehicle that

is powered primarily by an electric motor drawing current from rechargeable batteries, fuel cells, or other portable sources of electric current, the original use of

which commences with the taxpayer, and that is acquired for use by the taxpayer

and not for resale. The full amount of the credit is available for purchases prior to

2002. The credit begins to phase down in 2002 and does not apply to vehicles placed

in service after 2004.

Certain costs of qualified clean-fuel vehicles and clean-fuel vehicle refueling property may be deducted when such property is placed in service. Qualified electric vehicles do not qualify for the clean-fuel vehicle deduction. The deduction begins to

phase down in 2002 and does not apply to property placed in service after 2004.

Energy from wind or biomass

A 1.5-cent-per-kilowatt-hour tax credit is provided for electricity produced from

wind, ‘‘closed-loop’’ biomass (organic material from a plant that is planted exclusively for purposes of being used at a qualified facility to produce electricity), and

poultry waste. The electricity must be sold to an unrelated 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.

Solar energy

A 10-percent investment tax credit is provided to businesses for qualifying equipment that uses solar energy to generate electricity, to heat or cool or provide hot

water for use in a structure, or to provide solar process heat.

Energy conservation subsidies

Subsidies provided by public utilities to their customers for the purchase or installation of energy conservation measures are excluded from the customers’ gross income. An energy conservation measure is any installation or modification primarily

designed to reduce consumption of electricity or natural gas or to improve the management of energy demand with respect to a dwelling unit.

19

Administration proposals

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 therhave just got a brief question. It is sort of a generic question, and

mal unit) content of 5.8 million.

Chairman HOUGHTON. Well, thanks very much, Mr. Mikrut. I

f then I will turn it over to Mr. English and Mrs. Thurman.

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 continued production.

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

20

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 policy writers.

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 areas?

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,

21

which is essentially equivalent to, I think, $25 a ton for coal, for

the production of synthetic fuels from coal.

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?

22

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 credits.

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.

23

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 for conservation?

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

efficiency?

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 years.

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.

24

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 incentives.

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

25

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 forecast.

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

26

remainder of this year for WTI at about $30 again this year, before

easing several dollars by mid next year.

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 year.

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

27

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 figure 5.

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 energy analyses.

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 alternative cases.

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

28

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 helped ease 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 31 percent.

29

TABLE 1.—WINTER HEATING OIL COSTS FOR AN AVERAGE NORTHEAST HOUSEHOLD HEATING WITH

OIL

1997–1998

actual

1998–1999

actual

1999–2000

actual

2000–2001

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 percentis 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

actual

1998–1999

actual

1999–2000

actual

2000–2001

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

30

TABLE 2.—WINTER NATURAL GAS COSTS FOR AN AVERAGE MIDWEST HOUSEHOLD HEATING WITH

NATURAL GAS—Continued

1997–1998 actual1998–1999 actual1999–2000 actual2000–2001 projected

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 imports from 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, respectively.

Conclusion

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)


Insert offset folio 38 here 74211a.001
31

Figure 2. Total OECD Oil Stocks, Including Commercial and Government Stocks,

1995–2002 (million barrels)

Figure 3. Wellhead Natural Gas Prices, 1999–2002 (dollars per thousand cubic feet)


Insert offset folio 41 here 74211a.003
32

Figure 4. Working Gas in Storage, 1998–2002 (billion cubic feet)

Figure 5. Lower 48 Natural Gas Wells Drilled and Average Wellhead Prices, 1985–

2000


Insert offset folio 45 here 74211a.005
f33

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 supplies—— 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 the Department 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;

right?

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.

34

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 before.

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 process.

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.

35

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

sources—— Mrs. THURMAN. Or a slowing of our economy. Will less use have

any effect on future considerations by those that we are dependent

on?

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 the costs 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

36

in other parts of the country may kind of even out the number a

little bit, helping more consumers that way.

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 automobile drivers.

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.

37

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 that.

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 nationally?

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 question.

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.

38

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

ahead.

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 Gehrig’s disease.

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

39

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 go there, to ask for this assistance. I have to keep my

mother warm. There was no other alternative.

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 oil.

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 situaVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00043 Fmt 6633 Sfmt 6602 E:\HR\OC\A211.XXX pfrm01 PsN: A211
40

tion 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 other sources.

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 with.

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 keepVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00044 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
41

ing 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

ful, wonderful message.

prosperity of this country. I wonder what they would feel now.

Chairman HOUGHTON. Thank you so much. That was a wonderf What I thought we would do is just go through the panel, and

then we will have questions and general afterward. Ms. Sosinski.

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

42

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 Dr. bills.

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 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 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 citiAiken.

zens and that is very very sad.

Chairman HOUGHTON. Thank you very much, Ms. Sosinski. Mr.

f 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

43

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 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 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.

44

[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 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 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 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 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 work.

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.

Holbrook.

[The attachments are being retained in the Committee files.]

Chairman HOUGHTON. Thank you very much, Mr. Aiken. Mr.

f 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 operVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00048 Fmt 6633 Sfmt 6602 E:\HR\OC\A211.XXX pfrm01 PsN: A211
45

ating 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 activity.

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 reduced activity.

The irony in all this is even today’s high prices won’t necessarily

support renewed drilling activity. Now, I know it was mentioned

46

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 sold product.

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 predictability.

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

47

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 the prospects, 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 time.

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.

Heine.

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.

48

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-percent decline.

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 market.

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.

49

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 influence that.

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

Pennsylvania.

50

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 previous

years?

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.

51

How does National Fuel keep our natural gas purchase prices as low as possible?

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 encouraging.

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 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’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 price possible.

I would like to thank you for the opportunity to present this information to the

Committee.

52


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53


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54


Insert offset folio 72 here 74211a.011
55

Nalbone.

Chairman HOUGHTON. Thank you very much, Mr. Heine. Mr.

f 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 limited partnerships.

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 lowyield reservoirs. This particular region, western Pennsylvania and

western New York, is that type of region that falls under that jurisdiction.

Chairman HOUGHTON. Thank you.


Insert offset folio 73 here 74211a.012
56

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 mid-1980s.

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 longterm 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 farm industry.

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

57

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 credits expired.

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 Market.

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 distribution systems.

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.

58

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 equipment.

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 investor incentive to participation in drilling ventures as was the

changing of the passive loss rules.

Thank you for allowing me to make this address.

What I am going to do is turn to Ms. Thurman and ask her to

Chairman HOUGHTON. Thank you very much.

f 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

59

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-sensitive customers.

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

60

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 activity.

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 the economy.

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 provision.

So I thank you, and I thank all of you for taking the time to testify.

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;

61

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?

Go ahead.

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 we

do.

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 understandable observation.

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

62

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 after 1992.

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 supply deals.

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 contracts.

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 many layoffs.

63

So we need long-term changes and whatever you can enact, that

we can rely on it for a long period of time.

Thank you.

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 adjourned.

[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 policy.

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,

64

and accounting for high health and environmental costs. Consumers, our environment, and our economy will benefit from these changes.

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 overuse 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 fuel efficiency.

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.

65

Recommendations

• Reduce and phase out tax breaks that benefit oil and gas exploration and production, particularly at marginal wells and on federal lands.

• 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 SO2.

• 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 gasoline-electric drive;

• Incentives for smart-growth development patterns that conserve land, discourage sprawl, and reduce dependence on car travel;

• 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 transit benefits.

• 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 industries.

• 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 oil.

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 apVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00069 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
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proved 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.

Recommendations

• 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 transmission costs.

• 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 businesses.

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 on oil.

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 wellequipped to deal with the types of crises we are now experiencing in both the West

and Northeast.

Recommendations

• 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 inVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00070 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
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clude 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 distribution. • Over 2,500 economists, eight Nobel Prize winners among them, have stated that

the United States can most effectively implement climate policies through marketbased 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

run.

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 future.

I. INTRODUCTION

Statement of the American Petroleum Institute

f 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 marketing.

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 North America.

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 development.

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 interVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00071 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
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national 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 international marketplace.

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 market share 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 barriers.

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.

69

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

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 longstanding 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.

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Percentage Depletion

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 the phenomenal 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.

EOR Credit

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.

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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 basis.

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 businesstypes 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 Related Income

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 general operating 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

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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 income.

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 repeal.

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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, lookthrough 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, lookthrough 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. taxpayer.

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 recharacterization of future domestic income as foreign source income will reduce the

risk that FTC carryovers do not expire unused.

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 comparable detriment.

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 disproportionately high.

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

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to allocate interest on certain qualifying debt on a mini-group basis, i.e., looking

only to the assets of that subsidiary, including stock.

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.

IV. SUMMARY

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

Opening

Statement of Michael Sopp, Anchor Glass Container, Elmira, New York

’s major products.

f 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 Southern Tier.

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 natural gas. 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.

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The Problem

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.

Closing

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.]

fBATH, 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 Corporation.

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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 matter.

Respectfully,

HELEN D. BROWN

Lake Country Estates, Inc.

East Washington Street

Bath, NY 14810

February 13, 2001

BROWN

30 ASH

Lake Country Estates

Bath, NY 14810

Reference: NINETY DAY NOTICE OF ASSESSMENT/RENTAL FEES FOR LAKE

COUNTRY ESTATES MANUFACTURED HOUSING COMMUNITY.

DEAR TENANT:

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 fee.

Respectfully,

f 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.

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1 IRC § 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).

Who is CIPA

California Independent Petroleum Association, also known as ‘‘CIPA,’’ is a nonprofit, 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 imports.

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.

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.

78

2From 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. 3 IRC § 613A(c)(3)(B).

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.

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 § 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.

Percentage Depletion

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 § 613A.

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

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continue drilling and developing our oil and gas reserves. CIPA supports the removal of the alternative minimum tax on producers.

Capital Recovery

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 this Subcommittee.

David S. Hal

Chairman, Economic Policy and Taxation Committee

Statement of the Hon. William J. Coyne, a Representative in Congress from

[Attachments are being retained in the Committee files.]

the State of Pennsylvania

f 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 lives.

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 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

(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.

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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

basis.

Statement of Ben Hardesty, General Manager, Northeast Gas Basin Exploration and Production Company, Dominion, Jane Lew, West Virginia

f 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 lower48 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. 31, 2002.

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.

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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.

fBATH, 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/year per 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.

Sincerely yours,

PATRICIA EATON

Tenant

LAKE COUNTRY ESTATES, INC.

EAST WASHINGTON STREET

BATH, NY 14810

February 13, 2001

P EATON

17 Birch

Lake Country Estates

Bath, NY 14810

Reference: NINETY DAY NOTICE OF ASSESSMENT. RENTAL FEES FOR LAKE

COUNTRY ESTATES MANUFACTURERED HOUSING COMMUNITY

DEAR TENANT: 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.

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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 fee.

Respectfully,

f 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 threequarters 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.

OVERVIEW

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 problem.

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 transmission capacity 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 mainteVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00086 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
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nance 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 distribution facilities.

• 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 MW.

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.

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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 country grew, 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

customers.

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 marketplace.

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.

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nies 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 MARKET

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

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missioning 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 ELECTRICITY MARKETPLACE

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 S. 389.

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 likely.

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 electricity.

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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 electricity.

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 a review 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 costeffective 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.

CONCLUDING COMMENTS

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.

f88

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 being metered.

I am a senior citizen and I need your HELP!

Sincerely,

MILDRED C. HALL

f 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 the Windfall 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

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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 per day.

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 testimony.)

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 this testimony.)

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 testimony.)

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.

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Next Steps

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.)

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Conclusion

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 tak- ers’’. 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.

FACT SHEET

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.

Proposal

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 production. • 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 risk.

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 activity.

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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.

Status

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.

March 2001

FACT SHEET

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.

Proposal

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.

Status

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.

March 2001

FACT SHEET

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.

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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.

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 concluded:

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 contributions.

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 was the 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.

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.

March 2001

FACT SHEET

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 purposes.

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.

Proposal

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

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2The net income limitation for marginal wells is suspended through 2001.

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 resource recovery.

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.

Current Status

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.

March 2001

FACT SHEET

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.

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 years. • Carried over percentage depletion could be carried back for ten years subject

to the same annual election on taxable income limitation.

Status

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 to support such provisions to enhance and preserve domestic oil

and natural gas production.

March 2001

FACT SHEET

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

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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 recovery.

Proposal

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.

March 2001

FACT SHEET

Plowback Incentive

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.

Proposal Alternatives

• 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 drillVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00099 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
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ing 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 Association .......................... Michigan Oil & Gas Association

Colorado Oil & Gas Association ................................................ Mississippi Independent Producers & Royalty Association

East Texas Producers & Royalty Owners Association ............... Montana Oil & Gas Association

Eastern Kansas Oil & Gas Association ..................................... National Association of Royalty Owners

Florida Independent Petroleum Association .............................. Nebraska Independent Oil & Gas Association

Illinois Oil & Gas Association .................................................... New Mexico Oil & Gas Association

Independent Oil & Gas Association of New York ...................... New York State Oil Producers Association

Independent Oil & Gas Association of Pennsylvania ................ Ohio Oil & Gas Association

Independent Oil & Gas Association of West Virginia ............... Oklahoma Independent Petroleum Association

Independent Oil Producers Association Tri-State ...................... Panhandle Producers & Royalty Owners Association

Independent Petroleum Association of Mountain States .......... Pennsylvania Oil & Gas Association

Independent Petroleum Association of New Mexico .................. Permian Basin Petroleum Association

Indiana Oil & Gas Association .................................................. Tennessee Oil & Gas Association

Kansas Independent Oil & Gas Association .............................. Texas Alliance of Energy Producers

Kentucky Oil & Gas Association ................................................ Texas Independent Producers & Royalty Owners Association

Louisiana Independent Oil & Gas Association .......................... Wyoming Independent Producers Association

The Lubrizol Corporation of Wickliffe, Ohio, hereby submits the following comStatement of Lubrizol Corporation, Wickliffe, Ohio

f ments 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 formulation.

I. Overview

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

A. 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.

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1These quantities vary slightly in winter formulations designed to address cold weather operation. 2See section 4041(a)(2) of the Internal Revenue Code of 1986, as amended by P.L. 105–34,

§ 907(a)(1) (reducing the rates of taxation on propane, liquified natural gas, and methanol

dervied from natural gas).

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.

B. PuriNOXTM Water-Diesel Fuel Emulsions

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 waterdiesel 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.

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 benefits.

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

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to form an emulsion. Such an amendment would ensure consistent treatment

throughout the Tax Code.

IV. Conclusion

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 Code.

Statement of Craig G. Goodman, National Energy Marketers Association

Thank you.

fI. Introduction

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.

II. Background

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

99

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 monopoly.

III. Recommendations

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 interconnection procedures.

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 and customer protection rules, even different

units of measurements. As long as market participants are forced to divert scarce

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1 National Energy Technology Policy (October 30, 2000). Available on the NEM website at:

http://www.energymarketers.com/documents/

NEMlNationallEnerglTechnologylPolicylfinal.pdf 2. 2 Uniform Business Practices for the Retail Energy Market, Sponsored by EEI, NEM, CUBR

and EPSA. Accessible at www.eei.org.

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.

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.

Conclusion

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

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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 recommendations.

Statement of New York State Assemblywoman Catharine M. Young (R

f –

Olean), 149th A.D.

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 much.

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 AuthorVerDate 31-AUG-2001 15:46 Sep 09, 2001 Jkt 074211 PO 00000 Frm 00105 Fmt 6633 Sfmt 6621 E:\HR\OC\A211.XXX pfrm01 PsN: A211
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ity. 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.

Motor Fuel

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 than half.

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 20 percent.

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 new attempts to meet increased demand with supply.

103

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 for now.

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-regulation.

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 mandatory conservation.

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.

Needed Action

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 permitting applications.

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 prosper.

Thank you.

f104

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.

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