[House Hearing, 107 Congress]
[From the U.S. Government Printing Office]
THIRD IN SERIES ON EFFECT OF FEDERAL TAX LAWS ON THE PRODUCTION,
SUPPLY, AND CONSERVATION OF ENERGY
SUBCOMMITTEE ON SELECT REVENUE MEASURES
COMMITTEE ON WAYS AND MEANS
HOUSE OF REPRESENTATIVES
ONE HUNDRED SEVENTH CONGRESS
JUNE 13, 2001
Serial No. 107-25
Printed for the use of the Committee on Ways and Means
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COMMITTEE ON WAYS AND MEANS
BILL THOMAS, California, Chairman
PHILIP M. CRANE, Illinois CHARLES B. RANGEL, New York
E. CLAY SHAW, Jr., Florida FORTNEY PETE STARK, California
NANCY L. JOHNSON, Connecticut ROBERT T. MATSUI, California
AMO HOUGHTON, New York WILLIAM J. COYNE, Pennsylvania
WALLY HERGER, California SANDER M. LEVIN, Michigan
JIM McCRERY, Louisiana BENJAMIN L. CARDIN, Maryland
DAVE CAMP, Michigan JIM McDERMOTT, Washington
JIM RAMSTAD, Minnesota GERALD D. KLECZKA, Wisconsin
JIM NUSSLE, Iowa JOHN LEWIS, Georgia
SAM JOHNSON, Texas RICHARD E. NEAL, Massachusetts
JENNIFER DUNN, Washington MICHAEL R. McNULTY, New York
MAC COLLINS, Georgia WILLIAM J. JEFFERSON, Louisiana
ROB PORTMAN, Ohio JOHN S. TANNER, Tennessee
PHIL ENGLISH, Pennsylvania XAVIER BECERRA, California
WES WATKINS, Oklahoma KAREN L. THURMAN, Florida
J.D. HAYWORTH, Arizona LLOYD DOGGETT, Texas
JERRY WELLER, Illinois EARL POMEROY, North Dakota
KENNY C. HULSHOF, Missouri
SCOTT McINNIS, Colorado
RON LEWIS, Kentucky
MARK FOLEY, Florida
KEVIN BRADY, Texas
PAUL RYAN, Wisconsin
Allison Giles, Chief of Staff
Janice Mays, Minority Chief Counsel
Subcommittee on Select Revenue Measures
JIM McCRERY, Louisiana, Chairman
J.D. HAYWORTH, Arizona MICHAEL R. McNULTY, New York
JERRY WELLER, Illinois RICHARD E. NEAL, Massachusetts
RON LEWIS, Kentucky WILLIAM J. JEFFERSON, Louisiana
MARK FOLEY, Florida JOHN S. TANNER, Tennessee
KEVIN BRADY, Texas
PAUL RYAN, Wisconsin
Pursuant to clause 2(e)(4) of Rule XI of the Rules of the House, public
hearing records of the Committee on Ways and Means are also published
in electronic form. The printed hearing record remains the official
version. Because electronic submissions are used to prepare both
printed and electronic versions of the hearing record, the process of
converting between various electronic formats may introduce
unintentional errors or omissions. Such occurrences are inherent in the
current publication process and should diminish as the process is
C O N T E N T S
Advisory of June 6, 2001, announcing the hearing................. 2
Alcoa Inc., Vince T. Van Son..................................... 50
Alliance of Automobile Manufacturers, Josephine S. Cooper........ 6
American Petroleum Institute, Domestic Petroleum Council, U.S.
Oil & Gas Association, and Chevron Corporation, Charles N.
American Public Gas Association, and Louisiana Municipal
Association, Tom Ed McHugh..................................... 35
American Public Power Association, Large Public Power Council,
and South Carolina Public Service Authority, John H. Tiencken.. 77
Edison Electric Institute, and Ameren Corporation, Gregory Nelson 84
Fuel Cell Advocates, and Plug Power Inc., Roger Saillant......... 16
Independent Petroleum Association, National Stripper Well
Association, California Independent Petroleum Association, and
Berry Petroleum Company, David S. Hall......................... 55
National Mining Association, and Murray Energy Corporation,
Robert E. Murray............................................... 20
National Rural Electric Cooperative Association, and Claiborne
Electric Co-op, Inc., Jerry D. Williams........................ 70
Placid Refining Company LLC, Dan Robinson........................ 11
Sustainable Energy Coalition, and American Council for an Energy-
Efficient Economy, Howard Geller............................... 25
SUBMISSIONS FOR THE RECORD
Air Conditioning Contractors of America, Arlington, VA, Larry
Taylor, statement.............................................. 93
Alliance for Resource Efficient Appliances, statement............ 95
American Chemistry Council, Arlington, VA, statement............. 96
American Public Power Association, and Washington Public Utility
District Association, Seattle, WA, Stephen Johnson, statement.. 98
Baldor Electric Company, Fort Smith, AR, John A. McFarland, and
Roland S. Boreham, Jr., statement and attachments.............. 99
Coalition of Publicly Traded Partnerships, and Chambers
Associates Incorporated, Letitia Chambers, joint statement and
Methanol Institute, Rosslyn, VA, statement....................... 106
Natural Gas Vehicle Coalition, Arlington, VA, statement.......... 107
Natural Resources Defense Council, San Francisco, CA, David B.
Goldstein, statement and attachment............................ 108
Power Ahead, statement and attachment............................ 113
Solid Waste Association of North America, Silver Spring, MD, John
H. Skinner, letter............................................. 117
United Technologies Corporation, statement and attachments....... 119
THIRD IN SERIES ON EFFECT OF FEDERAL TAX LAWS ON THE PRODUCTION,
SUPPLY, AND CONSERVATION OF ENERGY
WEDNESDAY, JUNE 13, 2001
House of Representatives,
Committee on Ways and Means,
Subcommittee on Select Revenue Measures,
The Subcommittee met, pursuant to notice, at 10:05 a.m., in
room 1100 Longworth House Office Building, Hon. Jim McCrery,
(Chairman of the Subcommittee) presiding.
[The advisory announcing the hearing follows:]
FROM THE COMMITTEE ON WAYS AND MEANS
SUBCOMMITTEE ON SELECT REVENUE MEASURES
CONTACT: (202) 226-5911
FOR IMMEDIATE RELEASE
June 6, 2001
McCrery Announces Third in a Series of Hearings on the Effect of
Federal Tax Laws on Production, Supply, and Conservation of Energy
Congressman Jim McCrery (R-LA), Chairman, Subcommittee on Select
Revenue Measures of the Committee on Ways and Means, today announced
that the Subcommittee will hold a third hearing on the effect of
Federal tax laws on the production, supply, and conservation of energy.
The hearing will take place on Wednesday, June 13, 2001, in the main
Committee hearing room, 1100 Longworth House Office Building, beginning
at 10:00 a.m.
Oral testimony at this hearing will be from invited witnesses only.
Witnesses will include industry and environmental groups. However, any
individual or organization not scheduled for an oral appearance may
submit a written statement for consideration by the Committee and for
inclusion in the printed record of the hearing.
The Internal Revenue Code provides several incentives for the
domestic production of oil and gas including: (1) expensing of certain
exploration and development costs, (2) depletion rules, and (3) a tax
credit for enhanced oil recovery costs. The tax code provides
incentives for the production of electricity from certain renewable
resources, including wind and closed-loop biomass facilities, and the
acquisition of equipment that uses solar or geothermal energy. The tax
code also encourages energy conservation by allowing taxpayers to
exclude from income the value of certain energy conservation measures
provided by a utility company to consumers and by providing a credit
for qualified electric vehicles.
In announcing the hearing, Chairman McCrery stated: ``This is the
third in the series of important hearings on energy. I look forward to
hearing from industry and environmental groups about proposals to ease
the energy woes we are currently facing.''
FOCUS OF THE HEARING:
The hearing will focus on proposals to increase domestic production
of traditional and renewable energy resources, to facilitate the
distribution of energy resources, and to promote conservation measures.
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, Tuesday,
June 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
wish to have their statements distributed to the press and interested
public at the hearing, they may deliver 200 additional copies for this
purpose to the Subcommittee on Select Revenue Measures office, room
1135 Longworth House Office Building, by close of business the day
before the hearing.
Each statement presented for printing to the Committee by a
witness, any written statement or exhibit submitted for the printed
record or any written comments in response to a request for written
comments must conform to the guidelines listed below. Any statement or
exhibit not in compliance with these guidelines will not be printed,
but will be maintained in the Committee files for review and use by the
1. All statements and any accompanying exhibits for printing must
be submitted on an IBM compatible 3.5-inch diskette in WordPerfect or
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pages including attachments. Witnesses are advised that the Committee
will rely on electronic submissions for printing the official hearing
2. Copies of whole documents submitted as exhibit material will not
be accepted for printing. Instead, exhibit material should be
referenced and quoted or paraphrased. All exhibit material not meeting
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3. A witness appearing at a public hearing, or submitting a
statement for the record of a public hearing, or submitting written
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4. A supplemental sheet must accompany each statement listing the
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the designated representative may be reached. This supplemental sheet
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The above restrictions and limitations apply only to material being
submitted for printing. Statements and exhibits or supplementary
material submitted solely for distribution to the Members, the press,
and the public during the course of a public hearing may be submitted
in other forms.
Note: All Committee advisories and news releases are available on
the World Wide Web at ``http://waysandmeans.house.gov.''
The Committee seeks to make its facilities accessible to persons
with disabilities. If you are in need of special accommodations, please
call 202-225-1721 or 202-226-3411 TTD/TTY in advance of the event (four
business days notice is requested). Questions with regard to special
accommodation needs in general (including availability of Committee
materials in alternative formats) may be directed to the Committee as
Chairman McCrery. The hearing will come to order.
Today's hearing is a continuation of a series of hearings
we're having on energy policy vis-a-vis the Tax Code in the
United States. Yesterday we heard from about 20 members of
Congress who brought to the Subcommittee various ideas for
using the Tax Code as an incentive for increased production of
oil and gas in the United States, for incentives for
conservation of energy in the United States, and also some
ideas for using the Tax Code for an incentive to produce new
kinds of energy, alternative fuels, renewable fuels, and the
Subcommittee was impressed with both the scope and the depth of
the suggestions that were made by members of Congress.
Today we are going to hear from witnesses representing
industry, business, interest groups that have concerns about
the environment, about energy policy, so we look forward to
hearing from these folks from outside the Congress to tell us
what your ideas are about energy policy in this country and how
the Tax Code might establish sensible energy policy.
And with that, I will turn it over to my good friend from
New York, Mr. McNulty.
Mr. McNulty. Thank you, Mr. Chairman, and thank you again
for holding these very important hearings. I am pleased to join
with you in this, the third hearing conducted by the Select
Revenues Subcommittee on tax incentives for the production,
supply, and conservation of energy in our country.
As we consider energy tax issues, it is important to
understand that the energy problem is not limited to the high
cost of electricity on the West Coast. Indeed, this is a
national problem and we should seek a national solution on a
The administration, in my opinion, is correct to develop a
long-term plan to address our energy needs. However, it would
be wrong to ignore the short-term problems of the West Coast
and to focus all our attention on production initiatives. The
problems of the West Coast can easily grow into the problems of
my home State of New York, spreading up and down the East Coast
across the Midwest and encompassing the entire country. We need
a balanced energy program which reflects appropriate tax
initiatives in the area of production, renewable and
alternative fuels development, conservation and energy
The testimony we will receive today from our distinguished
private sector witnesses will be extremely valuable in
analyzing and developing pending energy tax legislation. I look
forward to this testimony and I welcome each of you.
Mr. Chairman, I also want to express my sincere
appreciation for your including Mr. Roger Saillant as a
witness. Mr. Saillant is the CEO of Plug Power, which is
headquartered in my congressional district. Plug Power is an
industry leader in fuel cell technology and is involved in
exactly the type of energy saving innovation this Committee
should be encouraging.
Now I just want to depart for a moment from my prepared
statement to again thank you, Mr. Chairman, for holding these
hearings and focusing on this issue. My friend Roger asked me
before we started the hearing do I think we will actually do
anything this year? And my answer is yes and the reason I gave
a positive answer is because of your positive attitude and your
focus on this issue. And I think we struck a good chord several
times yesterday when we discussed specific legislative
proposals by the Members. We will have those issues that we
disagree about on Arctic National Wildlife Refuge (ANWR) and
price caps and all the rest but I was struck by the number of
specific bills before this Committee upon which there is broad
And I mentioned the old song; I think we ought to live by
its words. ``Accentuate the positive; eliminate the negative.''
Let us do what we can do. Let us do what we can agree upon and
let us not hold meaningful reform hostage to some of these
So I think we have, Mr. Chairman, broad bipartisan support
on a lot of these issues. I thank you and your Members for the
support that you have given to the fuel cell technology issue,
which was voiced by many of the members who testified
yesterday, and I look forward to working with you in the coming
weeks to make sure that we do get a bill on the floor and we do
accomplish something this year. Thank you, Mr. Chairman.
[The opening statement of Mr. McNulty follows:]
Opening Statement of the Hon. Michael R. McNulty, a Representative in
Congress from the State of New York
I am pleased to join you in this, the third hearing conducted by
the Select Revenue Measures Subcommittee on tax incentives for the
production, supply and conservation of energy in our country.
As we consider energy tax issues, it is important to understand
that the energy problem is not limited to the high cost of electricity
on the West Coast. Indeed, this is a national problem and we should
seek a national solution on a bipartisan basis.
The Administration is correct in seeking to develop a long-term
plan to address our energy needs. However, it would be wrong to ignore
the short-term problems of the West Coast, and to focus all our
attention on production incentives. The problems of the West Coast can
easily grow into problems of my home state of New York, spreading up
and down the East Coast, across the Midwest, and encompassing the
We need a balanced energy program which reflects appropriate tax
incentives in the areas of production, renewable and alternative fuels
development, conservation, and energy efficiency.
The testimony we will receive today from our distinguished private
sector witnesses will be extremely valuable in analyzing and developing
pending energy tax legislation. I look forward to this testimony and
welcome each of you.
Mr. Chairman, I appreciate your including Mr. Roger Saillant as a
witness. Mr. Saillant is CEO of Plug Power, which is headquartered in
my Congressional District. Plug Power is an industry leader in fuel-
cell technology innovation, and is involved in exactly the type of
energy-saving innovation this Committee should be encouraging.
Chairman McCrery. Thank you, Mr. McNulty. And I do look
forward to working with you and Members on both sides of the
aisle to accomplish some very positive things for energy policy
This morning our first panel is composed of a number of
distinguished representatives from the private sector. We have
Joseph Cooper, who is president and chief executive officer of
Alliance of Automobile Manufacturers; Daniel R.Robinson,
president and CEO of Placid Refining Company in Dallas, Texas; Roger
Saillant, president and CEO of Plug Power, Inc. on behalf of the Fuel
Cell Advocates, Latham, New York; Robert Murray, president and CEO of
Murray Energy Corporation on behalf of the National Mining Association;
and Howard Geller, executive director emeritus, American Council for an
Energy Efficient Economy on behalf of the Sustainable Energy Coalition.
Welcome, everyone. Your written testimony will be submitted
in its entirety for the record. We ask you though to summarize
that testimony in 5 minutes. You will notice before you there
is a little machine there that will light up in just a minute.
As long as the green light is on, you are in good shape. When
the yellow light comes on, start wrapping up. And when the red
light comes on, we expect you to conclude.
So now we will proceed and begin with Ms. Cooper.
STATEMENT OF JOSEPHINE S. COOPER, PRESIDENT AND CHIEF EXECUTIVE
OFFICER, ALLIANCE OF AUTOMOBILE MANUFACTURERS
Ms. Cooper. Thank you, Mr. Chairman. On behalf of the 13
members of the Alliance of Automobile Manufacturers, it is a
pleasure to be here today to provide the Subcommittee with our
position on the role of cars and light trucks in our national
energy policy. Today I would like to make three basic points.
First, existing energy policies are not delivering
anticipated results. That is why we are all sitting here today.
Second, to be successful, we must maintain a consumer focus
because consumers determine fuel economy every day through
their purchasing decisions on dealers' lots.
And third, with your help we can increase the fuel economy
of the fleet and meet consumer demands by accelerating the
introduction of advanced technology fuel efficient vehicles.
Let me expand. We are a mobile society. Today
transportation accounts for nearly two-thirds of all oil
consumption and is almost 97-percent dependent on petroleum.
Federal fuel economy requirements are established by a 25-year-
old regulatory program known as Corporate Average Fuel Economy
or CAFE. In 1992 the National Academy of Sciences called CAFE a
flawed program in need of review. At the direction of Congress,
the academy is once again reviewing CAFE and will issue a
report this summer. This report may well focus on how CAFE only
addresses the supply side of the equation but I am not here to
dwell on the inefficiencies of the CAFE program, which are well
documented and included in my written statement.
I am not here today, either, to focus on the future of
CAFE. Congress has already acted in that regard. Congress does
not need to set new standards or change the structure of the
CAFE program. Current law requires the Department of
Transportation to promulgate new light truck standards; that
is, fuel economy standards for pick-ups, sport utility
vehicles, mini-vans and vans at the maximum level possible when
considering certain criteria. We will be working with the
department to ensure appropriate standards are set.
Meanwhile, we continue to work on increasing fuel
efficiency. Auto manufacturers have consistently increased the
fuel efficiency of their models since the 1970s. According to
Environmental Protection Agency (EPA) data, fuel efficiency has
increased steadily at nearly 2 percent a year on average from
1975 to 2001 for both cars and light trucks. This fuel
efficiency is a measure of how effectively a vehicle uses
energy from fuel.
While car and light truck fuel efficiency continues to
increase, their combined fuel economy has stabilized for one
reason: consumers are in the driver's seat when it comes to
determining fuel economy. This is the demand side of the
Today you are in the role of policy-makers but you are also
consumers and like millions of consumers nationwide, you may
also value advanced safety features, passenger room, towing
capacity, cargo-carrying capacity, utility, comfort and
performance when you buy a vehicle. In fact, most consumers
want it all. In surveys, consumers indicate they want greater
fuel economy but in their purchases they do not want to
sacrifice size, safety, cargo room, acceleration or other
vehicle attributes to get it.
Today manufacturers offer more than 50 models with fuel
economy ratings above 30 miles per gallon. We also offer
vehicles that get more than 40 miles per gallon or greater but
these highly fuel efficient vehicles account for less than 2
percent of sales.
So here we are. CAFE only addresses the supply side of fuel
economy and to be successful we must maintain a consumer focus,
a focus on the demand side.
We all want greater fuel economy but how do we get there
from here? The auto industry strongly believes that technology
will allow us to address energy conservation goals and still
provide consumers with vehicles that meet their family and
their business needs. That is why we support the alternative
fuel and advanced technology provisions in Vice President
Cheney's national energy policy.
We also support the tax credit provisions in Congressman
Camp's bill, H.R. 1864, which you all heard about yesterday,
the Clean Efficient Automobiles Resulting from Advanced Car
Technologies Act. The CLEAR Act would provide tax incentives
for fuel cells, hybrid electric vehicles, battery electric
vehicles and dedicated alternative fuel vehicles, along with
alternative fuel and alternative fuel infrastructure
The CLEAR Act is timely legislation. New technologies have
set the stage for transforming the auto industry. Today you can
purchase alternative fuel vehicles from subcompacts to SUVs to
pick-ups. Alliance Members are developing and introducing
hybrid electric cars, SUVs and pick-ups that can increase city
fuel economy by up to 200 percent.
Mr. Chairman, we support consumer tax credits. As a result,
the manufacturers can increase production and lower costs for
consumers. Consumers will have more fuel efficient vehicles
with the vehicle attributes that they desire, and the policy-
makers will see increases in fuel economy.
In conclusion, let us not try to fix CAFE. Let the program
as it stands continue. Second, as we go forward, we must
maintain consumer focus. And lastly, tax credit will accelerate
the market penetration of highly fuel efficient vehicles that
consumers will buy. Thank you, Mr. Chairman.
[The prepared statement of Ms. Cooper follows:]
Statement of Josephine S. Cooper, President and Chief Executive
Officer, Alliance of Automobile Manufacturers
Thank you for the opportunity to testify before your Subcommittee
regarding energy policy issues. My name is Josephine S. Cooper and I am
President and CEO of the Alliance of Automobile Manufacturers, a trade
association of 13 car and light-truck manufacturers. Our member
companies include BMW of North America, Inc., DaimlerChrysler
Corporation, Fiat, Ford Motor Company, General Motors Corporation,
Isuzu Motors of America, Mazda, Mitsubishi, Nissan North America,
Porsche, Toyota Motor North America, Volkswagen of America, and Volvo.
Alliance member companies have more than 620,000 employees in the
United States, with more than 250 manufacturing facilities in 35
states. Overall, a recent University of Michigan study found that the
entire automobile industry creates more than 6.6 million direct and
spin-off jobs in all 50 states and produces almost $243 billion in
payroll compensation annually.
The Alliance supports efforts to create an effective energy policy
based on broad, market-oriented principles. Policies that promote
research development and deployment of advanced technologies and
provide customer based incentives to accelerate demand of these
advanced technologies set the foundation. This focus on bringing
advanced technologies to market leverages the intense competition of
the automobile manufacturers worldwide. Incentives will help consumers
overcome the initial cost barriers of advanced technologies during
early market introduction and increase demand, bringing more energy
efficient vehicles into the marketplace.
This year, there has been increased attention on vehicles and their
fuel economy levels with particular discussion of the Corporate Average
Fuel Economy (CAFE) program. Rather than simply engage in an exercise
updating a 26-year-old program with all of its flaws, Congress needs to
consider new approaches for the 21st century. The Alliance and its 13
member companies believe that the best approach for improved fuel
efficiency is to aggressively promote the development of advanced
technologies--through cooperative, public/private research programs and
competitive development--and incentives to help pull the technologies
into the marketplace as rapidly as possible. We know that advanced
technologies with the potential for major fuel economy gains are
possible. As a nation, we need to get these technologies on the road as
soon as possible in an effort to reach the national energy goals as
fast and as efficiently as we can.
The Alliance is pleased that Vice President Cheney's National
Energy Policy report recommends and supports a tax credit for advanced
technology vehicles (ATVs). Specifically, it proposes a tax credit for
consumers who purchase a new hybrid or fuel cell vehicle between 2002
and 2007. In addition, the report supported the broader use of
alternative fuel and alternative vehicles. This is consistent with the
Alliance's position of supporting enactment of tax credits for
consumers to help offset the initial higher costs of advanced
technology and alternative fuel vehicles until more advancements and
greater volumes make them less expensive to produce and purchase.
In reviewing House legislation that has been crafted to spur the
sale of advanced technology fuel-efficient vehicles, the Alliance is in
general agreement with H.R. 1864 introduced by Congressman Camp.
Automakers would like to see some minor, technical changes made to the
hybrid-electric vehicle section of the bill and would also support the
inclusion of tax credits for advanced lean burn technology. The
Alliance believes that the overall concepts and provisions found in
H.R. 1864 are the right approach and would benefit American consumers.
The bill would ensure that advanced technology is used to improve
fuel economy. Performance incentives tied to improved fuel economy are
incorporated into the legislation in order for a vehicle to be eligible
for the tax credits. These performance incentives are added to a base
credit that is provided for introducing the technologies into the
Specifically, H.R. 1864 has a number of important provisions
addressing various types of advanced technologies. These include:
Fuel Cell Vehicles
The most promising long-term technology offers breakthrough fuel
economy improvements, zero emissions and a shift away from petroleum-
based fuels. A $4,000 base credit is included along with performance
based fuel economy incentives of up to an additional $4,000. The credit
is available for 10 years to accelerate introduction--extremely low
volume production is expected to begin in the 2005-2007 timeframe.
Electronics that integrate electric drive with an internal
combustion engine offer near term improvements in fuel economy. A
credit of up to $1,000 for the amount of electric drive power is
included along with up to $3,000 depending upon fuel economy
performance. The credit is available for 6 years to accelerate consumer
demand as these vehicles become available in the market and set the
stage for sustainable growth. To be eligible for the credit, hybrid
vehicles must meet or beat the average emission level for light duty
Dedicated Alternative Fuel Vehicles
Vehicles capable of running solely on alternative fuels, such as
natural gas, LPG, and LNG, promote energy diversity and significant
emission reductions. A base credit of up to $2,500 is included with an
additional $1,500 for vehicles certified to ``Super Ultra Low
Emission'' standards (SULEV).
Battery Electric Vehicles
Vehicles that utilize stored energy from ``plug-in'' rechargeable
batteries offer zero emissions. A base credit of $4,000 is included
(similar to the fuel cell--both have full electric drive systems) and
an incremental $2,000 is available for vehicles with extended range or
Alternative Fuel Incentives
Alternative fuels such as natural gas, LNG, LPG, hydrogen, B100
(biomass) and methanol are primarily used in alternative fueled
vehicles and fuel cell vehicles. To encourage the installation of
distribution points to support these vehicle applications, a credit of
$0.50 for every gallon of gas equivalent is provided to the retail
distributor. This credit is available for 6 years and will support the
distribution of these fuels as vehicle volume grows and may be passed
on to the consumer by the retail outlet. Note that ethanol is not
included in these provisions due to the existing ethanol credit.
Alternative Fuel Infrastructure
Complementary to the credit for the fuel itself, the existing
$100,000 tax deduction for infrastructure is extended for 10 years and
a credit for actual costs up to $30,000 for the installation cost of
alternative fuel sites available to the public is included. One of the
key hurdles to overcome in commercializing alternative fuel vehicles is
the lack of fueling infrastructure. For nearly a century,
infrastructure has focused primarily on gasoline and diesel products.
These infrastructure and fuel incentives will help the distributors
overcome the costs to establish the alternative fuel outlets and
support distributors during initial lower sales volumes as the number
of alternative fuel vehicles increases.
Automobile manufacturers believe that CAFE, however well-intended,
has not achieved its desired goals and has had a number of unintended
consequences. Meeting CAFE standards is not something that
manufacturers can do by themselves. Because the standards are a sales-
weighted fleet average, the ultimate outcome depends on what the
consumer purchases. If not enough customers purchase the higher fuel
economy models of a given manufacturer, then the fleet average for that
automaker may not achieve the CAFE standard. Since manufacturers have
widely varying fleet mixes and product offerings, the CAFE program has
had widely disparate impacts on automakers and has afforded some
manufacturers with significant competitive advantages at times.
Increasing CAFE standards will only exacerbate these problems.
Higher standards may result in vehicles that are less attractive to
customers in terms of meeting their needs for work and family. If
consumer demand is not aligned with manufacturers' production, there is
the potential for significant negative impact on employment throughout
the industry. Ultimately, any fuel savings that result will come at
high cost to consumers, manufacturers and the economy. In short,
automakers need to produce vehicles that appeal to customers. CAFE acts
as a market intrusion that over time will create distortions and
unintended adverse consequences.
Recent sales figures support this position. The top ten most fuel-
efficient vehicles account for less than 2% of total sales. The
ultimate goal for any business is to provide products consumers want to
buy. Increasing CAFE standards will require automakers to produce less
of the products that American consumers are actually purchasing today
and more of the products that are in lower demand.
Fuel economy standards only address the supply side of the
equation. The Alliance believes, however, that Congress does not need
to set new standards or change the structure of the program as the law
requires the Department of Transportation (DOT) to promulgate new light
truck standards (pickups, SUVs, minivans and vans) at the maximum level
taking into consideration certain criteria. Automakers will be working
with the DOT to ensure appropriate standards are set.
In the industry, CAFE regulations affect each Alliance member
differently. Manufacturers whose fleets are comprised primarily of
larger, lower fuel economy vehicles are more constrained in their
product planning by CAFE standards than manufacturers with fleets
comprised mainly of smaller, higher fuel economy vehicles. As each
manufacturer attempts to design, produce and sell vehicles in their
target markets, CAFE operates, for some manufacturers, as a roadblock
to supplying their vehicles to the market.
The domestic/non-domestic passenger car fleet distinction is
another important matter. While originally designed to keep small car
production in the U.S. and protect American jobs, this distinction has
inhibited some manufacturers from increasing the procurement of U.S.
parts and materials. The domestic/non-domestic distinction has had
widely disparate impacts on automakers. The requirement for separate
fleets serves as a clear example of CAFE's market distorting effects,
which then have a negative impact on the U.S. economy.
Another consequence of CAFE has been the downsizing of the
passenger car fleet. Weight and size reductions remain one of the prime
means of achieving improved fuel efficiency. The basic laws of physics
dictate that smaller, lighter vehicles fare worse in accidents than
larger, heavier vehicles, all things being equal.
To reiterate, a better way to improve vehicle and fleet fuel
economy, and one that is more in tune with consumer preferences, is to
encourage the development and purchase of advanced technology vehicles
(ATVs). Consumers are in the driver's seat and most independent surveys
show that Americans place a high priority on performance, safety, space
and other issues with fuel economy ranking much lower even with today's
gas prices. ATVs hold great promise for increases in fuel efficiency
without sacrificing the other vehicle attributes consumers desire. Just
as important, the technology is transparent to the customer.
Member companies of the Alliance have invested billions of dollars
in research and development of more fuel-efficient vehicles. Automobile
companies around the globe have dedicated substantial resources to
bringing cutting-edge technologies--electric, fuel cell, and hybrid
electric vehicles as well as alternative fuel vehicles and powertrain
improvements--to the marketplace. These investments will play a huge
role in meeting our nation's energy and environmental goals.
These advanced technology vehicles are more expensive than their
gasoline counterparts during early market introduction. As I mentioned
earlier, the Alliance is supportive of Congressional legislation that
would provide for personal and business end-user tax incentives for the
purchase of advanced technology and alternative fuel vehicles. Make no
mistake: across the board, tax credits will not completely cover the
incremental costs of new advanced technology. However, it will make
consumers more comfortable with accepting the technology and begin to
change purchasing behavior. In short, tax credits will help bridge the
gap towards winning broad acceptance among the public leading to
greater volume and sales figures throughout the entire vehicle fleet.
This type of incentive will help ``jump start'' market penetration and
support broad energy efficiency and diversity goals.
Enabling consumers to make more effective fuel-efficient choices
rather than mandating government standards makes more sense to achieve
the desired outcome. After all, the industry already spends a
significant amount on compliance with government regulations while
investing large sums in capital improvements and competitive designs.
Some of the discussion today has centered on the vehicles of the
automobile manufacturers. But it is important not to forget about a
vital component for any vehicle--the fuel upon which it operates. As
automakers looking at the competing regulatory challenges for our
products--fuel efficiency, safety and emissions--and attempting to move
forward with advanced technologies, we must have the best possible and
cleanest fuels. EPA has begun to address gasoline quality but it needs
to get even cleaner. This is important because gasoline will remain the
prevalent fuel for years to come and may eventually be used for fuel
Beyond gasoline, the auto industry is working with a variety of
suppliers of alternative fuels. In fact, the industry already offers
more than 25 vehicles powered by alternative fuels. More than 1 million
of these vehicles are on the road today and more are coming. Today, we
find vehicles that use:
Natural gas, which reduces carbon monoxide emissions by 65
to 90 percent;
Ethanol, which produces fewer organic and toxic emissions
than gasoline with the longer term potential to substantially reduce
Liquefied petroleum gas (propane), the most prevalent of
the alternative fuels, which saves about 60% VOC emissions; and
For the future, hydrogen, which has the potential to emit
nearly zero pollutants.
The Alliance has submitted comments to the DOT in support of an
extension of the dual fuel vehicle incentives through 2008. Current law
provides CAFE credits--up to 1.2 mpg--for manufacturers that produce
vehicles with dual fuel capability. These vehicles can operate on
either gasoline or domestically produced alternative and renewable
fuels, such as ethanol. However, the dual fuel credits end in model
year 2004 unless extended via rulemaking by the National Highway
Traffic Safety Administration. The Alliance believes an extension is
important so that these vehicles continue to be produced in high volume
to help encourage the expansion of the refueling infrastructure and
giving consumers an alternative to gasoline.
In addition to alternative fuels, companies are constantly
evaluating fuel-efficient technologies used in other countries to see
if they can be made to comply with regulatory requirements in the
United States. One such technology is diesel engines, using lean-burn
technology, which have gained wide acceptance in Europe and other
countries. Automakers have been developing a new generation of highly
fuel-efficient clean diesel vehicles--using turbocharged direct
injection engines--as a way to significantly increase fuel economy and
reduce greenhouse gas emissions. However, their use in the U.S. must be
enabled by significantly cleaner diesel fuel.
Earlier this year, EPA promulgated its heavy-duty diesel rule that
the Alliance supports, as far as it goes. The rule reduces the amount
of sulfur in the fuel. Low sulfur diesel fuel is necessary to enable
the new clean diesel technology to be used in future cars and light
trucks. Providing cleaner fuels, including lowering sulfur levels in
gasoline and diesel fuel, will provide emission benefits in existing
on-road vehicles. Sulfur contaminates emissions control equipment, such
as catalytic converters. Efforts to reduce sulfur content will provide
environmental benefits and allow vehicles to operate more efficiently.
Unless there are assurances that fuels will be available, companies
will not invest in new clean diesel technologies.
As you can tell, the automobile companies--from the top executives
to the lab engineers--are constantly competing for the next
breakthrough innovation. If I can leave one message with the
Subcommittee today, it is to stress that all manufacturers have
advanced technology programs to improve vehicle fuel efficiency, lower
emissions and increase motor vehicle safety. These are not ``pie in the
sky'' concepts on a drawing board. In fact, many companies have
advanced technology vehicles in the marketplace right now or have
announced production plans for the near future. That's why now is the
perfect time for the enactment of tax credits to helpspur consumers to
purchase these new vehicles which years of research and development
have made possible.
Higher CAFE standards, with all of the disparate impacts inherent
in that program, would divert limited resources from these ongoing
efforts and distort the market for our products. Competition will drive
improvements and success in the area of increasing vehicle fuel
economy. This powerful market force should be allowed to work where it
can and should be enhanced with incentives where they are needed to
``prime the pump.''
We would urge that public policy decisions focus on the steps that
will achieve real improvements in fuel consumption and benefit our
environment. We believe that advanced technology vehicles and
appropriate tax policy are a better way to increase fuel efficiency
than the policy of CAFE that effectively limits consumer choice,
adversely affects safety and affordability and creates ``winners and
losers'' within the auto community.
Thank you for the opportunity to testify before the Subcommittee
today. I would be happy to answer any questions you may have.
Chairman McCrery. Mr. Robinson.
STATEMENT OF DAN ROBINSON, PRESIDENT AND CHIEF EXECUTIVE
OFFICER, PLACID REFINING COMPANY LLC, DALLAS, TEXAS
Mr. Robinson. Thank you, Mr. Chairman, members of the
Subcommittee. I appreciate the opportunity to be here today to
testify about the outlook of the small refining industry in the
I represent Placid Refining Co., which is a privately owned
independent refiner, a small refiner with the capacity of
50,000 barrels per day. Our plant is located in Port Allen,
Louisiana. We produce primarily gasoline, military jet fuel,
and diesel fuel suitable for on-road use. I do not represent
any other group of small refiners but due to our size, we are
fairly representative of small refiners in the United States,
which by some standards includes a group of up to 43 companies
operating 57 refineries or up to 8.6 percent of our nation's
We have been seeing over the past 25 years an alarming rate
of refinery closures in this country. We have had a loss of
from up to 300 plants down to the current level of about 150.
Most of these losses admittedly have come from small refineries
owned by small refiners. In fact, Secretary Abraham is quoted
as saying over 50 of these refineries have been lost in the
last 10 years alone, the most recent being the one in Blue
The loss of this capacity has been replaced largely by the
expansion of the remaining refineries in the country, primarily
the larger ones. The smaller plants, however, have not
participated to a great degree in expanding their capacities
and we feel that they should be encouraged to do so. Certainly
any impediments to expansion of small refineries need to be
addressed wherever they are found.
One particular example of this can be found in section
613(a) of the Internal Revenue Code. That particular section
provides that any independent producer stands to lose his
status as an independent producer if he owns an equity interest
in any refinery that refines more than 50,000 barrels per day
of crude oil on any single day.
Placid has long opposed this particular test of any single
day because it limits the flexibility of a refiner to produce
more than 50,000 barrels per day on certain days of the year in
order to offset production lost on other days of the year when
it has to be shut down for maintenance. We alternatively
support a change in this language so that the test would be
made on an annual average basis rather than an any single day
This is not a new proposal. It has been around for a while.
The Ways and Means Committee has considered this measure in
1999 when the 1999 tax bill was under consideration. The
Committee adopted this proposal, incorporated it into the tax
bill and, as we all know, it was later vetoed by President
The measure continues to have broad bipartisan support. It
has currently been readopted into two bills, Senator
Murkowski's energy bill, S. 389, and Representative
Thornberry's bill, H.R. 805, and we urge the Committee to once
again give us favorable consideration on this issue when it
comes before you.
But in light of the opinions stated by President Bush, Vice
President Cheney, Secretary Abraham and others that we need to
make a national priority of expanding refining capacity in this
country, we think it is entirely appropriate now to address the
50,000 barrel issue itself. This standard was instituted in
1975 into the Code and it has remained unchanged at that 50,000
barrel level for over 25 years. Other agencies on the Hill
considered that higher standards are probably more reasonable
for small refiners. The Small Business Administration, for
example, uses a standard of 75,000 barrels per day. The
Environment Protection Agency recently adopted 155,000 barrels
per day as its standard for small refiners.
We urge the Committee to consider favorably any legislation
that would come forward in the near future regarding the
changing of these limits from 75,000 to higher levels, which
will encourage small refiners to increase their production.
Before I close I would like to mention one other quick
issue that is a particular concern to small refiners regarding
Environmental Protection Agency (EPA's) current regulations to
reduce sulphur limits in gasoline and diesel fuel dramatically.
This is going to affect all refiners in the United States but
in particular, small refiners are going to be particularly
affected because the level of investments that are going to be
required of these plants in some cases will exceed the entire
market value of their refineries.
Given the fact that small refiners have limited resources,
limited access to capital, and armed with the knowledge that
investments that have been made traditionally in the past to
produce cleaner fuels have yielded little, if any, return,
there are going to be some very serious decisions that are
going to have to be made in the board rooms of small
In order to soften the blow, some refiners have formed a
loose ad hoc committee to explore whether tax credits or
expensing of investments to meet these investments that are
going to be required to produce these lower sulphur fuels might
be appropriate. These proposals are currently being developed
and being discussed on the Hill and there is not a particular
proposal ready to go right now but we think that there will be
one soon and we urge the Committee to keep in mind this need
when any legislation that might come from these efforts will
come before you.
We thank you very much for your patience today.
[The prepared statement of Mr. Robinson follows:]
Statement of Dan Robinson, President and Chief Executive Officer,
Placid Refining Company, LLC, Dallas, Texas
REGARDING THE ROLE OF SMALL REFINERS IN THE NATIONAL ENERGY PICTURE
Mr. Chairman and Members of the Subcommittee:
I appreciate the opportunity to appear before you today to discuss
the outlook for the small refining industry in the United States.
Placid Refining Company LLC is a privately owned independent
refiner. The company owns and operates a refinery located in Port
Allen, Louisiana with a rated capacity of 50,000 barrels per day. This
facility produces roughly 50% of its output as gasoline and another 40%
as military jet fuel and diesel fuel suitable for on-road use. The
company is not engaged in retail marketing. Rather, it wholesales its
fuel production throughout the Southern and Southeastern regions of the
United States. Placid is certified as a small refiner under both the
Small Business Administration (SBA) and the Environmental Protection
Agency (EPA) guidelines.
Under the SBA guidelines Placid is representative of 36 small
refining companies operating 40 refineries, and having total refining
capacities of 75,000 barrels per day or less. While this group owns
about 26% of the nation's operable refineries they represent only about
5.5% of the total national refining capacity.
Under the EPA small refiner guidelines Placid is representative of
43 small refining companies, which have a total refining capacity of
155,000 barrels per day or less. This group owns and operates 57
refineries or about 38% of the nation's operating refineries,
comprising about 8.6% of the total national capacity.
The Challenges for Small Refiners
These refineries are located in diverse regions all over the United
States. Some are located in remote areas and serve as the nearest and
best source of fuels for the regional inhabitants; some are specially
designed to refine the specific grades of crude oil produced in their
immediate locales; some produce specialty products and solvents; some
produce asphalt; some concentrate on lube oils. Many provide reliable
supplies of jet fuel for the United States armed forces, and most
contribute to the nation's fuel supplies. All are important to the
economy of our nation and the closure of any would be an irretrievable
Yet, if the history of the last twenty-five years tells us anything
it is that more closures are virtually inevitable. Since 1975 the
number of operable refineries in the United States has dwindled from
about 300 to about 150. Most of these casualties were small refineries
owned by small refiners. According to U.S. Energy Secretary Abraham,
about 50 U.S. refineries have closed in the last 10 years alone, the
most recent being the Premcor refinery in Blue Island, Illinois. Not
coincidentally, this 10-year period commenced with the enactment of the
Clean Air Act of 1990. Massive investments have been required of the
refining industry to produce cleaner burning fuels and to reduce
stationary source emissions.
Unfortunately these investments have proved to produce little or no
return and have served to drain resources away from the other more
economically productive endeavors. The recent enactment of ultra-low
sulfur regulations for both diesel fuel and gasoline by the EPA portend
more of the same, which is of particular concern to small refiners who
have less resources and more limited access to capital than the larger
During the last 25 years, not a single new refinery has been
constructed in the United States due to insufficient economic
justification and increasingly onerous permitting requirements.
Instead, the capacity lost by these refinery closures has been replaced
solely by expanding the remaining refineries. This strategy may not be
sustainable indefinitely, but it appears to be the only near term
practical way to increase refinery capacity in this country.
The remaining operating refineries should be encouraged to employ
their resources for the purpose of expansion. Certainly, any
impediments to such expansion should be addressed wherever they are
encountered. At the present, it is becoming apparent that refinery
capacity in the United States, which was once abundant, is now becoming
severely strained. The demand for transportation fuels can now only be
met when the industry is operating at full capacity. There is little
room for unexpected shutdowns without creating local supply
disruptions, which can result in or contribute to regional price
Small refiners face a number of formidable challenges, which must
be successfully met if this trend is to be halted. The refining
industry has proven to be a low return business over the past twenty-
five years. By virtue of their size alone, small refiners are at a
competitive disadvantage to their larger peers in the struggle to
capture a share of these already thin margins.
Since economies of scale take on a particular importance in the
refinery industry, small refiners see the need to focus their attention
and resources on expansion of both capacity and complexity in order to
improve their competitive position and insure their survival. However,
certain regulatory impediments and requirements are posing challenges
to this focus. In addition, low profitability and limited access to
capital force small refiners to be very judicious with their investment
strategies. I would like to focus on two particular areas where tax
legislation might be constructive in preserving this vital segment of
the refining industry. The first of these addresses the capacity
limitations imposed in Section 613A of the Internal Revenue Code, and
the second addresses tax relief related to the capital investments
required to comply with the newly enacted EPA regulations for the
reduction of sulfur in gasoline and diesel fuels.
Internal Revenue Code Section 613A
While larger refiners are moving forward with efforts to expand
their refineries some small refiners face a serious impediment to doing
the same due to a limitation imposed in Section 613A of the Internal
Revenue Code. Section 613A allows an independent producer to claim
percentage depletion on an annual average daily production of up to
1,000 barrels of oil per day, and to expense certain intangible
drilling costs, provided that the producer meets certain tests.
Included among these tests is the requirement of having little or no
ownership in a refinery which runs more than 50,000 barrels of crude
oil ``on any single day'' during the taxable year. The effect of the
``on any single day'' language is to prohibit a small refiner from
using any excess capacity to replace production lost from planned or
unplanned outages. It is proposed that the language be modified to
provide that the 50,000 barrel per day limit be imposed on a ``annual
average'' basis rather than on an ``any single day'' basis.
In order to meet the ``on any single day'' test, a refiner must run
less than 50,000 barrels per day every day to allow for inadvertent
errors in metering and gauging. In addition, refiners must shut down or
reduce runs during certain days of the year for scheduled or
unscheduled maintenance. The requirement that refinery runs cannot
exceed 50,000 barrels per day ``on any single day'' does not allow the
refiner any flexibility to recover from its lost runs. The effect of
this limitation is that small refiners must process on average,
significantly less than 50,000 barrels per day in order to avoid the
loss of independent producer status to its owners and affiliates.
Consequently, a small refiner capable of processing up to or more than
50,000 barrels per day is discouraged from the most efficient use of
We gratefully acknowledge that this proposal was supported by the
Ways and Means Committee in 1999, by way of bills introduced by
Chairman McCrery from the House of Representatives and by Senator
Breaux from the Senate that were incorporated into the larger 1999 tax
bill, subsequently vetoed by President Clinton. We also are grateful
that this initiative has recently been incorporated into both Senator
Murkowski's National Energy Security Act of 2001 (S.389) and
Congressman Thornberry's Independent Energy Production Act of 2001
(H.R.805), and urge the Committee to once again pass this measure when
it comes before you for review.
However, in light of the views publicly expressed by President
Bush, Vice President Cheney, and Secretary Abraham, and shared by many
in Congress, that expansion of refining capacity in the United States
should be a national priority, we believe it is appropriate that the
50,000 barrel per day threshold in Section 613A should be raised to a
higher level. Raising this limit would remove an important impediment
to expansion of refineries owned by independent producers.
Section 613A was enacted in 1975. Since that time the trend has
been for refineries to grow by expanding existing capacity. As noted
earlier, many small refineries have been closed and those that cannot
expand face increasing competitive pressures from those that can. Other
regulatory bodies have recognized that ceilings higher than 50,000
barrels per day are now appropriate for defining a small refiner. The
Small Business Administration has adopted a definition, which requires
a small refiner to have a capacity of no more than 75,000 barrels per
day and a maximum of 1,500 employees. Recently the Environmental
Protection Agency adopted a small refiner definition of 155,000 barrels
per day with a maximum of 1,500 employees. The world has changed since
1975 and so has the refining industry. It is, therefore, entirely
appropriate to revisit the antiquated 50,000 barrel small refiner
standard established in the Code more than 25 years ago. While changing
the ``on any single day'' language to ``annual average'' would be
favorable, raising the threshold from 50,000 barrels per day to 75,000
barrels per day would be better. Raising the limit to 155,000 barrels
per day would be better still, and more reflective of small refiner
standards, given the nature of today's refining industry.
It should be noted that the change of the ``on any single day''
language included in the 1999 tax bill was liberally scored at less
than $2 million per year by the Joint Committee on Taxation. At the
request of Chairman McCrery, new revenue estimates are currently being
prepared on each of these three proposals. Of course, any revenue
estimate of these proposals carries the inherent weakness of ignoring
the positive revenue benefits that would flow from small refiners that
are allowed to grow and improve their operations.
The EPA Sulfur Reduction Regulations
The EPA has recently issued two new regulations governing the
sulfur levels, which will be permitted in transportation fuels.
Beginning in 2004 gasoline sulfur levels will have to meet a 30 part
per million standard, which is about a tenfold decrease from current
levels. In its consideration of this rulemaking the EPA provided an
extended timetable for full compliance by small refiners until 2008
provided that they meet less strict interim standards in the meantime.
For purposes of determining which small refiners would qualify for this
treatment, the EPA adopted a 155,000 barrels per day capacity and 1,500
employee limit as its small refiner definition.
Subsequently, the EPA enacted a 15 part per million sulfur standard
for on-road diesel to take effect in 2006. This standard as compared to
the current 500 part per million specification represents a 97%
reduction. Unlike the gasoline regulation the new diesel standard has
no deferred compliance provision for small refiners. In addition, the
industry expects the EPA to issue another new ruling reducing the
sulfur limit for off-road diesel in the near future. All small refiners
produce diesel fuel and many also produce gasoline. The combined effect
of these regulations will close the markets to any small refiner who
does not or cannot undertake the installation of expensive
While no one opposes the larger objective of a cleaner environment,
the onus of these regulations is falling heavily on the refining
industry. The technology to produce these ultra low sulfur fuels
exists, but it is not inexpensive. Due to their size and limited
capital resources small refiners will be disproportionately affected.
It is impossible to generalize about the specific effects that a
typical small refiner will encounter. Each refiner will encounter its
own unique challenges depending upon its location, its existing
infrastructure, and its marketing strategy. But it is safe to say that
few, if any, small refiners will escape the need to make large
investments in desulfurization equipment in order to continue in
business beyond the effective dates of these regulations.
In some cases these investments may actually exceed the entire
market value of the existing refinery. Moreover, if history is any
guide, little return can be expected from these particular investments.
It is not hard to envision the concerns that are raging through the
small refiner contingent about the ability to raise the capital needed
for investments which will do little more than allow them to merely
stay in business. Many hard decisions lie ahead.
The Blue Island refinery closed this year citing the very same
regulatory burdens being addressed herein. In addition, the former
Pennzoil refinery in Shreveport, Louisiana was recently sold and ceased
production of transportation fuels, devoting its resources instead to
lubrication products, which are not affected by the latest EPA sulfur
reduction regulations. We believe it inconsistent with the best
interests of the nation to allow any more such occurrences if they can
When considering the energy needs of the nation, policymakers have
not been averse to including the use of tax incentives to spur
development, and guide policy. Notable examples include the excise tax
exemption on ethanol used in gasoline, tax credits for enhanced oil
recovery costs, tax incentives for energy conservation investments and
investments in power generation from renewable resources, and even
proposed tax credits for the purchase of fuel efficient hybrid or fuel
cell automobiles. The present danger of losing a significant portion of
the country's refining infrastructure suggests that a similar strategy
may be necessary.
An ad-hoc group of small refiners has been working on proposals
permitting the use of either tax credits, or expensing of investment,
or a combination of the two which would apply to all investments
required of small refiners by the new EPA ultra-low sulfur regulations
for diesel fuel. Since small refiners will be facing diesel fuel
desulfurization expenditures sooner than gasoline desulfurization, the
early proposals have focused on diesel fuel. However, similar proposals
would be equally applicable to investments required of small refiners
to meet the EPA ultra-low sulfur regulations for gasoline. Under these
proposals the qualifying refiners would have to meet the EPA small
refiner definition of 155,000 barrels maximum capacity and a maximum of
1,500 employees. I urge the Committee to give careful consideration to
any bill that develops from these efforts.
The small refiner is an important national resource. Small refiners
are eager to contribute to the national good but can only do so much
with limited resources. Tax relief in whatever form it finally assumes
could be the appropriate prescription for helping small refiners cope
with the eminent challenges to their survival being posed by the new
EPA gasoline and diesel sulfur reduction regulations.
Thank you very much for your invitation to present these issues
before the Subcommittee.
Chairman McCrery. Thank you, Mr. Robinson.
STATEMENT OF ROGER SAILLANT, PRESIDENT AND CHIEF EXECUTIVE
OFFICER, PLUG POWER INC., LATHAM, NEW YORK, ON BEHALF OF THE
FUEL CELL ADVOCATES
Mr. Saillant. Thank you, Mr. Chairman and Members of the
Committee. My name is Roger Saillant, chief executive officer
of Plug Power, Incorporated, a developer of fuel cell systems
in Latham, New York, right outside of Albany. We are developing
proton exchange membrane fuel cell systems for the stationary
market, particularly for utilities, small businesses and
ultimately, homes. We are testifying today on behalf of the
fuel cell companies, suppliers, and other interested parties
who have come together to support tax incentives for stationary
fuel cell power systems. In particular, we are supporting House
Resolution 1275 and its companion Senate Bill 828.
A fuel cell system is the cleanest fossil fuel generating
technology available today and will be an integral part of the
hydrogen economy of the future. Fuel cells are power generation
systems that electrochemically combine hydrogen and oxygen--
oxygen from the air and hydrogen readily available from fossil
fuels. The benefits of fuel cell technology include higher
efficiency and near-zero emissions of pollutants like oxides of
sulphur and nitrogen and particulate matter. If widely
deployed, fuel cells can address peak power demand and reduce
the need for new central station power generation and power
The fuel cell tax credit, if passed, would provide $1,000
per kilowatt for purchasers of fuel cell systems and would be
available for purchase of all types and sizes of stationary
fuel cell systems. It would be available for 5 years, January
1, 2002 through December 31, 2006, at which point fuel cell
manufacturers should be able to produce a product at market
entry cost. The credit does not specify fuel inputs,
application or system sizes.Thus, a diverse group of customers
can take short-term advantage of the credit to deploy a wide range of
fuel cell equipment.
The credit will allow access to fuel cell systems by more
customers now, when there is a serious need for reliable power
in many parts of the country. Additionally, the credit will
speed market introduction and create an incentive for
prospective customers, thus increasing volume and helping to
reduce manufacturing costs.
As with any new technology, low initial volumes keep
companies from developing a manufacturing base of component and
subsystem suppliers and therefore we cannot leverage better
prices. For example, we have a control module in our fuel cell
system that is similar to one we purchased when I was at Ford
Motor Company. However, due to where we are on the learning
curve and our volumes, we pay eight to 10 times more than does
Ford for the same module.
Passage of H.R. 1275 will not only benefit fuel system
developers but also customers and the public at large.
Customers will be able to take advantage of the reliable and
uninterruptable power that fuel cells provide, which is
important to customers who are highly sensitive to power grid
Additionally, customers in rural areas or in load pockets
will have reliable and secure power and will be able to have
that power sooner and at a more affordable price with the
passage of the tax incentive.
The public benefits are many. First and probably most
important, fuel cells and the idea of distributed power lay the
foundation for a truly different way to view energy generation
and transmission. In other words, power becomes localized to
the point of use, rather than centralized and distributed. The
analogy is mainframe versus PC, cell phone versus conventional
pole and line telephones.
Second, fuel cells minimize emissions. I have already
mentioned NOX sulphur and particulates.
Third, they are relatively small, quiet, and are easily
sited in areas in and around people's homes.
Fourth, fuel cell systems as a distributed generation
technology can address the immediate need for secure and
adequate energy supplies while reducing grid demand and
increasing grid flexibility.
Fifth, they avoid costly and environmentally problematic
installation of transmission and distribution systems and
siting issues surrounding central station power generation.
And finally, they provide a framework to move from a fossil
fuel-based economy to a longer term truly sustainable energy
The tax credit introduced by Congressman McNulty and
Congresswoman Johnson will help to bring fuel cell power
systems to market more quickly and help address this country's
power needs. The Fuel Cell Advocates encourage you to enact the
legislation this calendar year. Thank you.
[The prepared statement of Mr. Saillant follows:]
Statement of Roger Saillant, President and Chief Executive Officer,
Plug Power Inc., Latham, New York, on behalf of the Fuel Cell Advocates
Good Morning. My name is Roger Saillant, and I am the President and
Chief Executive Officer of Plug Power, Inc., a developer of on-site
energy generating systems utilizing proton exchange membrane fuel cells
for stationary power applications. Our Latham, NY-based company was
founded in 1997, as a joint venture of DTE Energy Company and
Mechanical Technology Incorporated. Plug Power's fuel cell systems for
residential and small commercial stationary applications are expected
to be sold globally through a joint venture with the General Electric
Company, one of the world's leading suppliers of power generation
technology and energy services.
We are testifying today on behalf of a loose coalition of fuel cell
companies, suppliers, and other interested parties, which we are
calling ``Fuel Cell Advocates.'' Plug Power has facilitated this group
coming together to urge passage of a fuel cell tax credit and a similar
program for non-taxpaying entities such as federal, state and local
government entities and municipalities. The group, which includes
companies from all over the country, is supporting passage of H.R.
1275, introduced by Ranking Member McNulty and Congresswoman Johnson.
We also support the Senate companion bill, S. 828. Attached is
information on our advocacy effort, which includes the list of
participating companies (manufacturers, suppliers and related
FUEL CELL DESCRIPTION
A fuel cell is an on-site power generation system that
electrochemically combines hydrogen from readily available fuels--such
as natural gas and propane--with oxygen in the air to form electricity.
Different catalysts are used for the chemical reactions, which provides
for a very diverse portfolio of fuel cell system availability. Fuel
cell systems, whether for the residential, commercial, institutional or
industrial market, produce not only electricity, but also heat that can
be captured for combined heat and power applications. This makes them
highly efficient as well as environmentally friendly.
The fuel cell was first developed in 1839 by Sir William Grove.
Fuel cells were used in the 1950s and 1960s as part of NASA's space
program, but the costs were prohibitive for more widespread use as
compared to conventional power generation technologies. More recently,
the cost of fuel cells has been reduced to the point of commercial
application viability. One company has been selling a single fuel cell
product, at very low volumes, for ten years, and this year, multiple
fuel cell developers are beginning to introduce product. Dozens of U.S.
companies are involved in developing fuel cells themselves or
components for the systems.
Fuel cell systems are the ideal technology to transition to a fully
sustainable energy future. By operating on hydrogen, fuel cells can be
powered not only from hydrocarbon fuels, but also from renewable energy
sources such as hydropower, wind and solar energy. Our growth rate in
fossil fuel use is unsustainable. According to Professor Evar Nering of
Arizona State University, this continued growth is akin to compound
interest and produces exponential growth if calculated at a continuing
rate. Fuel cells will allow us to continue to rely on electricity and
consumers will see no change in service and quality of that electricity
even as its becomes more sustainable.
FUEL CELL BENEFITS
Reduced Carbon Dioxide Emissions: Fuel cells emit less than half
the CO2 (a primary ``greenhouse gas''), of a traditional,
coal-fired power plant when operating on a fossil fuel such as natural
gas. When fueled by hydrogen from a renewable energy source such as
solar, wind, or hydropower, or if the fuel source is bio-fuel like
ethanol from plant wastes, CO2 emissions are net zero.
Environmental: Fuel cells create electricity through an
electrochemical process with reduced emissions and high efficiency.
Fuel cell systems operating on natural gas emit near zero levels of
NOX, SOX and particulate matter. Fuels cell
systems that operate on direct hydrogen from a renewable energy source
can eliminate greenhouse gas emissions completely.
Power Reliability: Fuel cells can provide electricity that meets
the need for high reliability. This is particularlyimportant for
sensitive mechanical installations, such as internet and computer based
Power Quality: Some studies estimate that power quality and
reliability issues cost our economy alone as much as $150 billion in
lost materials and productivity, while others have reported estimates
as high as $400 billion (source: Bear Stearns, April 2000 Distributed
Energy, p. 8).
Modular Installations and Load Profiles: Modularity, whether for
large or small fuel cell systems and applications can be designed for
particular profiles allowing maximum flexibility to the utility and
Fuel Choice: Fuel cells need hydrogen and oxygen to chemically
react and product electricity (and thermal energy) and can therefore
use any hydrogen rich fuel, or direct hydrogen. This allows fuel cell
products to be ``customized'' for customers' available fuel. It also
provides the option of renewably generated hydrogen for a fully
renewable and zero emissions energy system.
Grid Impact and Support: Because fuel cells provide electricity at
the site of consumption, they reduce the load on the existing
transmission and distribution system. This reduces the overall cost for
electric infrastructure development and improvement. Additionally, fuel
cell can operate in either grid parallel or grid independent modes.
Energy Efficient: Again, because they provide electricity at the
point of use, fuel cell systems can be more efficient than central
station power. They avoid the up to 15% line losses inherent in moving
electricity and provide an alternative to what are often cost
prohibitive and unattractive traditional power lines. Additionally,
because fuel cells make both electric and thermal energy where it is
needed, the heat can be recaptured in combined heat and power
applications to improve efficiencies significantly.
Siting: Fuel cell systems are quiet. Combined with their
environmental friendliness, fuel cells are very easy to site in
neighborhoods and urban centers. These characteristics allow for the
potential of indoor installations.
Combined Heat and Power: Because they generate both electricity and
heat at the point of consumption, fuel cell systems allow for the
recapture and use of the thermal (heat) energy. For example, Plug Power
is currently working with a heating manufacturer to develop a
residential fuel cell system that will provide all of the heat and
electricity for the average home. Use of thermal energy can increase
overall efficiencies approaching 80%.
Tax Credit Provisions
The Fuel Cell tax credit if passed, would provide $1000 per kW for
purchasers of fuel cell systems and would be available for purchase of
all types and sizes of stationary fuel cell systems. It would be
available for five year, January 1, 2002 through December 31, 2006, at
which point fuel cell manufacturers should be able to produce a product
at market entry cost. The credit does not specify fuel inputs,
application or system sizes so a diverse group of customers can take
short-term advantage of the credit to deploy a wide range of fuel cell
Need for a Fuel Cell Tax Credit
Solid engineering work has advanced fuel cell technology over the
past ten years. In fact, the cost per kW of energy produced in a fuel
cell has come down by a factor of ten over the past five years (source:
Bear Stearns, April 2000, Distributed Energy Services p. 17). Plug
Power was founded in 1997 and our costs have already been reduced
several fold. In part, this has been through the reduced amount of
platinum as a catalyst, but most of the reduction is due to
engineering, materials improvements and vigorous applied research and
development efforts. We, along with all of the fuel cell system
developers in this country, continue a vigorous cost reduction effort.
Still, current costs are, at best, $4500 per kW and need to be reduced
to the $1500 per kW range to be competitive with existing distributed
An important point to understand when comparing the costs of fuel
cell technology to current central station power is that fuel cells
will realize their cost advantage through economies of production. As
we sell more systems, we are able to provide larger sales volumes to
our component and subsystem suppliers and leverage lower costs.
Additionally, we are able to benefit from scale of manufacturing in our
own facility. By way of example, we have a control module in our fuel
cell system that is similar to one we purchased when I was at Ford
Motor Company. However, due to where we are on the learning curve and
our volumes, we pay 8-10 times more than does Ford.
In conclusion, we urge you to pass H.R. 1275 and/or it's companion
S. 828. Providing a fuel cell tax credit to consumers will encourage
energy efficiency, provide great environmental benefits to our country
and will allow customer choice in their power needs.
Thank you for the opportunity to testify.
Chairman McCrery. Thank you, Mr. Saillant. Mr. Murray.
STATEMENT OF ROBERT E. MURRAY, PRESIDENT AND CHIEF EXECUTIVE
OFFICER, MURRAY ENERGY CORPORATION, PEPPER PIKE, OHIO, ON
BEHALF OF THE NATIONAL MINING ASSOCIATION
Mr. Murray. Thank you, Mr. Chairman, Members of the
Committee. My name is Robert E. Murray and I am president and
chief executive officer of the Murray Energy Corporation. It is
a privilege to be here today on behalf of the National Mining
Association. The National Mining Association represents 80
percent of the coal production in the United States and all of
the uranium production. Murray Energy Corporation operates in
the States of Pennsylvania, Illinois, Ohio, West Virginia,
Kentucky, and Utah.
Mr. Chairman, I would like to request that my written
statement be included in the record and, in the essence of
time, I will discuss only two areas today of my testimony--the
use of investment and production tax credits (PTC) to
accelerate commercialization of clean coal technologies, both
in existing and in new electric power generating facilities,
and the elimination of the alternative minimum tax, which is
adversely affecting the ability of the mining industry to
attract capital for expansion.
Affordable, reliable electricity is necessary to maintain
economic growth. By 2020, electricity consumption will increase
40 percent in our country. Yet the current electric generating
fleet is not large enough to meet the demand. New electric
generating plants will need to be built.
Coal is now the source for 52 percent of the electricity
produced in the nation and many of the new plants should be
coal. Coal is reliable, domestic, and affordable. It is the
lowest cost way to generate electricity. And with new
technologies, it can provide electricity with minimal impact on
the environment. But new coal-based generating plants that
would be capable of using this natural resource are not being
built. This is largely due to the uncertainty about
environmental regulations from the Environmental Protection
Agency and also utilities are reluctant to assume the risk
associated with large investments for advanced technologies,
even when these technologies mean lower emissions.
We must do two things, Mr. Chairman and members of the
Committee. First, we must expand the use of newer, more
advanced NOX and SO2 control technologies
in existing plants through retrofits. Second, we need to move
advanced new technologies that have been proven at the
demonstration stage to the commercial marketplace.
The National Electricity and Energy Technology Act, so-
called NEET, has been developed to meet these challenges. The
legislation has been introduced in the Senate, S. 60, and we
expect that we will shortly have thisbill introduced in the
House. It is supported by coal producers, power generators, coal
hauling railroads, the National Mining Association, Edison Electric
Institute, Association of American Railroads, the National REAs, and
the American Public Power Association.
As the subject of this hearing is specifically changes in
the Federal tax code, we will limit our comments to those
relevant provisions of the NEET Act.
For existing coal-fired generating units first, NEET
provides a 10-percent investment tax credit on the first $100
million of investment in a qualifying system of continuous
emission control retrofitted on an existing coal-fired
generating unit. If an existing unit is repowered then a
$0.0034/Kwhr production tax credit for the first 10 years of
operation is provided. All units must meet improved efficiency
targets to qualify for any tax credit.
The second portion of the NEET Act involves a tax credit
for a new generation of technologies installed on new
generating plants and just a limited number of plants. NEET
proposes to amend the Internal Revenue Code to provide a 10-
percent tax credit on variable, efficiency-based 10-year
production tax credit investments in advanced clean coal
technologies on a limited number of new and repowered units.
These technologies must meet improved design efficiency
standards and there are limits on the amount of the capacity
for each technology and this tax credit would go away as the
technology becomes competitive.
Tradable tax credits are also provided for electric power
cooperatives and publicly traded utilities.
It is expected that the revenue impact of the NEET Act
would be between $1.7 and $2.2 billion for the first five years
and $3.2 to $4.5 billion for the second five years. These
incentives will offset the significant technical and financial
risks associated with putting new technologies online. In turn,
these new technologies will allow greater use of affordable
coal with lower emissions while keeping electricity costs as
low as possible. This is a win for the environment, a win for
the economy, a win for the lower income Americans who pay a far
higher percentage of their incomes for electricity.
The second area of my presentation involves the corporate
alternative minimum tax. As we know, Representative English has
proposed that it be eliminated in earlier legislation and
indeed the House enacted legislation to have historical
corporate AMT taxpayers, such as mining, utilize accumulated
AMT tax credits to offset prospective AMT tax liability, as
proposed by Representative Hayworth. Unfortunately, this was
vetoed by President Clinton.
Most mining companies are not profitable according to
accepted accounting principles, yet we all pay the alternative
minimum tax. This is a disincentive to investment in mining, a
disincentive in coal, the lowest cost form of electricity
generation in America.
Finally, we believe that mining companies should be
provided with the opportunity to fully expense exploration and
development costs, as does the oil and gas industry. The
current limitations on expensing such exploration and
development costs result in mining companies being forced to
capitalize a percentage of these costs. This is a disincentive
to open new mines.
Mr. Chairman, this concludes my remarks. I would be pleased
to answer any questions.
[The prepared statement of Mr. Murray follows:]
Statement of Robert E. Murray, President and Chief Executive Officer,
Murray Energy Corporation, Pepper Pike, Ohio, on behalf of the National
Mr. Chairman, my name is Robert E. Murray. I am President and Chief
Executive Officer of the Murray Energy Corporation. It is a privilege
to appear here on behalf of the National Mining Association (NMA) to
talk about changes that can be made in the Federal tax laws to
encourage the more efficient use of coal to provide reliable and
affordable electric energy for America with reduced environmental
Coal comprises over 90 percent of our domestic energy reserve. It
is the fuel for approximately 52 percent of the electricity that our
citizens use to run our businesses and support our everyday lives. Coal
is electricity. As stated in the President's May 17th report,\1\
National Energy Policy: ``If rising electricity demand is to be met,
then coal must play a significant part.'' Coal, is and must continue to
be, one of the cornerstones of our Nation's energy strategy.
\1\ ``National Energy Policy,'' Report of the National Energy
Policy Development Group.
The Murray Energy Corporation is the largest independent, family
held, coal producer in the United States. The coal companies operating
under Murray Energy Corporation's ownership produced over 20 million
tons of coal in 2000 in five states: Ohio, Pennsylvania, Kentucky,
Illinois and West Virginia. We are expanding our operations in these
states and in Utah, and expect to produce at least 30 million tons
annually within the next three years.
The National Mining Association represents the producers of over 80
percent of America's coal and all of the uranium mined and processed in
the United States. NMA also represents companies that produce metals
and non-metals--large industrial energy consumers--as well as
manufacturers of processing equipment and mining machinery and
supplies, transporters, and engineering, consulting and financial
institutions serving the mining industry.
Mr. Chairman my statement today will focus on three areas in which
we believe changes in the Federal tax laws could enhance energy
production and use: (1) the use of investment and production tax
credits to accelerate commercialization of clean coal technologies both
in existing and new electric power generating facilities; (2) the
elimination of the alternative minimum tax; and, (3) changes in the tax
code needed to encourage domestic uranium production and processing.
Accelerating the Use of Clean Coal Technologies for the Generation of
As so well described in the National Energy Plan that President
Bush released on May 17th the American economy in the 21st century will
require reliable, clean and affordable electricity to keep the engine
running, the lights on, and the computers humming. The Department of
Energy forecasts that, by the year 2020, U.S. electricity consumption
will be over 40 percent higher than today. The current electric
generating fleet is not capable of meeting these new demands. As a
result, a large number of new base load electric generating plants will
be required to meet expanded electricity demand reliably, and at
\2\ The Energy Information Administration forecasts show that
nearly 400 GW of new and replacement capacity will be required by 2020,
the equivalent of 1,300 plants at 300 MW each. Some 378 MW of the
needed capacity is still in the ``unplanned'' stage.
Today, more than one-half of U.S. electricity is generated from
abundant, low cost, domestic coal. Coal can play a greater role in
meeting future demands, as it constitutes more than 90 percent of
United States' fossil fuel resources, enough to last more than 250
years at current consumption rates.
However, new coal based generating plants that would be capable of
using this great resource are not being built. To illustrate, over
43,000 megawatts (MW) of coal capacity came on line between 1980 and
the end of 1984. In the past five years, only 3,500 MW of new coal
capacity have been brought on line. This is largely due to uncertainty
about new environmental requirements from the U.S. Environmental
Protection Agency, coupled with the risks associated with large
investments as the utility industry becomes more diverse and more
The development and commercialization of more efficient and lower
emitting clean coal technologies is required to meet new electricity
demands while continuing to improve the environment. In the short term
the challenges are two. The first challenge is to expand the use of
newer, more advanced NOX and SO2 control
technologies in existing plants through retrofits. While such
investments are extremely costly, technologies are available to do this
while improving the efficiency of fuel combustion and increasing
output. The second challenge is to move new advanced clean coal
technologies that have been proven at the demonstration stage to, and
through, placement in the commercial marketplace.
Legislation the ``National Electricity and Environmental Technology
Act'' (NEET) has been developed to meet this dual challenge. It is
important to note that this legislation, which is pending in the Senate
as S. 60, and, we expect will shortly be introduced in the House, is
strongly supported by coal producers, coal based electric generators,
and coal hauling railroads, along with the NMA, the Edison Electric
Institute, the Association of American Railroads The National Rural
Electric Cooperative Association and the American Public Power
The NEET legislation has three important programs:
A research and development program that addresses long-
term clean coal technology needs;
Financial incentives--a limited investment tax credit--
designed to incentivize the application of advanced technologies to
existing coal units; and,
A limited demonstration program to provide tax incentives
(a combination of investment tax credits and efficiency production tax
credits) for initial commercial scale application of advanced coal
based generating technologies in both existing and new facilities.
Not only would implementing the NEET Act result in reduced
environmental impact and greater efficiencies in converting coal to
electricity, it would assure that our Nation has the affordable
electricity we need for continued economic growth. NEET will result in
significant reductions in emissions. NOX emissions would be
reduced by 741,000 tons, SO2 emissions would be reduced by
over 2.5 million tons, and CO2 emissions would be reduced by
nearly 12 million tons. NEET is complementary to the United States'
climate change strategy outlined by President Bush on Monday. NEET is a
win for the economy, a win for the environment and for the lower income
Americans who pay a far higher percentage of their income for
electricity than others in society.
As the subject of this hearing is specifically on changes to
Federal tax code, we will limit our comments to the relevant portions
of the NEET proposal. Tax changes proposed are:
(1) For existing coal-fired generating units: NEET proposes to
amend the Internal Revenue Code to provide a 10 percent investment tax
credit on the first $100 million investment in a qualifying system of
continuous emission control retrofitted on an existing coal-based
generating unit. If an existing unit is repowered with a qualifying
clean coal technology, NEET proposes that units under 300MW be eligible
for a $0.0034/Kwhr production tax credit for the first 10 years of
operation. All units must meet improved efficiency targets to qualify
for any tax credit.
(2) For advanced clean coal technologies installed on new
generating plants: NEET proposes to amend the Internal Revenue Code to
provide a 10 percent tax credit and a variable, efficiency based 10
year production tax credit for investments in advanced clean coal
technologies for use in new or repowered units. Again, these
technologies must meet increasingly improved design efficiency
standards. The ``bar'' to qualify for tax credits gets higher in the
out years of the program. NEET limits the amount of capacity for each
technology that would qualify for credits with the understanding that,
once a technology is proven commercially, tax credits are not needed to
make that technology competitive.
Tradable tax credits are available for electric cooperatives and
publicly owned utilities so they may also utilize the financial
benefits of NEET.
It is expected that the revenue impact of the NEET proposal would
be between $1.7--$2.2 billion for the first five years and between
$3.2--$4.5 billion for the second five years. Over a 24 year period,
the total revenue impact is projected to be from $8.3--$11.2 billion.
Why are aforementioned incentives necessary? Uncertainty about new
environmental requirements and electricity deregulation, coupled with
the fact that only expensive retrofit technologies can achieve the more
stringent emissions limits being considered for existing coal based
generating facilities, have caused electric generators to delay
investments in new technologies. Additionally, initial commercial
deployment of new technologies entails significant technical and
financial risk. These risks can be offset in part, and needed
investments can be encouraged, through the tax-based incentives
outlined above. Coal based generation must and will continue to play an
important role in meeting new energy demands and it is important that
coal generators use the most efficient and environmentally sound
The fact that incentives are needed to encourage the use of
advanced clean coal technologies is clearly seen by analyzing recently
announced additions to the coal based generating fleet. Since the first
of this year, companies have announced intentions to build nearly
34,000 MW of new coal fired capacity.\3\
\3\ Source for this and all data in this paragraph: ``New Coal-
Fired Generation, A summary of Developments and Impacts to the US Coal
Industry,'' Mark Morey, Principal Coal Group, RDI Consulting,
presentation to the Western Coal Council Spring Pacific Forum, June 6,
According to the referenced RDI study, 23,000 MW will be at new
sites, 9,800 MW will be in the form of expansion at existing sites and
851 MW will involve repowering at existing sites. A full 12,000 MW, or
one-third of the new capacity planned, will use existing PC
technologies. Only 4,000 MW will use the most advanced gasification
technologies. Another 9,000 MW will use fluidized bed, and the
technologies at the remaining units are unknown. This illustrates the
reluctance of electric generators to take either the financial or the
technical risks associated with the most advanced clean coal
technologies and illustrates clearly the need for incentives to put
``first and second'' of a kind technologies on line. The incentives
included in NEET will provide the impetus to increase the supply of
electricity, improve the environment through reductions of pollutants
regulated under the Clean Air Act, and reduce the amount of carbon
dioxide emitted per unit of energy produced through significant
increases in the efficiency of converting coal to electricity.
Tax Changes to Encourage Increases in Coal Production
Tax policy can be a major component of energy policy as taxes
affect the development and production of energy, including electricity.
Several provisions of the Internal Revenue Code should be modified to
address counterproductive policies previously put into place. These
issues are also of significant importance to the oil and gas industry.
The corporate alternative minimum tax (AMT) should be repealed or
modified. Mining is a capital-intensive business, and the AMT works a
hardship on such businesses. As measured by generally accepted
accounting principles, most mining companies are not profitable. In
recent years, most companies have been consistently unprofitable. The
fact that mining companies are required to pay the AMT, even if they
have no profit, has added to the difficulty of attracting capital to
maintain, expand, or construct new mines. If elimination of the AMT as
provided in legislation introduced by Rep. English and other members of
the Committee, is not politically or fiscally achievable in the near
term, at a minimum, provisions similar to legislation advanced by Rep.
Hayworth and many other members of the committee in the previous
Congress should be supported to allow historical corporate AMT
taxpayers, such as mining, to utilize accumulated AMT tax credits to
offset prospective AMT tax liability. Legislation to effect such a
change was enacted by the previous Congress, but was vetoed as part of
a larger tax package by former President Clinton.
Further, mining companies should be provided the opportunity to
fully expense exploration and development costs as does the oil and gas
industry. The current limitations on expensing result in mining
companies being forced to capitalize a percentage of their exploration
and developments costs. This tax treatment serves as a disincentive to
the development of new mines to meet our Nation's needs.
Modifications in the Tax Code to Assist Domestic Uranium Producers
The United States uranium recovery industry has long been
recognized as vital to United States energy independence and essential
to National security. The domestic uranium industry has been found to
be ``not viable'' by the Secretary of Energy under provisions of the
Atomic Energy Act of 1954, as amended. Transfers and sale of government
uranium inventories, including those related to the United States/
Russian HEU Agreement and the privatization of the United States
Enrichment Corporation, have had material adverse impacts on the United
States uranium industry to the extent that the current spot market
price of uranium is at an all time low. The unfettered introduction of
government inventories has caused domestic uranium producers to either
cease or curtail production.
At such time as the price of natural uranium recovers to approach a
reasonable cost of production, the United States uranium industry can
be competitive with foreign producers due to advances in technology.
Providing assistance to the domestic uranium industry is essential to
mitigate the impacts on a private industry from government disarmament
policies and government transfers of excess uranium reserves. This will
assure an adequate long-term supply of domestic uranium for the
Nation's nuclear power program and will preclude any threat from
foreign supply disruptions or price controls.
The National Mining Association supports modification of the tax
code to allow domestic users of uranium products a credit for the
purchase of domestic uranium products. Suggested changes are appended
to my statement.
Mr. Chairman, this concludes our statement. We will be pleased to
answer any questions either now or for the record.
Chairman McCrery. Thank you, Mr. Murray.
I advise the Members of the Subcommittee that I am going to
go forward with Mr. Geller's testimony. At the conclusion of
his testimony we will recess to go vote. However, any Member
wishing to leave and go vote and come back is welcome to do
that, but we will recess following Mr. Geller's testimony. Mr.
STATEMENT OF HOWARD GELLER, FORMER EXECUTIVE DIRECTOR, AMERICAN
COUNCIL FOR AN ENERGY-EFFICIENT ECONOMY, ON BEHALF OF THE
SUSTAINABLE ENERGY COALITION
Mr. Geller. Thank you, Mr. Chairman. I am testifying today
on behalf of the Sustainable Energy Coalition, a coalition of
over 30 national business, environmental, consumer and energy
policy organizations. I appreciate the opportunity to appear
before the Subcommittee.
The Sustainable Energy Coalition supports a broad array of
tax credits for innovative energy efficiency and renewable
energy technologies. Adopting these tax credits will help
manufacturers justify mass production and marketing and help
buyers offset the relatively high first cost of the new
technologies, thereby expanding sales and market share. Once
the new technologies become widely available and produced on a
significant scale, costs should decline and the tax credits can
be phased out.
The Sustainable Energy Coalition supports tax incentives
for a limited time period, typically for 5 years, for the
following energy efficiency and renewable energy technologies.
High efficiency appliances. We support a tax credit of $50
to $100 for manufacturers of highly efficient clothes washers
and refrigerators with a cap on the total credit per
manufacturer. This proposal has been introduced by
Representatives Nussle and Tanner, H.R. 1316, and also S. 686
in the Senate.
Highly efficient building equipment. We support a 20-
percent investment tax credit with caps for innovative building
technologies, including very efficient furnaces, stationary
fuel cell power systems, gas-fired heat pumps, and electric
heat pump water heaters. This proposal is included in S. 596 in
the Senate. The coalition also supports H.R. 1275 mentioned by
Combined heat and power. We support either a 10-percent
investment tax credit or 7-year depreciation for combined heat
and power systems with an overall efficiency of at least 60 to
70 percent. This proposal is included in S. 389 and S. 596 in
the Senate, as well as H.R. 1045 and H.R. 1945 in the House.
High efficiency commercial buildings. We support a tax
deduction of $2.25 per square foot for highly efficient
commercial buildings and multi-family residences. This proposal
is included in H.R. 778 introduced by Representative Cunningham
and also S. 207 introduced by Senator Bob Smith in the Senate.
Hybrid electric, battery electric and fuel cell vehicles.
We support tax credits of up to $5,000 for hybrid electric
vehicles, up to $6,000 for battery electric vehicles, and up to
$8,000 for fuel cell vehicles to stimulate introduction and
purchase of these innovative fuel efficient technologies. This
proposal is included in the CLEAR Act, H.R. 1864, in the House
and S. 760 in the Senate.
Energy efficient new homes. We support a tax credit of up
to $2,000 for highly efficient new homes. Versions of this
proposal are included in S. 207, S. 389 and S. 596.
Next, renewable energy electricity production. We support
extending the existing credits for electricity generated from
wind power and closed loop biomass for 5 years. Also, this
credit should be expanded to include electricity produced by
agricultural and forestry residues, geothermal energy and
incremental hydropower. These provisions in part or full are
included in a Filner bill, H.R. 269, Foley bill, H.R. 876,
Herger-Matsui bill, H.R. 1657, and the Dunn bill, H.R. 1677 in
the House, as well as a number of bills in the Senate.
Residential solar energy systems. We support a 15-percent
investment tax credit capped at $2,000 for residential solar
electric and water heating systems. This proposal has been
introduced by Representative Hayworth, H.R. 2076, also Senator
Allard in S. 465.
And finally, small scale wind turbines. We support a 30-
percent investment tax credit for wind turbines 75 kilowatts
and below. This proposal is included in the Bingaman-Daschle
bill, S. 596, in the Senate.
As you can see, virtually all these proposed tax credits
have bipartisan support. A number of them, specifically for
hybrid and fuel cell vehicles, combined heat and power systems,
and renewable energy technologies, areincluded in President
Bush's energy plan.
The administration estimates its clean energy technology
tax provisions will cost the Treasury about $7 billion over 10
years. We estimate that our full set of recommendations would
cost the Treasury around $10 to 14 billion over 10 years. This
is a relatively modest cost considering the broad scope and
importance of these technologies for addressing our long-term
In summary, the Sustainable Energy Coalition urges the
Congress to make adoption of tax credits for innovative energy
efficiency and renewable energy technologies a high priority.
By enacting tax credits on a broad set of energy efficiency and
renewable energy technologies, the Congress can pave the way to
a cleaner, more secure and more affordable energy future for
all Americans. Thank you very much.
[The prepared statement of Mr. Geller follows:]
Statement of Howard Geller, Former Executive Director, American Council
for an Energy-Efficient Economy, on behalf of the Sustainable Energy
ACEEE is a non-profit organization dedicated to increasing energy
efficiency as a means for both promoting economic prosperity and
protecting the environment. I am testifying today on behalf of the
Sustainable Energy Coalition, a coalition of over 30 national business,
environmental, consumer, and energy policy organizations. I appreciate
the opportunity to appear before the Subcommittee.
The Sustainable Energy Coalition supports a broad array of tax
credits for innovative energy efficiency and renewable energy
technologies. Adopting tax credits for these technologies will
stimulate technological innovation and reduce future consumption of
fossil fuels, thereby providing a number of benefits including:
saving consumers and businesses money;
reducing the costs and risks that U.S. manufacturers
confront when considering introducing innovative new energy
reducing the risk of power shortages and improve the
reliability of our overtaxed electric systems;
reducing future oil and natural gas imports;
reducing air pollution of all types since burning fossil
fuels is the main source of most air pollution;
lowering U.S. greenhouse gas emissions and slowing the
rate of global warming.
Many new energy efficiency and renewable energy technologies
including photovoltaic power systems, bioenergy systems, advanced wind
turbine technologies, fuel cell power systems, hybrid and fuel cell
vehicles, super-efficient refrigerators and clothes washers, and super-
efficient new buildings have been commercialized in recent years or are
nearing commercialization. But these technologies may never get
manufactured on a large scale or widely used due to their initial high
cost, market uncertainty, lack of consumer awareness, and other
Tax incentives can help manufacturers justify mass production and
marketing for innovative energy efficiency and renewable energy
technologies. Tax credits also help buyers (or manufacturers) offset
the relatively high first cost premium for the new technologies,
thereby helping to build sales and market share. Once the new
technologies become widely available and produced on a significant
scale, costs should decline and the tax credits can be phased out.
The Sustainable Energy Coalition supports providing tax incentives
for a limited time period (typically for five years) for the energy
efficiency and renewable energy technologies listed below. With regard
to the energy efficiency measures, a key element in designing the
credits is for only highly efficient products to be eligible. If the
eligibility level is set too low, there will be many so-called ``free
riders'' (i.e., individuals who would purchase the measure without the
tax credit), and the cost to the Treasury will be high and incremental
energy savings low. The renewable energy credits, with a few
exceptions, are based on the amount of electricity generated. This
provides manufacturers with an incentive to improve the performance and
reduce the cost of their renewable energy technologies.
Here is a summary of our ``clean energy'' tax incentives
recommendations (items are listed in alphabetical order, not indicative
of any priority for the Coalition as a whole):
Energy Efficiency Provisions
Appliances. We support a tax credit of $50-100 for
manufacturers of highly efficient clothes washers and refrigerators
(with a cap on the total credit per manufacturer). This will lead to a
new generation of superefficient appliances, thereby saving energy and
water. This proposal has been introduced by Sens. Allard, Lincoln, and
Grassley in the Senate (S. 686) and Reps. Nussle and Tanner (H.R. 1316)
in the House. It is strongly supported by the appliance industry.
Building Equipment. We support a 20% investment tax credit
with caps for innovative building technologies including very efficient
furnaces, stationary fuel cell power systems, gas-fired heat pumps, and
electric heat pump water heaters. This proposal is included in the
Bingaman-Daschle bill. Also, Rep. Nancy Johnson has introduced a
version of the stationary fuel cell tax credit (H.R. 1275) which the
Combined Heat and Power. We support either a 10%
investment tax credit or seven-year depreciation period for combined
heat and power (CHP) systems with an overall efficiency of at least 60-
70% depending on system size. This proposal has strong industry support
and is included in the Murkowski-Lott energy bill (S. 389), the
Bingaman-Daschle energy bill (H.R. 596), as well as a bills targeted to
CHP promotion introduced by Rep. Wilson (H.R. 1045) and Rep. Quinn
(H.R. 1945) in the House.
Commercial Buildings. We support a tax deduction of $2.25
per square foot for investments in commercial buildings and multifamily
residences that achieve a 50% or greater reduction in heating and
cooling costs compared to buildings meeting current model energy codes.
This proposal is included in legislation sponsored by Sen. Bob Smith
(S. 207) and Reps. Cunningham and others (H.R. 778).
Hybrid Electric, Battery Electric, and Fuel Cell Vehicles.
Tax credits of up to $5,000 for hybrid electric vehicles, up to $6,000
for battery electric vehicles, and $8,000 for fuel cell vehicles will
help jump start introduction and purchase of these innovative, fuel-
efficient technologies. The incentives should be based primarily on
energy performance and provide both fuel savings and lower emissions.
This proposal is included in the CLEAR Act, S. 760, introduced by Sens.
Hatch, Rockefeller, and Jeffords, and the companion bill (H.R. 1864)
introduced by Rep. Camp.
New Homes. A tax credit of up to $2,000 for highly
efficient new homes will stimulate efficiency and help lower housing
costs for American families. Versions of this proposal have been
introduced by Sen. Bob Smith (S. 207) and Rep. Bill Thomas and others
in the last session of Congress. Variants are included in both the
Murkowski-Lott (S. 389) and Bingaman-Daschle (S. 596) energy bills.
Renewable Energy Provisions
Renewable Energy Electricity Production (Section 45). We
support extending the existing credits for electricity generated from
windpower and closed loop biomass for five years. Also, this production
creditshould be expanded to include electricity produced by open loop
biomass (i.e., agricultural and forestry residues but excluding
municipal solid waste), geothermal energy, and incremental hydropower.
The same credit should be provided to closed loop biomass co-fired with
coal, and a smaller credit (one cent per kWh) should be provided for
electricity from open loop biomass co-fired with coal. These provisions
(in part or full) are included in the Murkowski bill, Bingaman-Daschle
bill, Grassley bill (S. 530), Reid bill (S. 249), Dorgan bill (S. 94),
Collins bill (S. 188), Filner bill (HR. 269), Foley bill (HR 876),
Herger-Matsui bill (HR 1657), and Dunn bill (HR 1677).
Residential Solar Energy Systems. We support a 15%
investment tax credit capped at $2,000 for residential solar electric
and water heating systems. In this case, an investment credit is
preferable to a production credit due to the relatively high cost of
smaller scale solar technologies at this time. This proposal has been
introduced by Sen. Allard (S. 465) and Rep. Hayworth (HR 2076). It also
is included in the Murkowski-Lott bill.
Small-scale Wind Turbines. We support a 30% investment tax
credit for small (75 kW and below) windpower systems. These are used in
commercial and farm applications and are relatively costly compared to
large wind turbines (500 kW and up). This proposal is included in the
As noted above, virtually all of these tax credits have been
introduced in the Congress with bipartisan support. Some have numerous
co-sponsors already. And a number of the credits, specifically for
hybrid and fuel cell vehicles, combined heat and power systems, and
renewable energy technologies, are included in President Bush's energy
plan. The Administration estimates that these provisions will cost the
Treasury about $7 billion over 10 years. We estimate that our full set
of recommendations would cost the Treasury around $10-14 billion over
10 years. This is relatively modest considering the scope and
importance of our energy problems.
In summary, The Sustainable Energy Coalition urges the Ways and
Means Committee and the Congress to make adoption of tax credits for
innovative energy efficiency and renewable energy technologies a top
priority. By enacting tax credits on a broad set of energy efficiency
and renewable energy technologies, the Congress can pave the way to a
cleaner, more secure, and more affordable energy future.
That concludes my testimony. Thank you again for the opportunity to
Chairman McCrery. Thank you, Mr. Geller.
There is a vote on the floor, gentlemen and lady. If you
would just hold tight for a few minutes while we go vote, we
will be right back and then allow members of the Subcommittee
to ask questions. Thank you.
The Committee stands in recess.
Chairman McCrery. The Committee will come to order. The
witnesses will take their seats. We apologize for the
interruption but occasionally we have to vote on the floor.
Ms. Cooper, I will start with you. If the new hybrid and
alternative fuel vehicles save money in the long run through
greater fuel economy, despite their higher up front costs, why
do not consumers consider those factors when they are making
new vehicle purchases? Why do we need an added incentive?
Ms. Cooper. Well, I think the key, Mr. Chairman, is that as
you know, when you develop a new technology vehicle it is in
many cases much more expensive than the conventional vehicles
with which these new technology vehicles would compete. So as
the vehicles gain consumer acceptance and production volumes
increase, the cost differential between these two advanced
technology vehicles and conventional vehicles will be reduced
and, in fact, even eliminated over time.
So we think it is really important to balance that gap
between the incremental cost in a way that makes it easier for
consumers to try a new technology. So that is really why we
support these tax credits for the consumers because the real
value is to deliver the benefits that these vehicles will
obtain into the overall fleet and we have to get--that is the
challenge we have, is to get consumers to purchase these
As I said in my testimony, we currently make a lot of
vehicles that are very fuel efficient, 30 to 40 and above 40
miles per gallon, but they represent a very small part of what
consumers buy. So what we really have to do is deliver the
technology and put it in an array of vehicles that deliver all
of the attributes that people are looking for, if it is towing
capacity, if it is added passenger capacity, other features,
because consumers really want everything. And when they say
they want fuel economy, we want to be able to deliver that
without sacrificing safety and the other features that
consumers look for.
So getting it up front and beginning to build the market
penetration so that we get the volumes up, we think that is the
best way over time to really begin--as we said, we are on the
cusp of real change in the automobile industry and that truly
is what we are trying--we are trying to bootstrap ourselves. We
are trying to sort of give ourselves a leg up in the process
and doing it through incentives that get the consumers, really
help the consumers.
Chairman McCrery. Well, let us assume that Congress passes
Congressman Camp's bill and the up-front credit to the consumer
is in law. How many more fuel efficient cars do you estimate
would be sold, say, in 5 years than if no credit were
Ms. Cooper. We cannot really give you that estimate at this
point in time. We think, based on all of our companies looking
at their product plans and the like, that there would probably
be a dozen or more models or vehicles that would incorporate
these new advanced technologies but I cannot tell you. All the
companies are looking at what the time line would look like and
what an accelerated schedule would look like. So I cannot give
it to you but we can work to get a number back to you so that
we can give you a better idea of what it would mean in the
Chairman McCrery. Yes, that would be helpful if you could
get us some idea of what this credit would mean in terms of
enhanced vehicle sales. And also, once you get that number,
give us some idea of the reduction in gasoline use in the
country with those new cars on the road.
Ms. Cooper. Well, we think that as this program is laid
out, you do get credit for the technology itself being
incorporated and then, as we believe a performance bonus for
the fuel savings and the efficiency or economy that you would
achieve. So we will work with you to provide some better
estimates. Clearly they will be estimates, as I say.
Chairman McCrery. Thank you.
Also, I would like for you to get the Committee in writing
the changes in Congressman Camp's bill that you think are
necessary. You say in your written testimony that your
coalition would suggest minor changes and some technical
Ms. Cooper. Yes.
Chairman McCrery. In H.R. 1864. If you could get those to
us in writing, that would be helpful.
Ms. Cooper. We would be glad to do that, glad to do that.
Chairman McCrery. Thank you.
Mr. Robinson, with respect to the 50,000 barrel a day
limit, can you expound a little bit on the problems that
causes? In current law if you go over the 50,000 barrel limit
even one day during the year then you lose your status as an
independent. And you are suggesting that we go to a 50,000
barrel average per day, which would give you some flexibility.
And then, of course, you suggest that we go even higher than
that but let us stick right now to the question of a single day
occurrence versus an average day output.
What is the difference? Why is that better for you?
Mr. Robinson. Mr. Chairman, thank you for the question. I
did not have a chance to address it much in my testimony.
This particular rule, of course, as you expounded, if the
refinery produces 50,001 barrels of crude even on one day
during the tax year, the code provides that the independent
producer owner of that refinery loses his status for the entire
tax year. As such, that requires that the refiner that is owned
by such producers have to be very careful in monitoring their
day-to-day operations. We have to essentially run well below
50,000, maybe 49,500 or something like that, so that we do not
have an inadvertent measuring error or metering error or
something like that and inadvertently break this limit. That is
for every day during the year.
Our refinery, on the contrary, we believe is capable of
running more than 50,000 barrels a day, although because of
this limit we have never really tested that.
Also, there are many days during the year when the refinery
has to be closed or operations have to be scaled back because
of routine maintenance, either scheduled or unscheduled.
If we remove this on-any-single-day test and replace it
with the concept of an annual average, in other words, the
refinery will run 50,000 barrels per day or less on an annual
average, that will permit any surplus capacity we have to be
used on certain days when we can run greater than 50,000 in
order to offset those days when we cannot but yet we would
still achieve over a year, stay within the intended limit of
50,000, which we think is still in accordance with the spirit
of what the code is attempting to achieve here.
Chairman McCrery. Thank you. It sounds like to me this is
just common sense. If you want to limit an independent producer
to refining no more than 50,000 barrels a day, you ought to
average it out to give you some flexibility for your
maintenance needs and, of course, to eliminate those extra
costs in monitoring every single day of the year to make sure
you do not go over that. It just sounds like common sense. So
thank you for your response.
Mr. Robinson. That is correct. And, by the way, Chairman,
thank you for your support on this issue in the past and your
concern for all the issues of the refining industry in this
Chairman McCrery. Mr. Saillant, I understand how economies
of scale help bring down the per-unit cost of new technologies,
such as fuel cells. In fact, in your testimony you noted that
already the cost per kilowatt of energy produced by fuel cells
has come down by a factor of 10 over the past five years.
Based on your look at this, if we were to adopt the tax
credit proposal that you propose, how much further could we
expect the cost per kilowatt hour to come down, say, in the
next 5 years?
Mr. Saillant. Thank you. The economies of scale will really
only kick in when we start getting into higher volumes,
probably really outside the coverage of this bill. I am talking
100,000 units a year. So I would like to keep the economy of
scale idea out of there for the moment as being impacted by
What this bill does, it enables us to incentivize the
purchaser at the high end who can afford a more costly device
while we are working on getting the size of the device, the
fuel cell system, down, while we are getting the weight down,
while we are getting the reliability up and we have to go
through a number of design iterations for that to happen.
The biggest single cost right now of a fuel cell system is
related to fundamental design, fundamental design in the sense
that the science is known, and the application engineering is
unknown. So what we are trying to do is to bridge that gap and
get units in the field so that utilities, commercial users can
begin to have experience with it and give us feedback on how to
redesign in order to get into the volume regime that we think
will open up in the $1,000 to $2,000 per kilowatt target area,
Is that helpful?
Chairman McCrery. Yes, sir, very much so. In other words,
you think you need the tax credit to help you basically
research the practical application of the fuel cells in the
Mr. Saillant. Do the practical application, the bridge. You
are exactly right. It is beyond research but it is into the
early adopter phase where we need the incentive.
Chairman McCrery. Okay. If Congress were to approve the
fuel cell tax credit, how quickly do you think we could see or
we would see a substantial increase in the amount of national
energy demand met by fuel cell technology?
Mr. Saillant. Our company's estimate right now, in
collaboration with other companies in this space, we think that
we could begin to have a significant impact in year 2005, 2006.
And by that I mean 2, 3, 4 percent, which may not seem like a
lot but in terms of peak shaving and back-up, it is very, very
[The following was subsequently received:]
Plug Power Inc.
Latham, New York 12110
June 15, 2001
The Honorable Jim McCrery,
Chairman, Select Revenue Measures Subcommittee
Committee on Ways and Means
U.S. House of Representatives
Washington, DC 20515
Dear Chairman McCrery:
Thank you for the opportunity to testify at the June 13th hearing
on the effect of Federal tax laws on production, supply and
conservation of energy. You had asked me during the witnesses
questioning about the ability of fuel cells to reduce demand for
electricity. For the record, I wanted to clarify the verbal response I
provided to you at that time.
Alan Greenspan is correct: the short-term market for stationary
fuel cells (the term of H.R. 1275) is relatively small. The fuel cell
industry has estimated that fuel cell systems can provide 500 megawatts
of electricity during that five-year time frame. According to data
supplied by the Department of Energy, the average annualized electric
demand in the United States is 440,000 megawatts. Further, data
supplied by the DOE's Energy Information Agency indicates that the
increase in average energy demand is growing at a rate of 7,200
megawatts per year.
Accordingly, while the impact of the fuel cell tax benefit during
the five year term, will be relatively small percentage (0.114%) of
total demand, it can account for approximately 1.4% of the new
megawatts needed over the next five years. By 2020, the U.S. Department
of Energy estimates that distributed generation, including fuel cells,
will account for 20% of the energy mix of the country. In addition,
fuel cells and other distributed generation technology have the
capability to address load pockets and peak demand a very targeted
manner, thereby making a significant contribution in certain geographic
The importance of the fuel cell tax credit is not necessarily found
in megawatt demand reduction during the term of the actual tax
incentive, but rather supports the production and deployment of a cost-
effective product that will increasingly offload megawatts of
electricity capacity over the next two decades and beyond. Without
passage of H.R. 1275, many of the companies in the fuel cell industry
today will be unable to sustain themselves long enough to provide the
desired public good of reducing our central station power demand.
Thank you again for the opportunity to testify and the opportunity
to clarify my answer.
Chairman McCrery. That is more significant than the
estimates that we have heard in this Committee from the
Congressional Budget Office (CBO), for example, for all of
alternative sources, not just fuel cell. And I will tell you,
too, I heard Chairman Greenspan the other day, in responding to
a question from a member, say not to expect too much from fuel
cell technology in the near future. So you might want to get
some of your research over to the Fed.
Mr. Saillant. I might want to add to that. When I talk
about fuel cells I am including 250 kilowatt units, for
example, from International Fuel Cell, Fuel Cell Corp.,
Ballard, and so forth. I am not necessarily talking about the
small fuel cells in the 5 kilowatt area.
Chairman McCrery. Thank you.
Mr. Geller, in your written testimony you describe several
types of new technologies and say we ought to be supporting
those through the Tax Code. Do you think that without the tax
incentives we will be unable to achieve commercial success for
some of these technologies?
Mr. Geller. I think it varies from technology to
technology. Some of the technologies are already available and
are being sold on a limited basis. For example, wind power,
there are wind farms going up virtually on a weekly basis in
different parts of the country and it used to be only in
California. Now it is the Great Plains, the Northwest. There
are wind farms going up in New York State, also.
Other technologies are a bit down the road and are not
commercially available yet, like fuel cell vehicles, for
example. And I think the idea across the board here is to help,
as previous witnesses have said, help manufacturers and help
consumers to bear the higher cost for these new technologies
for a limited time period to help them get well established, to
help get the bugs worked out and get the economies of scale
happening so that we have these technologies in hand.
This is not going to help us much in the short run; let us
be honest. This is not going to do anything in the next year or
two, these advanced technologies. The objective is to get them
well established in the marketplace by 2005 so that we can be
well prepared to address our energy needs over the long term.
This is about thinking in the medium and long term. I think
there are lots of other things we should be doing for the short
term, given the energy problems that our nation is facing, but
I think this is part of the mix, to support these innovative
technologies so that they are produced on a larger scale, to
help the manufacturers make that decision to go into
production. There is uncertainty and risk and the tax
incentives will help overcome these obstacles.
I think without the tax incentives some of it will happen
but a lot less. I mean we have a couple of hybrid vehicles
being produced today, for example, but I think we will have a
lot more if the tax credits in the CLEAR Act are adopted.
Can I just add a comment on your initial question to Miss
Chairman McCrery. Sure.
Mr. Geller. I was involved personally in the development of
the CLEAR Act and the discussions with the auto companies that
developed it and we estimated that there might be something
like 1 million to 1.5 million hybrid vehicles, just talking
about the hybrid vehicles, vehicles that would get the credit
over the time period. I think it is a 6-year time period
through 2007. About 1.5 million hybrid vehicles would qualify
for the credit and the Treasury Department uses a similar
number for their estimates of the cost to the Treasury.
That is not a lot of vehicles, considering the market is
about 15 million passenger vehicles sold per year, 1 million
over 6 years, but the whole idea again is not to get a lot of
impact from the credits directly but to get the technologies
well established, get the products well established. I think if
this is successful, the potential market by 2010 and the decade
after 2010 could be millions of vehicles per year providing
major energy savings down the road. I would encourage you to
look at it in that perspective, that it is not about how much
do we save from the products getting incentives.
I do not think there is enough money available to
incentivize a large fraction of the market for any of these
technologies. It is more important to get them introduced,
support the earlier adopters, get them beyond a niche product
to where they are a couple of percent of the marketplace, and
then phase out the credits and allow the market to work after
Chairman McCrery. Thank you. Mr. McNulty.
Mr. McNulty. Thank you, Mr. Chairman. As usual, you have
done a good job of covering all the salient points. Let me just
take a moment before I yield to our other colleagues to try to
elicit a few more of the Saillant points with regard to fuel
Roger, you and your colleagues have succeeded in getting me
interested and even excited about the future application of
fuel cells to address our energy needs but it is my view that
probably most of my constituents and probably most Americans do
not really have a clue about what fuel cells are. And you have
described them very ably in your testimony today but I was
wondering if you could expand a little bit more on the future
I know these would be guesses but how long do you think it
would be before there would be a widespread use of fuel cells
in residential homes? And would you have a guess as to how much
a unit would cost and how long it would last before it had to
be replaced, practical things like that?
Mr. Saillant. The general industry belief is that the
automobile will be the largest single user of fuel cells in the
2020, 2025 type of frame of reference. In order to do that, it
has to be $35 a kilowatt. The price volume sensitivity is real.
Before you can get to the automobile, we believe you will
come to what we call the John and Jane Doe market. That market,
we think, is somewhere in the neighborhood of $350 to $500 a
kilowatt. We think that that market will begin to be real in
probably the 2008 to 2010 or so timeframe.
Before that market there is a market where it will be
$2,000 a kilowatt, which will be back-up power, telcoms,
utility substations, small commercial, whether it is a 7-Eleven
or a Mobil gas station, and so forth. That area will probably
be entered, and I think incentives would help that, somewhere
between 2004, 2005, 2006 and 2007.
We have just recently acquired a sale of 75 units with a
single utility and it is not necessarily public but the point
really is they want to work with the technology to understand
how to use them in back-up power and how to integrate them into
their already-existing grid network, creating microgrids, and
So specifically back to your question, it is price-
sensitive. It is probably two decades before we begin to see
general widespread usage.
I would say that thing that you are doing in this market
area by incentivating is different than regulating. When I was
in the auto industry, we regulated emission controls and
brought about expenditures in excess of tens of billions of
dollars for automobiles over a 10- or 15-year period, cars and
trucks, to go from unemissionized to emissionized.
One thing that I can see in parallel to this area is the
seriousness with which the world is facing the CO2
problem. That may lead to regulation. All this work is really
about preparing ourselves in converting from a fossil fuel
CO2-based economy to one where eventually you can
actually have total renewables. So I look at this money as very
well spent, and a better alternative to going the regulatory
route in a crisis.
Mr. McNulty. Thank you very much.
And Mr. Chairman, one of the reasons I asked that question
was because I do not think that you should be too concerned
about Mr. Greenspan's comments because, first of all, he was
talking about in the short term and obviously here we are
talking about the long term.
And the other thing is that I have tried to figure out for
many years why, for instance, the stock market does what it
does. A lot of people think it is based upon Greenspan's
comments and it has been my experience, because I have been
tracking this, that the stock market also goes up and down
based upon whether or not Alan Greenspan has had a bad hair
So I really would not worry too much about his comments
with regard to fuel cells. Thank you.
Chairman McCrery. Thank you, Mr. McNulty. Mr. Brady.
Mr. Brady. Mr. Chairman, I came in a little late so on this
panel I am clueless, not that the two are always related but in
this case it is, and I will wait for the next panel. Thank you.
Chairman McCrery. Okay, thank you very much.
I want to thank all the Members of the panel for your
excellent testimony and your being patient with us, staying to
receive our questions, and now we will excuse you and invite
our second panel to come forward.
In the second panel we have Tom Ed McHugh, the executive
director of the Louisiana Municipal Association, Baton Rouge,
Louisiana on behalf of the American Public Gas Association;
Charles N. MacFarlane, assistant general tax counsel, Chevron
Corporation on behalf of the American Petroleum Institute;
Vince T. Van Son, manager, business development, Alcoa Energy
Division, Alcoa Inc.; and Mr. David S. Hall, manager of
taxation, Berry Petroleum Company from Taft, California on
behalf of the Independent Petroleum Association of America.
Gentlemen, the Subcommittee is pleased to have all of you
with us today. I am particularly pleased to have an old friend
of mine, Tom Ed McHugh from Louisiana, whom I have gotten to
know over the years and have a great deal of respect for. He is
a former mayor of the second largest city in our State, Baton
Rouge, did a great job there and is now continuing to assist
the municipalities all over the State through the Louisiana
Municipal Association. And Mr. McHugh, we will begin with you.
You may proceed.
STATEMENT OF TOM ED McHUGH, EXECUTIVE DIRECTOR, LOUISIANA
MUNICIPAL ASSOCIATION, BATON ROUGE, LOUISIANA, ON BEHALF OF THE
AMERICAN PUBLIC GAS ASSOCIATION
Mr. McHugh. Thank you, Mr. Chairman, Mr. McNulty and
members of the Subcommittee. I am delighted to be here.
I am in support of H.R. 1986 by Congressman Mac Collins and
this legislation's purpose is to clarify the treatment of tax-
exempt bonds used to fund long-term prepaid contracts for
natural gas. The reason for this clarification is to deal with
the problem created by the IRS that has effectively prevented
the use of tax-exempt bonds, a privilege granted to the
municipal and state governmental entities by Congress.
As background, the American Public Gas Association and
municipal gas systems, APGA, is a national association
representing 570 members in 36 states across this great nation,
of the nearly 1,000 systems that serve 4.8 million customers or
5 percent of the national gas market.
The Louisiana Municipal Gas Association is comprised of 62
members of the 109 systems throughout the State of Louisiana
and it is managed by the Louisiana Municipal Association, an
association of 303 municipal governments across the entire
State of Louisiana and one parish, or county that you might be
more familiar with.
Municipal-owned gas systems are not-for-profit entities,
public entities owned and accountable to the citizens that they
serve, generally serving a mixture of residential, commercial
and industrial customers. Reliability of service is paramount.
As a practical matter, service can never be interrupted,
heating our homes, our hospitals, and our schools.
Let us review for a minute the important issues that bring
us to where we are today. The Federal Energy Regulatory
Commission in 1993 restructured the natural gas industry.
Municipal local distribution companies, LDCs, could no longer
buy direct from interstate pipelines. They now are required to
acquire a reliable gas supply and arrange transportation in
order to serve the members across their districts.
In response to this new changing marketplace, joint action
agencies or authorities were created to help the LDCs to assure
a supply of competitive price natural gas. Joint action
agencies or authorities looked at options. They, in effect,
tried to form business plans. They looked at options such as
pay-as-you-go, drilling wells, operating buying production,
long-term prepay, both taxable and nontaxable bond issues, and
other business plans in order to meet the requirements of a
reliable service of long-term prepaid and as we went through
that business process, it became absolutely clear to us that
the prepay was a substantial business response to the needs
that we had.
And based on the risk factors--credit issues and good
public policy--we had no commercially reasonable alternative.
In August 1999 the IRS, in an unrelated matter, raised some
questions and asked for public comments and threatened the
potential of a retroactive clause in the issuance of the
prepaid tax-exempt bonds.
In January of 2000 they had a public hearing. No other
action has resulted from that public hearing and the action or
the lack of action has effectively prevented the issuance of
tax-exempt bonds to fund long-term prepaid contracts for
natural gas. By no action, IRS, since January 2000, have
basically overturned a privilege granted by Congress.
If we review the current law, prepayment does not result in
prohibited arbitrage if prepayment is made for a substantial
business purpose other than investment returns. And the issuer
has no commercially reasonable alternative.
This is precisely the case with prepaid natural gas
contracts for municipal gas systems. Our substantial business
purpose is the duty to protect the general health and welfare
of the citizens that we serve. We must deliver gas that heats
our homes, our schools, our hospitals, our businesses and our
factories. Prepay allows long-term contracts that have severe
penalties for failure to perform. The overriding business
purpose is to secure delivered supplies of gas on a competitive
price basis. Prepaid transactions are designed to meet these
goals andthey become a clear business purpose.
As previously mentioned, other transactions, such as pay-
as-you-go, drilling, and others, are not reasonably commercial
alternatives. Although municipal gas systems clearly have a
substantial business purpose and no commercially reasonable
alterative, IRS' failure to clear up this matter in line with
the current law has eliminated this most efficient tool
available to public gas systems to secure long-term reliable
supplies of natural gas. Congress must step in and enact
legislation clarifying this law.
Mr. Chairman, this concludes my prepared testimony. Thank
you for this opportunity.
[The prepared statement of Mr. McHugh follows:]
Statement of Tom Ed McHugh, Executive Director, Louisiana Municipal
Association, Baton Rouge, Louisiana, on behalf of the American Public
Mr. Chairman, Mr. McNulty, and Members of the Subcommittee:
I appreciate the opportunity to discuss with you ways to facilitate
the reliable distribution of natural gas. My name is Tom Ed McHugh. I
am the Executive Director of the Louisiana Municipal Association and I
am here on behalf of the American Public Gas Association. We are
testifying in support of H.R. 1986, legislation that has been
introduced by Congressman Mac Collins to clarify the treatment of tax-
exempt bonds used to fund long term prepaid contracts for natural gas.
Background on APGA and Municipal Gas Systems
APGA is the national association of municipally owned natural gas
distribution systems, with some 570 members in 36 states. Overall,
there are nearly 1,000 municipally owned natural gas systems in the
United States, serving approximately 4.8 million customers or about 5%
of the national market for gas.
In Louisiana there are approximately 109 publicly owned, municipal
or utility district gas distribution systems, of which 60 are members
of the Louisiana Municipal Gas Authority. My organization, the
Louisiana Municipal Association, manages the day-to-day operations of
the LMGA. The LMGA was created in 1987 by an act of the Louisiana
legislature. The LMGA and its members are political subdivisions of the
State of Louisiana. The primary purpose of the LMGA is to purchase
wholesale natural gas supplies for its members at the best price
possible. These 60 members are connected to 11 pipelines. The LMGA was
in the process of prepaying for a 10-year supply of natural gas in
August 199 when the IRS chilled the market.
Municipally owned gas systems are not-for-profit retail gas
distribution entities that are owned by, and accountable to, the
citizens they serve. They include municipal gas distribution systems,
gas and other public utility districts, county districts, and other
public agencies that own and operate natural gas distribution
facilities. I will refer to systems as ``Municipal LDCs.'' Although
they are located throughout the nation, municipal gas systems are most
prevalent in the Southeast, and within the Southeast mostly in small
Municipal LDCs generally serve a mix of residential, commercial and
industrial customers. The service provided by most Municipal LDCs to
their customers is predominantly firm service, which means that natural
gas deliveries as a practical matter can never be interrupted. The
reliability of service is of paramount importance, since natural gas is
used mostly to provide heat to homes, hospitals and schools.
As departments or enterprises of governmental units, Municipal LDCs
operate under different principles than do for-profit, investor-owned
corporations. As a general matter, governmental units operate in a
conservative, risk-averse manner and do not enter into transactions
that may have the potential of generating substantial profits but which
also expose public funds and capital investments to substantial risk of
loss. As applied to Municipal LDCs, this principle would foreclose in
most instances consideration of certain transactions that would be
considered by private companies in obtaining gas supplies, such as the
various means of purchasing natural gas in the ground, due to the
production risks associated with such transactions. As a general rule,
Municipal LDCs in the deregulated supply market are seeking, and will
continue to seek, to obtain their natural gas supplies through
contractual arrangements containing appropriate security provisions
with reputable, substantial suppliers of natural gas, whether producers
Regulatory and Market Changes
In 1993, the Federal Energy Regulatory Commission (``FERC'')
restructured the natural gas industry so that municipal LDCs could no
longer purchase natural gas supplies from interstate natural gas
pipelines. This fundamental change in the marketplace meant that for
the first time municipal LDCs both had to acquire reliable gas supplies
and transport those supplies on their own in a deregulated marketplace.
In response, many formed joint action agencies--as contemplated in the
FERC restructuring--to acquire and manage the delivery of gas.
Joint action agencies provide a range of services to municipal LDCs
to assist them with their responsibilities to provide an assured supply
of competitively priced natural gas to their customers. The preferred
means of fulfilling these responsibilities in today's gas markets is
through long-term prepaid contracts financed with the proceeds from
tax-exempt bonds. The joint action agency deals directly with the gas
supplier negotiating the terms of the prepaid, long-term contract for
the delivery of natural gas. These contracts are typically for ten-year
terms. The contract with the supplier is for a fixed price based on the
market conditions at the time of the contract. In most cases, the
parties then enter into a swap agreement with a third party financial
institution where the fixed price is converted to a monthly indexed
price as the gas is delivered.
The municipal LDCs enter into swap agreements because as public
bodies, accountable to their citizens, they prefer to avoid the risk
associated with purchasing long term gas at fixed prices. For example,
they want to avoid a situation where they have a supply of gas that was
purchase at $5.00 per MMBtu when the current market price is at $3.00
per MMBtu. In such case, the municipal LDC risks incurring substantial
losses, as well as the loss of industrial customers, where they have
purchased gas at one price and the market price is considerably less.
In August 1999, in the preamble of unrelated proposed regulations,
the Internal Revenue Service (IRS) published a request for comments
that has effectively prevented municipal LDCs from using their tax-
exempt borrowing authority to fund the purchase of long-term, prepaid
supplies of natural gas for their citizens. In the preamble statement,
the IRS questioned whether the purchase of a commodity, such as natural
gas, under a prepaid contract financed by tax-exempt bonds has a
principal purpose of earning an investment return. If this were the
case, the bonds could run afoul of the arbitrage rules of the Internal
This action, together with the treat of retroactive action, has
effectively prevented the issuance of tax-exempt bonds to fund long-
term prepaid contracts for natural gas. Municipal LDCs, and the joint
action agencies which represent them, have resorted to the use of
short-term contractual arrangements or have issued taxable bonds. Other
than to hold a hearing in January of 2000, and to threaten retroactive
regulations, the IRS has not made any public statements nor taken any
further steps toward the issuance of further guidance to clarify
current lawor adopt new rules.
This has seriously impeded the gas supply planning efforts of
municipal gas systems throughout the United States. Meanwhile, during
this period the natural gas markets have been in turmoil, as supply has
not kept up with growing demand. As a result, prices have reached
record levels and supply disruptions have occurred throughout the
country. While prices have currently settled down because of the
seasonal drop in demand, uncertainties continue in the natural gas
H.R. 1986 does not overturn current law nor change any IRS
regulation. It simply restates the law as it has been understood for
years, both with respect to the arbitrage rules and the private loan
financing rules, to allow an effective and reasonably-priced energy
delivery system to continue unimpeded. The legislation provides that a
prepayment contract for the purchase of natural gas reasonably expected
to be used in the business of a governmentally owned utility is not
investment property under the arbitrage rules. It would also clarify
that prepayment contracts for the purchase of natural gas reasonably
expected to be used in the business of a public utility do not create a
loan of the bond proceeds to the gas supplier for purposes of the
private loan financing test. Although no current issue exists with
respect to the private loan financing test, this change is included to
deal with any potential attempt by the IRS to characterize prepaid
natural gas contracts for public utilities as private loan financings.
The existing Treasury regulations relating to the treatment of
prepayments under the private loan financing rules contain basically
the same standard as the existing Treasury regulations relating to the
treatment of prepayments under the arbitrage rules.
Investment Type Property. Section 103(a) of the Internal Revenue
Code of 1986 (the ``Code'') provides that interest on an obligation of
a State or local government is not included in gross income. Section
103(b) of the Code provides an exception to this general rule under
which interest on any arbitrage bond is not tax-exempt. Section 148 of
the Code, in turn, defines an arbitrage bond as a bond issued as part
of an issue any portion of the proceeds of which are reasonably
expected to be used directly or indirectly to acquire higher yielding
investments. With one important exception, these general rules have not
changed since 1969, when the arbitrage bond prohibition was first added
to the Internal Revenue Code of 1954 (the ``1954 Code'').
Under the 1954 Code, the only types of investments that were
subject to the arbitrage restrictions were ``securities or
obligations.'' As a result, under the 1954 Code, the investment of bond
proceeds in investments other than securities or obligations did not
result in the loss of tax-exempt bond status. The terms ``security''
and ``obligation'' were relatively narrowly defined under the
As part of the enactment of the Tax Reform Act of 1986 (the ``1986
Act''), Congress expanded the arbitrage limitations applicable to tax-
exempt bonds in a variety of ways. One specific change was to expand
the types of investments that are subject to the arbitrage
restrictions. This was accomplished by providing that the acquisition
of ``higher yielding investments'' result in arbitrage bond status.
Under the Code, the term ``higher yielding investments'' is defined as
any ``investment property'' that produces a yield over the term of the
bond issue that is materially higher than the yield on that bond issue.
``Investment property'' was, in turn, defined to include securities,
obligations, annuity contracts, and any ``investment-type property.''
The term ``investment-type property'' is not defined by the Code,
although Congress did provide some guidance on the meaning of this term
in the legislative history to the 1986 Act. The General Explanation of
the Tax Reform Act of 1986 prepared by the staff of the Joint Committee
on Taxation includes a reference to prepayments in a reference on page
1202: ``Congress was aware that bond proceeds might be used to prepay
items as a means to avoid arbitrage restrictions, and intended for the
Treasury Department to adopt rules to treat such prepayments as
investment-type property where appropriate.''
The regulations, 1.148-1(e), issued in June, 1993, include a
definition of ``investment-type property'' that reads as follows:
(e) Investment-type property--(1) In general. Investment-type
property includes any property, other than property described in
section 148(b)(2)(A), (B), (C), or (E), that is held principally as a
passive vehicle for the production of income. For this purpose,
production of income includes any benefit based on the time value of
money, including the benefit from making a prepayment.
(2) Non-customary prepayment. Except as otherwise provide in this
paragraph (e), a prepayment for property or services gives rise to
investment-type property if a principal purpose for prepaying is to
receive an investment return from the time the prepayment is made until
the time the payment otherwise would be made. A prepayment does not
give rise to investment-type property if--
(i) The prepayment is made for a substantial business purpose other
than investment return and the issuer has no commercially reasonable
alternative to the prepayment; or
(ii) Prepayments on substantially the same terms are made by a
substantial percentage of persons who are similarly situated to the
issuer but who are not beneficiaries of tax-exempt financing.
Private Loan Financing. Section 141 of the Code includes rules for
purposes of determining if a bond is a private activity bond. A bond
will be considered to be a private activity bond if the ``private loan
financing'' test set out in section 141(c) of the Code is met. The test
is met if more than a certain amount of the proceeds of the issue are
used, directly or indirectly, to finance a loan to a person other than
a governmental unit. The General Explanation of the Tax Reform Act of
1986 prepared by the staff of the Joint Committee on Taxation provides
on page 1166 that ``a loan may arise--from transactions in which
indirect benefits that are the economic equivalent of a loan are
conveyed.'' That discussion goes on to describe circumstances in which
a lease, management contract, or output contract may in substance
constitute a loan of bond proceeds. There is no discussion whatsoever
of prepayments by the governmental entity and the situations described
have no relationship to contracts under which a governmental entity
purchases a needed commodity or service.
Nevertheless, the regulations interpreting the private loan
financing test, 1.141-5(c)(2)(ii), provide that certain prepayments
will be treated as loans if ``a principal purpose for prepaying is to
provide a benefit of tax-exempt financing to the seller. A prepayment
is not treated as a loan for purposes of the private loan financing
(A) The prepayment is made for a substantial business purpose other
than providing a benefit of tax-exempt financing to the seller and the
issuer has no commercially reasonable alternative to the prepayment; or
(B) Prepayments on substantially the same terms are made by a
substantial percentage of persons who are similarly situated to the
issuer but who are not beneficiaries of tax-exempt financing.
This language is substantially the same as the language used for
purposes of the ``investment-type property'' test described above.
Position of American Public Gas Association
It has been our position, and that of every bond counsel who has
reviewed these transactions, that the existing arbitrage rules, as
illuminated by their legislative history, do not prevent the prepaid
purchase of natural gas by a municipal gas supply agency. Those rules
were intended to target prepayment abuses, not prepaid natural gas
supply contracts entered into by municipalities or their gas supply
joint action agencies.
The use of tax-exempt financing to prepay long-term gas supply
contracts is not prohibited arbitrage because: (1) receiving an
investment return is not a principal purpose of the prepayments; and,
(2) the prepayment is made for a substantial business purpose and the
issuers have no commercially reasonable alternative. Furthermore,
theuse of tax-exempt financing to prepay long-term gas supply contracts
is not private-loan financing because: (1) the prepayment is not made
to provide a benefit of tax-exempt financing to the seller; and (2) the
prepayment is made for a substantial business purpose and the issuers
have no commercially reasonable alternative.
As noted above, H.R. 1986 would not change current law or any IRS
regulations, it would simply deal with the confusion created by the
August 1999 IRS request for comment by clarifying the law to allow
public gas systems to continue providing reasonably-priced energy to
Substantial Business Purpose and Commercially Reasonable Alternatives
Municipal LDCs have a duty to protect the general health and
welfare of their customers, i.e., the citizens of their community, and
therefore they cannot fail to deliver gas that heats homes, hospitals,
schools, businesses, and factories. The security, reliability, and
adequacy of natural gas supplies are the paramount concern for these
gas distributors. In a partially deregulated industry, supply security
can be obtained only by contract. Prepaid gas contracts allow Municipal
LDCs to obtain long-term supplies under a contract structure that often
includes severe penalties if the supplier fails to perform. Such
agreements have become the vehicle for the Municipal LDCs to acquire
the most reliable gas supply possible.
In today's turbulent natural gas markets, long-term prepaid supply
arrangements are the most reliable means of obtaining an assured supply
of natural gas. To fund prepayment contracts, the municipality or the
joint action agency issues tax-exempt bonds. The seller discounts the
prepaid price for several reasons, including because the contract is
prepaid, which eliminates the normal credit risk associated with
selling gas to non-rated governmental entities. (The LDC's credit risk
became even more of a limiting factor in the kind of high priced,
volatile gas markets witnessed last winter.) Municipal LDCs are able to
obtain these very firm gas supplies at more competitive prices. Until
August of 1999, joint action agencies entered into prepayment supply
contracts with gas suppliers to obtain a long-term (e.g., 10-year)
supply of gas.
The law does not impose the arbitrage restrictions on all
prepayment transactions funded with tax-exempt bonds. Rather, those
restrictions only apply if a principal purpose of the transaction was
arbitrage and there is no other substantial business purpose or
evidence that the prepayment is a customary transaction. The approach
taken by the IRS, Treasury, and Congress has been not to prohibit
transactions where tax-exempt bond proceeds are used and a time value
of money benefit results so long as there is a good business purpose or
the transaction is customary. Passage of H.R. 1986 will preclude the
IRS from changing this policy with respect to gas purchased by
The gas prepayment transactions at issue do not result in
investment-type property. Without question, the principal purpose of
municipal gas systems that have entered into gas prepayment
transactions has not been arbitrage. The joint action agencies that
have entered into prepaid gas transactions have two overriding
purposes: (1) they must obtain a secure delivered supply of gas to meet
their obligations to their members and other customers and (2) they
must obtain delivered gas at competitive prices to ensure that their
members can remain competitive. The gas prepayment transactions are
designed to meet these two goals, which also reflect the raison d'etre
of these joint action agencies.
Municipal LDCs have concluded that these transactions are the best
way to cope with deregulation of natural gas sales. They have not been
able to assemble the benefits derived from a long-term, prepaid gas
supply contract in any other sort of transaction. Sellers extract a
substantial premium for the features of a prepaid contract when the gas
is sold on a pay-as-you-go basis. Thus, many Municipal LDCs and joint
action agencies have concluded that there is no commercially reasonable
alternative to a prepaid gas contract.
Some confusion has developed around this matter because of the use
of commodity swaps in these transactions. A commodity swap is a price
hedge that has become a widely used tool in the industry by both buyers
and sellers of natural gas. Natural gas supply prices are extremely
volatile. The risk of future changes in natural gas prices is great. It
is not uncommon to see price swings of $1.00 to $2.00 per MMBtu from
one month to the next. Protecting against price risk is commonplace in
the natural gas industry. Producers, distributors and end-users
regularly purchase natural gas price protection through swap agreements
or natural gas futures contracts.
The fact that municipalities or municipal joint action agencies
purchase separate protection to address their price risk does not add
to, or take from, the analysis under the arbitrage regulations. The
test is whether the natural gas supply prepayment is to earn an
investment return. It is not. It is to obtain long-term, firm, secure
natural gas supply to meet the obligations of the municipalities or
agencies. The benefits of the natural gas supply prepayment are locked
in by the up-front payment and are exactly the same whether or not the
municipalities or agencies purchase the separate price protection.
Municipal LDCs have responded to the federally mandated
restructuring of the natural gas industry in just the manner envisioned
by the federal government. They have joined together into gas
purchasing groups, and they have then developed a supply transaction
that helps them compete. That transaction is consistent with the rules
and the purposes that underlie those rules. There is no valid basis for
prohibiting prepaid natural gas contracts funded by tax-exempt bond
Although municipal gas systems clearly have a ``substantial
business purpose'' for entering into prepayment transactions and ``no
commercially reasonable alternative,'' the IRS' failure to issue any
guidance following its August 1999 request for comment has eliminated
the most efficient tool available to public gas systems to secure long-
term supplies of natural gas. Congress must step in and enact
legislation clarifying the law.
Mr. Chairman, this concludes my prepared testimony. I will be
pleased to answer any questions you or other members of the
Subcommittee may have.
Chairman McCrery. Thank you, Mayor McHugh. I might add,
too, Mayor McHugh is ably assisted by another old friend of
mine, former State representative Robert Adly from Louisiana,
who was also a floor leader for our Governor in his days in the
legislature, so they come well prepared. Thank you both for
coming. Mr. MacFarlane.
STATEMENT OF CHARLES N. MacFARLANE, ASSISTANT GENERAL TAX
COUNSEL, CHEVRON CORPORATION, SAN RAMONE, CALIFORNIA, ON BEHALF
OF THE AMERICAN PETROLEUM INSTITUTE, DOMESTIC PETROLEUM
COUNCIL, AND U.S. OIL & GAS ASSOCIATION
Mr. MacFarlane. Thank you, Mr. Chairman. My name is Charles
MacFarlane and I am assistant general tax counsel at Chevron
Corporation. I am appearing today as a witness for the American
Petroleum Institute, the Domestic Petroleum Council, and the
U.S. Oil and Gas Association.
The United States today finds itself at a crossroads.
Natural gas price increases last winter and higher gasoline
prices this spring are in large part the inevitable result of
our Nation's past failure to address its long-term energy
needs. According to the Department of Energy, energy demand in
this country will only continue to grow, with demand for oil
and natural gas expected to rise 33 percent by the year 2020.
The oil and natural gas industry stands ready to do all
that we can to meet the dual challenges of satisfying increased
future U.S. energy demand while at the same time maintaining a
clean environment. In the short run, our industry is working
flat out to produce the gasoline consumers need. With eight
consecutive weeks of record production, refinery utilization is
up to 97 percent. However, securing our Nation's long-term
energyfuture will take time and will require an incredible
amount of capital investment.
U.S. tax policy significantly impacts our industry's
ability to compete and will play a pivotal role in determining
whether the needed capital investment will be made. 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.
In 1999 the united oil and gas industry proposed a series
of tax changes designed to spur domestic oil and gas
production--expensing of geological and geophysical costs,
expensing of delay rental payments, relief from the alternative
minimum tax, a marginal domestic oil and natural gas well tax
credit, and eliminating restrictions on percentage depletion
for independent producers. In addition, expanding the enhanced
oil recovery and a heavy oil production credit would help to
increase domestic production.
Finally, recent events have demonstrated that it is equally
important that we maintain an adequate refining and pipeline
transportation infrastructure. Modifying the depreciation lives
for refinery assets, oil and gas pipelines, and storage tanks
by making them more consistent with other manufacturing assets
will help promote the tremendous investment that is needed in
While the United States has a strong strategic and economic
interest in maintaining a vibrant domestic oil and gas
industry, we also need a wide diversity of international
supplies. The U.S. taxation of foreign source income imposes a
substantial burden on all U.S. multinational companies by
exposing them to double taxation and significant compliance
costs. Significant additional tax restrictions are imposed on
the oil and gas industry that place us in a less favorable
position than U.S. industry in general.
In order to survive, the industry must operate where it has
access to economically recoverable reserves. Since access to
domestic opportunities has been substantially foreclosed, the
tax treatment of international operations is critical to the
industry's ability to supply consumers' energy needs.
Tax measures that would enable U.S. oil and gas companies
to better compete in the global oil and gas market include the
repeal of the separate oil and gas foreign tax credit
limitation and other items enumerated in my written statement.
In summary, we support tax provisions that will encourage
the needed capital investment in our Nation's refining and
distribution infrastructure. Further, our industry strongly
supports efforts to encourage increased petroleum and natural
gas production activity in the United States through more
equitable tax rules that will facilitate the use of new
technologies for exploration, development, and production.
It is clear that despite our best efforts, U.S. demand for
oil and natural gas cannot be met solely through increased
domestic production. While U.S. reliance on imported oil can
and should be reduced, maintaining the global competitive
position of the U.S. oil and gas industry will be crucial to
ensuring that U.S. consumers continue to enjoy a readily
available supply of affordable fuels.
Thank you for the opportunity to present our views.
[The prepared statement of Mr. MacFarlane follows:]
Statement of Charles N. MacFarlane, Assistant General Tax Counsel,
Chevron Corporation, San Ramone, California, on behalf of the American
Petroleum Institute, Domestic Petroleum Council, and U.S. Oil & Gas
These comments are submitted by the American Petroleum Institute
(API) and the Domestic Petroleum Council for inclusion in the record of
the June 13, 2001 House Ways and Means Subcommittee on Select Revenue
Measures Hearing on the effect of federal tax law on the production,
supply and conservation 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. The Domestic Petroleum Council is a national trade
association representing 22 of the largest U.S. independent natural gas
and crude oil exploration and production companies. The U.S. Oil & Gas
Association represents more than 2000 members of all sizes involved in
the exploration and production of oil and natural gas.
Last year, and again this spring, U.S. energy consumers experienced
sudden increases in oil and gas prices, and regional price volatility
in response to events such as unusual weather, difficulties in
producing regional gasoline blends, and refinery and transportation
interruptions. With the President's national energy strategy proposals
joining those from Democrat and Republican members of Congress,
Americans will benefit from the long-neglected national debate now
underway concerning our nation's energy future. Recent events affecting
energy supplies and prices also serve as a reminder that oil and
natural gas remain essential to fueling the growth of both the U.S. and
the world economies, and measures to ensure sufficient quantities of
these products must be part of any U.S. energy plan. Together, oil and
natural gas supply more than 60 percent of U.S. and world energy needs,
and their role in fueling future economic growth is expected only to
The Department of Energy's (DOE) most recent International Energy
Outlook estimates that by 2020, world energy demand will be almost 60
percent higher than in 1999. 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 68 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 potential
supplies in North America.
From strictly a world 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. Advanced
technology has greatly increased industry's ability to pursue the
development of new oil and natural gas reserves without adverse
environmental impact. Nevertheless, there are a number of sobering
challenges that must be met in order to satisfy our country's future
These challenges stem not from resource scarcity, but from self-
imposed policy restrictions on accessing key remaining domestic supply
prospects, policies that have deterred adequate U.S. downstream
infrastructure investment, 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, the National Petroleum Council
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
Downstream, the refining industry has long been able to meet its
objective of supplying American consumers with readily available,
reasonably priced petroleum products. However, massive investments will
be required in the next ten years both to expand refinery capacity to
meet growing demand and offset the production loss resulting from more
stringent product quality specifications and possible refinery
closures. Combined with the historically low rates of return in
refining, the size of these investments will make the task of expanding
refinery capacity increasingly difficult in the future. The number of
refineries in the U.S. peaked in 1981, when therewere 315 operating
refineries in the United States. Many of these closed in the 1980s and
1990s, and there are now only 152 refineries operating in this country.
Fortunately, despite the fact that no new U.S. refinery has been built
since 1976, growth in capacity at existing refineries has offset the
effect of refinery closures with the result that total refinery
capacity grew from 15.5 to 16.5 million barrels per day in the 1990s.
Nevertheless, this increase has not been adequate to keep up with the
growth in petroleum product demand, and refinery utilization rates are
now approaching 100 percent.
While the United States has a strong strategic and economic
interest in maintaining a vibrant domestic oil and gas industry, we
also need a wide diversity of international supplies. Over the last 30
years, imports as a percentage of U.S. petroleum deliveries have risen
from 23.3 percent to almost 60 percent during the first part of this
year. 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.
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. However, the ability of the U.S. oil and
gas industry to compete globally is currently 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
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 the barriers to development of oil and natural
gas supplies at home, supports necessary international risk taking and
encourages the tremendous capital investment that will be needed to
meet U.S. and global energy demand growth.
II. DOMESTIC TAX PROVISIONS
While most other countries encourage energy development, flawed
public policies--especially excessive restrictions on access to federal
lands and unreasonably burdensome regulations--continue to place
substantial restrictions on our ability to explore for, produce, refine
and transport oil and gas in this country. Moreover, continued high
corporate tax rates and an obsolete cost recovery regime limit the
capital available to U.S. oil and gas companies at the very time huge
investments in both exploration and production and refining capacity
must be made to meet future energy needs. As with all industries, the
after-tax economics of oil and gas development projects determines
whether or not those investments will be made. The most important thing
Congress and the Administration can do is enact a national energy plan
that will change these policies to promote the economic and
environmentally sound recovery of domestic reserves, increased U.S.
refining capacity, and an expanded nationwide oil and gas pipeline
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.
Finally, while it is vitally important to promote increased oil and
gas production, it is equally important that we maintain an adequate
refining and pipeline transportation infrastructure to ensure that
sufficient quantities of our industry's finished products will be
available when and where they are needed. Modifying the depreciation
lives for refinery assets, oil and gas pipelines and storage tanks by
making them more consistent with other manufacturing assets will help
promote the tremendous investment needed in these areas.
Many of these proposals continue to enjoy bipartisan support and
have been included in numerous bills that have been introduced in both
the House and Senate. Moreover, most of these provisions are included
in one or both of the two national energy plans pending in the Senate--
S 389, introduced by Sen. Murkowski on February 26, 2001, and S. 596,
introduced by Sen. Bingaman on March 22, 2001.
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.
Delay rentals are paid by oil and gas exploration companies to
defer the commencement of drilling on leased property without
forfeiting the lease. Treasury regulations and case law clearly
supported the option to expense or capitalize delay rental payments.
However, with the 1986 enactment of the Section 263A uniform
capitalization rules, the IRS began to challenge the deductibility of
delay rentals during audits. In 1997, the IRS unequivocally adopted the
position that for tax years beginning after December 31, 1993, delay
rentals had to be capitalized unless the taxpayer could establish that
the lease was acquired for some reason other than development. This
position ignores forty years of history and long-established
regulations. Congress should pass legislation that clarifies and
reaffirms the long-standing rule that delay rentals be expensed rather
than capitalized. By permitting a current deduction for both delay
rentals and G&G costs, more capital will be available for new outlays
that otherwise wouldn't be available for extended periods of time.
In addition to having been included in the vetoed 1999 tax bill,
proposals to expense both G&G costs and delay rental payments are
included in both S. 389 and S. 596. Even former President Clinton
expressed support for these tax provisions in his March 2000 proposal
to ``strengthen America's energy security.''
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 survival ofmarginal
wells. Like the proposed AMT relief, the credits would phase out as oil
and natural gas prices rise to an economically viable level. Finally,
the credit should be allowed against both regular and alternative
minimum tax and to be carried back ten years. A marginal oil and gas
well production credit proposal is included in both S. 389 and S. 596.
Another way Congress could assist independent producers is 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. Moreover, independent producers
and royalty owners should be permitted to carry back percentage
depletion deductions for ten years. These proposals are included in S.
Alternative Minimum Tax
The 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
subsequent 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
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 some of 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.
Some 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 from the Adjusted Current Earnings (ACE) adjustment,
and permit the EOR and Section 29 credits to reduce tentative minimum
tax. This proposed AMT relief would phase in and out as oil and natural
gas prices fall and rise between specified levels, thereby providing
the greatest assistance to producers in times of low prices.
Another non-industry specific way to mitigate the adverse impact of
the AMT would be to allow AMT credits to be applied against future
tentative minimum tax. This specific provision was included in the
vetoed 1999 tax bill.
The Enhanced Oil Recovery (EOR) credit provides a credit equal to
15 percent of costs attributable to qualified enhanced oil recovery
projects. Since the enactment of the EOR credit in 1990, new
technologies have greatly enhanced the ability of oil producers to
economically recover additional domestic reserves from existing wells
with minimal environmental impact. By extending the EOR credit to
certain nontertiary production methods such as horizontal drilling,
gravity drainage, cyclic gas injection, and water flooding, the
economic viability of these oil recovery methods would be greatly
enhanced. In turn, the up to 70 percent of an oil well's reserves that
otherwise would be left in the ground could be added to the nation's
available energy supply.
Heavy Oil Production Credit
So-called ``heavy oil'' is one source of domestic petroleum that is
significantly less economic, but represents a key component of the U.S.
energy base. Currently, heavy oil accounts for over 11 percent of U.S.
production. However, its potential is far more significant because the
measured U.S. heavy oil resource base is over 100 billion barrels.
Heavy crude oil is generally characterized by its high specific gravity
or weight, as well as its high viscosity or resistance to flow. Because
of these characteristics, heavy oil is substantially more difficult and
expensive to extract and refine than other types of oil. Additionally,
this oil is less valuable because a smaller percentage of high-value
petroleum products can be refined from a barrel of heavy oil than from
a barrel of higher quality crude oil. A heavy oil production tax credit
would help the nation maximize its domestic energy supply by making
that resource economic to produce.
Depreciation of Refineries, Pipelines and Storage Tanks
The Administration's development of a National Energy Policy and
recent gasoline price increases have drawn attention to the fact that
U.S. demand for refined petroleum products exceeds the domestic
refining capacity to produce them. Among the solutions to this problem
is to have government policies in place that create an environment
conducive to refinery capacity expansion investments. One option for
doing so is eliminating the currently outdated tax treatment of
Most manufacturing assets are depreciated over five or seven years.
Despite substantial changes in the refining business and considerable
investment made during the last decade, refinery assets are still
subject to a 10-year depreciation schedule. The longer recovery period
for refinery capital assets results in a depreciation deduction present
value that is 17 percent to 25 percent less than that for other
manufacturing assets and thus reduces the incentive to invest in
refinery capacity expansion projects. Shortening the depreciation life
for refinery assets to five years will reduce the cost of capital and
remove the current bias in the tax code against needed refinery
In addition to refineries, substantial investments will be needed
in the nation's oil and natural gas pipeline system, as well as in new
petroleum storage facilities. The present law 15-year depreciation life
for pipelines denies an adequate cost recovery for tax purposes. In the
case of gas gathering lines, which carry natural gas from the well to
the processing plant or trunk line, the proposal to permit 7-year
depreciation, as provided for in S. 389, would merely clarify their
status as lease and well equipment. Contrary to an appellate court
decision, the IRS currently challenges that classification in certain
Under antiquated IRS classifications (dating from the early 1960s),
petroleum storage facilities are depreciated over 5 years or 15 years,
depending on whether the IRS considers them to be movable property.
This demarcation is difficult to administer, depends on factors
unrelated to useful life, and easily penalizes the economics of a
project, often retroactively on tax audit. The assurance of 5-year
depreciation for such facilities will increase the tax deduction's
present value and improve project economics. All of these depreciation
changes, which are similar to proposals included in S. 389, will help
spur the investment needed to assure the maintenance of an adequate and
environmentally safe pipeline transportation system and petroleum
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 maintaining global supply
diversity and ensuring the industry's continued ability to supply the
nation's hydrocarbon energy needs. Therefore, while federal tax policy
should promote domestic oil and gas production and an adequate refining
and transportation infrastructure, it should also seek to enhance the
competitiveness of U.S. companies operating abroad. The following tax
changes would help enable U.S. companies operating overseas to
bettercompete in the global oil and gas marketplace.
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. 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. However, since
enactment of the Tax Reform Act of 1986, the overall limitation must be
computed separately for not less than nine ``separate limitation
categories'' or ``baskets.'' Some of the separate limitations apply for
income: (1) whose foreign source can be easily changed; (2) which
typically bears little or no foreign tax; or (3) which often bears a
rate of foreign tax that is abnormally high or in excess of rates of
other types of income. In these cases, a separate limitation is
designed to prevent the use of foreign taxes imposed on one category to
reduce U.S. tax on other categories of income. There are other examples
of normal active-business types of income that also must be calculated
separately. Examples of these normal business-types of foreign source
income include dividends received from 10/50 companies (i.e., foreign
companies owned between 10 percent and 50 percent by U.S. owners),
gains on the sale of foreign partnership interests, and payments of
interest, rents and royalties from non-controlled foreign corporations
Section 907: Foreign Oil and Gas Extraction Income and Foreign Oil
Under the separate basket rules, foreign oil and gas income falls
into the general limitation basket. 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 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.
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 determine 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.
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. As was done in the vetoed H.R. 2488, Section 907
should be repealed as obsolete. This would promote simplicity and
efficiency of tax compliance and audit with minimal loss of revenue to
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. This denies U.S. multinationals the full U.S. tax
benefit from the interest incurred to finance their U.S. operations.
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, and the cost basis in stock does not
depreciate. 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 to allocate interest on certain qualifying debt on a
mini-group basis, i.e., looking only to the assets of that subsidiary,
At the very least, taxpayers should be allowed to elect to use the
E&P bases of assets, rather than the adjusted tax bases, for purposes
of allocating interest expense. Use of E&P basis would produce a fairer
result because the E&P rules are similar to the rules now in effect for
determining the tax bases of foreign assets.
Foreign Tax Credit Carryover Rules
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. 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. Credits are often lost, most likely resulting in double
taxation. A practical proposal to help 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 each 10/50 company, effective after the year 2002. A
separate FTC basket will be required for post-2002 dividends received
from pre-2003 earnings. 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 should be
accelerated. The requirement of maintaining a separate limitation
basket for dividends received from earnings and profits accumulated
before the repeal should be eliminated. These provisions were included
in the last few Clinton Administration budget proposals, as well as in
the vetoed 1999 tax bill, H.R. 2488.
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, the gain from such an interest is
treated as separate basket passive income, thereby limiting the
opportunity of FTC utilization. This is not only inequitable but also
counterintuitive for the legal form of the value realization to control
the FTC basket characterization. Accordingly, for a 10 percent or
greater partnership interest, look-through treatment should apply to
the gain in the same way that it applies to the distributive share of
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 partnerships or 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).
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. 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. Only a corresponding re-
characterization of future domestic income as foreign source income
will reduce the risk that FTC carryovers do not expire unused.
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 more than 50 percent
increase in U.S. natural gas demand by 2020. Existing tax laws do not
begin to address how this nation will encourage the massive capital
investment needed to meet this energy demand growth. Positive tax
changes will help promote the use of new technologies for exploration,
development and production, help maintain the economic viability of
mature production sites, and develop urgently needed new refining
capacity. Notwithstanding the positive effects of these new tax
provisions, 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 imposed on all segments of
the industry. 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
affordable supplies of our industry's major products.
Chairman McCrery. Thank you, Mr. MacFarlane. Mr. Van Son.
STATEMENT OF VINCE T. VAN SON, MANAGER, BUSINESS DEVELOPMENT,
ALCOA ENERGY DIVISION, ALCOA INC., PITTSBURGH, PENNSYLVANIA
Mr. Van Son. Mr. Chairman and Members of the Subcommittee,
my name is Vince Van Son and I am manager of business
development for the Energy Division of Alcoa Inc. of
Pittsburgh, Pennsylvania. I appreciate the opportunity to
appear before you today. My comments today are a summary of
written testimony submitted to the Subcommittee for the
official record and are made on behalf of Alcoa Inc. My
responsibilities at Alcoa include the procurement of
electricity and the development of additional energy assets.
Alcoa is the world's leading producer of primary aluminum,
fabricated aluminum and alumina. Its activities include mining,
refining, smelting, fabricating, and recycling. Since the cost
of energy to support some of these activities represents up to
25 percent of total production costs, Alcoa takes considerable
interest in all energy and electricity developments. The total
size of Alcoa's energy expenditures, coupled with Alcoa's
ambitious environmental goals, makes Alcoa keenly interested in
both measures to improve energy efficiency and conservation,
and the growing market potential of clean and renewable energy
Consistent with these interests, Alcoa is a Member of the
World Resources Institute's Green Power Market Development
Group. The group consists of Alcoa and nine other large U.S.
companies interested in promoting the development of 1,000
megawatts of renewable and clean energy sources by 2010 through
directed purchasing and investment. My remarks today are based
on my direct experience with renewable energy markets and my
involvement in the Green Power Market Development Group's
activities over the last 12 months. Through this effort Alcoa
has been looking at renewable energy supplies not only from the
perspective of contributing to environmental protection and
sustainable development but also as a viable business
An integral part of a corporate or national energy strategy
is to ensure energy is used as efficiently as possible.
Extending energy efficiency and conservation can be orders of
magnitude more cost effective and quicker to implement than
extending supply. Efficiency and conservation of resources are
integral to the Alcoa business system and Alcoa's values and
therefore a natural part of Alcoa's overall energy management
strategy. A national energy strategy would be incomplete
without a keen focus on conservation and efficiency.
In addition, recognizing that additional generation
capacity is inevitable to meet growing energy demands, Alcoa
believes that there is a significant role for green power
technologies within the nation's future energy mix. Green power
technologies, including solar, wind, landfill gas, cogeneration
and fuel cells, offer a number of environmental advantages.
Consequently, Alcoa feels that renewable and clean energy
technologies should be given an explicit place and support in
the nation's future energy strategy.
Typical of many new technologies, renewable energy
technologies currently face several obstacles that limit their
growth. The primary obstacle Alcoa and the Green Power Market
Development Group has encountered that currently inhibits more
aggressive demand for green power and corresponding development
is its relatively high delivered cost. The cost of power from
renewables is often greater than the market price established
by more common sources of generation for several reasons, more
details of which are given in my written testimony.
Some factors relate to the relatively high capital cost of
still-developing technologies. Other factors relate to the
particular characteristics of some renewable technologies, such
as the intermittency of wind power or the location specificity
and size of landfill gas to energy projects, which present
challenges to energy developers and purchasers alike.
One key factor for green power's current competitive
disadvantage is that no monetary value is placed on the
superior environmental attributes of green power technologies.
In making decisions about new generation capacity, developers
and purchasers are not presented with comparable life cycle
costs and profitability that reflect environmental attributes.
In short, renewable energy sources are not competing on a
level playingfield with traditional energy sources. While
technological and market developments will help us overcome
some of the obstacles currently facing renewables, policy
solutions are also needed.
A national energy strategy should provide incentives for
energy conservation and accelerated development and deployment
of renewable and clean energy sources. An ideal framework would
ensure that after a certain future date, monetary values were
placed on environmental benefits and included in all new energy
investment decisions, whether conservation measures or
investment in new generation. Such an outcome could be achieved
through the introduction of comprehensive emission credit
programs. Such programs would lead to increased development of
renewables and clean energy sources. Furthermore, by extending
the credit programs beyond power generation activity to include
other sources of emissions, larger gains in energy efficiency
could be achieved.
We recognize that a broad system of incentives cannot be
designed and implemented immediately. In the meantime there
will have to be bridging policies that encourage the
development of renewable and clean energy sources. We believe
that specific short-term tax provisions can play a vital role
in encouraging investment decisions that support a more
sustainable environment. In particular, we support the
immediate renewal of the section 45--production tax credit for
wind and closed loop biomass. In addition, we support the
extension of the PTC to include a broader range of biomass
technologies, such as landfill gas and combined heat and power
or cogeneration applications. We would also strongly encourage
incentives such as accelerated depreciation of capital
investments in equipment that reduces energy use and associated
emissions from industrial processes.
In conclusion, we hope that the Federal government can
instigate the development of broad emission credit programs
open to sectors beyond just power generation. Until such
programs are firmly established, the PTC will continue to be a
vital support for near-term development and application of
renewable energy and clean energy technologies. The PTC and
other investment incentives are needed to bridge the gap
between the cost of generation between renewable and clean
energy sources and the cost of generation from the technologies
and sources that the nation has historically adopted.
Thank you for the opportunity to testify. I look forward to
[The prepared statement of Mr. Van Son follows:]
Statement of Vince T. Van Son, Manager, Business Development, Alcoa
Energy Division, Alcoa Inc., Pittsburgh, Pennsylvania
Mr. Chairman and Members of the Subcommittee, my name is Vince Van
Son, and I am Manager of Business Development for the Energy Division
of Alcoa Inc. of Pittsburgh, Pennsylvania. I appreciate the opportunity
to appear before you today.
My responsibilities at Alcoa include the procurement of electricity
and the development of additional energy assets. Alcoa is the world's
leading producer of primary aluminum, fabricated aluminum, and alumina.
It is active in mining, refining, smelting, fabricating, and recycling.
Since the cost of energy to support some of these activities represents
up to 25% of total production costs, Alcoa takes considerable interest
in all energy and electricity developments. The total size of Alcoa's
energy expenditures coupled with Alcoa's ambitious environmental goals
makes Alcoa keenly interested in both measures to improve energy
efficiency and conservation; and the growing market potential of clean
and renewable energy sources.
Consistent with these interests, Alcoa is a member the World
Resources Institute's Green Power Market Development Group. The Group
consists of Alcoa and nine other large U.S. companies interested in
promoting the development of 1,000 MW of renewable and clean energy
sources by 2010 through directed purchasing and/or investment. We plan
to achieve our objective by engaging suppliers and technical experts,
sharing knowledge, developing strategies, and investing in green power.
Green power technologies--including solar, wind, landfill gas,
biomass, geothermal, cogeneration, hydroelectric and fuel cells--have
an increasingly important role to play within the nation's overall
energy mix. Furthermore, certain policies could be implemented that
would accelerate the growth of these technologies, and so facilitate a
smooth transition to a more sustainable energy future.
My remarks today are based on my direct experience with renewable
energy markets and my involvement in the Green Power Market Development
Group's activities over the last twelve months. These activities have
been centered on preparations for making contractual commitments for
renewable power. Alcoa has been looking at renewable energy supplies
from the perspective of contributing to environmental protection and
sustainable development as well as being a viable business proposition.
II. Role of Conservation and Renewables within a National Energy
An integral part of a corporate or national energy strategy is to
ensure energy is used as efficiently as possible. Extending energy
efficiency and conservation can be orders of magnitude more cost-
effective and quicker to implement than extending supply. Efficiency
and conservation of resources are integral to the Alcoa Business System
and Alcoa's values and therefore are a natural part of Alcoa's overall
energy management strategy. A national energy strategy would be
incomplete without a keen focus on conservation and efficiency.
In addition, recognizing that additional generation capacity is
inevitable to meet growing energy demands, Alcoa believes that there is
a significant role for green power technologies within the nation's
future energy mix.
From our review of green power technologies, it is clear that they
offer a broad range of positive attributes, not always possessed by
traditional forms of power generation. These include the following:
Green power does not emit or emits less air pollutants,
such as nitrogen oxides, carbon dioxide, and sulfur dioxide than more
common power generation technologies.
Green power reduces the potential for undesirable climate
change through the reduction of fossil fuel-derived carbon dioxide
released into the atmosphere.
Green power can help stabilize energy prices by
diversifying the blend of fuels and related transportation or
transmission infrastructure used to support national energy needs
Green power increases energy self-sufficiency by
harvesting untapped and renewable resources within our own borders.
Some green power technologies such as fuel cells and micro-turbines
and clean energy technologies such as combined heat and power or
cogeneration can be co-located with electric demand. This provides
additional benefits such as improved reliability of supply, increased
efficiency, reduced transportation/transmission losses, and optimal use
of existing and future transportation/transmission infrastructure.
Enhancing self-sufficiency and efficiency, stabilizing energy
costs, ensuring reliable supply and reducing environmental impacts are
important goals. Consequently, Alcoa feels that renewable and clean
energy technologies should be given an explicit place and support in
the nation's future energy strategy.
III. Principal Obstacles to Increased Supply from Renewable Energy
Typical of many new technologies, renewable energy technologies
currently face several obstacles that limit their growth. The primary
obstacle Alcoa and the Green Power Market Development Group have
encountered that currently inhibits more aggressive demand for green
power and corresponding development is its relatively high delivered
cost. The cost of power from renewables is often greater than the
market price established by more common sources of generation and is
largely the result of:
1. High Capital Costs. The cost per kilowatt of generating capacity
installed is much higher than conventional sources. The cost premium is
due in part to the lack of commercial scale relative to manufacturing
and installing associated equipment and sufficient experience to
improve upon the same.
2. Small Project Size. The small size of some renewable projects
such as photovoltaic and landfill gas to energy projects (typically 3-6
MW) increases their capital, labor, and transactional costs on a unit
3. Operating Constraints. Some renewable projects, such as larger
scale wind farms, offer some advantages of scale (100 to 200 MW) but
suffer from intermittent energy output which totals 30% to 40% of
installed generating capacity. Furthermore, generation from wind is
often concentrated during off peak hours when market prices are the
4. Location and Cost of Delivery. Resources for some green power
technologies are location specific such as geothermal, wind, and
biomass. Location is significant in that the additional cost of moving
generated power across distribution and transmission systems can make
an otherwise competitive cost of generation non-competitive.
5. Need for Additional Generation Assets to Offset Operating
Constraints. The variability in output inherent in some green power
projects can be better absorbed and managed by entities with multiple
generating resources and/or positions such as large regional utilities
than by individual consumers.
6. Inability to Independently Secure Output From Projects. Current
transaction structures in both regulated and deregulated environments
make it difficult for individual consumers to secure the output from a
particular green power project. The continued reliance upon
intermediary parties can add complexity and cost to a transaction. Net
metering provisions that provide credit for off-site renewable
generation as if it was physically located at a consumer's site and
displacing retail purchases can mitigate this problem. Net metering may
also be able to mitigate the location issues associated with renewable
technologies that cannot be located at a consumer's site.
7. Higher Transaction Costs On A Unit Basis. Administrative and
procurement costs associated with securing power are relatively fixed
regardless of the amount of power involved. This coupled with the
relatively novel nature of green power transactions can result in a 50
MW ``traditional'' transaction being easier and less costly to execute
than a 3 MW transaction involving green power.
8. Value of Environmental Attributes Not Recognized. Currently no
monetary value is placed on the superior environmental attributes of
green power technologies. Consequently, in making decisions about new
generation capacity, developers and purchasers are not presented with
comparable life cycle costs and profitability. Renewable energy sources
are not competing on a level playing field with traditional energy
Technological and market developments will help us overcome some of
these obstacles. Policy solutions are also needed.
IV. Policy Solutions to Promote Energy Conservation and to Accelerate
Increased Supply from Renewable and Clean Energy Technologies
A national energy strategy should provide incentives for energy
conservation and accelerated development and deployment of renewable
and clean energy sources.
An ideal framework would ensure that after a certain future date
monetary values were placed on environmental benefits and included in
all new energy investment decisions--whether conservation measures or
investment in new generation. Such an outcome could be achieved through
the introduction of comprehensive emissions credit programs. An
emissions program could extend to cover carbon dioxide and other
emissions and would evolve into a market driven program much like the
sulfur dioxide trading program that exists today. Such programs would
lead to increased development of renewables and clean energy sources.
Furthermore, by extending the credit programs beyond power generation
activities to include other sources of emissions larger gains in energy
efficiency could be achieved.
We recognize that such a broad system of incentives cannot be
designed and implemented immediately. In the meantime, there will have
to be bridging policies that encourage the development of renewable and
clean energy sources. We believe that specific short-term tax
provisions can play a vital role in encouraging investment decisions
that support a more sustainable environment. In particular:
1. We support the immediate renewal of the Section 45 production
tax credit (PTC) for wind and closed-loop biomass. The current
uncertainty regarding the renewal of the PTC has stalled development of
projects that cannot meet the current 2001 in service deadline.
2. In addition, we support the extension of the PTC to include a
broader range of biomass technologies such as landfill gas and combined
heat and power or cogeneration applications. Provisions should also be
made to provide the PTC to direct applications of the renewable and
clean energy technologies. For example, in some cases it is more
efficient for industrial consumers to consume landfill gas directly in
other processes instead of using it to fuel electricity generation.
3. We would also strongly encourage incentives such as accelerated
depreciation of capital investments in equipment that improves energy
efficiency and reduces emissions from industrial processes.
Alcoa does not support government mandates that require the use of
electricity generated from renewable or clean energy technologies by
utilities or consumers. Over time, appropriately structured markets
will yield the optimal blend and amount of renewable and clean energy
technologies based on consumer demand.
We hope that the Federal Government can help instigate the
development of broad emissions credit markets open to sectors beyond
just power generation. Until such programs are firmly established the
PTC will continue to be vital to support near-term development and
application of renewable and clean energy technologies. The PTC and
other investment incentives are needed to bridge the gap between the
cost of generation from renewable and clean energy sources and the cost
of generation from the technologies and sources the nation has
Thank you for the opportunity to testify. I look forward to your
Chairman McCrery. Thank you, Mr. Van Son. Mr. Hall.
STATEMENT OF DAVID S. HALL, MANAGER OF TAXATION, BERRY
PETROLEUM COMPANY, TAFT, CALIFORNIA; CHAIRMAN, ECONOMIC AND
POLICY AND TAXATION COMMITTEE, CALIFORNIA INDEPENDENT PETROLEUM
ASSOCIATION; ON BEHALF OF THE INDEPENDENT PETROLEUM ASSOCIATION
OF AMERICA, AND THE NATIONAL STRIPPER WELL ASSOCIATION
Mr. Hall. Mr. Chairman and Members of the Committee, I am
David Hall, manager of taxation for Berry Petroleum Company of
Taft, California and a member of the Tax Committee of the
Independent Petroleum Association of America.
Today's hearing examines the effect of Federal tax laws on
energy. To put this issue in a clear perspective we can turn to
the 1999 National Petroleum Council's Natural Gas Study. This
study concluded that the U.S. demand for natural gas would
increase by over 30 percent during the next 10 years. The
report also identified general areas that must be addressed to
assure that this clean burning fuel will be adequately supplied
to American consumers (IPAA).
The Federal Government and the tax code play a
significant--if not pivotal--factor in two areas: (1) access to
capital, and (2) access to resource base. Federal tax policy
has historically played a substantial role in developing
America's oil and natural gas. But the converse is equally
true, such as the Windfall Profits Tax and the AMT that have
sucked millions of dollars from the exploration and production
of oil and gas. These changes have discouraged capital from
flowing toward this industry. And, without capital, the
ultimate result is lower production.
The independent producers are now recovering from the low
prices 1998 and 1999 that starved the industry of funds to
maintain existing production and to generate new production.
Today we have a domestic industry ready to find and produce new
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 both producing and consuming states
alike that more must be done to increase the domestic
production. The question is how, and much of that answer lies
within this Committee.
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 alike. These include: (1)
allowing expensing for G&G costs and expensing of delay rental
payments, (2) creating a marginal tax credits, (3) suspending
or eliminating the net income limitation on percentage
depletion for marginal wells, and the 65-percent net overall
taxable income limit on percentage depletion, (4) and providing
for an extended period for net operating loss carry-back or for
the carry-back of carried-over percentage depletion.
Equally important, these changes must be crafted in a
manner to assure that AMT does not nullify the benefits that
would be created. The mistake 1986 should not be repeated.
For the future, the country needs to look toward tax
policies to encourage domestic production. The AMT remains the
constriction, which should be addressed. Some of the future
focus need to be directed to getting more out of existing
resources. For example, the Enhanced oil Recovery Tax Credit
does not consider technologies that have been developed in the
last 20 years.
Equally significant, policies need to address encouraging
more new development. For example, the section 29 tax credit
for unconventional fuels proved to be a strong inducement to
developing those resources, and was addressed in an earlier
Fundamentally, the question facing the nation is how to
marshal the capital to develop its domestic resources. The '99
natural gas study estimates that an additional $10 billion will
need to be invested annually in domestic production over the
next 15 years to meet the expected demand. One source is the
capital markets, but it has significant drawbacks. First, the
capital markets have yet to show a strong interest in the E&P
industry, despite the recent high prices in 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 the 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 to domestic production.
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 increasingly squeezing
the capital that is available. Second, this capital also will
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 expenditure
for domestic oil and natural gas. This type of proposal would
encourage capital formation and development of domestic wells
provided it was immediately beneficial. It would address a
compelling need to improve natural gas supply as well as reduce
the growing dependency on foreign oil. It must also apply to
both oil and natural gas because they are inherently
intertwined, and often found together. A healthy domestic
natural gas industry cannot exist without a healthy comparable
oil industry. The IPAA has been evaluating two approaches. The
first would be a deduction against gross income of wells
drilled domestically after 2001. The second would be an
investment tax credit applied to domestic investment made after
2001. One of these could provide a substantial in-flow of
capital for domestic production.
In conclusion, if Congress wants to see more domestic oil
and natural gas production, it must recognize that Federal tax
policy plays a critical role in whether capital will flow
toward this industry and production of these resources. There
are immediate actions that can and should be taken. The time is
right as the nation is seeking a more stable energy supply, and
Congress should act. Thank you very much.
[The prepared statement of Mr. Hall follows:]
Statement of David S. Hall, Manager of Taxation, Berry Petroleum
Company, Taft, California; Chairman, Economic and Policy and Taxation
Committee, California Independent Petroleum Association; on behalf of
the Independent Petroleum Association of America, and the National
Stripper Well Association
California Independent Petroleum Association
Colorado Oil & Gas Association
East Texas Producers & Royalty Owners Association
Eastern Kansas Oil & Gas Association
Florida Independent Petroleum Association
Illinois Oil & Gas Association
Independent Oil & Gas Association of New York
Independent Oil & Gas Association of Pennsylvania
Independent Oil & Gas Association of West Virginia
Independent Oil Producers Association Tri-State
Independent Petroleum Association of Mountain States
Independent Petroleum Association of New Mexico
Indiana Oil & Gas Association
Kansas Independent Oil & Gas Association
Kentucky Oil & Gas Association
Louisiana Independent Oil & Gas Association
Michigan Oil & Gas Association
Mississippi Independent Producers & Royalty Association
Montana Oil & Gas Association
National Association of Royalty Owners
Nebraska Independent Oil & Gas Association
New Mexico Oil & Gas Association
New York State Oil Producers Association
Ohio Oil & Gas Association
Oklahoma Independent Petroleum Association
Panhandle Producers & Royalty Owners Association
Pennsylvania Oil & Gas Association
Permian Basin Petroleum Association
Petroleum Association of Wyoming
Tennessee Oil & Gas Association
Texas Alliance of Energy Producers
Texas Independent Producers & Royalty Owners Association
Wyoming Independent Producers Association
Mr. Chairman, members of the committee, I am David S. Hall, Manager
of Taxation for Berry Petroleum Company (an independent heavy oil
producer since 1909), of Taft, California, and Chairman of California
Independent Petroleum Association's (CIPA) Economic and Policy and
Taxation Committee. I am also a member of the Tax Committee of the
Independent Petroleum Association of America (IPAA). 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 when domestic
energy policy does not recognize the importance of our own national
resources. NSWA represents the small business operators in the
petroleum and natural gas industry, producers with ``stripper'' or
Today's hearing addresses the effect of Federal tax laws on the
production, supply and conservation of energy. I have attempted to
answer your challenge by 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 crude oil. To put this issue in a
clear perspective all we have to do is look to the 1999 National
Petroleum Council (NPC) Natural Gas study. The last NPC study of crude
oil was done in 1994 and addressed Marginal Wells only. The 1999 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 crude oil.
Federal tax policy has historically played a substantial role in
developing America's natural gas and crude oil. 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 1,000 barrels per day of crude oil (or
equivalent natural gas) produced. A higher rate is allowed for marginal
wells, which increases as the crude oil 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
Alternative Minimum Tax that sucked millions more dollars from the
exploration and production of crude oil and natural gas. These changes
have discouraged capital fromflowing toward this industry. And, without
capital the ultimate result is lower production. Since 1986, domestic
crude oil 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 crude oil and natural gas. Today, we look at a world where
petroleum production is perilously close to petroleum demand. In late
2000 essentially all countries except Saudi Arabia were producing at
full capacity. Later this year as seasonal demand increases, we could
well return to a similar situation. Today, we look at natural gas and
crude oil supplies struggling to meet demand in the United States
primarily because of the loss of capital when crude oil 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 and S. 596--both of the comprehensive energy
bills--include a tax title with key provisions.
First, action should be taken to clearly allow expensing of
geological and geophysical costs and of delay rental payments. Congress
has passed these changes. These changes would clearly aid the
development of new wells and they reflect historic practice in treating
these costs. (IPAA Fact Sheets detailing these issues follow this
Second, there is wide support for a countercyclical marginal well
tax credit. This approach was recommended by the National Petroleum
Council in its 1994 Marginal Wells study. This tax credit today can be
crafted with a negligible impact on the federal budget, but at the same
time create an important safety net for the most vulnerable American
producing wells--wells that produce petroleum roughly equivalent to
imports from Saudi Arabia--wells that are the nation's true strategic
petroleum reserve. (An IPAA Fact Sheet detailing this issue follows
Third, Congress has suspended the property taxable income
limitation on percentage depletion for marginal wells through 2001. The
tax bill passed by the 106th Congress would have suspended this
provision through 2004. The suspension that was in place in 1998 and
1999 saved many marginal wells during the price crisis. This provision
should be permanently eliminated to provide domestic producers of these
wells an incentive not to plug the wells during a low price cycle. Once
the well is plugged, the potential to produce the remaining reserves is
lost forever. (An IPAA Fact Sheet detailing this issue follows this
Fourth, the 106th Congress' tax bill would have 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 crude oil and natural gas. It too should be
eliminated. (An IPAA Fact Sheet detailing this issue follows this
The number of independent producers qualifying for percentage
depletion has decreased. Percentage depletion has been further limited
as a result of mergers and acquisitions of the various producers as
they seek ways of reducing their costs, consolidating production
fields, and operating more efficiently. However, percentage depletion
remains very important to the small producer with marginal well
production. Limiting the number of barrels qualifying for percentage
depletion and artificially lowering the rate in a declining industry is
counterproductive. Increasing the number of barrels qualifying and/or
increasing the depletion rate would go a long ways to help the small
independent when prices are low.
Fifth, the 106th Congress' tax bill extended the net operating loss
carryback period for independent producers to five years. This approach
or one that would allow for the carryback of carried over percentage
depletion that was limited by the 65 percent net taxable income limit
both have been introduced in the 107th Congress. Taken together with
the changes passed regarding percentage depletion, millions of dollars
would be made available based on costs and losses already incurred to
enhance domestic production.
Collectively, these provisions have wide support. They would be of
significant national value. They should be enacted now. Equally
important, they must be crafted in such a manner to assure that the
Alternative Minimum Tax does not nullify the benefits that they would
create. The mistake of 1986 should not be repeated. When the industry
is in desperate need of capital, it should not be stripped away.
For the future, the country needs to look toward tax policies to
encourage domestic production of its crude oil 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 some 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, it is clear that the Enhanced
Oil Recovery tax credit has added millions of barrels of crude oil
production and continues to assist in recovering the economically
higher-cost significant heavy oil reserves using technologies that have
been proved to work for more than twenty years. This provision should
be reviewed with the intent of examining and adding appropriate EOR
methods as qualified methods. (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. In early May, Steve Williams,
President of Petroleum Development Corporation in Bridgeport, West
Virginia--and a member of IPAA's Tax Committee--testified regarding
Section 29 before this subcommittee. His testimony included several
recommendations regarding Section 29 and IPAA commends that testimony
for your consideration.
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. This investment is essential to provide for
the supply increase of approximately 30 percent over this time period.
So far, this target does not appear to have been met. The NPC study was
based on 1998 actual information. From 1998 through 2000, domestic
natural gas production has increased by about two percent--an average
one percent per year --roughly half the amount needed. Some of this
limitation reflects the consequences of the 1998-99 oil price crisis as
it played out in natural gas development. Now, natural gas drilling
rigs are at record levels constrained in part because of rig
availability. The success of this activity is showing up in increased
natural gas reserves, but it is important to recognize that--over the
past five years--domestic natural gas reserve replacement has
essentially stayed even. To meet future demand increases reserves must
grow appreciably. Moreover, in recent years the depletion rate for
domestic production has increased substantially to now average 24
percent per year--with some significant Gulf of Mexico fields depleting
at rates exceeding 40 percent per year. New production must not only
overcome this depletion, it must grow in absolute terms.
With regard to domestic oil production, the challenge is to
maintain existing production levels to (1) reduce foreign dependence
and (2) to assure the existence of a healthy domestic exploration and
production industry. For example, while natural gas drilling rig counts
are at record rates, domestic oil rig counts are essentially half of
their 1997 level. Heavy oil production and development budgets in
California has been drastically cut as the result of: (1) record high
Southern California border natural gas prices, (2) the California
utilities cash-flow problems including a bankruptcy, and (3) the non-
payment to some qualified facilities (QF's) that produce electricity
for sale. The sale of electricity offsets the cost of the co-generation
steam, which is injected into the reservoir and is critical for heavy
oil production. At issue, then, is how to obtain the continuing capital
essential 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. IPAA has identified two alternatives to create
a plowback incentive.
The first would be a special deduction from gross income from the
well. The deduction would be allowed for an amount equivalent to 50% of
the costs incurred in the drilling and development of domestic oil and
natural gas wells after December 31, 2001. These costs would include
all Intangible Drilling Costs, Geological & Geophysical costs,
equipment and related costs. In the event of a dry well, the costs
would be allowed to offset qualifying gross income from other
productive wells with any excess carried forward to offset future
qualifying income of the taxpayer. Qualifying income is gross income
from an oil or gas well, which was completed or re-completed by
incurring additional qualifying costs after December 31, 2001. The
deduction would be from gross income and would not reduce the costs or
deductions generated by the expenditures themselves. Deductions in
excess of gross income from a well could be carried forward or carried
back to offset qualifying income from that well. If a well were plugged
and abandoned prior to complete utilization of the deduction, the
balance would be treated similarly to dry hole costs.
The second approach would be a 10% tax credit, based on the total
drilling and development costs for wells drilled after 2001. These
costs would include all Intangible Drilling Costs, Geological &
Geophysical costs, equipment and related costs. 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.
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 then enhance domestic investment. (An
IPAA Fact Sheet detailing this issue follows this testimony.)
If Congress wants to see more domestic crude oil and natural gas
production, it must recognize that federal tax policy plays a critical
role in whether capital will flow toward this industry and the
production of this resource. That has always been the case and it will
continue to be. Domestic producers have always been ``risk takers.''
During these times of plentiful investment opportunities, they need
some assistance in attracting capital (or retaining it for use
internally) and directing it towards domestic projects. There are
immediate actions that can and should be taken. The time is right. The
nation is seeking a more stable energy supply. Congress should act.
Independent Petroleum Association of America
Geological And Geophysical Costs
Geological and geophysical (G&G) surveys are used to locate and
identify properties with the potential to produce commercial quantities
of oil and natural gas, as well as to determine the optimal location
for exploratory and developmental wells.
Allow current expensing of geological and geophysical costs
incurred domestically including the Outer Continental Shelf.
G&G expenses include the costs incurred for geologists, seismic
surveys, and the drilling of core holes. These surveys increasingly use
3-D technology rather than the conventional 2-D technology used for
most of the last seven decades. Previously only very large companies
were able to utilize this state-of-the-art, computer-intensive, 3-D
technology because of its high cost and the considerable technical
expertise it requires. However, as the costs of computer technology
have declined, more and more domestic independent producers are making
use of this technology. Still, while 3-D seismic provides a vastly
superior tool for exploration, it is far more expensive than 2-D
technology. 3-D seismic surveys usually cost between five or six times
more per square mile onshore than the older technology and, in some
instances can account for two-thirds of the costs of some wells.
Encouraging use of this technology has many benefits:
More detailed information. Conventional 2-D seismic is
only able to identify large structural traps while 3-D seismic is able
to pinpoint complex formations and stratigraphic plays.
Improved finding rates. Producers are reporting 50-85%
improvements in their finding rate. In prior years a producer might
have to drill three to eight wells in order to find commercially viable
Reduced environmental impact. Because the use of advanced
seismic technology significantly improves the odds of drilling a
commercially viable well on the first try, this reduces the number of
wells that are drilled and, thus, reducing the footprint of the
industry on the environment.
Investment capital. Many investors are requiring producers
to provide 3-D seismic surveys of potential development before
committing their capital to the project in order to minimize their
Current law treatment
G&G costs are not deductible as ordinary and necessary business
expenses but are treated as capital expenditures recovered through cost
depletion over the life of the field. G&G expenditures allocated to
abandoned prospects are deducted upon such abandonment.
Reasons for change
These costs are an important and integral part of exploration and
production for oil and natural gas. They affect the ability of domestic
producers to engage in the exploration and development of our national
petroleum reserves. Thus, they are more in the nature of an ordinary
and necessary cost of doing business.
These costs are similar to research and development costs for other
industries. For those industries such costs are not only deductible but
a tax credit is available.
Crude oil imports are at an all-time high, which makes the U.S.
vulnerable to sharp oil price increases or supply disruptions. The
National Petroleum Council Natural Gas study concluded that natural gas
supplies need to increase by over 30 percent by 2010 to meet demand.
Domestic exploration and production must be encouraged now to offset
this potential threat to national security, to meet future needs, and
to enhance our economy. Allowing the deduction of G&G costs would
increase capital available for domestic exploration and production
The technical ``infrastructure'' of the oil services industry,
which includes geologists and engineers, has been moving into other
industries due to reduced domestic exploration and production.
Stimulating exploration and development activities would help rebuild
the critical oil services industry.
Encouraging the industry to use the best technology available and
to reduce its environmental footprint are important public policy
reasons to clarify that these ordinary and necessary business expenses
for the oil and gas industry should be expensed.
The Taxpayer Refund And Relief Act Of 1999 included a provision to
allow expensing of G&G costs, but the bill was vetoed. Congress needs
to pass legislation now to implement this common objective to enhance
and preserve domestic oil and natural gas production.
Independent Petroleum Association of America
Tax Treatment of Delay Rentals
Delay rental payments are made by producers to an oil and gas
lessor prior to drilling or production. Unlike bonus payments (made by
the producer in consideration for the grant of the lease) which
generally are treated as an advance royalty and thus capitalized,
producers have historically been allowed to elect to deduct delay
rental payments under Treasury Regulations 1.612-3(c). However, in
September 1997, the IRS issued a coordinated issues paper stating that
such payments are preproduction costs subject to capitalization under
Section 263A of the Internal Revenue Code. The legislative history of
Section 263A is unclear and subject to varying interpretation.
Clarify that delay rental payments are deductible, at the election
of the taxpayer, as ordinary and necessary business expenses.
Reasons for change
In passing the Section 263A uniform capitalization rules, Congress
broadly intended to only affect the ``unwarranted deferral of taxes.''
Congress did not intend to grant the IRS the authority to repeal the
well-settled industry practice of deducting ``delay rentals'' as
ordinary and necessary business expenses.
Treas. Reg.1.612-3(c) states that, ``a delay rental is an amount
paid for the privilege of deferring development of the property and
which could have been avoided by abandonment of the lease, or by
commencement of development operations, or by obtaining production.''
Such payments represent ordinary and necessary business expenses, not
an ``unwarranted deferral of taxes.'' Given the clear disagreement over
the legislative history and the likelihood of costly and unnecessary
litigation to resolve the issue, clarification would eliminate
administrative and compliance burdens on taxpayers and the IRS.
The Taxpayer Refund And Relief Act Of 1999 included a provision to
clarify that delay rental payments could be expensed, but the bill was
vetoed. Congress needs to enact legislation to implement this common
position if the Administration is unwilling to correct the current
confusing interpretation of the tax code.
Independent Petroleum Association of America
Marginal Well Tax Credit
Summary of Legislation
The Marginal Well Production Tax Credit amendment to the Internal
Revenue code will establish a tax credit for existing marginal wells.
Marginal oil wells are those with average production of not more than
15 barrels per day, those producing heavy oil, or those wells producing
not less than 95 percent water with average production of not more than
25 barrels per day of oil. Marginal gas wells are those producing not
more than 90 Mcf a day. The amendment will allow a $3 a barrel tax
credit for the first 3 barrels of daily production from an existing
marginal oil well and a $0.50 per Mcf tax credit for the first 18 Mcf
of daily natural gas production from a marginal well.
The tax credit would be phased in and out in equal increments as
prices for oil and natural gas fall and rise. Prices triggering the tax
credit are based on the annual average wellhead price for all domestic
crude oil and the annual average wellhead price per 1,000 cubic feet
for all domestic natural gas. The credit for the current taxable year
is based on the average price from the previous year. The phase in/out
prices are as follows:
OIL--phase in/out between $15 and $18;
GAS--phase in/out between $1.67 and $2.00.
The amendment would allow the tax credit to be offset against
regular and the alternative minimum tax (AMT). In addition, for
producers without taxable income for the current tax year, the
amendment would provide a 10-year carryback provision allowing
producers to claim the credit on taxes paid in those years. The
carryback credit may be used to offset regular tax and AMT.
Reasons For Change
The 1994 National Petroleum Council's Marginal Wells report
Preserving marginal wells is central to our energy security.
Neither government nor the industry can set the global market price of
crude oil. Therefore, the nation's internal cost structure must be
relied upon for preserving marginal well 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
\1\It also recommended expanding the Enhanced Oil Recovery tax
credit, an inactive well recovery tax credit, and expensing of capital
expenditures associated with marginal wells.
As the 107th Congress begins, legislation has been introduced in
both the House and Senate to create a tax credit. If enacted now, this
countercyclical credit would establish a safety net of support for
these critical wells. As Congress addresses energy policy issues, IPAA
believes a marginal wells tax credit should be an essential component.
Independent Petroleum Association of America
Eliminate The Net Income Limitation On Percentage Depletion
The net income limitation severely restricts the ability of
independent producers to use percentage depletion, particularly with
respect to marginal wells. Percentage depletion is already subject to
many limitations. First, the percentage depletion allowance may only be
taken by independent producers and royalty owners and not by integrated
oil companies. Second, depletion may only be claimed up to specific
daily production levels of 1,000 barrels of oil or 6,000 Mcf of natural
gas. Third, depletion is limited to the net income from the property.
Fourth, the deduction is limited to 65% of net taxable income. These
limitations apply both for regular and alternative minimum tax
The net income limitation requires percentage depletion to be
calculated on a property-by-property basis. It prohibits percentage
depletion to the extent it exceeds the net income from a particular
property. The typical independent producer can have numerous oil and
gas properties, many of which could be marginal properties with high
operating costs and low production yields. During periods of low
prices, the producer may not have net income from a particular
property, especially from marginal properties. When domestic production
is most susceptible to being plugged, the net income limitation
discourages producers from investing income to maintain marginal wells.
Eliminate the net income limitation on percentage depletion.
Reasons for change
Marginal oil wells--those producing on average 15 barrels per day
or less or producing heavy oil--account for approximately 20 percent of
domestic oil production, an amount roughly equivalent to imports from
Saudi Arabia. The U.S. is the only country with significant production
from marginal wells. Once wells are plugged, access to the remaining
resource is often lost forever. Eliminating the net income limitation
on percentage depletion would encourage producers to keep marginally
economic wells in production and enhance optimum oil and natural gas
The current requirement creates a paperwork and compliance
nightmare for taxpayers and the Internal Revenue Service. Eliminating
the net income limitation on percentage depletion would simplify
recordkeeping and reduce the administrative and compliance burden for
taxpayers and the IRS.
The Taxpayer Relief Act of 1997 created a two-year suspension of
the net income limitation on percentage depletion; this suspension has
been extended through 2001. However, it is time to make this suspension
permanent. If the country learned anything from the high oil and
natural gas prices of 2000, it is that America needs to maintain and
enhance its domestic oil and natural gas production. This tax reform
allows more capital to be retained by producers where it can do the
most good--producing more domestic oil and natural gas.
Legislation has been introduced to eliminate or further suspend the
net income limitation provision for marginal wells. It should be
enacted prior to 2002 when the current suspension ends.
Independent Petroleum Association of America
Percentage Depletion Expansion and Carryback Proposal
Current tax law limits the use of percentage depletion of oil and
gas in several ways. First, the percentage depletion allowance may only
be taken by independent producers and royalty owners and not by
integrated oil companies. Second, depletion may only be claimed up to
specific daily production levels of 1,000 barrels of oil or 6,000 Mcf
of natural gas. Third, the net income limitation requires percentage
depletion to be calculated on a property-by-property basis.\2\ It
prohibits percentage depletion to the extent it exceeds the net income
from a particular property. Fourth, the deduction is limited to 65% of
net taxable income. These limitations apply both for regular and
alternative minimum tax purposes.
\2\ The net income limitation for marginal wells is suspended
Percentage depletion in excess of the 65 percent limit may be
carried over to future years until it is fully utilized. Many
independent producers have been limited in the past because they have
spent their income on continuing development of their properties,
thereby reducing their taxable income. When oil prices dropped to
historically low levels independent producers were unreasonably
constrained by these tax provisions limiting their cash flow. They
cannot use these carried over deductions. Now, when capital to develop
oil and natural gas should be maximized, producers can be constrained
due to the alternative minimum tax (AMT). Even if they could use the
deductions, they may not benefit to the fullest extent possible from
actual tax savings. This proposal would alleviate these limits by
implementing the following changes:
By annual election, the 65 percent taxable income
limitation would be reduced or eliminated for current and future tax
Carried over percentage depletion could be carried back
for ten years subject to the same annual election on taxable income
Legislation has been introduced in the 107th Congress to eliminate
or suspend the 65 percent net taxable income limit and to provide for
carryback of carried over deductions.
Congress needs to include such provisions in future tax reform
bills and the Administration needs to support such provisions to
enhance and preserve domestic oil and natural gas production.
Independent Petroleum Association of America
Enhanced Oil Recovery
Section 43 of the Internal Revenue Code provides an enhanced oil
recovery (EOR) credit equal to 15 percent of the qualified enhanced oil
recovery costs incurred in a tax year. Existing Treasury guidelines for
the section 43 tax credit are very narrow, generally including only
expensive EOR processes--many of which are no longer in use. It
excludes, however, many EOR processes that are the result of
technological advances now considered common in the industry.
The Petroleum Technology Transfer Council (PTTC) in March 1997
compiled a list of EOR methods that should be included under section
43. This study was part of an industry effort to expand the EOR
definition to include technologies that have proven potential for
mitigating well abandonment and increasing oil productionand resource
Have the IRS review and expand the definition of methods qualifying
for the EOR tax credit.
Reason for Change
The existing Treasury guidelines are based on 1979-vintage
technology. This list has not kept pace with technology. A second
rationale is the incentive generated by allowing domestic producers to
position themselves to glean existing reservoirs in order to maximize
production of existing reserves.
Two additional categories to the EOR list are proposed. Those
categories include Enhanced Gravity Drainage (EGD) and Marginally
Economic Reservoir Repressurization (MERR). Included under EGD would be
horizontal drilling, multilateral well bores and large diameter lateral
well bores. Included in MERR would be natural gas injection and
waterflooding. Certain qualifiers and limiting factors include economic
criteria for approved projects and incremental production limitations
on each project.
By redefining the definition of EOR projects to include both EGD
and MERR technologies, the EOR tax credit will encourage conservation
measures to expand recovery of existing crude oil reservoirs and
promote new drilling activity.
The benefit of these changes is well stated in the National Energy
Anywhere from 30 to 70 percent of oil, and 10 to 20 percent of
natural gas, is not recovered in field development. It is estimated
that enhanced oil recovery projects, including development of new
recovery techniques, could add about 60 billion barrels of oil
nationwide through increased use of existing fields.
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.
Independent Petroleum Association of America
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; capital expenditures are essentially
flat. 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
(1) A special deduction from gross income from the well would be
allowed for an amount equivalent to 50% of the costs incurred in the
drilling and development of domestic oil and natural gas wells after
December 31, 2001. These costs would include all Intangible Drilling
Costs, Geological & Geophysical costs, equipment and related costs. In
the event of a dry well, the costs would be allowed to offset
qualifying gross income from other productive wells with any excess
carried forward to offset future qualifying income of the taxpayer.
Qualifying income is gross income from an oil or gas well which was
completed or re-completed by incurring additional qualifying costs
after December 31, 2001. The deduction is from gross income and would
not reduce the costs or deductions generated by the expenditures
themselves. Deductions in excess of gross income from a well could be
carried forward or carried back to offset qualifying income from that
well. If a well were plugged and abandoned prior to complete
utilization of the deduction, the balance would be treated similarly to
dry hole costs.
(2) A 10% tax credit, based on the total drilling and development
costs for wells drilled after 2001. These costs would include all
Intangible Drilling Costs, Geological & Geophysical costs, equipment
and related costs. 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.
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.
Chairman McCrery. Thank you, Mr. Hall.
Mr. MacFarlane, I want to talk about the part of your
testimony dealing with our foreign tax provisions in the Tax
Code because I think probably that is an area that is just not
familiar to a lot of people, including some Members of the Ways
and Means Committee, so I would like for you to expound a
little bit on that.
Particularly, tell us what benefits would be derived from
the changes you suggest in terms of domestic jobs, the economic
benefits. Tell us why we should change our foreign tax rules to
benefit the people here in the United States. How does it
Mr. MacFarlane. Sure, I would be happy to. We support
increased domestic production but I think we all realize that
that alone will not be enough and that we are going to have to
have access to oil from outside the United States, oil and gas.
And the foreign tax credit system and the U.S. tax system that
applies to U.S.companies is a little different than it is for
some of the other competitors that we face in the international arena.
Non-U.S.-based companies typically have a tax system that
is a territorial system, so they would only tax income which
arose in their country, or they may have a credit system like
we do, but it may be more fully effective.
What we have in the United States is a credit system where
the worldwide income of U.S.-based companies is taxed and it
comes back into the U.S. tax return and you are allowed a
foreign tax credit against that for the taxes that are paid to
There are some limitations in that system that are not
suffered by our competitors that are not U.S.-based companies
and we feel that there are several reasons why it is important
for U.S. companies to be involved in the development of foreign
oil reserves and production.
One is that the more different sources of oil that you may
have, the better the security situation is because you can look
to a variety of sources and this allows you to compete in more
places. It also helps that U.S. companies are involved in this.
It creates jobs back in the United States, people supporting
these efforts creating technical expertise and bringing that to
bear to produce oil in the foreign locations. And it is better
that the U.S.-based companies be involved in that than leave it
to others from outside the United States.
Chairman McCrery. So in other words, some of the foreign
tax provisions in our Tax Code make American companies less
competitive with foreign companies doing the same business
Mr. MacFarlane. That is correct. When we look at an oil and
gas investment--exploration, production, development--these are
long lead-time high risk ventures, so we look very carefully at
what we anticipate the returns would be on these investments.
And if we suffer costs from additional compliance or the
foreign tax credit system not working as well as it might, then
the return that we can get is not equal to that of our foreign
competitors and therefore we can lose the business.
Chairman McCrery. Thank you for expounding on that.
I want to let you talk and Mr. Hall talk about the AMT. A
lot of the provisions that you all talked about and previous
panels have talked about, we are going to try to get in a tax
bill. They do not cost much, frankly, so we think we might be
able to squeeze some of the incentives for production of oil
and gas, some of the incentives for alternative fuels,
renewable fuels, some of the incentives for conservation into a
tax bill and get it through to the president, but when you are
talking about the AMT, you are talking big bucks.
However, when I go home to Shreveport, Louisiana and talk
to small independent producers, they tell me the thing that
just kills them is the AMT.
I will start with you, Mr. Hall, since you represent the
independent producers. Can you explain why my guys complain so
much about the AMT? Explain it to the Subcommittee.
Mr. Hall. If I can say it in such a manner that everybody
understands, depreciation is probably the big issue. As we
invest back into the industry and do more exploration and
development, we incur depreciation. That depreciation limits
the ability we can take our credits, and so forth. So having
more credits does not always benefit us. If we have alternative
minimum tax that puts a threshold to not being able to utilize
those credits. So we cannot monetize our credits, which means
we cannot put that money back into the ground because as Berry
Petroleum, we take our money internally from what is generated
from our production and put it back into our development
program. So if we are----
Chairman McCrery. So number one, it discourages
Mr. Hall. That is correct.
Chairman McCrery. OK, what is number two? What if you have
a bad year?
Mr. Hall. Well, bad year, you may still have AMT involved
because you may have production from the prior year. So the
first 2 to 3 years of depreciation limits your ability to claim
credits before the AMT turns around and works to your
advantage. So if you are constantly on a drilling program and
moving forward on a constant basis, you never get to that third
year. You have to have two or three bad years in a row and then
you have other problems.
Chairman McCrery. So the AMT is a rather perverse----
Mr. Hall. Big-time problem for the small independent
producer, big-time problem.
Chairman McCrery. What about the big guys, Mr. MacFarlane?
Is it for them, as well?
Mr. MacFarlane. We also find AMT to be a problem. I think
Mr. Hall said it well. The problem is that some of the
incentives we are talking about here, you do not get them if
you are subject to AMT. The other problem is that AMT tends to
hit you the hardest in the bad years. It has the effect of
making you pay taxes when basically you do not have the income
that would warrant it. So it is a difficult situation to deal
with when you are trying to encourage investment.
Chairman McCrery. Well, that is the third point, getting
outside investors to even look at financing an oil and gas
deal. When they can put their money into bonds or something
that is safe and get a fairly good rate of return, they look at
the oil and gas deal and say well, even if the deal works, if
the price goes down we have a bad year, we do not make money,
we are still going to have a tax liability. Not a real good
So I am hopeful that this Congress will finally come to
grips with the alternative minimum tax, not just for the oil
and gas industry but for our whole economy it is a relic of
past tax policy; it has no place in our Tax Code today. Yes, it
is going to be expensive to do away with it but we ought to do
that. But we will particularly look at the effects on
additional incentives that we put in the Tax Code, trying to at
least insulate those from the effects of the AMT. So I
appreciate your testimony.
Mr. McNulty. Thank you, Mr. Chairman. I have no questions.
I just want to thank all the witnesses for their testimony. I
especially want to thank Mr. Van Son for his focus on
renewables and I certainly hope that legislation with regard to
those issues will be included in our final legislative package.
Thank you, Mr. Chairman.
Chairman McCrery. Mr. Brady.
Mr. Brady. Thank you, Mr. Chairman.
First, Mayor McHugh, I know that the Internal Revenue
Service's job is to collect revenue but I am always constantly
amazed at how good a job they do. When organizations work hard
to try to get the most efficient, the most affordable cost for
their customers it has to be frustrating to have a Federal
agency step in and negate those very gains you have made for
your own customers. So I am hopeful that we can help in that
For Mr. Van Son, you put a big emphasis on conservation. I
appreciate the point you make, too, which is it is not either
conservation or supply; it is not either conservation or
technology. We have to have all three in a balanced approach--
some help short term, some help long.
But the main point that you make, the Green Power Group
supports immediate renewal of section 45 and the expansion of
it; is that included in the president's energy proposal?
Mr. Van Son. I'm sorry; could you please repeat the second
half of your question?
Mr. Brady. The section 45, your main proposal, immediate
renewal of 45, the production tax credit for wind and closed
loop biomass and then the extension of it. Is that included in
the president's plan?
Mr. Van Son. Yes. Actually, many of the comments I said
today are consistent with what is outlined in the national
energy policy document recently published. In particular, the
extension of section 45 should include landfill gas to energy
projects for both the production of electricity, as well as
direct use applications by conversion to a BTU credit as in
some cases it is more efficient to route the methane directly
to a boiler or other application.
Mr. Brady. Sure, thank you.
And Mr. MacFarlane and Mr. Hall, it seems to me that the
issue of energy security is more than just economics; it is a
matter of national security. And as long as our country
continues to rely on foreign sources for more than half of our
daily needs, we are vulnerable. It also seems like as one of
the most prosperous nations in the world, there is no
responsible reason we ought not be taking more care of our own
From the national security standpoint, because no one pays
much attention to you when oil is $10 or $12 a barrel but part
of your effort at encouraging domestic supply in a consistent
and affordable manner, does that not contribute to our National
security efforts, just to have more control over our own daily
energy needs so that we again have more strength when dealing
with circumstances that are beyond our control? Either one of
you may answer.
Mr. MacFarlane. Certainly I would agree. It is important to
produce what we can from this country. I think it gives us more
options from a security point of view and it is important. I do
not think it is the total answer but I think it is a very
important part of it.
Mr. Hall. Coming from the independent producer side of it,
the issue becomes when you have low oil prices and you stop
producing, you have these marginal wells that may be shut in on
a permanent basis, which means you have lost that reserve for a
long period of time, if not forever. They may not come back.
They may not be brought back ever.
So every barrel that we import, every barrel we do not
produce internally, or domestically we have to import from
someplace else, which means there are a lot of environmental
issues, as well, by bringing tankers in and everything else. So
there are multiple facets to that issue and we do concur with
you. That its a National Security issue as well
Mr. Brady. Right. Well, thank you to the panelists and
thank you, Mr. Chairman.
Chairman McCrery. Thank you, Mr. Brady. And thank all of
you for your testimony today. We appreciate your helping us to
try to craft a national energy policy that makes sense.
Now we will go to our third panel. Jerry D. Williams,
general manager and CEO of Claiborne Electric Co-op, Homer,
Louisiana on behalf of the National Rural Electric Cooperative
Association; John Tiencken, president and CEO of South Carolina
Public Service Authority on behalf of the American Public Power
Association; Greg Nelson, vice president and tax counsel,
Ameren Corporation, St. Louis, Missouri on behalf of the Edison
Welcome to all of you, gentlemen, and a particular welcome
to Mr. Jerry Williams, who is from north Louisiana and my
congressional district and I have worked with him on electric
co-op issues for quite a number of years. He always brings a
load of expertise and common sense to our discussions so I
welcome him particularly. And Mr. Williams, since you are from
my district, you get to go first.
STATEMENT OF JERRY D. WILLIAMS, GENERAL MANAGER AND CHIEF
EXECUTIVE OFFICER, CLAIBORNE ELECTRIC CO-OP, INC., HOMER,
LOUISIANA, ON BEHALF OF THE NATIONAL RURAL ELECTRIC COOPERATIVE
Mr. Williams. Thank you, Mr. Chairman and Members of the
Committee. I am Jerry Williams, the general manager and CEO of
Claiborne Electric Co-op in Homer, Louisiana. I appreciate the
opportunity to appear before you today to discuss tax law
changes that are needed to ensure adequate power supplies and
to facilitate fair competition for all electric utilities in
the move toward a more competitive marketplace.
Mr. Chairman, my verbal testimony will summarize Rural
Electric Co-op's strong support for the bipartisan legislation
H.R. 1601 introduced by Representative Scott McInnis and John
Tanner, and please refer to my written statement for background
information and an explanation on the need to provide rural
electric co-ops with tradable tax credits.
As you are aware, electric cooperatives have a different
tax status. Because cooperatives are not-for-profit businesses,
they are owned and operated for the benefit of consumer owners.
It is particularly important that in an era of restructuring
that tax policy adjust to keep the cooperative business
structure viable. All three sectors of the utility industry
agree that legislative tax fixes are needed to keep pace with
the changes occurring in the industry.
An electric cooperative is tax-exempt as long as 85 percent
or more of its annual income comes from Members. Even though
tax-exempt, income derived from business lines unrelated to the
co-op's tax-exempt purpose is still taxed under the unrelated
business income tax. If restructuring were accompanied by a
loss of the tax-exempt status of electric cooperatives, the
prices cooperative members face might rise as a result of it.
The 85/15 percent test posed few problems for cooperatives
prior to retail competition, mainly because cooperatives, like
all electric providers, had exclusive service territories. But
with retail competition, the very nature of the business is
changing. The 85/15 percent test was enacted in 1924 and has
not been substantially altered in 75 years.
To compute a co-op's income, the tax code currently ignores
two type of revenue. H.R. 1601 proposes eight additional
exclusions from the income test. The first exclusion is income
earned by a subsidiary is fully taxed at the subsidiary level
and would not be counted in the 85/15 test until paid to the
Second, in order to operate on an at-cost basis, rural
electric co-ops are required to assign and distribute capital
credits, also called patronage dividends, to their Members.
These capital credits represent the difference between revenue
received from a member less the operating cost to serve that
member. In a competitive market, certain members may be willing
to forego their capital credits in exchange for lower rates and
the donated capital would not be considered for the 85/15 test.
And third, for competitive reasons, a rural electric co-op
may need to sell electricity below fully allocated cost and at
a price based on incremental cost in order to meet market rates
and such income would be excluded from the 85/15 test. An
example of this, Mr. Chairman, would be the rates that
Claiborne Electric offered Con-Agra to build a poultry plant
near Farmerville, Louisiana.
And fourth, the nuclear decommissioning investment income
would also be excluded. As the Nuclear Decommissioning Fund
grows over the life of a nuclear power plant, investment
earnings on the fund could cause the co-op to fail the 85/15
Fifth, condemnation income would not be considered.
Nationwide, rural electric cooperatives suffer the condemnation
and annexation of their service territories by municipalities.
This would not limit a municipality's right or authority to
Sixth is prepaid income that would not be considered income
to rural electric co-ops. This is a clarification that is
important because approximately 20 percent of all the rural
electric cooperatives have prepaid their debt to the RUS.
Because the present value payment is a discount from the par
value of the debt, the IRS presently considers the discounted
amount to be nonmember income.
And seventh, H.R. 1601 excludes contributions in aid of
construction by members or nonmembers to build new lines or
improve electric service from the 85 percent Member income
And eighth, H.R. 1601 provides that if a rural electric co-
op enters into a mutually beneficial agreement to sell, lease
or swap service territory or other assets, the capital gains
from that transaction are excluded from the 85/15 test.
In addition to the exclusions from member income that I
have just described, four other types of income would be
considered member income under H.R. 1601. In general, this is
income that was member income prior to restructuring.
Those four are first, wheeling income and, as an example,
Claiborne Electric may be required to transmit or wheel
electricity through our lines for other utilities or third
Second would be regional transmission organization income.
It is quite likely that either a statute, regulation or market
condition would force the rural electric co-ops to participate
in regional transmission organizations.
And third is unbundled income and electric energy sales
income. The income of co-ops may be unbundled and charges for
things like billing, collecting, et cetera may be broken out
and these transactions with or for our members would be
considered member income, even if we actually collected it from
a third party.
And then fourth, replacement electric energy sales income.
If a rural electric cooperative loses kilowatt-hour sales in an
open market, the co-op would be allowed to replace those sales
with an equal amount of outside sales.
Mr. Chairman, the bill also provides generally the same
relief for taxable co-ops.
In conclusion, 75 years ago when the 85/15 percent test was
established it was impossible to contemplate what is going on
in the industry today. We respectfully request that Congress
recognize the changing market and revise the 85/15 percent test
to ensure that cooperatives are part of the future competitive
landscape of the electric industry.
Thank you for the opportunity to appear before you today.
[The prepared statement of Mr. Williams follows:]
Statement of Jerry D. Williams, General Manager and Chief Executive
Officer, Claiborne Electric Co-op, Inc., Homer, Louisiana, on behalf of
the National Rural Electric Cooperative Association
Good morning Mr. Chairman and Members of the Committee. My name is
Jerry Williams, and I am the General Manager and CEO of Claiborne
Electric Co-op in Homer, Louisiana. I greatly appreciate the
opportunity to appear before you today to discuss tax law changes that
are needed to ensure adequate power supplies and to facilitate fair
competition for all electric utilities in the move toward a more
Mr. Chairman, my verbal testimony will summarize rural electric co-
op's strong support for the bipartisan legislation, H.R. 1601--The
Rural Electric Tax Equity Act, introduced by Representatives Scott
McInnis and John Tanner and cosponsored by several other Members of
this Committee. Please refer to my written statement, Addendum A, for
background information and an explanation of the need to provide rural
electric co-ops with tradable tax credits. Secondly, we respectfully
urge Congress to provide tradable tax credits to rural electric co-ops
if other sectors of the electric utility industry receive broad new tax
incentives for environmental protection, electric generation, and the
commercialization of clean coal technology.
Claiborne Electric serves 22,000 customers in northwest Louisiana.
We are one of 12 Louisiana electric cooperatives serving over 350,000
customers in the state. Nationally, there are nearly 1,000 electric
cooperatives serving over 35 million consumers in 46 states.
The table in Addendum B shows an overview of the electric industry,
and illustrates that one of the co-op industry's greatest challenges is
the lack of customer density. On average, electric cooperatives serve 6
consumers and generate $7,000 per mile of line; whereas investor-owned
utilities (IOUs) have 35 consumers and generate $60,000 per mile of
line. At Claiborne Electric we average just over 5 consumers per mile
Nationally, co-ops are the smallest sector of the utility industry
but are burdened with some of the highest costs. As Addendum C
illustrates, our industry serves a disproportionate number of
As you are aware, electric cooperatives have a different tax status
because cooperatives are not-for-profit businesses that are owned by
and operated for the benefit of consumer-owners. There is, of course, a
place in the market for all types of utilities. It is particularly
important that, in an era of restructuring, tax policy be adjusted to
keep the cooperative form of business structure viable.
In addition to electric energy, cooperatives serve many other
sectors of our economy, such as agriculture, finance, retailing,
telecommunications, housing and energy. The 45,000 member-owned co-ops
nationwide provide $500 billion worth of goods and services annually in
the United States.
Ensure competitive parity in tax relief
As the Committee Members know, 24 states have passed legislation to
restructure parts of the electric utility industry; others states have
similar proposals or are studying the issue. In Louisiana, although the
Public Service Commission has formulated a deregulation plan, they are
not implementing the plan while they watch the issue unfold in other
states. The business environment for electric utilities is changing
rapidly due to federal and state legislative and regulatory actions. It
is imperative that tax provisions, advanced in any budget, tax, or
utility restructuring proposals provide for a smooth transition for
electric cooperatives to ensure that all electric consumers can
All sectors of the utility industry--the investor-owned utilities
(IOUs), the publicly-owned municipal utilities (munis) and the
consumer-owned cooperative utilities (co-ops)--agree that legislative
``tax fixes'' are needed to keep pace with the changes occurring in the
electric utility industry.
To continue to be able to function as self-reliant, at-cost
providers of electricity and electricity services, electric
cooperatives must receive comparable treatment. Restructuring of the
electric utility industry could forcecooperatives to accept non-member
revenues that jeopardize their federal tax-exempt status. Therefore,
comparability with the other sectors of the utility industry also
requires changes in the 85/15 member-non-member income test.
Tax Treatment of Electric Cooperatives
An electric cooperative is tax-exempt so long as 85 percent or more
of its annual income comes from members. Even though tax-exempt, income
derived from business lines unrelated to the co-op's tax-exempt purpose
is still taxed under the unrelated business income tax (UBIT).
Substantially all of the approximately 900 electric distribution
cooperatives throughout the nation annually pass the 85 percent member
income test and thus qualify for tax-exempt status. These distribution
cooperatives are fully taxable on unrelated business income.
An electric cooperative which does not pass the annual 85 percent
member income test is treated as a taxable entity. Nationally, most of
the largest electric generating cooperatives (G&Ts)--as opposed to
distribution cooperatives--throughout the nation derive more than 15
percent of their income from non-members and are taxable entities. As a
consequence, over 80 percent of the electricity generated by the
cooperative segment of the electric utility industry was produced and
sold by taxable electric cooperatives.
The 85/15 test posed few problems for cooperatives prior to retail
competition, mainly because cooperatives (like all electricity
providers) had exclusive service territories. But with retail
competition, the very nature of the business is changing. For example,
cooperatives will be collecting ``wire charges'' when competitors sell
power to cooperative customers over cooperative-owned power lines. As I
will explain later, cooperatives may also sell power to non-cooperative
members and there are other transactions in which cooperatives may
become involved with non-members.
The 85/15 test was enacted in 1924 and with a few limited
exceptions has not been substantially altered in 75 years. Given
today's electric industry and given the fact that most other kinds of
cooperatives do not have a 85/15 test comparable to the one for rural
electric cooperatives, I believe that changes are in order.
The Joint Committee on Taxation, in its October 1997 report of tax
issues related to restructuring, recognized the problem. It noted that:
``With electric power industry restructuring, it is not clear that
a rural electric cooperative can be assured that it will receive 85
percent of its income from its members because fees that the
cooperative receives for wheeling electricity through its system and
sales of surplus electricity will not be income from members.''
The report goes on to state:
``If restructuring were accompanied by a loss of the tax-exempt
status of electric cooperatives, the prices cooperative members face
might rise as a result . . .''
H.R. 1601, THE RURAL ELECTRIC TAX EQUITY ACT
As you are aware, NRECA strongly supports H.R. 1601, the Rural
Electric Tax Equity Act, introduced by Representatives Scott McInnis,
John Tanner and others. This legislation updates the tax laws to
reflect the changes that have occurred in the deregulating electricity
marketplace over the past few years, as well as anticipated changes. It
is important to note that last year the Joint Committee on Taxation
provided a revenue estimate of $164 million over ten years on
legislation virtually identical to H.R. 1601.
Exclusions from Member Income Test
As mentioned earlier, the Tax Code provides that rural electric co-
ops are exempt from federal income taxes if 85 percent or more of their
income consists of amounts collected from members for the sole purpose
of meeting loses and expenses. To compute a co-op's income, the Tax
Code currently ignores two types of revenue. H.R. 1601 proposes eight
additional exclusions from the income test.
1. Income Earned by Affiliates
The threat of competition has brought significant changes to the
electric marketplace. Consumers are asking for more efficient methods
of delivery of not only electricity, but also related services.
H.R. 1601 excludes the income of subsidiaries from the 85/15 test
until a dividend is paid by the subsidiary to the cooperative. Rural
electric co-ops have formed subsidiaries to provide their members non-
electric services--to meet the menu of services offered by rural
electric competitors and in response to member demand for these
services. Many states require that a subsidiary be formed if an REC is
to offer non-electric services. This bill provides that subsidiary
income is fully taxed at the subsidiary level. Subsidiary dividend
payments flowing back to the parent co-op are considered non-member
income except in those states that prohibit non-electric services from
being provided on a cooperative basis.
2. Waiver Income
H.R. 1601 excludes waiver income from the 85/15 test calculation.
In order to operate on an at-cost basis, rural electric co-ops are
required to assign and distribute capital credits (or ``patronage
dividends'') to their members. This capital credit or patronage
dividend represents the difference in revenue received from a member
less the operating cost to serve that member. For example, if a rural
electric co-op collects $11 million in revenues and incurs $10 million
in operating costs, the excess $1 million in revenue is allocated and
distributed to the rural electric co-op's members in proportion to each
member's electric use. In a competitive market, certain members may be
willing to forego their capital credits or patronage dividends in
exchange for lower rates.
3. Incremental Cost Electric Energy Income
H.R. 1601 excludes the incremental cost of the electric energy
income from the 85/15 test. For competitive reasons, a rural electric
co-op may need to sell electricity below fully allocated cost and at a
price based on incremental cost in order to meet market rates (any
price above incremental cost lowers the remaining fixed cost the other
rural electric co-op members must cover).
4. Nuclear Decommissioning Income
In addition, nuclear decommissioning investment income is not
considered when calculating the 85/15 test. A number of electric
generation and transmission co-ops are part owners of nuclear power
plants with other utilities. Under current tax law, investment income
is treated as non-member income for purposes of the 85/15 test. As the
nuclear decommissioning fund grows over the life of the nuclear power
plant, investment earnings on the fund could cause the electric
generation and transmission co-op to fail the 85/15 test.
5. Condemnation Income
Furthermore, condemnation income under H.R. 1601 is not considered
when performing a calculation of the 85/15 test. Nationwide, rural
electric co-ops suffer from the condemnation and annexation of their
service territories by municipalities. Under current tax law,
condemnation income is non-member income for purposes of the 85/15
test. This provision will not limit a municipality's right or authority
to condemn territory. It merely will allow the rural electric co-op to
exclude the income from the condemnation from the 85/15 test, so that
the condemnation cannot threaten the rural electric co-op's tax-exempt
6. Prepayment Income
Approximately 20 percent of all rural electric co-ops have prepaid
their debt to the Rural Utilities Service, an agency of the United
States Department of Agriculture. Because the present-value payment is
a discount from the par value of the debt, the IRS presently considers
the discounted amount to be non-member income. H.R. 1601 proposes that
gain from the prepayment of Rural Utility Service debt not be
considered income to rural electric co-ops.
7&8. Contributions in Aid of Construction Income and
Property Transfer Income
Finally, H.R. 1601 excludes contributions by members or non-members
to facilitate establishing or improving electric service from the 85%
member income test. In addition, H.R. 1601 provides that if an rural
electric co-op enters into a mutually beneficial agreement to sell,
lease or swap service territory or other assets, the income from that
transaction is excluded from the 85/15 test.
Income Included as Member Income
In addition to the exclusions from member income described above,
H.R. 1601 deems other types of income to be member income for the 85/15
test. In general, the items deemed to be member income are those which
were member income or patronage-sourced income prior to electricity
industry restructuring. These newly defined income sources include:
H.R. 1601 clarifies that income from transmission and distribution
wheeling transactions conducted to, with or for co-op members, even if
actually collected from a third party, are member income for purposes
of the 85/15 member income test. Wheeling is the transmission of
electricity by an entity that does not own or directly use the power it
is transmitting. Wholesale wheeling means bulk transactions in the
wholesale market. Retail wheeling allows power producers direct access
to retail customers.
Regional Transmission Organization Income
H.R. 1601 also provides that, if properly authorized, regional
transmission organization income will be considered member income for
the 85/15 test. This provision is needed because it is quite likely
that either a statute, regulation or market condition will force rural
electric co-ops to participate in regional transmission organizations,
placing the co-op's transmission assets or control of its transmission
assets within the organization.
Unbundling Income and Electric Energy Sales Income
H.R. 1601 provides that unbundling income and electric energy sales
income will both be considered member income when calculating the 85/15
test. Member income currently includes income received from billing and
collection services. This bill clarifies that should restructuring
require the unbundling of the rural electric co-op's services such
income from electric energy sales transactions conducted to, with or
for co-op members, even if collected from a third party continues to be
defined as member income.
Replacement Electric Energy Sales Income
H.R. 1601 identifies replacement electric energy sales income as
member income for the 85/15 test. To the extent that a rural electric
co-op loses kilowatt-hour sales in an open market, the co-op will be
allowed to replace those sales with an equal amount of outside
kilowatt-hour sales and treat such outside sales as member income.
This bill also provides generally the same level of relief for
taxable cooperatives. By defining these similar types of income as
patronage-sourced income, taxable electric cooperatives are able to
participate in the open competitive market without increased tax
All sectors of the electric industry have tax concerns due to
restructuring. For the cooperative sector, it is clear that the 85/15
test, when imposed 75 years ago, never contemplated the vast changes
the industry is poised to undergo today.
We respectfully request that Congress recognize the changing market
and revise the 85/15 test to ensure that cooperatives are part of the
future competitive landscape of the electric industry by passing H.R.
Thank you for the opportunity to appear before you today. I would
be pleased to answer any questions that you may have.
TRADABLE TAX CREDITS TO INCREASE RENEWABLE ENERGY SUPPLY
In light of ongoing energy supply shortages and environmental
challenges throughout the nation, Congress and the Administration
should continue to pursue legislative options to promote the production
of domestic, low-cost, efficient and clean energy supplies. However,
tax benefits that create financial incentives for IOUs do not create
incentives for rural electric or publicly owned electric utilities
because these entities are not-for-profit, and do not generate federal
income tax liability from which to deduct the credits.
In order to establish comparability and fairness with the IOUs,
cooperatives and other not-for profit electric utilities must be
provided with tradable tax credits. Furthermore, cooperatives must be
permitted to sell, trade or transfer the tax credits to private
entities that can utilize them. Proceeds from such sales provide
comparable incentives for cooperatives' investment in new energy
production similar to what is being proposed for the IOUs.
Benefits of Providing Tradable Tax Credits
A competitive electricity market rewards efficient energy
production: Providing tax benefits to only one sector of the industry
provides a competitive advantage for IOUs and a competitive
disadvantage for the nearly 900 cooperatives and 2000 publicly owned
utilities that comprise 25 percent of the nation's electricity load.
Offering incentives that are not usable by this significant segment of
the market removes the opportunity to employ the existing capacity of
cooperative and publicly owned utilities to deploy their expertise and
resources in seeking solutions to the nation's energy challenges.
Because renewable energy sources and environmentally clean,
advanced fossil fuel technologies usually are more expensive to operate
than traditional sources, the federal government has made it a policy
to provide investment incentives to encourage IOUs to build these
facilities. The rewards are cleaner, more secure, independent, and
diverse energy sources. Without comparable incentives, rural electric
cooperatives and publicly owned electric utilities are not afforded the
same opportunities to make these investments.
How Would a Tradable Tax Credit Work?
The cooperative builds an energy facility eligible for tax
The cooperative is then eligible to receive federal tax
credits comparable to those of IOUs.
The cooperative may, under the Internal Revenue Code
(IRC), sell, transfer or assign those credits to another entity that
could presumably use the credits to reduce tax liability.
Neither the tax credits nor the proceeds from a sale would
result in federal taxable income.
Taxpayers using the credits would not have their
alternative minimum tax increased as a result of using the credits.
Parallels in Law Supporting Tradable Tax Credit Proposal
There are several provisions in the Tax Code similar to the
tradable tax proposal. The only way to benefit from nearly all of the
tax credits in the IRC is to have tax liability equal to or in excess
of the credits. Exempt organizations can qualify for tax credits by
engaging in an unrelated trade or business; however their ability to
benefit from the general business credit (the term used to include
virtually all credits) is extremely limited. However, some of the
credits are directed toward the economic event targeted in the law as
opposed to taxpayer's investing in the property or activity generating
the credit. For example,
Section 41 Research credits are allowed for qualified
research expenses paid to tax exempt universities;
Section 38(b)(3) Alcohol fuel credits apply to the alcohol
sold or used as fuel, regardless of the tax status of the producer or
Section 47(a) credit addressing, in part, certified
historic structures, allows the credit even though the structure may be
used by a tax exempt entity; and
Sections 613A and 619 provide for the depletion allowance
for oil and gas and timber, regardless of the tax status of the owner
of the property.
Each of these examples advance the public policy without penalizing
any member of the economy that implements the public policy objective.
In addition, while not a tax provision, an excellent and parallel
example of the Tradable Tax Credit proposal is found in the tradable
credits of 1990, 42 U.S.C. section 7651 et seq. The Clean Air Act
Amendments of 1990 established a system to issue emission allowances
for airborne pollutants, implemented by the Environmental Protection
Agency. Electric utilities were issued emission allowances authorizing
the emission of a specified amount of airborne pollutants by the
utility during a specified calendar year or later period. Starting in
1993, unused allowances may be sold, traded or held in inventory for
use against emissions in future years.
ELECTRIC UTILITY COMPARISONS
owned owned Cooperatives \1\ Industry
Number of organizations................................ 190 2,000 930 3,120
Number of total customers.............................. 92m 18m. 14m 125
Size (median number of customers)...................... 230,000 1,800 10,600 ...........
Customers, % of total.................................. 74% 15% 11% ...........
Revenues, % of total................................... 76% 15% 9% ...........
kWh sales, % of total.................................. 75% 15% 9% ...........
Sales (billions kilowatt hours):
Residential........................................ 804 172 165 1,141
Commercial......................................... 767 155 52 974
Industrial......................................... 768 145 63 976
Other.............................................. 64 27 6 97
Total............................................ 2,403 499 286 3,188
Density (consumers/mile of line)....................... 35 39 6 32
Revenue/mile of line (dollars)......................... 62,866 63,988 8,156 57,563
Distribution plant investment per consumer (dollars)... 2,080 2,053 2,446 2,112
Assets ($ billions).................................... 606 126 70 802
Equity ($ billions).................................... 188 38 20 246
\1\ 870 Distribution, 60 Generation & Transmission cooperatives.
kWh = kilowatt hours.
Sources: 1999 Dept. of Energy/Energy Information Agency, NRECA Strategic Planning & Analysis, Feb 2001.
Chairman McCrery. Thank you, Mr. Williams. Mr. Tiencken.
STATEMENT OF JOHN H. TIENCKEN, PRESIDENT AND CHIEF EXECUTIVE
OFFICER, SOUTH CAROLINA PUBLIC SERVICE AUTHORITY, MONCKS
CORNER, SOUTH CAROLINA, ON BEHALF OF THE AMERICAN PUBLIC POWER
ASSOCIATION, AND THE LARGE PUBLIC POWER COUNCIL
Mr. Tiencken. Thank you, Mr. Chairman. My name is John
Tiencken and I am president and chief executive officer of the
South Carolina Public Service Authority, also known as Santee
Cooper. I am here today on behalf of the American Public Power
Association, which represents more than 2,000 publicly owned
utilities across this nation, and also on behalf of the Large
Public Power Council, which represents 21 of the nation's
largest publicly owned utilities.
I would like to address certain aspects of H.R. 1459, which
deal with tax-exempt bonds, which public power has
traditionally issued to build its facilities. This tax-exempt
debt is subject to a strict set of Federal tax rules which
limit the amount of power that can be sold to private parties
and the amount of transmission service that we can provide to
Now these rules, which perhaps made sense in a regulated
noncompetitive world, are problematic in the world in which we
now do business and are a barrier to our ability to deliver
electricity at a time when our Nation is experiencing power
I want to emphasize that the private use rules are a real-
world problem. They are one that weaves its way into the fabric
of our decisionmaking at our utility and I wanted to give you a
few examples of that, to describe howwe run into this very
frequently during our business transactions.
Private use rules restrict public power systems from
opening up our transmission to use by all parties and even
though the 2001 IRS temporary regulations permit public power
to participate in transmission open access without creating
private use on existing lines, the regulations are only
temporary and will expire in 3 years unless extended or made
Now public power cannot make a long-term commitment to open
access when the door may be closed in a 3-year timeframe. I
will also point out that we cannot build new transmission lines
with tax-exempt debt if we participate in open access.
Another limitation on our ability to provide open access is
that public power is restricted by private use rules from
joining regional transmission organizations. Although the 2001
temporary tax regs again provide some relief, that relief is,
in fact, limited to only a timeframe of 3 years and may expire
Private use rules also limit our ability to sell surplus
power into wholesale markets. My utility, for instance, is a
net power purchaser now but at other times may be selling into
the wholesale market. Under the 2001 temporary regulations, we
may only make wholesale sales which are less than 1 year in
duration. However, long-term contracts are, in fact, favored in
the electric industry now and you do not have to look much
further than California to see the value of long-term
contracting for electric supply. The proposed bill will also
allow longer term sales under certain conditions.
Finally, I want to address the complexity of private use
rules and the lack of clarity in their interpretation and how
this creates a challenge to us and a chilling effect on our
ability to do transactions. As an example, Santee Cooper, along
with a number of other public power entities, formed an
organization by the name of The Energy Authority to market and
purchase power for us. The sales that The Energy Authority
makes are sales which are governed by the private use rules.
Now what is not evident to most folks is the amazing
complexity of these private use rules. I was a tax lawyer in a
former life and I can tell you that this area is as complex as
any that I have had to deal with in my tenure. To give you an
example, I have been on the phone with five tax lawyers and
bond lawyers to try to determine whether we could do a specific
transaction for The Energy Authority. You can imagine that
there is going to be a difference of opinion in whether or not
that can be done.
So what you find is that the complexity and the lack of
clarity in this set of arcane rules makes us seek the lowest
common denominator among the divergent opinions, so you end up
with in many instances not being able simply to do a deal.
What H.R. 1459 does and will do is provide us with clarity
and it will enhance our ability to provide open access and
compete in the new competitive world. So I appreciate your
consideration and thanks for your time.
[The prepared statement of Mr. Tiencken follows:]
Statement of John H. Tiencken, President and Chief Executive Officer,
South Carolina Public Service Authority, Moncks Corner, South Carolina,
on behalf of the American Public Power Association, and the Large
Public Power Council
My name is John Tiencken and I am chief executive officer of the
South Carolina Public Service Authority (``Santee Cooper''). I appear
today on behalf of the American Public Power Association (APPA) and the
Large Public Power Council (LPPC) and the American Public Power
Association (APPA) in support of H.R. 1459, the Electric Power Industry
Tax Modernization Act. The purpose of the bill is to remove federal tax
impediments to effective use of the electric transmission grid and to
the expansion of generation and transmission capacity.
APPA is the national service organization representing the
interests of over 2,000 community-owned public power systems throughout
the U.S. APPA member systems account for about 14 percent of all
kilowatt-hour sales to ultimate U.S. consumers, located in some of the
nation's largest cities as well as in numerous small and medium-sized
communities. LPPC is an organization of 21 of the largest public power
systems in the United States. APPA members comprise virtually all of
U.S. public power systems. All members of both organizations are state
or local governmental units overseen run by elected or appointed public
H.R. 1459, introduced by Congressman J.D. Hayworth and co-sponsored
by 16 other Members of the Ways and Means Committee, represents a
landmark effort to accommodate the often-divergent positions of public
power and investor-owned utilities on a range of federal tax issues.
The bill's contains four key elements that remove federal tax
impediments that hamper effective use of the transmission grid and
expansion of generation and transmission capacity. Key provisions
include the following:
Private Use: With respect to In connection with the
``private use'' rules that apply to public powers' electric facilities
financed by public power using tax-exempt bonds:
The bill allows any public power system to elect to
terminate issuing new tax-exempt bonds to finance most
generation facilities, in return for an exemption from
``private use'' rules for its existing tax-exempt bonds.
Private use rules that remain applicable to non-
electing systems are modernized in order to permit such systems
to provide open access transmission and distribution services,
to join regional transmission organizations (RTOs), and--if
they provide open access services--to make certain sales free
of the private use rules to retain and replace existing
customers' electric loads.
The bill restricts the use of tax-exempt bonds to
finance transmission lines not necessary to service public
power systems' governmental units' electric loads or to finance
start-up utilities' distribution facilities.
CIAC: The bill excludes contributions-in-aid-of
construction (CIAC) for electric transmission and distribution
facilities from gross income.
Transcos: The bill allows taxable entities to sell or spin
off transmission facilities to independent FERC-approved RTOs without
recognition of gain.
Nuclear Decommissioning: The bill modifies federal income
tax treatment of nuclear decommissioning funds.
I appreciate the opportunity to provide the views of APPA and LPPC
and APPA to the Committee. My testimony will focus on the private use
provisions of the bill and certain important aspects of the CIAC
provisions. EEI's witness will address the CIAC, transco and nuclear
decommissioning provisions in detail.
In addition, I want to state for the record that both APPA and LPPC
and APPA support H.R. 1601, the Rural Electric Tax Equity Act.
ENERGY POLICY CONTEXT
Before I address the private use and CIAC provisions in more
detail, I would like to explain why these tax issues are not just a
technical problem that keeps lawyers and accountants busy. Rather, they
deal with one of the key problems we face today in our industry--how to
move electric power from generation to load. In almost every area of
the country, we face electric transmission constraints--bottlenecks in
our electric grid that keep us from delivering power where we need it.
In some regions, we are unable to deliver available electric power
needed to keep the lights on. This is the case in California, where
transmission constraints into the State, and between the northern and
southern parts of within the State, can trigger rolling blackouts.
Elsewhere in the country, these constraints keep us from importing low-
cost power into high load areas and require instead that we use
expensive local generation. Physical limitations on the transmission
system are largely responsible for these constraints. But the reason we
are here today is to explain why federal tax law makes these
transmission constraints worse by limiting. These federal tax laws
restrict the use of public power's existing transmission lines and by
restricting limit public power's ability to expand and to improve these
lines. The tax rules also, prevent public power from making its surplus
electricity available in the most economic manner. The purpose of H.R.
1459 is to remedy these problems.
Access to the Transmission Grid
The first issue is that the private use rules limit the extent to
which state and local governmental units that own transmission
facilities financed by tax-exempt bonds are allowed to let non-
governmental entities use those facilities. Violation of these rules
results in loss of tax-exempt status for the bonds (in some cases
retroactively to the date of issuance). By way of background, 8% of
transmission nationally is owned by public power. In some states, the
percentage is much higher. In California, for example, about 25% of the
transmission is controlled by municipal systems. One of the nation's
our important national goals right now is to ensure that the entire
transmission grid (including public power transmission facilities) is
fully and efficiently utilized. The Federal Energy Regulatory
Commission (FERC), which regulates investor-owned utilities, has
adopted policies to open access to transmission lines to all potential
users in a manner that does not allow transmission owners to favor
their own sales. This is known as ``non-discriminatory'' open access
transmission. Open access transmission is mandatory for investor-owned
utilities subject to FERC jurisdiction, but is largely voluntary for
public power systems. FERC has also adopted policies encouraging
formation and membership in RTOs. The essential purpose of these RTOs
is to enhance non-discriminatory, open access transmission by
coordinating transactions among transmission lines that have
historically been owned and operated by different utilities. FERC has
adopted open access transmission policies that are designed to open up
the grid to all potential users on a non-discriminatory basis. Open
access transmission is mandatory for investor-owned utilities subject
to FERC jurisdiction, but is largely voluntary for public power
systems. FERC also has adopted policies encouraging formation of and
membership in RTOs. Carrying out these policies is critically necessary
to getting power where we need it on the existing grid.
Prior to 1998, the private use rules barred public power from
committing to providing full open access transmission and from joining
RTOs. Treasury temporary regulations issued by Treasury in 1998 and
reissued in 2001, provided partial temporary relief from these rules.
But because the rules are only temporary, they do not permit us to make
long-term commitments to open access transmission and to RTOs and they
frustrate long-term planning. More importantly, under the temporary
regulations, no real relief is available for transmission facilities
financed by recently issued tax-exempt bonds. If the issuer reasonably
could expect that the transmission facilities are reasonably expected
to be used to provide open access transmission service, tax-exempt
bonds cannot be used. This means not only that public power systems
that issued bonds to finance transmission after open access
requirements were establishedbecame the norm are barred from offering
open access transmission and joining RTOs., Moreover, but also that
public power systems now in RTOs or now providing open access, cannot
continue to provide open access or remain members of RTOs if they use
tax-exempt bonds to finance badly-needed transmission upgrades. This is
backwards. We should encourage--not deter--expansion of the grid in
these circumstances. H.R. 1459 fixes this problem by providing the same
relief to new issuers as is provided to other transmission owners and
by making the relief permanent for both new and existing issuers.
Another impediment to opening up the grid under the private use
rules is how those rules deal with power sales from tax-exempt financed
generation to non-governmental entities. Providing open access
transmission service exposes transmission owners to competition,
because their wholesale customers can switch to other suppliers.
Transmission owners will not voluntarily provide this service if they
will lose sales to existing customers and, because of private use
limitations, are unable to sell that power to other new customers. To
protect against or mitigate such losses, these public power systems
need to be allowed to negotiate rates for sales of power, something
they cannot do under private use rules as they currently exist.unless
they can offer negotiated rates to retain existing customers and to
replace the loads of departing customers. The current private use
rules, including the temporary regulations, impose significant
constraints on public power systems that need to use negotiated rates
to retain or replace existing customers. H.R. 1459 modernizes the
private use sales rules to remove this disincentive to open access
transmission by permitting negotiated sales to existing customers and
by providing a reasonable transition period during which sales can be
made to replace lost customers.
H.R. 1459 also enhances our ability to sell our surplus power under
long-term contracts. Our experience in California over the last 18
months has taught all of us that long-term contracts are key to
disciplining market power and market volatility and ensuring that
customers receive reliable and economic service. Public power systems
have surplus power that can be sold into wholesale markets under long-
term contracts. However, the private use rules significantly restrict
our ability to do so. The current temporary regulations impose a one-
year limit on power sales made to non-governmental entities. H.R. 1459
will liberalize theses rules for public power systems that offer
voluntary open access transmission and/or open retail access. In
particular, public power systems that lose load because of open access
transmission can make replacement sales for up to a seven-year term
under the bill. Long-term contracts are also permitted for certain
sales to existing customers.
New Generation Interconnection
A key national objective for the electric power sector is new
generation capacity. We need not only to build these units, but also to
expand the transmission grid to accommodate them. The current tax
treatment of contributions-in-aid-of-construction drives up the cost of
transmission facilities necessary for new generators. Typically, the
owner of a new unit must pay the transmission owner for transmission
upgrades necessary to connect up to the grid. If the transmission owner
is an investor-owned utility, the payment is included in gross income
in the year received and, as a general practice, the amount due the
transmission owner is increased (``grossed-up'') by about one-third to
reflect the tax due. H.R. 1459 changes the tax treatment of these
payments by excluding CIAC from income for transmission and
distribution facilities. This change permits our generation and that of
independent power producers to be hooked up to the grid without paying
In addition to the provisions discussed above, the bill also
modifies the private use rules to accommodate retail competition
policies in states that have opted for retail competition. Under H.R.
1459, private use rules will not bar a public power system from
providing open access to its distribution facilities, or from making
sales under negotiated contracts to ``on-system'' customers (in
general, these are regular customers that are directly connected to the
The bill also contains new restrictions on the use of tax-exempt
financing to build new transmission lines outside of a public power
system's distribution area and not necessarily to serve public power
loads. This is designed to preclude the use of tax-exempt financing for
these ``merchant transmission lines,'' but will not to restrict
necessary additions and upgrades to existing transmission facilities or
transmission necessary to serve public power loads.
Finally, the bill permits public power systems that are willing to
forego issuing new tax-exempt bonds for generation facilities (subject
to limited exceptions) to be relieved of private use constraints for
their existing tax-exempt bonds. Public power systems in highly
competitive situations would be able to play under the same rules as
other players if they give up future tax-exempt financing for their
The provisions of H.R. 1459 thatwhich I have described above will
assist us in meeting the national need to use our existing transmission
grid more effectively, to expand it where necessary, to accommodate new
generation, and to make surplus power more readily available under
long-term contracts. We urge the Congress to take expeditious action on
A detailed explanation of the private use provisions of the bill
TECHNICAL EXPLANATION OF PRIVATE USE PROVISIONS OF H.R. 1459
A. Election to Terminate Issuing New Tax-Exempt Bonds
1. Termination Election
H.R. 1459 provides that public power systems can elect to
permanently terminate issuing most new tax-exempt bonds, in return for
an exemption from private use rules for all of their existing tax-
exempt bonds issued before the date of enactment. However, an electing
system may continue to issue certain tax-exempt bonds which are
2. Tax-Exempt Bonds That May Be Issued After a Termination
Qualified bonds and refunding bonds.--An electing system may
continue to issue any qualified bond as defined in Section 141(e) of
the tax code. (These are tax-exempt bonds that are currently free of
most private use constraints.) An electing system may also issue any
eligible refunding bonds. An eligible refunding bond is a state or
local bond issued after the system makes the election, that directly or
indirectly refunds tax-exempt bonds that were issued before the system
made the election, provided the weighted average maturity of the
refunding bonds does not exceed the remaining average maturity of the
Qualifying transmission and distribution facilities.--An electing
system may continue to issue bonds to finance a local transmission
facility over which the system provides open transmission access (a
qualifying transmission facility); and a distribution facility over
which the system provides open retail access (a qualifying distribution
facility). New transmission and distribution bonds issued under this
exception are subject to private use rules, as modified by the bill.
Repairs.--An electing system may continue to issue tax-exempt bonds
for repair of electric generating facilities that were in service on
the date of enactment or construction of which was commenced prior to
June 1, 2000. Repair may include replacement of components of the
electric generating facilities, but does not include replacement of an
electric generating facility. The repairs performed with the tax-exempt
financing may not increase the capacity of the generating facility by
more than 3% of base year capacity.
Environmental.--An electing system may also continue to issue tax-
exempt bonds to meet federal or state environmental requirements
applicable to electric generating facilities that were in service on
the date of enactment or construction of which was commenced prior to
June 1, 2000.
Renewables.--An electing system may issue tax-exempt bonds for
renewable energy generation facilities during any period in which tax
credits for the same type of facility are available to private
entities. Tax credits are currently available for solar, wind,
geothermal and closed-loop biomass generating facilities.
B. Updated Private Use Rules for Non-electing Systems
Under the bill, public power systems that do not make the
termination election remain subject to private use rules. However, the
bill would modify the private use rules applicable to public power
systems that do not make the termination election to permit open access
transmission and distribution; and to permit public power systems to
make certain electric sales not subject to private use rules in order
to retain or replace certain load.
1. Open Access
The following open access transmission and distribution activities
do not constitute a private business use: (1) providing non-
discriminatory open access transmission service; (2) participation in
an ISO or RTO approved by FERC; and (3) providing nondiscriminatory
open access to distribution facilities for retail delivery of
electricity sold by other suppliers. Open access transmission must be
provided under a FERC-approved RTO agreement or pursuant to an open
access tariff approved by FERC. If the open access tariff has been
filed voluntarily, the public power system must comply with
requirements of FERC Order No. 2000 concerning reporting its plans for
regional transmission organizations. For certain Texas utilities,
approvals are by the Public Utility Commission of Texas, rather than by
Wholesale sales by open access transmission utilities.--Public
power systems that do not make the termination election and that
provide open access transmission service are permitted to make certain
wholesale sales not subject to private use rules from generation
facilities in service on the date of enactment or construction of which
commenced prior to June 1, 2000. To qualify under this provision, the
sale must be to a ``wholesale native load purchaser'' or a ``wholesale
stranded cost mitigation sale.''
A wholesale native load purchaser is a wholesale purchaser to whom
the public power system had a service obligation in the base year, or
an obligation in the base year under a requirements contract or firm
sales contract that has been in effect for, or has an initial term of,
10 years or more.
A wholesale stranded cost mitigation sale is a wholesale sale to an
existing or new wholesale customer which replaces lost wholesale native
load. Lost load is measured by the difference between base year sales
to wholesale native load purchasers and the sales to such purchasers
during recovery period years. The recovery period is a seven year
period beginning with the start-up year; however, there is a limited
one year carry-over to an eighth year. At the election of the public
power system, the start-up year is the year the system first offers
open transmission access, the first year in which at least 10% of the
system's wholesale customers' aggregate retail load is open to retail
competition or, the year of enactment, if later. The base year is the
year of enactment or, at the election of the public power system, one
of the two preceding years.
On-system sales by open access transmission and distribution
utilities.--Public power systems that do not make the termination
election and that provide open access transmission (if the system owns
or operates transmission) and open access distribution service may also
make sales not subject to private use rules to an ``on-system
purchaser'' from generation facilities in service on the date of
enactment or construction of which commenced prior to June 1, 2000. An
on-system purchaser is specifically defined as one whose facilities or
equipment are directly connected with the public power system's
transmission or distribution facilities and who purchases electricity
from such system and is either a retail purchaser within the area in
which the system provided distributionservices in the base year or is
one to whom the system has a service obligation, or who is a wholesale
native load purchaser from the system.
C. Limits on New Tax-Exempt Financing for Certain Transmission and
Local transmission facilities limitation.--Pursuant to the bill,
whether or not they make the termination election described above,
public power systems may issue new tax-exempt bonds for transmission
facilities only if the facilities are ``local transmission
facilities.'' Local transmission facilities are transmission facilities
located in a public power system's existing distribution area or
facilities which are, or will be, necessary to serve its wholesale or
retail native load. A system's retail native load is the load of end-
users served by its distribution facilities. A system's wholesale
native load is its wholesale sales to its wholesale native load
purchasers (or purchasers under wholesale requirements or other firm
contracts that were in effect in the base year), or the electric load
of end-users served by any such wholesale purchaser's distribution
facilities. Electric reliability standards of national or regional
reliability organizations, or decisions of RTOs or state or federal
agencies shall be taken into account in determining whether facilities
are or will be necessary to serve wholesale or retail native load.
Transmission siting and construction decisions of RTOs and state and
federal agencies shall be presumptive evidence as to whether
transmission facilities are necessary to serve native load.
Exceptions.--Tax-exempt bonds may also be issued to finance any
repair, replacement or qualifying upgrade of an existing transmission
facility that is not a local transmission facility or to comply with an
obligation under an existing shared transmission agreement. However,
repair or replacement may not increase the voltage level nor may it
increase thermal load limit by more than 3%. A qualifying upgrade is
defined as an improvement to existing transmission facilities ordered
or approved by an RTO or ordered by a state or federal regulatory or
As under current law, a public system can use tax-exempt financing
to construct distribution facilities to serve its customers or existing
customers of other utilities as governed by state law. However, under
the bill, a public power system which begins operation after the date
of enactment would be precluded from issuing tax-exempt bonds for
distribution facilities until it has been in operation for 10 years. In
addition, except for certain transactions, public power systems could
no longer issue tax-exempt bonds under the state volume cap to purchase
distribution facilities owned by non-governmental utilities.
The CAIAC, transco and nuclear decommissioning provisions of the
bill are described in detail in EEI's testimony.
Chairman McCrery. Thank you, Mr. Tiencken. Mr. Nelson.
STATEMENT OF GREGORY NELSON, VICE PRESIDENT AND TAX COUNSEL,
AMEREN CORPORATION, ST. LOUIS, MISSOURI, ON BEHALF OF THE
EDISON ELECTRIC INSTITUTE
Mr. Nelson. My name is Greg Nelson. I am vice president and
tax counsel of Ameren Corp. in St. Louis, Missouri. Ameren is a
public utility holding company that owns utilities that serve
customers in Missouri and Illinois. I am speaking today on
behalf of the Edison Electric Institute, the trade association
of shareholder-owned utilities. We serve 90 percent of the
customers served by shareholder-owned utilities in the United
States and roughly 70 percent of all electric customers in the
I am particularly pleased to testify in support of H.R.
1459, along with Mr. Tiencken from the public power trade
organizations. The provisions of that bill are the product of a
long negotiation between our respective groups to try to find a
way to fairly balance the interests of our respective
constituencies in light of the changing situation, both on the
regulatory front and with the electric energy supply situation.
The context of the bill is the energy supply situation. We
are all familiar with the developments in California. We also
are familiar with the fact that the crisis in California
threatens to spread to the rest of the country if something is
not done. There is a wide range of opinion as to what went
wrong in California and why. I think a consensus among people
with different opinions is that energy supply is a big part of
the problem. There are policy-makers now at the Federal level
and the state level looking for ways to solve energy supply
Energy supply has two components. First is the generation
component, making sure that we have adequate generation
facilities in the country to produce the electricity that we
need. But second and very important to this bill is the need
for adequate transmission; that is, delivery of the electricity
from the plants to the population centers and industrial
centers where electricity is needed.
Mr. Tiencken covered the private use rules, the part of the
bill that affects tax-exempt bonds of public power. I would
like to cover three items and basically all three items, deal
with removing tax barriers to energy supply expansion and
modern restructuring developments.
The first is to remove barriers to the formation of
independent transmission companies. The Federal Energy
Regulatory Commission (FERC), which has jurisdiction over
interstate sales of electricity, is essentially requiring
electric utilities to join regional transmission organizations.
These are defined in roughly 1,000 pages of FERC orders and
regulations and FERC Order 2000 as having several
characteristics, including sufficient size and scope to have a
regional-type presence or concentration of transmission and
also independence from the present transmission owners
The ultimate business model that most utilities are moving
toward is a transmission company; that is, a company formed for
the purpose of owning transmission and being motivated to
improve and upgrade and keep the transmission system where it
needs to be, given our energy supply needs.
There are two hurdles right now in the Tax Code that limit
the ability to form independent transmission companies. The
first is just the normal rule. If we as the utility sell
transmission to a transmission company, we have to pay a tax on
the increment of the value over the tax basis. That is an
impediment right now to selling assets to a transmission
The second transaction to get to a transmission company is
a spinoff, and the problem is that if we were to spin off
transmission assets we would need to subsequently combine with
other spun-off companies to form a transmission company with
sufficient scope to meet the FERC guidelines. Under tax law,
section 355(e), the so-called anti-Morris trust provision, that
would trigger a tax event, as well.
So what 1459 would do, number one, is to provide tax relief
in both of those situations to promote the formation of
The second item is to restore in general the pre-1986 Act
law on contributions in aid of construction in an effort to
ensure that contributions to utilities by customers are not
taxed and that we do not have a tax impediment to the expansion
of our infrastructure.
Finally, 1459 would update the Nuclear Decommissioning Fund
provisions by removing the tie to regulatedrates that the Code
section 468A has going back to 1984 and by facilitating the transfer of
nuclear plants from one owner to another by providing for accelerated
funding of decommissioning if a regulator approves it or if a transfer
I see my time is running out. I would be happy to take
questions and I appreciate the opportunity to speak.
[The prepared statement of Mr. Nelson follows:]
Statement of Gregory Nelson, Vice President and Tax Counsel, Ameren
Corporation, St. Louis, Missouri, on behalf of the Edison Electric
I am Gregory Nelson, Vice President and Tax Counsel of Ameren
Corporation. Ameren is a shareholder-owned public utility holding
company that owns utilities serving 1.5 million electric customers in
east/central Missouri and south/central Illinois.
I am testifying today on behalf of the Edison Electric Institute
(EEI) on the impact of Federal tax laws on the reliability and
expansion of our electric generation and transmission infrastructure
and in support of tax legislation to help assure generation and
delivery of adequate electricity supplies throughout the nation. EEI is
the association of U.S. shareholder-owned electric companies,
international affiliates and industry associates worldwide. Our U.S.
members serve over 90 percent of all customers served by the
shareholder-owned segment of the industry. They generate approximately
three-quarters of all the electricity generated by electric companies
in the country and service about 70 percent of all ultimate customers
in the nation.
While many different tax provisions are needed to enhance
electricity generation and delivery, I am specifically discussing in
today's statement only the tax provisions in H.R. 1459, the Electric
Power Industry Tax Modernization Act. EEI submitted comments for the
Record to the Oversight Subcommittee on March 19, 2001 (for the hearing
held on March 5) that comprehensively explain the number of tax
initiatives that would promote energy supply, assure adequate
generation and transmission, and increase energy efficiency.
H.R. 1459 reflects policies that were jointly agreed to by EEI, the
American Public Power Association (APPA) and the Large Public Power
Council (LPPC). These provisions are needed to implement effectively
the Federal Energy Regulatory Commission's (FERC) policies to achieve
non-discriminatory transmission access for large regional markets
through independent regional transmission organizations and to
facilitate needed electric generation and transmission infrastructure
development. Specifically, the provisions of H.R.1459 would:
Help ensure additional transmission capacity and further
diminish tax barriers to wholesale and retail competition by providing
tax relief for the sale or spin-off of transmission facilities to
participants in independent FERC approved RTOs.
Facilitate the development of new generation, transmission
and distribution facilities by clarifying the tax free status of
payments for connecting new generation to the grid and by removing the
tax on payments (contributions in aid of construction, CIAC) for
upgrades and additions by developers to transmission and distribution
Updating the tax treatment of nuclear decommissioning
costs by facilitating the transfer of nuclear facilities to new owners
and allowing the owners of nuclear power plants that are no longer
subject to cost-of-service ratemaking to continue to make tax-
deductible contributions to decommissioning trust funds.
Promote public power participation in regional
transmission organizations, and enable public power to operate in
competitive markets without distorting competition by amending current
law ``private use'' restrictions.
We are extremely pleased to appear here today with a representative
of APPA and LPPC because we have worked hard to iron out previous
differences about tax and electricity policies to reach an agreement
that we all support and that furthers important national energy policy
goals. And we have done so in a way that is consistent with competition
in our industry, particularly at the wholesale level, in conformance
with energy policies being implemented by FERC.
I understand that Mr. John Tiencken, representing APPA and LPPC,
will discuss in detail the provisions of H.R. 1459 that would modify
the ``private-use'' restrictions that currently impede publicly-owned
utilities from participating in FERC-approved RTOs by providing non-
discriminatory transmission access to others in coherent regional
markets. Therefore, my testimony will focus on the provisions of H.R.
(I) remove tax impediments to shareholder-owned utility transfer of
assets to RTOs;
(II) remove tax impediments to non-utility investment in
transmission facilities, and, in particular, clarify the law relating
to those that connect new electric generating plants to the
transmission grid; and
(III) remove tax impediments to the transfer of nuclear assets and
provide that tax deductible contributions can continue to be made to
nuclear decommissioning trust funds when cost-of-service rate
regulation no longer applies in competitive markets.
I. PROMOTE FORMATION OF INDEPENDENT REGIONAL TRANSMISSION COMPANIES FOR
COMPETITIVE ELECTRICITY MARKETS
Transmission Capacity Must Be Expanded and Enhanced
Rapid economic growth, combined with the increasing electrification
of our homes, businesses and industries, has strained our energy
infrastructure. Unfortunately, neither our generation supplies, nor our
transmission network, have expanded to keep up with the growing demand.
Utilities built the bulk of today's transmission system before the
advent of wholesale and retail electricity competition, essentially to
move power limited distances from their generating facilities to their
customers and to provide additional reliability by interconnecting to
their neighboring utilities. 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
Moreover, the growth in demand for transmission capacity has far
outstripped investment in transmission. Today, many more suppliers are
trying to put more power on transmission lines, challenging the limits
of transmission capacity. 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 comparison, annual investment in transmission has declined in
real terms. According to the North American Electric Reliability
Council (NERC), which oversees the reliability of our Nation's
electricity grids, the level oftransmission capacity rated 230 kv or
higher has remained virtually unchanged since 1990 and will not likely
change during the next ten years. Most new transmission investment
today focuses on connecting new generation facilities to the grid, but
not on expanding overall transfer capability.
The result is that transmission capacity is becoming an
increasingly congested resource in certain parts of the country.
Between 1999 and 2000, transmission congestion grew by more than 200
percent. In the first quarter of 2001, transmission congestion was
already three times the level experienced during the same period in
2000. The effect of this congestion is that consumers may not have easy
access to lower-priced power, and reliability may become threatened.
FERC Approved RTOs Acting through Independent Transmission Companies
Will Facilitate Regional Transmission Investment
The Energy Policy Act of 1992 (``EPACT'') changed the conditions
under which utilities could request transmission service over the
systems of others, and expanded the circumstances in which two remote
utilities could economically move power from one to the other. Building
on this in two major orders, FERC has promoted the separation of
vertically integrated electric utilities into distinct entities and
substantially changed the ways in which our transmission grid is used.
In addition, almost half the states have initiated, or announced plans
to begin, retail electric competition as well, further increasing the
demands on transmission.
In 1996, in Orders No. 888 and 889, FERC required transmission
owning utilities to ``unbundle'' their transmission functions from
their wholesale electric sales and purchasing functions and to provide
nondiscriminatory open transmission access for other utilities and
In December, 1999, in Order No. 2000, FERC directed shareholder-
owned utilities, which are subject to FERC jurisdiction, to transfer
operational control of their transmission assets to independent
regional transmission organizations as soon as December 15, 2001, or to
explain why they could not do so. FERC expects that properly configured
RTOs, through control over a larger, regional grid, will:
(1) help reduce transmission congestion on the grid,
(2) reduce ``rate pancaking,'' i.e., the imposition of multiple
charges when a transaction takes place in the control areas of multiple
(3) improve efficiency and allow for more effective management of
parallel path flows within the RTO-controlled system; and
(4) allow for more efficient planning for transmission or
generation needed to increase transmission capacity.
Simply stated, the FERC issued Order No. 2000 to boost competition
in wholesale power markets by combining utilities' respective
transmission systems into large, regional systems that are operated
independently of participants in electric power markets. The objective
of Order No. 2000 is for all owners of transmission systems to join
``strong, independent, properly-sized'' RTOs by December 15, 2001.
While FERC lacks jurisdiction over publicly-owned utilities, it has
strongly encouraged such entities to participate in RTOs. Indeed, such
participation is essential since public power (including federal
transmission entities) owns about 19 percent of the transmission in the
nation, approximately a third in California and much more (including
the federal Bonneville Power Administration) in the Northwest.
FERC is not dictating a particular form of organization or
ownership of RTOs. Many RTOs are designed to result in a for-profit
independent transmission company or ``Transco'' that may own, as well
as control, the subject transmission facilities. One of the most
desirable aspects of the Transco option is that this entity would have
the business incentive to invest in building a robust transmission
A few of the RTO proposals to date have involved a not-for-profit
Independent System Operator or ``ISO'' which controls transmission
facilities that are passively-owned by others. ISOs would have far less
economic incentive to make new investments, but may be a more
appropriate vehicle for government-owned entities. FERC has already
approved RTOs which combine ISOs and Transcos.
Current Tax Laws Impede Transco Formation
Electric utilities seeking to form a Transco under the federal tax
code face an immediate impediment in the form of a substantial federal
income tax liability. Under current tax laws, utilities that sell or
spin-off their transmission assets to form RTOs would incur a
substantial federal income tax liability because the value of
transmission assets far exceeds their tax basis (due to depreciation).
Shareholder-owned utilities can avoid an immediate tax by
transferring control but not ownership to an ISO and become essentially
passive owners of transmission facilities. However, being forced to
separate ownership from control is poor public policy because it:
(1) reduces the incentive for owners to invest in new facilities,
(2) requires complex and inefficient corporate structures.
Tax 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
transactions designed to comply with the restructuring of transmission
ownership dictated by energy policy. This can be accomplished by
amending two sections of the Internal Revenue Code (IRC).
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.
Section 3 of H.R. 1459, the ``Electric Power Industry Tax
Modernization Act,'' incorporates these changes.
These provisions would defer taxes attributable to certain gains on
sales, (IRC Sec. 1033) and would permit tax-free spin-offs (IRC Sec.
355(e)), by a utility of transmission facilities to an entity which
FERC determines is not a market participant and which is either a FERC-
approved RTO or is part of a FERC-approved RTO, (or in portions of
Texas not subject to FERC jurisdiction is approved by the Texas Public
Utility Commission). These provisions assure that tax relief is
available only to independent entities which fully comply with FERC's
policies regarding RTOs.
Amending IRC Section 1033 would permit the deferral of tax on the
proceeds of the sale of transmission facilities to an independent
Transco. Utilities could defer taxes on the proceeds of a sale of
transmission facilities only if they reinvest such proceeds in other
electric or gas utility assets, thereby fostering further investment in
The spin-off provision, amendments to Section 355(e), would allow
individual transmission companies to consolidate into regional
businesses without incurring a tax liability. This result achieves the
FERC objective of promoting independent RTO's and provides an incentive
to shareholder-owned utilities to help promote FERC objectives. Without
this incentive, these companies would likely avoid tax liability by
establishing limited liability companies (LLC) which reduces the
incentive to improve and upgrade the transmission grid.Under existing
FERC precedent, if a tax is incurred, it would be passed through to
transmission customers in the form of higher rates. Hence, this
proposal could have the effect of lowering charges to customers.
II. PROMOTE ELECTRIC RELIABILITY AND INCREASE ENERGY SUPPLY
There is a critical need to add new electric generation sources and
expand our transmission and distribution infrastructure, particularly
in the West. New generators, which constitute the fastest growing
segment of the generation sector, usually pay the costs of the new
transmission facilities needed to connect their generation plants with
the grid. Similarly, developers of new industrial sites, office parks
and residential communities often pay the costs of new transmission and
distribution facilities they will use.
Unfortunately, these transactions incur a substantial tax penalty.
Under Section 118 (b) of the Internal Revenue Code, the costs of
building new transmission and distribution facilities paid by or on
behalf of a customer to a utility are treated as contributions in aid
of construction (CIACs) and are considered as taxable income to the
utility. The Internal Revenue Service (IRS) has suspended 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. Because of the current lack of clarity
resulting from the IRS' suspension, utilities must charge generators
for the cost of potential taxes as well as the cost of the
interconnecting, which increases the costs of interconnection by
Section 4 of H.R. 1459 clarifies the tax law so that such
reimbursements of costs needed to interconnect suppliers and customers
do not result in an unnecessary tax burden. Eliminating the tax on
CIACs would help expand transmission and distribution and improve
reliability by expanding the sources of financing available for needed
new facilities, reducing the costs of interconnections for new sources
of electric generation and lowering the costs of enhancing distribution
and transmission systems.
This tax law treatment would make it less costly to interconnect
generation facilities and provide electric services. This would help
increase the supply of power and improve electric reliability. This
provision also would help the construction of new transmission and
distribution facilities by third parties, especially if existing
utilities (as in California) lack the capital to invest in needed new
III. AMEND THE NUCLEAR DECOMMISSIONING TAX LAW TO ADAPT IT TO A
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, restructuring laws
and regulations in almost half of the states, and FERC policies, the
electric utility industry is in the process of rapid change. 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 should be adapted to the
structure of competitive electricity markets by permitting taxpayers to
continue to receive tax deductions for accumulating properly identified
nuclear decommissioning costs in external trusts independent of cost-
of-service ratemaking and for accelerated funding of nuclear
decommissioning costs, where required, in connection with the transfer
of a nuclear power plant.
Section 4 of H.R. 1459 resolves current law problems by:
eliminating the requirement that deductible payments not exceed the
amount permitted in regulated rates set by regulators; creating an
exception to the level-funding requirement if regulators allow higher
decommissioning charges or if accelerated funding is required in
connection with an ownership change of the nuclear power plant;
allowing taxpaying nuclear plant owners to utilize a qualified
decommissioning fund irrespective of the age of the plant; and defining
``nuclear decommissioning costs'' and discontinuing the burdensome
requirement that taxpayers must file for an IRS ruling before making
qualified fund contributions.
The Edison Electric Institute appreciates the opportunity to
express our strong support for the provisions of H.R. 1459.
These tax law changes are a critical part of any federal effort to
lower the cost, increase the delivery capacity, reliability and supply
of electric energy in the United States.
We look forward to working with the Members of the Committee on
Ways and Means on additional tax measures that will increase the supply
and reliability of the nation's electric system.
Mr. Hayworth. [Presiding.] And Mr. Nelson, we thank you for
your testimony and being mindful of the time, as have the other
two witnesses. Thank you very much.
Mr. Tiencken, let me turn to you first if I could. As I
understand it, if a utility is in a state that has restructured
its electricity industry, it may experience some loss of
customers to competition. Is it true that if private use rules
remain in place, that utility could find it difficult to sell
the excess power created by these losses to new customers on a
long-term basis, even though some parts of our country may
urgently need that power?
Mr. Tiencken. That is correct, Mr. Hayworth. The current
private use rules restrict our ability to sell into the open
market. We can sell to retail customers currently to our
existing customer base, but without the relief that is
represented by your bill, we will have difficulty in competing
in a competitive world and being able to remarket that power
without impacting our existing tax-exempt debt.
Mr. Hayworth. Mr. Tiencken, we have all heard about the
problems associated with inadequate supply but also in getting
that supply to the customer through the nation's transmission
grid. It appears that private use rules actually inhibit
municipal utilities from allowing their own transmission lines
to be utilized by others without jeopardizing the tax-exempt
status of the bonds used to build the assets.
Will you explain how changes in the private use rules could
enhance the use of the transmission and distribution systems to
deliver more power?
Mr. Tiencken. Yes, sir, Mr. Hayworth. The reality is that
we are impaired dramatically in our abilities to be able to
join regional transmission organizations and, in fact, to be
able to offer our transmission assets for use in open access
regimes. We have problems with that.
What your bill does is provide us with substantial ability
to have certainty in opening up to transmission access. In
moving power from one region to another it allows us to place
our assets in play in the transmission grid andhave those
assets utilized by all parties without fear of our tax-exempt bonds
becoming taxable. And that is a big issue for us in the public power
area, particularly those who own a substantial amount of transmission,
as does my utility.
Mr. Hayworth. One final question for you, Mr. Tiencken. The
Treasury Department has reissued temporary regulations related
to tax-exempt bonds in private use. I have heard from some of
my constituent utilities that while these temporary regulations
help, they are by no means totally adequate. Could you explain
why that is the case?
Mr. Tiencken. Yes, sir, I can explain. Congressman, the
temporary regs are, in fact, just that--temporary. They expire
within their 3-year timeframe. They also do not offer full
relief. New transmission cannot be funded with tax-exempt bonds
any longer. And in addition, transmission that was funded with
tax-exempt bonds recently may not now be placed into an RTO or
into open access without jeopardizing all of those bonds that
have been issued for that particular entity's transmission
So the rules that the IRS has proposed as temporary are not
going to resolve our problem for the long term and that means
we cannot do a substantial amount of planning based on a 3-year
window that might close on us.
Mr. Hayworth. Mr. Nelson, in your statement you suggest
that shareholder-owned utilities complying with FERC orders to
transfer their transmission assets are likely to choose a
limited liability corporation model. I really have a two-part
question for you, sir.
Why would they choose such a corporate form? Are there
advantages and disadvantages you could describe? And are you
aware of any instances where this has occurred?
Mr. Nelson. Yes, Mr. Hayworth. The reason that a
shareholder-owned utility right now would choose an LLC
structure is that by choosing a more direct structure, an
outright sale or a spinoff with the consolidation to follow,
both of those other structures would involve the imposition of
a tax and a very substantial tax.
The LLC model allows the assets to be contributed to an LLC
to satisfy the FERC requirements that control the transfer to a
separate entity but ownership stays with the utility to avoid
imposition of a tax. So it is really a tax-driven structure
where a utility can comply with the FERC rules but avoid
That really goes to the advantages and disadvantages, as
well. The advantage is that you avoid a tax; the disadvantage
is that you have a fairly cumbersome structure, as opposed to a
more direct sale and movement toward a transco.
In terms of the prevalence of the use, my own company is a
Member of the Alliance RTO, which stretches from our service
territory in Missouri all the way east to West Virginia. It
covers the States of Illinois, Indiana, Michigan, parts of
Virginia. We are using an LLC structure in that RTO. In
addition, I know there is an RTO in Wisconsin that is using an
LLC structure; also, in Florida. Frankly, I do not know of any
examples of RTOs that are not using the LLC structure.
Mr. Hayworth. Thank you, sir, very much. Let me turn to my
good friend, the ranking member from New York.
Mr. McNulty. Thank you, Mr. Chairman. I have no questions
of this panel and I thank you and the chairman for conducting
all three of these hearings and I look forward to working with
you in developing a consensus on reform legislation to serve
our energy needs in the future. Thank you.
Mr. Hayworth. Thank you, sir. Does my friend from Texas
have any questions?
Mr. Brady. No, it was excellent testimony. I know the
groups have worked hard to work out some solutions and it
shows. So thank you.
Mr. Hayworth. I look down the dais and I see my good friend
who has labored on this issue with me, the gentleman from
Mr. English. I thank the chairman. First of all, I would
like to salute the chair for all of his groundwork in moving
toward a legislative compromise between a couple of parties
interested in this issue and he really has been the leader on
this and I want to thank him for his efforts, both on behalf of
public power and investor-owned utilities.
I would like to ask Mr. Nelson a couple of questions. You
described in your testimony the corporate form that your
company has adopted in response to the issues you have
outlined. How much of the corporate structure you have adopted
is a function of tax liability, potential Federal tax
Mr. Nelson. I hate to use the word all but I would say
most, mostly driven by the need to avoid a tax that is built
into these assets under current law.
Mr. English. Can you describe it advantages and
disadvantages that drove your decision-making in that regard?
Mr. Nelson. Certainly. FERC Order 2000 is essentially
forcing us to join an RTO, to put our assets into an RTO. We
also have a merger order which requires us to do that. We have
found that the only structure that accommodates the FERC
requirement that there be independent control of the
transmission assets, while we still retain ownership and avoid
the triggering of a tax, is the LLC structure.
The disadvantage is that we separate ownership from
control. We own assets but we do not control them. The RTO will
control them. They will tell us what to do with those assets in
terms of maintenance, improvements, and et cetera. They can
call capital from us to do things to the assets. That is a
cumbersome and awkward way to own an asset.
Mr. English. Looking at the provisions of H.R. 1459, how do
they compare with Congressman Weller's bill, H.R. 1702?
Mr. Nelson. This is dealing with the nuclear
decommissioning components and they are virtually identical in
substance. The only difference is that Mr. Weller's bill has an
earlier effective date than does Mr. Hayworth's bill.
Mr. English. With regard to interconnection as you have
described it in your testimony, why do you propose that
interconnection be nontaxable?
Mr. Nelson. There are really two contexts that we have the
interconnection issue. The first is where the merchant
generation plant is being built and the first thing they need
to do is arrange for transmission.
The IRS for a very long period of time had a ruling posture
that would have allowed that generation plant to make a tax-
free interconnection payment. Recently the IRS has declined to
rule and to give us the comfort that we need that these
transactions are not taxable.
These transactions are happening and the problem is that we
have a situation where the IRS is not interpreting the law the
way that we believe it should be interpreted. This legislation
will clarify that and make sure that a generation plant, when
it makes an interconnection payment, does not get what turns
out to be a 30 to 35-percent increase in the cost of that
interconnection facility. The policy reason for that is not to
saddle these transactions with an incremental cost that is not
The second context is the situation where developers are
connecting housing developments and new electric customers to
the system. The reason to change the law in that context is
simply to reduce the cost of improving our electricity
infrastructure given the situation we have right now with an
energy supply problem in our country.
Mr. English. And can I finally ask you to elaborate? You
had mentioned tax policy considerations. I could understand why
some of these tax changes would benefit investor-owned
utilities but can you elaborate on the tax policy justification
for your position? You know, from a standpoint of tax policy
principles, can you elaborate on why you think we should go in
Mr. Nelson. May I assume that the context of your question
is in the 1033 and the 355 context?
Mr. English. Yes.
Mr. Nelson. The analogy there really is to involuntary
conversion. The tax code already provides for tax deferral in
the context of involuntary conversion. Our proposal analogizes
the situation where we are being obligated to turn over our
assets to an RTO. It analogizes that situation to the
involuntary conversion context and it is consistent with the
tax policy in the involuntary conversion context.
Mr. English. Thank you, Mr. Chairman.
Mr. Hayworth. I thank you. And the chair would note the
outstanding work done by the gentleman from Pennsylvania as we
took a look at some differences in this and reached across this
vital industry to reach an accommodation and come up with some
common-sense solutions. The chair also welcomes the very
constructive comments of the ranking minority Member but I
would be remiss if I did not state for the record the very
genuine energy and policy challenges that were overcome by the
work of my good friend from Pennsylvania. I am very
appreciative of the fact that we were able to team up on this.
Mr. English. I thank the chair and I am always very much
obliged for the opportunity to follow in your path of
leadership. Thank you, sir.
Mr. Hayworth. Well, I think we are walking side by side and
that is quite a spectacle, as we know. From time to time we
have been referred to as tag team partners and I am glad to
have you on my side, Mr. English.
I would like to thank the witnesses. Again, Mr. Williams,
the Chairman, as he was going out to vote, was very happy to
have you here from his district. We appreciate you representing
And for all our witnesses today, thank you very much for
your time and attention on these matters and this third hearing
of the Select Revenues Subcommittee is hereby adjourned.
[Whereupon, at 12:25 p.m., the hearing was adjourned.]
[Submissions for the record follow:]
Statement of Larry Taylor, President, Air Conditioning Contractors of
America, Arlington, Virginia
Mr. Chairman and members of the subcommittee, thank you for the
opportunity for ACCA to contribute to the national dialogue on ways to
conserve energy during these challenging times. In addition to serving
as the national president of ACCA, I am also the owner and president of
Air Rite Air Conditioning Co., in Fort Worth, Texas. ACCA is the
nation's largest trade association of those who design, install and
service residential and commercial heating, ventilation, refrigeration
and air conditioning systems (HVACR).
If the need to use energy more wisely wasn't clear before, it will
be unmistakable after a summer of higher gasoline prices and potential
electricity shortfalls. The recently released Report of the National
Energy Policy Development Group, chaired by Vice President Dick Cheney,
makes the challenge clear: demand for natural gas will increase by more
than 50 percent in the next 20 years; similarly, demand for electricity
will increase by 45 percent in the next 20 years. The need for
additional energy supplies--oil, gas and electricity--is obvious. Just
as critical are improvements to the nation's energy infrastructure,
repairing and improving the means for transporting energy and energy
resources throughout the country.
At the same time, Americans need to take advantage of every
opportunity to conserve and use energy more wisely. With respect to
products, appliances and services, the Vice President's Report makes it
clear that while there have been dramatic technological advances in
energy efficiencies that have resulted in significant energy savings,
there is room for improvement. The Vice President's Report recommends
that the President should direct the Secretary of Energy to improve the
energy efficiency of appliances where such improvements are
technologically feasible and economically justified. ACCA supports this
recommendation and pledges to work with the Secretary of Energy to
accomplish this objective.
PROPER AND TIMELY MAINTENANCE FOR ENERGY SAVINGS
A Simple Opportunity to Save Energy
ACCA wishes to make the point--not made in the Vice President's
Report--that there is an even more immediate opportunity to save energy
and that is by taking the simple and relatively easy steps to ensure
that HVACR equipment in homes and businesses is maintained at peak
In most homes, the HVACR equipment is the largest energy user. In
businesses, HVACR equipment is typically among the top three consumers
A recent survey conducted by Proctor Engineering Group of San
Rafael, CA, among 9,000 residents found that over 90% had HVACR systems
that were underperforming due to one problem or another. In many cases,
the problem was as simple as a dirty filter. In the commercial arena,
the Consortium for Energy Efficiency reports that up to 50% more energy
would be saved through proper installation, sizing and maintenance of
commercial central air conditioners and heat pumps. Improving system
efficiency by 10% to 20% is a conservative estimate of the impact of
proper maintenance. For systems that are seldom or never serviced, the
savings could reach 100%.
To achieve this efficiency, we recommend the following as the
minimum requirement for system maintenance: check the system's
mechanical functions, check the air flow, check and clean the inside
coil, replace the filter, straighten the outside coil fins if
necessary, check for refrigerant leaks and recharge the system if
necessary, clean and oil the fan motors and service other hardware, and
if needed, patch and repair leaky ductwork. Studies show that one of
every four dollars spent on cooling is lost through leaky ducts.
As a part of the overall strategy to achieve energy savings, ACCA
urges Congress to address the issue of improved maintenance of HVACR
equipment. Although we support legislation to provide tax deductions
and credit for the purchase or lease of energy efficient products or
equipment (S. 207, S. 595, and HR 778), nothing will have as broad or
as immediate an impact as proper maintenance of HVACR equipment.
The Vice President's Report contains several recommendations that
could be implemented in ways to encourage the efficiency of HVACR
equipment. These include the following, with ACCA's proposed advice:
The White House National Energy Policy Report recommends that the
President direct the Office of Science and Technology Policy and the
President's Council of Advisors on Science and Technology to review and
make recommendation on using the nation's energy resource more
ACCA urges the Office of Science and Technology Policy and the
President's Council on Science and Technology to take into account the
energy savings benefits of the proper and timely maintenance of heating
and air conditioning equipment.
The Report recommends that the President direct the Secretary of
Energy to promote greater energy efficiency.
ACCA urges the Secretary of Energy to promote the energy savings
benefits of the proper and timely maintenance of heating and air
The Advisory Group also recommends that the President direct heads
of executive departments and agencies to take appropriate actions to
conserve energy use at their facilities to the maximum extent
consistent with the effective discharge of public responsibilities.
Agencies located in regions where electricity shortages are possible
should conserve, especially during periods of peak demand. Agencies
should report to the President, through the Secretary of Energy, within
30 days on the conservation actions taken.
ACCA urges the President to direct heads of executive departments
and agencies to take the appropriate actions to ensure that heating,
ventilation and air conditioning equipment in Federal buildings is
serviced regularly to ensure that it is good working order.
As energy legislation is shaped this year to address the immediate
crisis and provide for long-term needs, we urge the Subcommittee not to
overlook the opportunity for a significant and immediate energy savings
that comes with the proper and timely maintenance of HVACR equipment.
Congress can accomplish this goal by directing the appropriate Federal
agencies to provide educational information to the public and by
providing incentives for the regular maintenance and servicing of HVACR
The benefits are real and lasting, with long-term savings, rather
than costs, to the American taxpayer.
Statement of the Alliance for Resource Efficient Appliances
The Alliance for Resource Efficient Appliances (AREA) fully
supports H.R. 1316, the ``Resource Efficient Appliance Incentives
Act.'' This bi-partisan appliance tax credit bill was introduced March
29, 2001 by Representative Jim Nussle (R-IA) and Representative John
Tanner (D-TN) along with many other Members from both sides of the
This proposed tax credit will provide a per unit tax credit for
appliance manufacturers who produce clothes washers and refrigerators
that exceed the current Department of Energy standards. The credit is
subject to an aggregate per company limit of $60 million and an annual
limit of two percent of corporate gross revenues as well as the
Washing Machines--Manufacturers of super energy-efficient washing
machines would be eligible to claim a credit of either $50 or $100 for
each super energy-efficient washing machine produced between 2002 and
2006. The $50 credit is available for units that use 35% less energy
than the standard in place through 2003 and use 17% less energy than
the standards announced by DOE. The $100 credit is available for units
that use 42% less energy than the standard in place through 2004 and
use 42.5% less energy through 2006 than the standards announced by DOE.
Refrigerators--Manufacturers of super energy-efficient
refrigerators would be eligible to claim a credit of $50 for each super
energy-efficient refrigerator produced between 2002 and 2004 that is at
least 10% more energy efficient than the DOE required efficiency
standard that went into effect on July 1, 2001. Manufacturers would be
eligible to claim a credit of $100 for each unit produced between 2002
and 2006 that is at least 15% more energy efficient than the 2001 DOE
required efficiency standard.
The tax credit for the production of super energy-efficient washing
machines and refrigerators creates the incentives necessary for both
manufacturers and consumers to increase the production and sale of
super energy-efficient appliances in the short-term and to expand
marketing opportunities. The more rapidly those super energy-efficient
appliances appear in the marketplace; the more rapidly energy savings
will occur. For example, as a result of making the tax credit available
between 2002 and 2006, the production and purchase of super energy-
efficient washers is estimated to increase by almost 200% and the
purchase of super energy-efficient refrigerators by over 285%.
Moreover, this increase in the purchase of super energy-efficient
appliances will create a market transformation. The long term cost
savings of increased energy efficiency will lead to a dramatic change
in consumer purchasing decisions that will last many years after the
expiration of this tax credit.
The expanded use of super energy-efficient appliances has
significant long-term environmental benefits. Over the life of the
appliances, over 200 trillion Btus of energy will be saved.\1\ This is
the equivalent of taking 2.3 million cars off the road or closing down
6 coal-fired power plants for a year. Energy savings of this magnitude
pay significant environmental dividends. For example, carbon emissions,
the critical element in greenhouse gas emissions, will be reduced by
over 3.1 million metric tons. In addition, the super energy-efficient
clothes washers will reduce the amount of water necessary to wash
clothes by 870 billion gallons or approximately the amount of water
necessary to meet the needs of every household in a city the size of
Phoenix, Arizona for two years. The net benefits to consumers over the
life of the super energy-efficient clothes washers and refrigerators
from operational savings is almost $1 billion.
\1\ Of the total, approximately 150 trillion Btus are attributable
to the super energy-efficient clothes washers and approximately 40
trillion Btus are attributable to super energy-efficient refrigerators.
The appliance industry and the advocacy organizations acknowledge
that substantial energy savings are being achieved today through the
use of more energy efficient appliances. However, industry has the
technological ability to achieve even greater energy savings if
properly crafted incentives are enacted to encourage greater consumer
receptivity to the super energy-efficient appliances. Currently, a
major hurdle to the more widespread use of the super energy-efficient
clothes washers and refrigerators is the reluctance of many consumers
to make a higher initial investment in order to receive the long term
savings of the super energy-efficient appliances.
A tax credit available to manufacturers for the production of super
energy-- efficient washing machines and refrigerators can overcome much
of the consumer reluctance by creating incentives for both
manufacturers and consumers that will increase sales of super energy-
efficient appliances. A credit provided at the manufacturers' level is
preferable to a credit at the consumer level because of--(1) the ease
of administration; (2) the ability to limit the cost of the proposal by
capping the benefits; (3) the higher leverage obtained by providing the
tax credits upstream; and (4) the flexibility to select among many
means of marketing for the best way to sell more energy-efficient
AREA Members Include:
Alliance to Save Energy........... City of Austin, Texas
American Council for an Energy- Friends of the Earth
Association of Home Appliance Natural Resources Defense Council
Appliance Standards Awareness Northwest Power Planning Council
The Business Council for Pacific Gas and Electric
California Energy Commission...... The Sierra Club
Statement of the American Chemistry Council, Arlington, Virginia
The American Chemistry Council (ACC) strongly supports
Administration and Congressional efforts to develop a national energy
strategy to ensure dependable, affordable and environmentally sound
energy resources, now and for the future. Energy production, supply and
conservation should be vital components of that national energy
strategy, and we commend this Committee for its attention to policies
that will encourage and promote these objectives. The ACC appreciates
the opportunity to comment on these important issues.
IMPORTANCE OF ENERGY TO THE BUSINESS OF CHEMISTRY
A comprehensive national energy policy is vitally important to ACC
members. We use energy products as fuel, electricity and steam for our
operations. In addition, and this distinguishes us from most other
sectors of the economy, we use energy as raw materials (feedstocks) for
our production processes. From these energy inputs we make many of the
products that allow others to conserve energy and reduce emissions. The
chemistry industry uses 6.9 quads of energy, 7% of total U.S. energy
consumption. Of the chemistry industry's consumption, 51% is used as
feedstocks. Natural gas comprises 41% of the industry's energy
consumption. Chemistry industry natural gas consumption represents 12%
of total U.S. consumption of natural gas and 29% of total consumption
by industry (excluding electric utilities).
Unstable markets and rising domestic energy prices are forcing key
segments of the chemical industry out of world markets, resulting in
layoffs and plant shutdowns.
COGENERATION/COMBINED HEAT AND POWER
Because many chemical plants are large users of both steam and
electricity, they are ideally suited for cogeneration, which is the
sequential production of electricity and steam (useful thermal energy)
from the same energy input. Cogeneration units producing steam and
electricity attain double the fuel efficiencies of a typical electric
utility power plant.
Cogeneration units producing steam and electricity readily attain
fuel efficiencies of 65%-75%, as compared to 35% for a typical electric
utility. Even advanced gas turbine combined cycle electric utility
units can only achieve a 50% overall efficiency. These same advanced
gas turbines will achieve 75%-80% overall efficiency in a cogeneration
The reason for the efficiency advantage is that a chemical plant
uses most of the steam from the cogeneration unit in its chemical
processes. Without cogeneration, this steam would have to be supplied
in some other manner (boiler steam, direct heating with natural gas,
etc.). In contrast to cogeneration technologies, a typical utility unit
would simply condense the steam and release the waste heat into the
atmosphere or cooling water.
Cogeneration offers significant environmental benefits. By
combining the production of steam and power, cogeneration facilities
burn far less fuel and release fewer emissions, including greenhouse
gas (CO2) emissions, than the combined emissions from
separate utility power plants and industrial steam generation
Cogeneration units built close to the sites where their power is
consumed reduce power losses during transmission, alleviate
transmission congestion and reduce the need to build additional
transmission lines in many regions of the country. Reliability of power
supplies to all electricity consumers is therefore improved as more
cogeneration units generate ``on-site'' power.
The chemistry industry's cogeneration units provide steam and
electricity to their own chemical plants and are connected to
utilities' transmission and distribution systems. Section 210 of the
Public Utility Regulatory Policies Act (PURPA) ensures that any excess
electricity from a qualifying cogeneration unit can be sold to a local
electric utility. Equally important is that this section ensures that a
qualifying cogeneration unit can receive backup and maintenance power
from the utility at just and reasonable, nondiscriminatory rates.
Given the environmental benefits of cogeneration, its importance to
the chemistry industry and the current need for every available
kilowatt of power, now is not the time to repeal these provisions of
PURPA. Properly structured energy policy legislation should spur the
development of new cogeneration facilities that will help alleviate
power shortages and transmission congestion that many high-growth
states and regions are facing.
TWO RECENT EXAMPLES OF THE BENEFITS OF COGENERATION/COMBINED HEAT AND
A company installed a new, highly efficient, state-of-the-art gas
turbine generator with a large heat recovery steam boiler. This
significantly reduced use of an aged cogeneration unit and boilers with
significant NOX emissions, displaced purchased electricity,
and enabled intermittent sales of excess electricity back to the grid.
Total plant NOx emissions are lower than before even with much higher
output, and energy savings are about 19.2% per unit of production.
A company installed a second gas turbine cogeneration system to
meet expanded steam needs. The new unit has duel fuel capability and
uses byproduct gas from another on-site process as well as natural gas.
Use of byproduct gas displaced purchased natural gas and ended flaring
of the byproduct gas. Energy savings are about 30%, with associated
emissions reductions including NOX reductions from selective
THE GOVERNMENT'S ROLE
Government can support and facilitate energy production, supply and
conservation throughout the economy in a number of ways.
One important way government can help is to devise and implement
appropriate fiscal and monetary policies to ensure the continued health
of the U.S. economy. A healthy economy facilitates company earnings
that can be used for investment in new plant and equipment and the
turnover of capital stock, and for private research and development.
Congress can also promote energy production, supply and
conservation by providing financial incentives to industries that
invest in highly efficient cogeneration units. Incentives might include
faster capital cost recovery for cogeneration assets (e.g., shortened
depreciation schedules), and amendment of technical rules that
sometimes require a cogenerator to pay taxes on behalf of an electric
utility to which the cogeneration facility is connected.
The American Chemistry Council appreciates the opportunity to
present its views to the Subcommittee on Select Revenue Measures. As an
industry leader in cogeneration, the business of chemistry will work
with the Subcommittee, the Committee on Ways and Means and the Congress
to develop targeted incentives that will effectively promote these
highly efficient forms of power generation.
Statement of Stephen Johnson, Washington Public Utility District
Association, Seattle, Washington, and American Public Power Association
On behalf of the American Public Power Association (APPA) and
Washington Public Utility District Association (WPUDA), I appreciate
the opportunity to provide testimony today regarding Congresswoman
Dunn's bill on incremental hydropower, the Hydropower Capacity
I am Stephen Johnson, Executive Director of the WPUDA, an
association of 28 utilities (8 of whom are hydropower owners) in
Washington State. WPUDA members have a long history of making
conservation, efficiency and the development of renewable resources a
Today I am providing testimony on behalf of the American Public
Power Association in support of H.R. 1677, the Hydropower Capacity
Improvement Act. This bill helps to accomplish an important
conservation and energy objective: reversing the decline in generation
of electricity from clean, ``zero emissions'' hydropower. Specifically,
the bill would provide a credit of $65 times the number of additional
kilowatts of licensed generating capacity added during a tax year that
can be used to offset tax liability, or traded with any taxpayer. I
would briefly note that the ``tradability'' feature is key for APPA's
member systems, who own almost 40% of the total hydropower capacity in
the U.S. and yet would not receive any incentive from a conventional
Before I comment on the details of the credit, I would like to
explain why the hydropower industry, which enjoys a relatively abundant
and inexpensive source of clean generation, needs an incentive to add
The U.S. Department of Energy has conducted studies that have
uncovered up to 21,000 MW of undeveloped hydropower capacity at
existing U.S. dams and hydropower facilities.\1\ This is a significant
amount of power--enough to displace 24 million metric tons of carbon
emissions from coal.\2\ Why has this capacity gone undeveloped when the
demand for new energy supplies--particularly clean energy with a unique
capacity to quickly meet peak demands--exists across the country and
urgently in the West?
\1\ Hydropower Resource Assessment program draft report, US DOE
Hydropower Program, Idaho National Engineering and Environmental
Laboratory, www.inel.gov/national/hydropower/index.html, November 1998.
\2\ According to ``impacts of the Kyoto Protocol on U.S. Energy
Markets and Economic Activity,'' prepared by the Energy Information
Administration, October, 1998, Table 17, p. 75, coal fired technologies
emit 571 pound of carbon per Megwatthour.
One reason is that incremental hydropower additions are capital
intensive. The National Hydropower Association has estimated that the
cost of new hydro generation upgrades run up to $2,000 per KW, or more,
if regulatory costs are considered. By way of comparison, capital costs
for a typical combined cycle gas plant can cost $550 per KW. Although
costly, making upgrades to hydropower facilities is important both for
power generation and the environment. Upgraded turbines and newer
technologies provide increased protection for fish, and can greatly
In addition to high capital costs, hydropower resources have gone
untapped because hydropower owners face significant regulatory hurdles
to license or relicense a facility, or even just to add capacity.
Adding capacity requires an amendment to a hydropower license, and
depending upon the environmental impacts, a simple amendment can
trigger regulatory hurdles like Federal Energy Regulatory Commission
(FERC) environmental reviews and agency studies equivalent to those
required when licensing an entire facility.
The regulations connected with hydropower licenses are designed to
ensure that the industry considers the welfare of the environment as
well as our power needs when we operate our existing dams or add
capacity. Though this goal is appropriate, the licensing process
through which these regulations are enforced is broken. Our hydro
owners face conflicting statues, a host of agency regulators at the
local and federal level, and federal agency licensing conditions that
can be set without regard to the effects on project economics and power
output. The process is costly and can take 10 years or more to
To summarize, because of the costs of incremental hydropower
upgrades, disincentives presented by the licensing process, hurdles
that must be cleared in order to amend licenses and restrictions on
power generation presented by new licenses, the industry is not adding
hydropower. Instead, the Department of Energy has projected that we are
losing hydroelectric generation.\3\ Looking in my own backyard, 73
percent of the hydro capacity in the Northwest will face relicensing in
the next 15 years, and in the process is likely to lose a significant
amount of generation capacity.
\3\ Scenarios of US Carbon Reductions: Potential Impacts of Energy
Technologies by 2010 and Beyond,'' Office of Energy Efficiency and
Renewable Energy, US DOE, September 15, 1997, p. 7.21.
The incentive described in Congresswoman Dunn's bill could help
offset these losses and maintain this vital commodity for energy
consumers, without the construction of a single new dam. In addition,
if Congress and the FERC make the needed improvements to the
relicensing process, we can make the most of our hydropower resources.
For this reason, the APPA, Washington PUD Association and National
Hydropower Association (NHA) applaud Congresswoman Dunn for introducing
H.R. 1677. We agree that our valuable hydropower resources must be
protected for future generations, and encourage this Committee to
strongly consider this bill as a means of addressing critical near-term
and long-term energy needs.
We further commend Congresswoman Dunn for ensuring that the owners
of 40% of the nations' hydropower capacity will not be excluded from
receiving this incentive. Hydropower systems owned by municipalities or
units of state and local government are not-for-profit and do not
generate federally taxable income. Our federalist system precludes the
taxation of one level of government, including local public power
systems, by another. Thus, conventional energy incentives through the
tax code, which are currently being advanced in a number of bills
before Congress, do not provide incentives for us because we have no
federal income tax liability to offset with a credit. To address this
situation, Congresswoman Dunn's bill would enable us to sell the credit
to any taxpayer. The taxpayer #8211; which could include our
customers--would be able to purchase the credit at a discount from face
value, and we would in turn be able to use the proceeds to offset the
high capital costs of making capacity additions.
We greatly appreciate Congresswoman Dunn's recognition not only of
our unique status, but of the fact that hydropower is a renewable
resource that should be enhanced, along with solar, wind, biomass,
landfill gas and other resources so that this nation's consumers can
benefit from a diverse mix of fuels and greater energy security. As
Congress considers this and other bills to provide incentives for
renewable and clean energy resources that fulfill important public and
environmental purposes, we urge Congress to ensure that public power
and rural electric cooperatives #8211; which serve 25% of the nation's
power consumers #8211; also receive an incentive through a tradable
Thank you again for the opportunity to provide this subcommittee
with testimony and tell you why H.R. 1677 is so important to us. Do not
hesitate to contact me if I can answer any questions or be of any
assistance to you.
Statement of John A. McFarland, President and Chief Executive Officer,
and Roland S. Boreham, Jr., Chairman, Baldor Electric Company, Fort
After years of productivity growth that has helped industrial
companies become more competitive in world markets, we now find
competitiveness threatened by high energy prices. Industry in the
United States faces a different challenge when attempting to control
energy costs than do individuals. The makeup of our electricity bill in
industry is much different than that of individuals. For industrial
companies, 63% of our electric bill is consumed by industrial electric
motors. In some industries, such as mining, as much as 90% of the
electricity bill is consumed by the use of industrial electric motors.
There is a solution to this problem that is available today that allows
industry to save money while saving energy--high efficiency electric
With industrial electric motors consuming 25% of all of the
electricity generated in the United States, it is important that we
address the conservation opportunities available to us today by using
more efficient electric motors. High efficiency electric motors are
available from a large number of domestic and foreign sources. These
products are fully developed and available today and, according to the
Department of Energy, could reduce industry's electricity consumption
by up to 18%.
Incentives to use high efficiency motors similar to the incentives
being discussed for high efficiency automobiles could produce immediate
and substantial savings in electricity. Also, since electricity is a
substantial cost for industry, incentives for the use of high
efficiency motors can help our industrial companies continue to become
more competitive in world markets. This can be one of the most
effective ways to achieve your Committees' objectives.
The following table shows the annual operating cost, the cost of a
new high efficiency motor, and the electricity savings in dollars of
using a high efficiency motor instead of older motors installed in
industry today. As you can see in the table below, there is substantial
opportunity to save electricity and electricity cost by replacing
existing motors with high efficiency motors.
With one quarter of all of the electricity generated in the United
States consumed by industrial electric motors, it is important that
industry conserve electricity by changing out older motors to new high
efficiency models available today. Using high efficiency motors will
help industry become more competitive throughout the world and provide
an immediate increase in electricity availability ``bridging-the-gap''
until additional energy production is installed.
We do not believe a major incentive is required to encourage people
take actions which is in their own best interests. Market forces will
work successfully over time; the issue we believe is to accelerate the
workings of those market forces. A tax credit of 10-15% for the
purchase of high efficiency motors and the resulting rise in awareness
would have a large impact on energy conservation in our country,
benefit industrial competitiveness, and make more energy available for
individuals. Perhaps the best thing is there is no tradeoff. Electric
motor users can save money and energy at the same time.
[The attachments are being retained in the Committee files.]
Statement of the Letitia Chambers, Coalition of Publicly Traded
Partnerships, and Chambers Associates Incorporated
The Coalition of Publicly Traded Partnerships is pleased that the
Subcommittee has provided this opportunity to share its views on tax
provisions that affect the production and supply of energy. The
Coalition is a trade association representing publicly traded
partnerships (PTPs) and those who work with them.
PTPs, also referred to as master limited partnerships or MLPs, are
partnerships which are traded on public stock exchanges. They combine
the benefits of a partnership investment with the affordability and
liquidity of stocks and bonds, and are valued by investors for the
income they provide through quarterly cash distributions and the
potential for growth in both income and market value.
Publicly traded partnerships are highly relevant to the issues
being examined by this Subcommittee because in addition to the benefits
they provide investors, PTPs benefit energy consumers by providing an
efficient and effective means of channeling needed capital to companies
that build, maintain, and operate our nation's energy infrastructure.
About half of all PTPs are in the energy sector, but their importance
far exceeds their numbers, for these PTPs represent two-thirds of PTPs'
market capital and close to three-quarters of assets owned by PTPs.
However, they are prevented from fully realizing their capital
formation potential by a provision--or more specifically, an omission--
in the tax code.
Although PTPs, as a liquid security providing a steady
income stream, should be an excellent investment for mutual
funds, they are not able to access capital from this source
because they are not on the tax code's list of qualifying
income sources for mutual funds. The reason they are not on the
list is that PTPs did not exist at the time that the mutual
fund provisions, including the qualifying income list, were
placed in the Code. This means that a mutual fund whose gross
income from PTPs and other ``nonqualifying'' sources exceeds
10% of its total gross income will lose its regulated
investment company status under the tax code. Faced with this
Draconian possibility and the burden of tracking income
percentage, mutual fund managers turn away from PTPs. With only
the retail market available to them, PTPs find that raising
capital for building energy infrastructure is far more
difficult and costly than it should be.
The Publicly Traded Partnership Equity Act (H.R. 1463),
sponsored by Rep. Wally Herger and a bipartisan group of
cosponsors \1\ would rectify this omission by adding income
derived from PTPs to the qualifying income list for mutual
funds. This change in the tax law would:
\1\ Reps. Crane, Houghton, Ramstad, Foley, English, Matsui, Neal,
and McKeon are original cosponsors; Reps. Hayworth and Cooksey have
also signed on.
Increase the flow of capital into the energy
industry and fund investments in energy infrastructure which
supports the U.S. economy as a whole.
Help lower energy prices for consumers by reducing
the cost of capital to energy companies.
Benefit current PTP unitholders through the
increase in value of their units resulting from increased
activity in PTP units and greater interest in PTPs by Wall
Street analysts and bankers.
Provide an opportunity for the millions of
individuals who invest in mutual funds to participate in an
investment that offers very attractive returns.
Eliminate the artificial constraints of the tax
code and place decisions on mutual fund investment in PTPs
where they belong--with mutual fund managers
For these reasons, we believe that the provisions of H.R.
1463 should be part of any energy-related tax bill considered
by this Subcommittee and by the Ways and Means Committee as a
It is appropriate to consider PTPs in the context of an
energy bill, because they began as a way for the energy
industry to raise additional capital. The energy industry, like
the real estate industry, had always used partnerships as a
means of raising equity capital, because partnerships allowed
investors more direct participation than the corporate form,
not only in the earnings of the business but also in the
considerable benefits that the tax code confers on these
The nature of partnership investment in the time before
PTPs, however, meant that this form of equity could be raised
only from investors in the upper-income tiers, often those
seeking a tax shelter. To become a limited partner, it was
necessary to invest a very large amount of money--$10,000 to
$20,000 at a minimum. Once an investor was in a partnership, it
was very hard to get out before the partnership was liquidated,
which typically did not occur for a number of years. Many
partnership deals did not receive the tough SEC scrutiny that
protects investors in publicly traded securities. Thus, limited
partnerships appealed only to investors with considerable
disposable income and either a high tolerance for risk or a
desire to minimize tax liability.
The PTP was the vehicle for addressing these disadvantages
of partnerships. Partnership interests were divided into units
which were sold at affordable prices and traded on public stock
exchanges, providing liquidity for investors who were wary of
the long-term required by nontraded partnerships. With public
trading of units came the full panoply of regulation that the
SEC requires for publicly traded entities--securities
registration, proxy statements, 10-K reports, and the like.
This allowed energy companies to market partnerships for the
first time to middle class investors who were seeking not a tax
shelter but an investment that would provide them with a steady
cash flow and potential for growth.
The first PTP, an oil company formed in 1981, was Apache
Oil Company. Apache was followed by a number of others, as both
energy and real estate companies discovered the advantages of
this new means of capital formation. PTPs were formed in a
number of other industries as well.
In 1987, Congress enacted section 7704 of the tax code,
which defined PTPs eligible for partnership tax treatment as
those earning their income from natural resource activities,
interest, dividends, real estate rents and capital gains, and
commodities income. While the growth of new PTPs in other areas
has diminished since 1987, PTPs continue to be an important
feature of the energy industry, with each year bringing both
new partnerships and new equity issues by existing
Publicly Traded Partnerships Today
There are currently about fifty PTPs trading on the New York,
American, and NASDAQ exchanges, with another in registration. Based on
their year 2000 10-Ks, the total market capital of all PTPs is about
$19 billion, total assets about $32 billion, and total annual revenue
about $39 billion.
About half of these PTPs are in the energy business. For the most
part, these are not the old oil and gas partnerships of the eighties,
but partnerships which are actively engaged in building and operating
the infrastructure that gathers oil and natural gas from underground
and offshore sites, processes it into liquified natural gas and
petroleum products, stores crude oil, natural gas, and refined products
in bulk terminals, and transports them via pipeline and truck to
communities throughout the United States. A number of PTPs also deliver
propane to industrial and rural customers throughout the United States.
In addition, one PTP is involved in coal mining and marketing.
Operating through PTPs works well for these companies because of
the good fit between the nature of their businesses and the nature of
partnerships. In a partnership, it is particularly important that
investors receive regular and substantial cash distributions because of
the fact that it is the partners who pay income tax on the partnership
earnings. An investment that requires an investor to pay tax on income
he doesn't receive (his allocated share of partnership income) will not
do well in the market unless it pays out cash to the investor that
comfortably exceeds that tax; therefore, a partnership must own assets
that generate a reliable income stream. The energy companies that
operate through PTPs meet this test by using the capital raised by
issuing equity units to acquire or build assets such as pipelines that
will then generate income for several years without much additional
While they constitute about half of the number of PTPs on the
market, the energy PTPs overwhelmingly dominate the PTP universe by
just about every other measure. They represent about two-thirds of PTP
market capital, close to three-fourths of the assets held by PTPs, and
nine-tenths of the total income earned by PTPs.
SUMMARY OF PTP FINANCIAL INFORMATION REPORTED ON FY 2000 10-Ks
[$millions, except numbers of PTPs]
Number Total Percsent Perscent Percent
of market of all Total of all Total of all
PTPs value PTPs assets PTPs income PTPs
Energy production, refining, 23 $11,929.8 64.2 $22,579.8 71.0 $35,116.9 89.7
Minerals and timber................ 5 349.3 1.9 1,850.1 5.8 1,563.4 4.0
All natural resources............ 28 12,279.1 66.1 24,429.9 76.8 36,680.4 93.7
Income properties and homebuilders. 8 1,278.5 6.9 3,113.0 9.8 1,010.6 2.6
Mortgage securities................ 7 727.8 3.9 1,528.6 4.8 160.6 0.4
All real estate.................. 15 2,006.2 10.8 4,641.6 14.6 1,171.1 3.0
June 18, 2001 miscellaneous............ 8 4,300.1 23.1 2,741.1 8.6 1,306.7 3.3
All PTPs......................... 51 18,585.5 100.0 31,812.6 100.0 39,158.2 100.0
Numbers may not add to totals due to rounding.
The information in this table was drawn from the Coalition's
compilation of 10-K filings for 2000. It does not capture a snapshot of
PTP market capital at a fixed point in time, both because 10-Ks usually
report market capitalization at the time the report is filed rather
than as of the end of the fiscal year, and because some PTPs have
fiscal years other than the calendar year and thus filed some months
earlier than the others.
However, A.G. Edwards & Co., an active underwriter of energy PTP
offerings and the source of several analyses of PTPs operating in the
midstream and pipeline energy sectors, recently compiled such a
snapshot. They found that as of May 29, 2001, the total combined market
capitalization of PTPs is $27.1 billion. The increase relative to the
figures in the table is largely due to several offerings that occurred
early in 2001, two of which were IPOs and the rest equity offerings by
existing PTPs, all in the energy field. Other A.G. Edwards findings
The top 10 PTPs, all in the energy field, currently
represent 68% of total market capitalization in PTPs.
The 12 midstream energy/pipeline PTPs listed on the New
York Stock Exchange:
Have enterprise values (market equity plus debt)
ranging from $6 billion to $461 million and a combined
enterprise value of $22.5 billion.
Have combined revenue of over $20 billion.
Have a current yield ranging from 5.5% to 10.3%, and
an average yield of 7.2%.
For the ten that were trading last year (two are 2001
IPOs), the annual growth in distributions ranged from 1.4% to
16.4%, with an average of 5.4%.
The Coalition compilation shows that the annual distributions for
these PTPs during calendar year 2000 ranged from $1.84 to $3.50 per
unit, with an average of $2.48 (the average for all energy PTPs was
$2.00, and for all PTPs was $1.66). For more detail, see Exhibit 1
following this testimony.
These energy partnerships have a substantial presence in energy
producing states. In Louisiana, for example, energy PTPs own $1.6
billion in assets or property, plant, and equipment located in the
state; employ 1,474 residents; and have an annual in-state payroll of
$88 million--and this does not count the three propane PTPs with
operations in that state. Louisiana residents own 3.9 million units in
these PTPs, valued at $160 million.
Similarly, in Texas energy PTPs own $3.6 billion in assets or
property, plant, and equipment located in the state; employ 2,787
residents, and have an annual in-state payroll of $178 million--again
not counting the three propane PTPs, as well as one natural gas
producer and one crude oil gatherer. Texas residents own units in
thesePTPs valued at $6.9 billion.
A list of the PTPs operating in the state of each Subcommittee
member can be found in Exhibit 2 accompanying this testimony.
The Issue: Lack of Mutual Fund Ownership
At this point you may be asking yourself where the catch is in this
rosy picture. The catch is this: these PTPs could be raising
substantially more capital, acquiring more assets, building more energy
infrastructure, transporting more energy products to the places where
they are so urgently needed, than they are at this time. The reason
that they have not done so is that they are currently operating with
one hand tied behind their backs: they are raising capital with
virtually no access to institutional investors. The reasons for this
can be found in the tax code. One reason is the unrelated business
income tax (UBIT) rules applying to tax-exempt investors such as
pension funds. The second, and the one we are asking you to address at
this time, is the regulated investment company (RIC) rules, which
govern mutual funds.
PTPs don't have access to mutual funds because they didn't exist
when the mutual fund rules were written. Mutual funds were created to
provide individuals with a convenient affordable means of owning a
varied portfolio of securities that they would otherwise buy themselves
on the market. Thus, the income that a mutual fund could earn and pass
through to its investors was limited to that derived from the
securities on the market at the time: interest, dividends, payments
with respect to securities loans, gains from the sale of securities and
foreign currency, etc.
The rule that was written into the Code was that this sort of
income must constitute 90% of the mutual fund's gross income in order
for the mutual fund to qualify as a RIC with passthrough tax status.
Partnership income--be it the partnership income allocated to the
investor on which the investor pays tax or the cash distribution paid
to the partner--is nowhere on the list because, as discussed in the
previous section, traditional nontraded partnerships were not the sort
of safe, liquid, common securities investment for which mutual funds
PTPs, however, are exactly that sort of investment. Liquid,
affordable, and completely SEC regulated, providing a steady stream of
income for distribution to mutual fund investors, they are as worthy of
qualification under the RIC rules as any other public security.
In other words, PTPs are living under an archaic rule that was
written before they existed with a completely different type of
partnership in mind. It is long past time for this section of the tax
code to be brought into the 21st century.
What is the effect of this rule on PTPs? Quite simply, mutual funds
rarely buy their units. If gross income from the PTP, along with any
other ``nonqualifying'' sources exceeds 10% of the fund's total, the
mutual fund will lose its RIC status. This is not a risk that most
mutual fund managers want to take. Moreover, they do not want to assume
the burden of tracking income percentages to make sure they do not go
over the line when they can avoid the whole problem by sticking to
stocks and bonds.
As a result, only about 10% of PTP common units examined by A.G.
Edwards were owned by institutional investors (exempt organizations and
mutual funds), while 55% of the common shares of midstream energy
corporations were held by institutions. And this is in a market where
mutual funds now account for an estimated 80% share of all equity
offerings, where 20% of all market equity is held by mutual funds, and
mutual funds have almost $7 trillion in assets under management.
In practical terms, this means that when existing PTPs want to
issue equity, or energy businesses want to create new PTPs, in order to
finance their plans for acquisition of new assets, broadening their
infrastructure, and more efficiently meeting the country's energy
needs, they can do so only to the extent that individual investors
arewilling and able to buy them. As a result, PTP managers wishing to
raise a certain amount of capital must do it in several smaller
offerings instead of one large one, increasing the cost of capital, or
must assume more debt than they would prefer. They must even check to
be sure that none of the other PTPs are planning an offering that is
near in time to theirs, because the retail market can only absorb so
many PTP units at a time. Needless to say, this hampers, delays, and
increases the cost of every major project or acquisition that these
companies wish to undertake.
There is no reason for PTP managers to be limited in this way when
there is such a need for the energy infrastructure that they could be
financing. The Publicly Traded Partnership Equity Act (H.R. 1463) would
put an end to this restrictive situation and modernize this bit of the
tax code by simply adding income derived from PTPs to the qualifying
income list in the RIC rules. H.R. 1463, which has been sponsored in
past years by Chairman Thomas, has been introduced this year by Rep.
Wally Herger and a bipartisan group of cosponsors. It has been approved
by Congress already, as part of the Taxpayer Refund and Relief Act of
1999, which was vetoed by President Clinton.
Enactment of the Publicly Traded Partnership Equity Act would:
Increase the flow of capital into the energy industry and
fund investments in energy infrastructure which supports the U.S.
economy as a whole.
Help lower energy prices for consumer by reducing the cost
of capital to energy companies.
Benefit current PTP unitholders through the increase in
value of their units resulting from increased activity in PTP units and
greater interest in PTPs by Wall Street analysts and bankers.
Provide an opportunity for the millions of individuals who
invest in mutual funds to participate in an investment that offers very
Eliminate the artificial constraints of the tax code and
place decisions on mutual fund investment in PTPs where they belong--
with mutual fund managers.
If this Subcommittee and the Ways and Means Committee as a whole
decide that this is an appropriate time to enact tax measures to help
address the energy situation, we urge that this provision be included.
It is simple, it is noncontroversial, it is low-cost (the Joint Tax
Committee estimated its cost as only $170 million over ten years in the
1999 bill), and it does not require any government intervention in the
energy industry or the capital markets. It simply gives PTPs the
freedom to do more of what they have been doing so well all along--
raising capital to build the infrastructure to process, store, and
transport the energy products that are critically needed to meet our
nation's energy requirements.
FEATURES OF 12 MIDSTREAM ENERGY/PIPELINE PUBLICLY TRADED PARTNERSHIPS AS OF MAY 29, 2001
Enterprise 2000 Current distribution 2000
value Revenue yield growth distributions
Buckeye Partners, L.P............................ $1,323.0 $299.0 6.4 5.8 $2.40
El Paso Energy Partners, L.P..................... 1,631.0 112.2 6.6 1.7 2.15
Enterprise Products Partners, L.P................ 3,672.0 3,049.0 5.5 9.3 2.05
EOTT Energy Partners............................. 754.0 8,340.0 10.3 1.7 1.90
Kaneb Pipe Line Partners......................... 856.0 156.3 7.4 3.1 2.80
Kinder Morgan Energy Partners, L.P............... 6,036.0 816.6 5.9 16.4 3.43
Lakehead Pipeline Partners....................... 2,095.0 305.6 7.7 4.6 3.50
Northern Border Partners, L.P.................... 2,455.0 339.7 7.6 3.5 2.70
Plains All American Pipeline L.P................. 1,186.0 4,102.0 7.3 1.4 1.84
Shamrock Logistics, L.P.......................... 631.0 92.0 7.9 N/A N/A
TEPPCO Partners, L.P............................. 1,417.0 3,087.9 7.2 6.2 2.00
Williams Energy Partners, L.P.................... 461.0 71.5 6.6 N/A N/A
Total (value & Revenue)/Average (Others)... 22,517.0 20,771.9 7.2 5.4 2.48
Sources: A.G. Edwards & Co., Coalition of Publicly Traded Partnerships.
PUBLICLY TRADED PARTNERSHIPS OPERATING IN SUBCOMMITTEE MEMBERS' STATES
Energy Boston Celtics, L.P.
Amerigas Partners, L.P. New England Realty Associates, L.P.
El Paso Energy Partners
Enterprise Products Partners
EOTT Energy Partners
Ferrellgas Partners, L.P.
Genesis Energy, L.P.
Kaneb Pipe Line Partners
Kinder Morgan Energy Partners
Plains All American Pipeline
Suburban Propane Partners, L.P.
ITEPPCO Partners, L.P.
NEW YORK Other
Energy FFP Partners, L.P.
Buckeye Partners, L.P.
Cornerstone Propane Partners, L.P.
Heritage Propane Partners, L.P.
Lakehead Pipe Line Partners
Star Gas Partners
Energy Alliance Capital Management
Amerigas Partners, L.P. American Real Estate Partners, L.P.
Cornerstone Propane Partners, L.P. W.P. Carey & Co., LLP
Ferrellgas Partners, L.P.
Heritage Propane Partners, L.P.
Kaneb Pipe Line Partners
Kinder Morgan Energy Partners
Energy Crown Pacific Partners, L.P.
Amerigas Partners, L.P.
Dorchester Hugoton, Ltd.
El Paso Energy Partners
Enterprise Products Partners
EOTT Energy Partners
Ferrellgas Partners, L.P.
Genesis Energy, L.P.
Heritage Propane Partners, L.P.
Kaneb Pipe Line Partners
Kinder Morgan Energy Partners
Plains All American Pipeline
Pride Companies, L.P.
Shamrock Logistics, L.P.
Suburban Propane Partners, L.P.
TEPPCO Partners, L.P.
Williams Energy Partners, L.P.
Energy FFP Partners, L.P.
Alliance Resource Partners, L.P. Hallwood Realty Partners
Buckeye Partners, L.P.
Ferrellgas Partners, L.P.
Kinder Morgan Energy Partners
Lakehead Pipe Line Partners
Northern Border Partners, L.P.
Plains All American Pipeline
TC Partners, L.P.
TEPPCO Partners, L.P.
Energy FFP Partners, L.P.
Cornerstone Propane Partners, L.P. Heartland Partners, L.P.
Heritage Propane Partners, L.P.
Northern Border Partners, L.P.
Williams Energy Partners, L.P.
Energy FFP Partners, L.P.
Alliance Resource Partners
Cornerstone Propane Partners
Heritage Propane Partners, L.P.
Kinder Morgan Energy Partners, L.P.
Star Gas Partners, L.P.
Energy FFP Partners, L.P.
Kaneb Pipe Line Partners
Lakehead Pipe Line Partners
Buckeye Partners, L.P.
Cornerstone Propane Partners, L.P.
Heritage Propane Partners, L.P.
Star Gas Partners
Statement of the Methanol Institute, Rosslyn, Virginia
This testimony is presented on behalf of the Methanol Institute
(``MI''), the national trade association for the U.S. methanol
industry. As the voice of the methanol industry, MI has been a leader
in supporting essential research and promoting the use of methanol in
zero-emission fuel cell vehicles.
The Methanol Institute is pleased to endorse H.R. 1864 and S. 760,
the Clean Efficient Automobiles Resulting from Advanced Car
Technologies Act of 2001 (``the CLEAR Act''), legislation introduced
this year by Congressman Dave Camp (R-Michigan) and Senator Orrin Hatch
(R-Utah). The CLEAR Act would help level the playing field between the
cost of advanced technology vehicles and conventional vehicles by
providing tax credits to consumers who purchase hybrid electric, fuel
cell, battery electric, and dedicated alternative fuel vehicles. In
addition, the bill would provide incentives for the development of an
alternative fuels infrastructure. The bill places a limit on the
duration of the tax credits, time enough to allow production numbers to
increase to the point that the new technology vehicles become price
competitive with conventional vehicles.
Among the primary benefits of this legislation are more energy
independence and cleaner air. Transportation in the United States
accounts for two-thirds of our oil consumption, and 97 percent of our
transportation needs depend on foreign oil. If we are going to reduce
our dependence on foreign oil and cut pollution, we must focus on
conserving and diversifying our transportation fuels. By promoting the
use of alternative fuels and the purchase of advanced car technologies,
the CLEAR Act would play a key role in our nation's energy security.
Every alternative fuel or advanced technology car, truck, or bus on the
road will displace a conventional vehicle's lifetime of emissions and
need for imported oil. The use of dedicated alternative fuel vehicles,
methanol and other fuel cell electric vehicles, battery electric
vehicles and hybrids will have the added benefit of reducing greenhouse
gases while providing consumers with increased choices.
The need to encourage the use of alternative technology vehicles
has never been greater. Americans now drive more than 2.5 trillion
miles annually and the collective odometer keeps rising. In 1998, 121
regions in our country failed to attain the Environmental Protection
Agency's National Ambient Air Quality Standards. This status directly
threatens the quality of life of more than 100 million of our citizens
who must bear the health and economic burdens associated with non-
attainment. With important programs such a California's Zero-Emission
Vehicle mandate set for launch in 2003, consumers need to know that the
government is interested in helping them reduce air pollution in their
communities. The CLEAR Act will reduce the incremental costs to
consumers to purchase cleaner vehicle technologies and help them become
a part of the solution.
Historically, consumers have faced three basic obstacles to
accepting the use of alternative fuels and advanced technologies. These
are the cost of the vehicles, the cost of alternative fuels and the
lack of infrastructure of alternative fueling stations. The CLEAR Act
would lower all three of these barriers.
Specifically, the CLEAR Act would provide a tax credit of 50 cents
per gasoline gallon equivalent for the purchase of alternative fuel,
including methanol, at fuel stations. To ensure that consumers have
better access to alternative fuel, the CLEAR Act extends until 2008 the
existing $100,000 deduction for the capital costs of installing
alternative fueling stations. The bill also provides a 50 percent
credit for the installation costs of retail and residential fueling
property, up to $30,000 and $1,000, respectively.
Furthermore, the CLEAR Act provides tax credits to consumers to
purchase alternative fuel and advanced technology vehicles. The
duration of the tax credits are limited to six years for qualified
alternative fuel motor vehicles and ten years for fuel cell motor
vehicles. To ensure that the tax benefit provided translates into a
corresponding benefit to the environment, the fuel cell vehicle tax
credit is split into two parts. First, a base tax credit of $4,000 is
provided for the purchase of qualified fuel cell vehicles which may use
any fuel, including methanol. A bonus credit of up to $4,000 is then
provided based on the vehicle's fuel efficiency. In this way, the CLEAR
Act provides the greatest impact in terms of providing a social benefit
to our citizens.
The CLEAR Act is supported by a broad and diverse coalition
including the alternative fuels industry, environmental groups, and
automobile manufacturers. President Bush's National Energy Plan also
endorses the concepts of the proposal.
The Methanol Institute believes that a comprehensive national
energy strategy would not be complete without an incentive that
promotes the use of alternative fuels and advanced car technologies.
Accordingly, MI urges the Committee to give favorable consideration to
the CLEAR Act as Congress continues to develop a comprehensive national
Statement of the Natural Gas Vehicle Coalition, Arlington, Virginia
This testimony is presented on behalf of the Natural Gas Vehicle
Coalition the national trade association dedicated to promoting new
markets for natural gas vehicles. As the voice of the natural gas
vehicle industry we are pleased to endorse H.R. 1864 the Clean
Efficient Automobiles Resulting from Advanced Car Technologies, CLEAR
ACT, of 2001.
It is vitally important to increase the use of non-petroleum
alternative motor fuels and advanced vehicle technologies, such as
hybrid and fuel cell vehicles. Now is the time to take action. Today,
there are more alternative fuel vehicle models in operation and
available than ever before. Despite recent unique events, domestic
natural gas and other alternative motor fuels are readily available.
And state and local governments across the country are adopting
However, despite all this, consumers continue to be hesitant to buy
these vehicles because of the additional costs involved and in the case
of alternative fuel vehicles, the lack of a fueling infrastructure.
Congress can help by providing incentives that will reduce incremental
costs and that spur alternative fuel infrastructure development.
Fortunately both of these can be addressed by the prompt enactment of
the CLEAR ACT that was introduced earlier this year by a number of
distinguished members of this Committee, including Congressmen Dave
Camp, Jim Ramstad, and Congresswoman Jennifer Dunn, and in the U.S.
Senate by Senators Orrin Hatch, Jay Rockefeller, Jim Jeffords, John
Kerry and Olympia Snowe. In addition, President Bush's National Energy
Plan also endorses the concept of providing tax incentives to spur
consumer acceptance of vehicles that reduce the use of foreign oil.
While we have made progress, much more has to be done at the
national level if we are to significantly reduce this country's
reliance on imported oil, improve our air quality and develop a
sustainable transportation future. A sustainable transportation future
is important to this country for two very important reasons. First,
alternative fuel and other advanced technology vehicles help reduce our
dependence on foreign oil. The US imports significantly more petroleum
today than it did in 1992 when the Energy Policy Act was enacted. The
recent oil curtailment by OPEC members demonstrates the serious
consequences of even small disruptions in world oil supply. In 2000
alone, US consumers have spent almost $56 billion more on motor fuels
than they did in 1999 because of OPEC's actions. Prices have remained
high and the bill to American consumers and businesses for higher fuel
prices will exceed the cost for last year. This is roughly 5 to 8 times
as much revenue in one year as might be lost to the Treasury over the
ten-year life of the CLEAR ACT. The only way to break free of our
reliance on petroleum fuels is to increase the use of non-petroleum
alternative fuels and improve the efficiency of gasoline and diesel
The second way America benefits from increased use of alternative
fuel, hybrid and fuel cell vehicles is the environment. Compared to
comparable gasoline vehicles, alternative fuel, hybrid and fuel cell
vehicles produce far less carbon monoxide, volatile organic compounds
and nitrogen oxides. In addition, these vehicles produce significantly
less greenhouse gases. For example, the Honda Civic GX, which is
produced in Ohio, has the cleanest internal combustion engine in
production today. A gasoline vehicle certified to just the minimum
current federal standards emits nearly 194 times more pollution than
the dedicated natural gas Honda Civic GX.
To ensure these energy security and environmental benefits, the
CLEAR ACT breaks new ground in legislation that has the support of a
major portion of the auto industry. The amount of the credit for hybrid
and fuel cell vehicles is tied directly to their fuel efficiency. While
there is a base level of credit for the technology, increases in the
amount of the credit are based on how much improvement in fuel economy
For alternative fuel vehicles, there also is a base credit for
vehicles that only can operate on alternative fuels. This credit can be
increased if the vehicles meet the most stringent standards available
for certification, standards that will not go into effect for many
years to come. The performance-based approach of this legislation has
earned it the support of many in the environmental community. We can
think of no similar legislation that has the broad support the CLEAR
Today, automobile and engine manufacturers have available more
makes and models of alternative fuel and hybrid vehicles than ever.
Soon, we will see the fuel cell vehicles. But, we are not there yet.
Demand for these vehicles must increase further if manufacturers are to
benefit from the economies of scale that come from mass production. To
give you just one example, Ford Motor Company manufactured over 100,000
Crown Victoria sedans last year. Of that total, only 1,000 were
dedicated natural gas Crown Victorias. If production of natural gas or
other alternative fuel models can reach critical mass, their cost will
come down dramatically and that's why HR 1864 needs Congressional
action this year.
The Natural Gas Vehicle Coalition is committed to working with the
Committee and provides its most enthusiastic support. We urge the
Committee to give favorable consideration to the CLEAR ACT and hope
that there is an opportunity to move this legislation this year.
Statement of David B. Goldstein, Ph.D., Energy Program Co-Director,
Natural Resources Defense Council, San Francisco, California
Mr. Chairman and Members of the Committee:
My name is David B. Goldstein and I am the Co-Director of the
Energy Program for the Natural Resources Defense Council, a national
environmental organization with over 500,000 members nationwide. I wish
to thank you, Mr. Chairman, and members of the Committee, for convening
this hearing on the role of energy efficiency and new technology in a
national energy policy and for inviting me to speak.
Energy efficiency is a critical piece of any national energy
strategy because of the impacts that energy use has on two things that
everyone cares about: the environment and their pocketbooks. Energy use
accounts for the overwhelming bulk of air pollution problems--problems
that are linked to over 60,000 excess deaths per year due to direct
causes such as cardiopulmonary disease and is the main cause of global
warming. Energy production also contributes to water pollution and loss
of environmental values such as wildlife protection and recreation.
Energy also costs a lot of money, as virtually all consumers and
businesses have become aware over the past year. Even before the recent
jumps in energy price, our nation's energy bill exceeded half a
trillion dollars a year \1\--or 6% of the gross domestic product (GDP).
This is much higher than is the case in other industrialized countries,
so energy is a competitive drag on the U.S. economy, in addition to
harming household budgets and reducing the bottom line of energy-
\1\ Energy Information Administration's ``Energy Overview'' data
for 1997 show $567 billion spent nationwide for energy, while GDP was
about $8.5 billion.
NRDC believes, and we hope members of the committee agree, that the
primary purpose of a national energy policy should be to minimize the
costs of energy services--both direct costs to consumers and costs to
the environment--while providing reliably for the energy service needs
of the growing economy.
Energy services deliver consumers warm buildings in the winter,
good lighting in buildings, access to where people want to go in a
comfortable manner, and production of consumer and industrial goods.
The sole purpose of energy use is to provide energy services--no one
enjoys energy use for its own sake.
Energy efficiency means providing the same or better energy
services for less energy consumption and cost. Optimum levels of energy
efficiency maximize the well being of consumers and businesses. In
theory, the market encourages everyone to optimize energy efficiency.
But in practice, an overwhelming array of market failures and market
barriers has prevented the economically attractive level of energy
efficiency from occurring naturally: after nearly 30 years of analysis
of all sectors in the economy, there is overwhelming evidence that
policy intervention is needed to optimize energy use.
How far can we go with energy efficiency? Prior to 1973, energy use
was growing in parallel with economic output (GDP). Many analysts
predicted that this trend would inevitably persist in the future, and
numerous forecasts of future energy needs were made based on this
premise. In fact, due to energy policy activities at the state,
regional, and federal levels, and with some small boost from energy
price spikes, energy use per unit of economic output began to decrease
after 1973, and is now 42% lower than it was at the first energy
crisis. About one half to three quarters of this decline is
attributable to energy efficiency improvements.\2\
\2\ The American Council for an Energy Efficient Economy, Fact
Sheet on Energy Efficiency Progress and Potential, 2001, estimates that
three quarters of the improvement came from energy efficiency. The
``National Energy Policy'' report of Vice President Cheney claims that
one half to two thirds of the improvement resulted from energy
These large improvements in energy efficiency occurred in the face
of inconsistent policy attention. During part of the last 30 years,
federal policy did little to facilitate energy efficiency improvements.
It therefore isn't surprising that additional improvements in energy
efficiency beyond the national average occurred at the state level
where strong policy efforts were expended. In California, electricity
intensity, which was already 28% below the national average in 1975,
had declined further to 46% below by 1998.\3\ If this had not occurred,
California's power shortages of the past two summers would have been
far worse. But even in California, numerous opportunities to enhance
energy efficiency were missed. Indeed, policy-driven funding for
utility-sponsored efficiency programs caused some 1,000 megawatts (MW)
of shortfall in the summer of 2000.
\3\ Source: A.H. Rosenfeld. Testimony Before California State
Committee on Environmental Quality.
One of the best examples of how innovative policies have reduced
demand for energy is refrigerators. In the mid-1970's, the refrigerator
was the largest single user of electricity in the home, and aggregate
use of electricity for home refrigerators was growing at an annual rate
If this growth rate had continued up to the present, as DOE and
most utilities and their state regulators predicted at the time, peak
demand by refrigerators today would be about 150,000 MW. That's about
one fourth of today's electric capacity for the nation.
Instead, as a result of state and federal energy policies,
including research and development, economic incentives, and six
iterations of efficiency standards, the actual level of peak demand
will be about 15,000 MW when the refrigerator stock turns over. The
difference between actual demand and forecast exceeds the capacity of
all U.S. nuclear power. Figure 1 shows the trend of growth and then
decline in energy use per refrigerator after World War II.\4\
\4\ Exponential extrapolation of past trends was not an unrealistic
assumption from either of two perspectives. First, in the mid-1970's,
when the turnaround from growth to decline in energy consumption for
refrigerators began, virtually every utility in the country, backed by
their regulatory agencies and Department of Energy forecasters, was
assuming that overall residential electricity use would continue to
grow at about the same 9.5% rate as it had grown during the prior
decades. The total growth in electricity consumption for refrigerators,
considering increasing sales of the product, was also about 9.5%.
Suggesting that this rate would come down in the future, as the author
did, was highly controversial. Second, of the 6.1% annual growth in
energy consumption per refrigerator, one-third of the increase was due
to decreases in efficiency, apparently from cost-cutting, rather than
from growth in size or features as shown in Figure 1 (both of which
have tended to plateau since the 1970s).
[GRAPHIC] [TIFF OMITTED] T4229A.001
The most effective federal policies that have been implemented to
improve energy efficiency are:
Efficiency standards for major users of energy, such as
buildings, appliances, equipment, and automobiles.
Targeted incentives for more efficient technologies based
on performance. These incentives have been administered primarily by
utilities, although the state of Oregon has run a successful tax
incentive program as well.
Education and outreach on energy efficiency, although
educational programs have worked best when performed in the context of
financial incentive programs.
But these policies alone will not allow the nation to reach the
goal of minimizing the cost of energy services. Standards provide a
floor for energy efficiency--they require manufacturers to use
efficiency technologies that are well known and well understood and
therefore can be employed by everyone. Incentive programs can encourage
more significant improvements in energy efficiency, but they typically
have been limited by the range of technologies that are already
available on the marketplace. New innovative ideas that are hard for
consumers to find or that have yet to be introduced by manufacturers
cannot easily be acquired by incentives established on a state-by-state
or regional level.
Advanced levels of energy efficiency can only be achieved by making
it worthwhile for manufacturers, vendors, retailers, and consumers all
to benefit from the introduction of a new technology.
That's why incentives to transform markets so that they deliver
advanced new energy efficiency technologies are so critical to a
comprehensive national energy policy. These types of incentives,
provided through the tax system, offer a key missing piece of the
solution to the problem of harnessing American ingenuity to improve
Pending Energy Efficiency Legislation
What follows are several energy efficiency tax incentive bills that
NRDC supports, and which would help promote a responsible energy
strategy. This list is not exhaustive.
H.R. 778 provides tax incentives for energy efficiency in buildings
and H.R. 1316 provides tax credits for energy efficiency appliances.
Buildings are an often-overlooked source of energy waste. They consume
over a third of U.S. energy use and account for about a third of total
air pollution in the United States--almost twice as much as cars.
Energy use in buildings can be cut in half or better using cost-
effective technologies that are available to those consumers that are
willing to look hard.
But in practice most of those technologies simply are not options
for energy users, whether consumers or businesses, because they are too
difficult to find. Economic incentives can cause the entire chain of
production and consumption, from the manufacturer to the contractor or
vendor to the consumer, to accept new technologies rapidly. In the few
cases where utility programs have been consistent enough across the
country and long-lasting enough, new products have been introduced that
have become or will become the most common product in the marketplace,
with reductions in energy use of 30%-60%.
Refrigerators, where, as discussed previously, new
products that are available this year consume less than a quarter of
the energy of their smaller and less feature-laden counterparts 30
years ago. The last step forward, saving 30%, resulted from a
coordinated incentive program, the Super Efficient Refrigerator Program
(SERP), which was sponsored by utilities with the advice of the U.S.
Environmental Protection Agency.
Clothes washers, where some 10% of the market now provides
cleaner clothes at a reduction in energy use of 60% or more. This gain
in efficiency resulted from a program organized by the Consortium for
Energy Efficiency (CEE) and supported by Energy Star. New standards
adopted by the Department of Energy--and supported by the
manufacturers--will bring all of the market to this level by 2007.
Fluorescent lighting systems, where new technologies that
also will be required by manufacturer-supported federal standards, will
reduce lighting energy consumption by 30% compared to mid-70's practice
while improving the performance of the lighting system.
The policies embodied in H.R. 778 and H.R. 1316 are built on
success stories like these.
Manufacturers have pointed out that in order to introduce new
technologies that cost more and that are perceived to be risky, they
need the assurance that the same product can be sold throughout the
country, and that the financial incentives will be available for enough
time to make it worth investing in production. H.R. 778 does this by
providing nationally uniform performance targets for buildings and
equipment that will be eligible for tax incentives for six full years.
H.R. 778 focuses its incentives at the largest energy uses within
both commercial and residential buildings, as well as public buildings.
These incentives focus on reductions in heating, cooling, lighting, and
water heating, by far the largest users of energy. If all new buildings
met the thresholds for qualification for the tax incentives in H.R.
778, the nation could cut energy use and air pollution by 6% over the
next 10 years, equivalent to taking40% of the nation's cars off the
road. The economic benefits of this pollution reduction would exceed
$100 billion. This large benefit to both the environment and the
economy is why the nation's largest public interest environmental
organizations have made passage of H.R. 778 their top priority.
The benefits of H.R. 1316 extend only to refrigerators and water
heaters, so they are proportionately much smaller. On the other hand,
the impact on the Treasury is also smaller.
When the public interest community first began discussions on this
issue over a year ago, we felt that the approach that has been embodied
into these bills was simply good economic and environmental policy: a
government action that could promote economic growth and protect the
environment at the same time. Subsequently, we have seen how these
bills could be the major part of a solution to some very real economic
and environmental problems associated with energy that have emerged
over the past two years.
Let's start with the problem of electric reliability. Not only in
California and the West, but in New Hampshire as well, we are facing
the risk of electrical blackouts and/or excessively high electricity
prices this summer and next. Regions that are confronting these
problems are trying to move forward aggressively both on energy
efficiency programs and on power plant construction. But the lead times
for most actions on the supply side are far too long to provide a
solution. And demand-side approaches attempted on a state-by-state
level are much less effective than coordinated national activities.
Here, H.R. 778 could be a critical piece of a national solution.
Air conditioners, for example, represent about 30% of summertime peak
electric loads. Air conditioners that use a third less power can be
purchased today, but they are not produced in large enough quantities
to make a difference to peak load. If incentives are made available,
manufacturers could begin to mass-produce these products in a matter of
months, not years. Mass production and increased competition for tax
incentives will drive prices sharply lower, so the incentives will be
self-sustaining in the long-term. And with 5 million air conditioners
being sold every year, a sudden increase in energy efficiency could
have a significant effect in balancing electricity supply and demand
even after less than a year.
Another peak power efficiency measure with a very short lead time
is installing energy-efficient lighting systems--either new or
retrofit--in commercial buildings. Some 15% of electrical peak power
results from lighting in commercial buildings. Efficient installations,
such as those NRDC designed and installed in our own four offices, can
cut peak power demand by over two-thirds while improving lighting
quality. Lighting systems are designed and installed with a lead time
of months, so incentives for efficient lightings as provided in H.R.
778 could begin to mitigate electric reliability problems as soon as
The second major new problem is the skyrocketing cost of natural
gas, which caused heating bills throughout the country to increase last
winter. Improved energy efficiency can cut gas use for the major uses--
heating and water heating--by 30%-50%. Much of this potential could be
achieved in the short term, because water heaters need replacement
about every ten years, and are the second largest user of natural gas
in a typical household (and largest gas user in households living in
efficient homes or in warm areas).
Clothes washers also turn over about every 15 years, and efficient
clothes washers save natural gas by reducing the amount of hot water
needed to get clothes clean and reducing the amount of time they must
spend in the dryer.
These types of quick-acting incentives help consumers in two
different ways: first, they provide new choices that are not now
available in practice for families and businesses that want to cut
their own energy costs while obtaining tax relief. But they also help
the non-participants, because reduced demand cuts prices for everyone.
Finally, NRDC supports tax incentives for hybrid vehicles as
embodied in H.R. 1864, the ``Clean Efficient Automobiles Resulting from
Advanced Technologies'' bill. This bill would help save energy through
improved vehicle fuel efficiency. Saving energy through fuel efficiency
is cleaner, cheaper, and faster than increasing petroleum supply. The
CLEAR bill promotes this goal by linking the amount of the tax credit
it offers in part to the actual fuel economy of the qualifying vehicle.
This is a major advance over previous vehicle tax proposals, and NRDC
strongly supports this legislation.
A comprehensive energy policy aimed at minimizing the cost and
environmental impacts of providing energy services for a growing
economy should, we believe, be a consensus goal. While we do not yet
know what the full set of measures that would be contained in a
national energy plan based on least-cost are, and thus do not yet know
the full range of policy measures that would be needed to achieve such
a vision, it is evident that energy efficiency will play a more
important role in the next 30 years, as it has in the past 30 when it
was the nation's largest source of new energy.
We also know that today's energy efficiency policies, relying
primarily on efficiency regulations at the state and federal levels and
on regionally-based economic incentives, are not sufficient to achieve
the least-cost goal. At least one missing piece of the policy mix is
the provision of long-term, nationally-uniform incentives for quantum
leaps forward in technology.
H.R. 778, H.R. 1316, and H.R. 1864 fill this gap for energy uses
exceeding a third of the nation's entire energy consumption, and an
even higher fraction of its energy bill.
[The attachment is being retained in the Committee files.]
Statement of Power Ahead
I. Power Ahead
Power Ahead is a coalition of electricity transmission owners and
transmission equipment manufacturers from across the country. The
coalition is dedicated to promoting the expansion, enhancement, and
reliability of North America's electrical transmission system. Power
Ahead is working to ensure that there is sufficient transmission
capacity to deliver the electricity that America generates to the
regions in which it is needed.
II. The Need for Additional Investments in Transmission Capacity
New investment in transmission capacity has not grown as quickly as
use of the transmission system, and projections for the future indicate
little planned growth in transmission investment. The lack of new
transmission investment threatens to impair the reliability of our
electric power networks and to impede progress toward competition in
electric power markets.
Recent changes in electric markets in which more electric
generators are independent from transmission and distribution companies
require more electric transmission infrastructure to allow multiple
generators access to each market and thereby to increase competition.
While this problem is most apparent in California, transmission
capacity lags behind consumption in all regions of the country, and
many needed transmission facilities in each region have not been built.
Tax and regulatory disincentives are a major reason for under-
investment in transmission. Private companies that build transmission
facilities are subject to federal regulation, and these companies will
only invest if they have reasonable expectations of adequate profits.
An important component of these expectations is the tax treatment of
investments in transmission. While there has been much discussion about
the growth in profits for independent power producers, the situation is
vastly different for transmission owners.
Allowing transmission owners the opportunity to earn higher returns
on their investments can actually reduce consumers' total costs for
power by encouraging investments to expand transmission capacity.
Increased transmission capacity will allow more power generators to
serve power markets, thus increasing competition among generators and
leading to lower rates. Electric transmission costs are a small portion
of the total delivered cost of electricity and are far outweighed by
costs of generation. While creating regional transmission organizations
(``RTOs'') and making other regulatory changes are important for
improving electric markets, only clear, legislatively mandated tax and
regulatory incentives for transmission investment and improved use of
existing capacity will ensure that we have the transmission
infrastructure we need.
Power Ahead advocates measures designed to increase investment in
transmission infrastructure and improve use of existing infrastructure
by enhancing the expected returns from such investments.
III. A Growing Chorus of Voices Identifies Transmission Capacity as Key
to Reliable and Cost-Effective Electric Power
A. In California . . .
``[A]n antiquated and inadequate transmission grid
prevents us from routing electricity over long distances and thereby
avoiding regional blackouts, such as California's.'' National Energy
Policy: Report of the National Energy Policy Development Group, May
``[T]he real solution to California's problems lies in
increased investments in infrastructure . . . the increased reliance of
regions within California and the rest of the West on widely dispersed
resources to provide peak needs over the past several years has
revealed significant needs for transmission expansion and investment.''
FERC, Notice Of Opportunity For Comment On Staff Recommendation On
Prospective Market Monitoring And Mitigation For The California
Wholesale Electric Market, Docket No. EL00-95-012, March 9, 2001.
``We need to not only increase electricity generation by
building new plants in under-served states like California, we need to
also build the transmission facilities that will create a reliable
electrical grid.'' House Majority Whip Tom Delay (R-TX), Testimony
before the House Energy and Commerce Committee, March 6, 2001.
``As a complement to the vital initiative of increasing
generation supply, we focus today on where we believe this Commission
can have the greatest impact--fostering the installation of critical
transmission investment.'' FERC, Order Removing Obstacles To Increased
Electric Generation And Natural Gas Supply In The Western United States
And Requesting Comments On Further Actions To Increase Energy Supply
And Decrease Energy Consumption, Docket No. EL01-47-000, March 14,
B. And Elsewhere . . .
``[The] shortage [in transmission capacity] could lead to
serious transmission congestion and reliability problems. . . . There
is a need to ensure that transmission rates create incentives for
adequate investment in the transmission system. . . .'' National Energy
Policy: Report of the National Energy Policy Development Group, May
``While attention is focused today on California's
blackouts and the harm that soaring natural gas and electric prices
have had on the economies of neighboring states, Abraham said New York
State, too, needs to ratchet up its electric transmission capacity to
handle rising demand.'' Energy Secretary Spencer Abraham, quoted in
Energy Secretary Encourages Investment, AP Online, March 21, 2001.
``Since the start of electric power restructuring in
earnest in the early 1990s the level of new investment in the
transmission sector has lagged behind the growth in consumer
electricity demand.'' PA Consulting Group, The Future of Electric
Transmission in the United States, January 2001.
``[E]lectric grid managers [need] to step up efforts to
add new transmission capacity in the state (Massachusetts) and region
to help curb soaring electric costs.'' Massachusetts Attorney General
Thomas F. Reilly, quoted in Peter J. Howe and Rick Klein, AG Urges
Boost in Power Grid Capacity Says Regional Upgrades of Transmission
Systems Would Curb Electric Rates, The Boston Globe, January 10, 2001.
``Concern about transmission capacity has reached a
fevered pitch in the electric industry in recent months. And in truth,
if the nation's electric transmission network continues as it has,
failing to expand enough to keep pace with growth in demand for
electricity, then within a few years today's problems could become a
crisis.'' Transmission Crisis Looming? Eric Hirst, Separating Hype From
Fact; Hard Numbers and Hopeful Projections on the Adequacy of the
Electric Grid, Public Utilities Fortnightly, September 15, 2000.
In keeping with the focus of this hearing, our testimony focuses on
eliminating tax disincentives to restructuring the electricity
transmission industry and to certain new investments and providing
limited incentives for new transmission investment.
IV. Key Tax Issues for Transmission Under Current Law
The Committee has heard testimony on a number of tax issues
relevant to transmission. What follows are some details regarding two
of the most important issues faced by transmission owners today.
A. FERC Wants to Separate Ownership of Transmission and Generation,
But, Under Current Tax Law, Separation Can Create Huge Tax
FERC's policy has been to encourage the formation of regional
transmission organizations or separate transmission companies
(``transcos'') to separate operating control of transmission and
generation assets. Under current tax law, however, it is very difficult
for vertically integrated providers to separate transmission from
generation without triggering large tax liabilities on the assets they
sell. Thus, even when utilities would like to spin-off or sell their
transmission assets, they are either constrained from doing so or
forced to restructure their assets in ways that lead to other business
One Power Ahead member, an independent transmission owner, had to
be structured as a limited liability company (``LLC'') to avoid current
tax on the separation of generation from transmission that led to its
formation. As a practical matter, the LLC structure discourages growth
through the addition of transmission facilities from other utilities
because it is difficult to acquire transmission assets in exchange for
LLC membership interests. Moreover, the LLC structure makes access to
the equity capital markets cumbersome.
B. The IRS Has Not Modernized Its Administration of Section 118 to
Reflect New Realities in the Power Markets
Section 118(b) requires the inclusion in income of ``contributions
in aid of construction'' (``CIAC'') that are made to encourage
utilities to sell power to a customer. Section 118, however, does not
treat payments made to encourage utilities to purchase power from co-
generation facilities as taxable CIAC. The IRS recognized this crucial
distinction in its Notice 88-129, stating as follows:
``In a CIAC transaction the purpose of the contribution of
property to the utility is to facilitate the sale of power by
the utility to a customer. In contrast, the purpose of the
contribution by a Qualifying Facility to a utility is to permit
the sale of power by the Qualifying Facility to the utility.
Accordingly, the fact that the 1986 amendments to Code section
118(b) render CIAC transactions taxable to the utility does not
require a similar conclusion with respect to transfers from
Qualifying Facilities to utilities.''
Notice 88-129, 1988-2 C.B. 541 (Dec. 12, 1988).
The Notice sets forth six criteria that must be met to report the
transaction as non-taxable under a ``safe harbor'' rule.\1\
Unfortunately, the Notice excludes from its safe harbor provisions many
current transactions that meet the intent of Section 118 merely because
the generation facilities being connected to the grid are not
``qualifying facilities'' (``QFs'') under the Public Utility Regulatory
Policies Act of 1978. (Following the restructuring of the industry,
most generators seeking interconnections to sell power across the grid
are not QFs.) Moreover, although some of the other Notice 88-129
criteria--notably, the requirement that the contract last for at least
ten years--are not practicable in restructured power markets, the IRS
has not updated the Notice to account for the restructuring of the
\1\ The six criteria include that (1) the generator making the
transfer of property is a QF, (2) the transfer is made either
exclusively for the sale of electricity by the QF to the utility grid
or for a dual-use interconnection where 5% or less of the expected
total power flows are sales to the QF; (3) the construction cost is not
included in the utility's rate base; (4) the utility and the QF have
entered into a power purchase contract of ten years or longer; (5) no
disqualifying event (e.g., a violation of the 5% limit in item #2,
above) has occurred; and (6) the utility company does not depreciate or
amortize any interconnection property unless or until it becomes a
taxable CIAC transaction.
Compounding this problem, last year, the IRS stopped issuing
private letter rulings confirming the non-taxable status of
transactions that meet most--but not all--of the Notice 88-129
criteria,\2\ and informal approaches to the IRS National Office have
yielded no guidance regarding current market transactions. As a result,
utilities have felt compelled to pay the CIAC tax on transactions that
clearly meet the Congressional policy of facilitating sales by
customers to the grid solely because the IRS no longer will rule on
\2\ Notably, the IRS used to issue private letter rulings
confirming the non-taxable status of interconnections that were
``analogous'' to QFs. See, e.g., PLR 9648030 (Aug. 29, 1996); PLR
9540016 (June 30, 1995); PLR 9443019 (July 22, 1994); PLR 9420012 (Feb.
15, 1994); PLR 9211030 (Dec. 16, 1991).
Finally, under current law, even if transactions are treated as
nontaxable contributions to capital, that status might not extend to
recipients, such as LLCs, that are not corporations. That nontaxable
status derives from Section 118(a)'s nontaxable treatment of
contributions to the capital of a corporation. Thus, if a non-corporate
entity receives otherwise nontaxable CIAC, the CIAC might not be
considered a contribution to the capital of a corporation and,
accordingly, would be taxable to the non-corporate recipient.
Correction of this disparity in treatment of CIAC by corporate and non-
corporate entities is important for transmission companies as some are
forced to adopt a non-corporate structure for other tax reasons.
Power Ahead proposes that Congress should address the tax
disincentives to transmission investment and provide limited tax
incentives for new transmission investments. Among the items Congress
should consider are the following:
A. Amend Section 1033 to defer tax on sales of transmission facilities
made to facilitate FERC policies on separating generation and
Because FERC's RTO policy makes dispositions of transmission
facilities essentially involuntary, it is appropriate to treat such
sales as involuntary conversions under Section 1033. This would allow
utilities to defer tax on the separation of transmission and generation
assets, provided that the proceeds of such sales are reinvested within
There are precedents for extending such treatment to sales made to
further Federal policy with respect to an industry. For example,
Section 1033(c) provides that sales of acreage made to comply with
limitations in Federal reclamation laws shall be treated as involuntary
conversions. Similarly, Congress allowed the telecommunications
industry a window in which to treat certain spectrum sales as
involuntary conversions when those sales were made to comply with the
FCC's microwave relocation policy. See Section 1033(j). We believe that
FERC's policies regarding restructuring the electric industry raise
similar issues and should be accommodated through tax policy.
Similar provisions are included in H.R. 1459.\3\
\3\ 3. H.R. 1459, the Electric Power Industry Modernization Tax
Act, was introduced by Representative Hayworth on April 4, 2001.
B. Ensure that payments made by generators to utilities to make
necessary interconnections and upgrades are not taxable CIAC to
At a minimum, Congress should clarify the policy behind Section 118
so that the IRS will not tax CIAC transactions that connect new sources
of generation to the grid. This could be accomplished by updating and
codifying the criteria set forth in Notice 88-129 or by directing the
IRS to issue regulations. In addition, Congress should confirm that
this nontaxable treatment extends to both corporate and non-corporate
Similar provisions are included in H.R. 1459 and S. 389.\4\
\4\ S. 389, the National Energy Security Act of 2001, was
introduced by Senator Murkowski on February 26, 2001.
C. A 10% tax credit, modeled on the existing solar/geothermal credit,
for new qualified investments
As part of a balanced energy policy and considering that current
law offers credits as incentives for certain forms of generating
capacity, we believe it is appropriate to offer credits as incentives
for new investments in transmission capacity that will deliver
generated energy where it is needed and enhance competition in the
wholesale electricity market.
D. Seven-year depreciation with language clarifying that such treatment
is not a ``tax preference'' subject to the AMT
Under current law, transmission assets are depreciated over
relatively lengthy periods--20 years in most cases. In an era of rapid
technological change, such lengthy depreciation periods may no longer
be appropriate. Moreover, allowing faster depreciation would improve
the after-tax returns on new investments in transmission capacity and
make such investments more attractive.
Similar provisions are included in H.R. 2108,\5\ S. 389, and S.
\5\ H.R. 2108, the Energy Security and Tax Incentive Policy Act of
2001, was introduced by Representative Matsui on June 7, 2001.
\6\ S. 596, the Energy Security and Tax Incentive Policy Act, was
introduced by Senator Bingaman on March 22, 2001.
E. Clarifying that the R&D tax credit is available for long-term
research and development to improve the efficiency of
As part of an overall look at the research and development tax
credit rules of Section 41, we urge Congress to clarify that the credit
is available for research to improve the efficiency of transmission.
Such research has great potential for expanding the capacity of the
existing transmission grid and should be encouraged as part of a
balanced energy policy.
F. ``Savings clauses'' so that intended tax incentives are not taken
away by public utility commissions in the rate-setting process
Finally, we believe that any tax provision enacted by Congress
should be structured to ensure that the benefits of those provisions
are not taken into account by state public utility commissions in the
rate-setting process. A similar approach was taken by Congress to
ensure that utilities reaped the benefits of accelerated depreciation.
Congress can make a real difference to the Nation's energy
situation by reducing roadblocks to transmission investment. The Power
Ahead proposals can make a difference quickly and spur new investment
in transmission capacity.
APPENDIX: POWER AHEAD MEMBERS
American Transmission Company LLC
Solid Waste Association of North America
Silver Spring, Maryland 20910
June 19, 2001
The Honorable Jim McCrery
Subcommittee on Select Revenue Measures
House Committee on Ways and Means
United States House of Representatives
Washington, DC 20515
Dear Congressman McCrery:
Statement of the Solid Waste Association of North America
to the Subcommittee on Select Revenue Measures
of the House Committee on Ways and Means
for the Record of the
June 13, 2001 Hearing on the Effect of Federal Tax Laws
on the Production, Supply and Conservation of Energy
On behalf of the Solid Waste Association of North America (SWANA),
I appreciate the opportunity to submit this written statement for the
record of the Subcommittee's hearing on current tax incentives and
their role in the nation's energy policy. SWANA would like to commend
you, and the members of your Subcommittee, for holding this timely
hearing in light of the critical efforts of the Bush Administration and
this Congress to develop sound energy policies to allow our nation to
maintain its economic vitality and self-sufficiency. The association
urges the Subcommittee to support HR 1863, which would amend the I.R.C.
Section 45 tax credit so it is available for landfill gas-to-energy
projects. Like the expired I.R.C. Section 29 nonconventional fuel
production credit did, an amended Section 45 can encourage the solid
waste management industry to produce energy as an adjunct to its
handling of the millions of tons of municipal solid waste (MSW)
generated by the country's households and businesses.
SWANA and MSW as a Source of Energy
SWANA, an association of over 6700 solid waste management
professionals, companies and government agencies in the United States
and Canada, has as its mission the advancement of environmentally and
economically sound solid waste management policies and practices. The
association has long recognized that development of energy from
municipal solid waste can be done reliably, while resulting in more
efficient solid waste management, resource recovery, cleaner air
quality, and reduced potential for global climate change. Accordingly,
SWANA has advocated the two types of energy production that are
identified with solid waste management: (i) projects which directly
combust MSW to produce electricity, also known as waste-to-energy (WTE)
projects, and (ii) projects that collect landfill gas, naturally
generated at a landfill as the waste decomposes, and utilize the gas as
a fuel either to produce electricity or to supplement local natural gas
supplies, known as LFG-to-energy projects or simply ``LFG projects.''
Currently, WTE projects and LFG projects provide energy to over 2
million homes and businesses. Both are an energy resource that is
sustainable, diverse, environmentally positive and local and provide a
multitude of benefits that are unique among renewables. WTE and LFG
projects together have the potential to generate a significant portion
of the nation's electricity as further technological innovations are
developed and public appreciation of their benefits grows. SWANA
continues to believe that federal policies should be adopted to
encourage our nation to diversify energy production against risks of an
uncertain future and to continue to develop supplements to fossil fuel
generation. Providing tax incentives for WTE and LFG project
development are clear examples of such federal policies.
Landfill Gas to Energy Projects and the Section 29 Tax Credit
Benefits of LFG Projects
A medium sized landfill can generate more than 300 billion BTUs of
methane gas a year, which, if converted to electricity, could annually
provide 3.0 MWs of capacity, enough to serve the yearly electrical
needs of 3000 households. Projects at larger landfills have generated
as much as 50 MWs of electric power. Typically, LFG-to-electricity
projects are located in urban areas allowing them to serve as
distributed power sources to help improve the reliability of the
region's power grid. The methane gas could also be used directly as a
supplement to natural gas supplies. Existing ``direct gas-use'' LFG
projects are providing the gas for commercial heating, as boiler fuel
at industrial installations, as an alternative fuel for various vehicle
fleets, and, recently, as a hydrogen source for fuel cells. Many of the
``direct gas-use'' LFG projects are dispersed in the urban centers of
our nation and provide a viable back up to local natural gas supplies.
LFG projects provide society with several ``external benefits'' in
addition to the domestic energy supply. Specifically, if not controlled
and flared, LFG can pose a fire hazard, is odorous, impairs local air
quality, and would add, for each ton of methane emitted, an equivalent
of 21 tons of CO2 into the global atmosphere.Consequently,
each of these impacts is eliminated when a LFG project is constructed
Section 29 Tax Credit
The tax credit for the production of nonconventional fuels provided
under Section 29 has been the key impetus for the solid waste
management industry constructing and operating more than 300 LFG
projects around the country. Under Section 29, taxpayers that produce
certain qualifying fuels from nonconventional sources, including ``gas
from biomass,'' are eligible for a tax credit until 2008 (or 2003 if
the project was installed before 1993) equal to $3 per barrel or
barrel-of-oil equivalent (adjusted for inflation) as long as the gas is
sold as a fuel to an unrelated party. The tax credit provided the
incentive to make LFG projects economically feasible. However, since
June 30, 1998, the deadline under Section 29 by which LFG projects must
be ``placed in service'' to qualify for the credit, no new LFG projects
have been planned and constructed.
For reasons unrelated to LFG projects, Congress to date has not
extended the Section 29 tax credit. Unfortunately, without the
continued availability of the Section 29 tax credit, private investors
have been reluctant to undertake development of new LFG projects at
more than 700 additional landfills identified by the Environmental
Protection Agency as producing sufficient volumes of LFG. Consequently,
the nation faces the real loss of a valuable domestic and renewable
energy resource, the recovery of which is simple, proven and has no
negative impact on the environment.
President Bush's National Energy Policy (NEP) recognizes the
contribution that LFG projects can make in addressing the nation's
current energy shortfalls. The NEP specifically recommends that ``the
Secretary of the Treasury. . . work with Congress on legislation to
expand the section 29 tax credit to make it available for new landfill
The Section 45 Tax Credit
Section 45 currently provides a 1.5 cents/kw-hr tax credit for
electricity generated by wind, closed-loop biomass (organic material
from a plant that is planted exclusively for purposes of being used to
generate electricity) or poultry waste. The tax credit is provided for
the first 10 years of production if such electricity is sold to an
unrelated party. In response to Congress' past unwillingness to extend
the Section 29 tax credit, SWANA and the landfill gas industry have
targeted Section 45 as a possible substitute.
Ironically, several pieces of legislation were introduced during
the 105th and 106th Sessions of Congress amending Section 45 to add
additional renewable energy sources as qualified fuels that expressly
excluded MSW and LFG. SWANA strongly believes that any recommendation
to include tax credits for encouraging renewable energy development as
part of our nation's energy policy should ensure that tax incentives
are provided on a ``renewable source neutral'' basis. A free market
government should not pick winners and losers among renewable energy
sources. Accordingly, landfill gas and waste to energy projects should
not be placed at a disadvantage in the energy policy.
Congressman Dave Camp has introduced HR 1863, legislation which
would duplicate the incentive provided by Section 29 by making both
LFG-to-electricity projects and LFG-``direct gas-use'' projects
``qualified facilities'' under Section 45. In the case of these latter
type of projects where the gas is sold for direct use, the 1.5 cents/
kw-hr tax credit is applied to the ``kilowatt-hour equivalents''
contained in the particular volume of gas calculated on a 10,000 BTU
per kilowatt-hour basis. HR 1863 is intended to compliment bills
introduced by other House Members each of who would add a specific
renewable energy resource as a qualified fuel under Section 45. SWANA
urges the Subcommittee to act on these bills and to do so in a
``renewable source neutral'' manner.
The ``renewable source neutral'' approach has been embraced by
Senator Frank Murkowski in his recently introduced S. 389, the National
Energy Security Act of 2001. That bill, among its many other
provisions, contains a provision similar to that contained in HR 1863
providing the Section 45 tax credit to both electricity generating and
``direct gas-use'' LFG projects. S. 389, however, also amends Section
45 by adding other renewables as qualified fuels, including MSW, and
extends the placed-in-service windows for projects generating
electricity from these renewable sources. The Energy Security Tax
Incentive Act of 2001, S. 596, introduced by Senator Jeff Bingaman,
also expands the list of qualified fuels in Section 45 to include
landfill gas and MSW. S. 596, however, only provides the Section 45 tax
credit to LFG-to-electricity projects and not ``direct gas-use''
projects. About one-third of the 300 existing LFG projects and about
one-third of the 700 potentially new LFG projects are ``direct gas-
use'' projects. Accordingly, unless the Section 45 tax credit is
provided to both types of LFG projects, approximately 233 ``direct gas-
use'' LFG projects would not be built for lack of a tax credit and the
nation would lose a valuable fuel source.
The Subcommittee has an opportunity to significantly impact the
development of a new energy policy for the nation. Use of the tax code
to encourage energy-related private investment is justified by the
compelling energy security, economic and environmental concerns facing
our nation currently and in the foreseeable future. Specifically, a tax
incentive for energy production through the combustion of MSW or the
utilization of LFG would allow the nation to not only benefit from
increased domestic energy supplies, but to also realize the many
consequent environmental and resource conservation benefits. SWANA
urges the Subcommittee to support the tax credit provision for LFG
projects contained in HR 1863. An extension of the Section 29 tax
credit for LFG projects is certainly another alternative. In any case,
it is important that a tax credit be available to both LFG projects
producing electricity and LFG projects providing the gas for direct
use. In addition, SWANA urges the Subcommittee to support adding waste-
to-energy projects that combust MSW to generate electricity as
qualified facilities under Section 45. I appreciate very much this
opportunity to present SWANA's views.
John H. Skinner, Ph.D.,
Executive Director and CEO.
cc: All Members of the House Subcommittee on Select Revenue
Statement of the United Technologies Corporation
United Technologies Corporation (UTC) is based in Hartford,
Connecticut and provides a broad range of high-technology products and
support services to the building systems and aerospace industries. Our
products include Carrier air conditioners, Otis elevators and
escalators, Pratt & Whitney jet engines, Sikorsky helicopters, Hamilton
Sundstrand aerospace systems and fuel cells by International Fuel
As the House Ways & Means Committee and its Subcommittee on Select
Revenue Measures consider tax policy initiatives that would encourage
energy efficiency and conservation, UTC would like to recommend several
actions that would accelerate deployment of clean, energy-efficient
technology. UTC supports tax credits for fuel cells in general and
specifically endorses H.R. 1275, introduced by Rep. Nancy Johnson (R-
CT) and Rep. Michael McNulty (D-NY), and its companion measure S. 828
sponsored by Senator Joseph Lieberman (D-CT) and Senator Olympia Snowe
(R-ME). These bills propose adoption of a five-year, $1,000 per
kilowatt stationary fuel cell tax credit that would accelerate the
commercialization of fuel cell technology.
Tax credits for mobile fuel cell applications also have been the
subject of various legislative proposals and recommended in President
Bush's National Energy Policy. As fuel cell vehicles become
commercially available, United Technologies supports the use of tax
incentives to accelerate their deployment.
UTC also endorses a change in the depreciation schedule for large
commercial chillers that would generate significant energy savings. In
addition, we support tax incentives for residential air conditioners
that reflect boththe energy efficiency as well as non-ozone depleting
characteristics of the equipment.
UTC spends an average of $1 billion per year on research and
development. Our corporate environment, health and safety policy
includes commitments to conserve natural resources in the design,
manufacture, use and disposal of products and the delivery of services;
and develop technologies and methods to assure safe workplaces and to
protect the environment worldwide. UTC has invested heavily in bringing
clean, energy-efficient technology to the global marketplace. Working
together with Congress and the Administration, we can maximize the
benefits of these innovative technologies through a variety of
measures, including the use of tax incentives and changes to the
FUEL CELL DESCRIPTION
Fuel cells are the cleanest, fossil-fuel generating technology
available today. They use an electrochemical process to convert
chemical energy directly from natural gas or other hydrogen-rich fuel
sources into electricity and hot water at a very high level of
REALITY OF FUEL CELLS
Fuel cells are not a futuristic dream. More than 250 U.S.
astronauts have depended on UTC's fuel cell products to provide all the
electrical power and drinking water used in every manned U. S. space
mission since 1966. Each space shuttle mission carries three IFC 12 kW
fuel cell units and we have accumulated more than 81,000 hours of fuel
cell operating experience in the most demanding environment of all--
Closer to home, IFC has produced and sold more than 220 fuel cell
systems in 16 countries on five continents. We're the only company in
the world with a commercial fuel cell product available today. It's
known as the PC25a fuel cell power plant and it produces 200 kWs of
power and 900,000 BTUs of heat per hour. Each unit provides enough
power for roughly 150 homes. The worldwide fleet of PC25s has
accumulated more than four million hours of operating experience with
proven reliability. The PC25 system requires only routine maintenance
and has a life of 40,000 hours or five years before a major overhaul is
RATIONALE FOR FUEL CELL TAX CREDIT
Deployment of fuel cell technology will generate environmental
benefits, provide a reliable source of power for homeowners and
businesses, reduce dependence on foreign oil supplies, help
commercialize clean technology, enhance U.S. technological leadership
and create economic benefits for the nation. Enactment of a fuel cell
tax credit will help accelerate the deployment of fuel cell technology
and make its many benefits available more quickly and more broadly. By
acting now, the U.S. can continue to maintain its technology
leadership, generating high-skill jobs and creating opportunities for
economic growth and exports in the process. It should be noted that 56%
of the PC25s sold to date have gone to foreign customers.
Since fuel cells operate without combustion, they are virtually
pollution-free. In addition, they produce significantly lower levels of
carbon dioxide emissions, the primary man-made greenhouse gas that
contributes to climate change. For example, while the average fossil
fuel generating station produces as much as 25 pounds of pollutants to
generate 1,000 kilowatt-hours of electricity, the PC25 power plant
produces less than an ounce.
The existing fleet of PC25s has already prevented nearly 800
million pounds of CO2 emissions and more than 14.5 million
pounds of NOx and SOx compared with typical U.S.
combustion-based power plants. The U.S. Environmental Protection Agency
recognized IFC last year with a Climate Protection Award in recognition
of these accomplishments.
EFFICIENT SOURCE OF POWER
Fuel cells are inherently more efficient than combustion-based
systems. In the ``electricity-only'' mode of operation, IFC's PC25 unit
achieves approximately 40% efficiency. When the waste heat from the
fuel cell is utilized, an efficiency of 87% can be achieved. In
addition, fuel cells can be installed at the point of use, thus
eliminating transmission line losses that can run as high as 15%.
MINIMAL IMPACT ON GRID
Fuel cells can provide power at the point of use, thereby
alleviating the load on the existing transmission and distribution
infrastructure, and eliminating or minimizing the need for additional
investment in the current transmission and distribution network.
The use of fuel cells helps to diversify the energy market and
reduce reliance on imported oil. Fuel cells can operate with a variety
of fuel sources, but most commonly use natural gas.
CONTINUOUS SOURCE OF BASE POWER
Unlike other environmentally favorable solutions, fuel cells can be
used as continuous sources of base power – independent of time-
of-day or weather--for critical facilities and power requirements.
Its compact size, quiet operation and near-zero emissions allow a
fuel cell system such as the PC25 to be sited easily in communities and
neighborhoods. Unlike many other forms of power generation, fuel cell
power plants are good neighbors. For example, two PC25s are located
inside the Conde Nast skyscraper at Four Times Square in New York City.
Fuel cell power plants offer a solution when power is needed on-
site, or when distribution line upgrades become cost-prohibitive and/or
environmentally unattractive. For example, a PC25 installed at the
Central Park Police Station in New York City provides all the power for
the facility in an onsite installation. In this case, it would have
been too expensive to dig up Central Park and install an additional
power line, so the fuel cell became the ideal solution for an operation
that required a dedicated, reliable power supply and flexible sitting.
Several hospitals in the U.S., including Department of Defense
facilities, rely on PC25 systems to provide on-line emergency power. In
Rhode Island, for example, a PC25 system provides power for the South
County Hospital. The installation supplies base load electrical and
thermal energy to the hospital and helps ensure clean, reliable power
for sensitive medical equipment and systems such as CAT scanners,
monitors, analyzers and laboratory test equipment. If there is a grid
outage, the PC25 automatically operates as an independent system,
continuing to power critical loads at the hospital. Heat from the
installation provides energy for space heating, increasing the fuel
cell's overall efficiency.
The largest commercial fuel cell system in the world is currently
operating at a U.S. Postal Service facility in Anchorage, Alaska. The
system provides one megawatt of clean, reliable fuel cell power by
joining five PC25 units. In this installation, the units operate in
parallel to the grid and are owned and operated by the local
utility.The system is seen as a single, one-megawatt generation asset
and is dispatched by the utility through its standard dispatch system.
The system is designed so the fuel cells can provide power either to
the U.S. Postal Service mail-processing center or to the grid. In case
the grid fails, a nearly instantaneous switching system automatically
disconnects the grid and allows the fuel cells to provide uninterrupted
ASSURED, RELIABLE POWER
As our society increases its reliance on sophisticated computer
systems, very short power interruptions can have profound economic
consequences. In 1996, the Electric Power Research Institute reported
that U.S. businesses lose $29 billion annually from computer failures
due to power outages and lost productivity.
PC25 power plants are currently delivering assured power at
critical power sites such as military installations, hospitals, data
processing centers, and sites where sensitive manufacturing processes
take place. One of IFC's installations at the First National Bank of
Omaha where four fuel cells are the major component of an integrated
assured power system, is meeting customer requirements for 99.9999%
reliability. This translates into a power interruption of one minute
every six years.
The Conde Nast Building at Four Times Square in New York City is a
``green building'' with two PC25 power plants installed inside that
provide five percent of the building's electrical needs. If there is a
blackout, the systems are capable of operating independently of the
utility grid to maintain power to critical mechanical components and
external landmark signage on the facade of the building. The waste heat
from the unit is used to run the air conditioning and the power plants
provide critical backup power in case the grid fails.
When fueled by anaerobic digester gases or biogas from wastewater
treatment facilities, fuel cells are a source of renewable power. IFC
and the U.S. Environmental Protection Agency (EPA) collaborated in the
early 1990s on a greenhouse gas mitigation program that continues to
bear fruit today. Initial efforts targeted landfills and the
development of gas cleanup systems that enable fuel cells to use waste
methane to generate electricity and resulted in the issuance of several
patents jointly held by EPA and IFC. These systems prevent methane--a
potent greenhouse gas--from being released into the environment and
obviate the use of fossil fuels as the fuel source.
Follow-on work has focused on anaerobic digester off-gases (ADGs)
from wastewater treatment facilities. This technology has been
implemented successfully at PC25 installations in Yonkers, New York;
Calabasas, California; Boston, Massachusetts and Portland, Oregon as
well as Cologne, Germany and Tokyo, Japan.
FLEXIBLE AND BROAD APPLICATION OF FUEL CELLS
The examples noted above demonstrate the flexibility of fuel cell
technology and its appeal to many different customers with a wide range
of requirements. But it gets better. Fuel cell technology and its
associated benefits, which have broad application in the commercial/
industrial sector, is also being developed for homes, small businesses,
cars, trucks and buses.
RESIDENTIAL AND LIGHT COMMERCIAL FUEL CELL APPLICATION
IFC is currently pursuing residential and light commercial fuel
cell applications for homes and businesses. These units will use next-
generation proton exchange membrane (PEM) fuel cell technology. We are
drawing on our experience in both commercial and mobile fuel cell
programs to develop a five-kilowatt PEM fuel cell system suitable for
homes and small commercial buildings. IFC is teaming up with its sister
UTC unit, Carrier Corporation, the world's largest maker of air
conditioners, as well as Toshiba Corporation and Buderus Heiztechnik on
this effort. We are currently testing our residential power plants and
plan to have residential fuel cells units commercially available in
The cost of fuel cells has been reduced dramatically in the past
decade. The space shuttle application had a price tag of $600,000 per
kW. Commercial stationary units being installed today cost $4,500 per
kW, but fuel cells are still not competitive with existing technology,
which costs about $1,500 per kW. Fuel cell production volumes are low,
which increases their cost. Increased volume is needed to bring the
purchase cost down and accelerate commercialization of this clean,
reliable, efficient source of power so its benefits can be more widely
Adoption of a fuel cell tax credit is consistent with financial
incentives currently enjoyed by other energy sources including wind and
solar technology. In addition, it builds upon the Department of
Defense/Department of Energy fuel cell ``buydown'' grant program that
was initiated in FY'95. The fuel cell tax credit provisions contained
in H.R. 1275 and S. 828 are consistent with the $1,000 per kW, up to
one third of the cost of the equipment benefit currently made available
to federal facilities and municipalities through the DOD/DOE grant
program. We support continuation of the federal grant program for
public sector and non-profit purchases of fuel cells and enactment of a
fuel cell tax credit to aid private sector customers.
SUPPORT FOR FUEL CELL TAX CREDIT
UTC/IFC is leading the industry effort to secure a tax credit for
homeowners and business property owners who purchase stationary fuel
cells. This initiative has gained support from major fuel cell
manufacturers, suppliers and related organizations as indicated in
There have been a variety of legislative proposals in the 107th and
previous Congresses that would provide tax incentives for fuel cell
technology. While these bills differ in the scope of applications
covered, the amount of credit and other details, a bipartisan and
diverse group of Members of Congress and Administration officials
support the concept of a tax credit for fuel cells. The recent National
Energy Policy (NEP) recommendations released by the White House also
reflect the Bush Administration's endorsement of the technology and its
support for fuel cell tax credits. The NEP refers to fuel cells as a
promising distributed generation technology and recommends additional
effort in the integration of fuel cells, hydrogen and distributed
UTC'S Carrier division is the world's largest manufacturer of air
conditioning, heating and refrigeration systems. The company believes
that with market leadership comes the responsibility for environmental
leadership. Carrier continues to lead the global air conditioning and
refrigeration industry in the phaseout of ozone-depleting refrigerants
well ahead of international and domestic mandates. And while pioneering
the technologies to enable this transition to non-ozone depleting
products, Carrier has also increased energy efficiency, minimized
materials and product weight, introduced new air quality management
features and developed the tools to evaluate a holistic building
systems approach to indoor comfort cooling.
The heating, air conditioning and refrigeration industry has made
significant improvements over the past two decades in technologies that
benefit the environment. And while these technologies are readily
available for consumers today, barriers to full deployment do exist,
preventing the realization of maximum environmental benefit.
ENVIRONMENTAL TECHNOLOGIES FOR COMMERCIAL AIR CONDITIONING
In the commercial air conditioning market, major advancements have
been achieved in large-building chiller technology. Not only does
Carrier manufacture non-ozone-depleting chillers throughout the world;
these same products are, on average, 20% more efficient than their
counterparts of 20 years ago, with 10-15% less weight for the same
capacity. This has reduced raw materials like steel and saved the
intensive energy required to produce it. In fact, we believe the
industry is saving 16 million pounds of steel each year, or enough to
build 7,000 cars.
Despite these breakthroughs, more than 44,000 old, inefficient,
CFC-based ozone-depleting chillers remain in operation in the United
States. If these chillers were replaced with today's products, roughly
seven billion kilowatt hours per year would be saved, enough to power
740,000 homes on an annual basis, saving four million tons of carbon
emissions at power plants. We believe these old CFC chillers would be
replaced more rapidly if it weren't for the U.S. tax code, which allows
building owners to depreciate chillers over a staggering 39-year
period! If this term were reduced to 15 or 20 years, the advanced
chiller technologies would become more prevalent in the marketplace
sooner, to the benefit of the environment.
ENVIRONMENTAL TECHNOLOGIES FOR RESIDENTIAL AIR CONDITIONING
Equal advancements have been made in residential systems within the
last decade. Carrier introduced the world's first non-ozone-depleting
residential central air conditioning system, called Puron, in 1996--a
full 14 years prior to the deadline mandated by the Clean Air Act. And
while we're proud to have been the first, we also congratulate the
three other major manufacturers that have followed suit so far.
Carrier also leads the residential market with the highest rated
efficiencies and supports a full 20% increase in the federal minimum
energy efficiency standard. But Carrier also believes that federal and
state governments can do more to deploy high efficiency products more
rapidly through tax incentives. We congratulate Rep. Duke Cunningham
(R-CA) and Senator Bob Smith (R-NH) for introducing H.R. 778 and S.
207, respectively, which we view as a good framework for tax
incentives, especially if the levels start at 13 SEER (Seasonal Energy
Efficiency Rating--the miles-per-gallon equivalent for air conditioning
But as federal and state governments examine tax credits, we would
like to point out that opportunities exist to maximize these incentives
for additional environmental benefit, like ozone protection, along with
energy efficiency. Not too long ago, there was a trade-off between
efficiency and ozone protection. Most residential systems sold today
operate with an ozone-depleting refrigerant scheduled for phaseout in
new products in 2010. The amount of this refrigerant required for
higher efficiency systems, like 13 SEER, is 40% greater than standard
10 SEER systems. Fortunately, Carrier pioneered the technology that
other manufacturers have followed to avoid this ``Hobson's choice'' of
efficiency or ozone protection. Clearly and happily we can have both,
and we urge any tax incentive plan to maximize the environmental
benefits of efficiency combined with ozone protection.
UTC products have useful lives that can be measured in decades.
That's one of the reasons our corporate environment, health and safety
policy statement requires conservation of natural resources in the
design, manufacture, use and disposal of products and delivery of
services. It also mandates that we make safety and environmental
considerations priorities in new product development and investment
UTC products offer the potential for significant energy savings as
well as improved environmental quality. Working with government to
adopt appropriate financial incentives as outlined above, we can ensure
that these benefits are optimized and accelerated. We look forward to
working with Congress, the Administration and other stakeholders to
achieve these goals.
WHY SHOULD CONGRESS AND THE ADMINISTRATION SUPPORT A STATIONARY FUEL
CELL TAX CREDIT?
A fuel cell is a device that uses any hydrogen-rich fuel to
generate electricity and thermal energy through an electrochemical
process at high efficiency and near zero emissions. Fuel cell
developers, component suppliers, utilities and other parties with an
interest in clean distributed generation technology are working
together to enact tax credit legislation that will accelerate
commercialization of a wide range of fuel cell technologies.
The $1000 per kilowatt credit will be applicable for purchasers of
all types and sizes of stationary fuel cell systems. It will be
available for five years, January 1, 2002-December 31, 2006, at which
point fuel cell manufacturers should be able to produce a product at
market entry cost. The credit does not specify input fuels,
applications or system sizes so a diverse group of customers can take
short-term advantage of the credit to deploy a wide range of fuel cell
Why is a fuel cell tax credit necessary?
A credit will allow access to fuel cells by more customers
NOW when there is a grave need for reliable power in many parts of the
A credit will speed market introduction of fuel cell
A credit will create an incentive for prospective
customers, thus increasing volume and reducing manufacturing costs. As
with any new technology, price per unit decreases as volume of
A credit will speed the development of a manufacturing
base of component and sub-system suppliers.
Benefits of Speeding Market Introduction through Tax Legislation
Because fuel cell systems operate without combustion, they
are one of the cleanest means of generating electricity.
While energy efficiency varies among the different fuel
cell technologies, fuel cells are one of the most energy efficient
means of converting fossil and renewable fuels into electricity
developed to date.
Fuel cell systems can provide very reliable,
uninterruptible power. For example, fuel cells in an integrated power
supply system can deliver ``six nines'' or 99.9999% reliability. Thus
fuel cells are very attractive for applications that are highly
sensitive to power grid transmission problems such as distortions or
As a distributed generation technology, fuel cells address
the immediate need for secure and adequate energy supplies, while
reducing grid demand and increasing grid flexibility.
Installation of fuel cell systems provides consumer choice
in fuel selection and permits siting in remote locations that are ``off
Fuel cell systems can be used by electric utilities to
fill load pockets when and where new large-scale power plants are
impractical or cannot be sited.
Fuel cell systems, as a distributed generation resource,
avoid costly and environmentally problematic installation of
transmission and distribution systems.
The five-year budgetary impact of the credit is less than $500
Contact Judith Bayer at 202-336-7436 or [email protected] if
you have questions.
KEY ELEMENTS OF A FUEL CELL TAX CREDIT FOR STATIONARY APPLICATIONS
The goal of the stationary fuel cell tax credit is to
create an incentive for the purchase of fuel cells for
residential and commercial use. The prompt deployment of such
equipment will generate environmental benefits, provide a
reliable source of power for homeowners and businesses, reduce
our nation's dependence on foreign oil supplies, help
commercialize clean technology, enhance US technology
leadership and create economic benefits for the nation.
Fuel cell tax credit proposals should be designed to
benefit a wide range of potential fuel cell customers and
manufacturers. They should therefore be all-inclusive without
discriminating between different kilowatt sized units, type of
technology, application, fuel source or other criteria. Efforts
should be made to keep the proposals as simple as possible to
aid in effective implementation. In addition, the proposals
should strike a balance between ensuring the level of tax
credit provided represents a meaningful incentive that will
stimulate purchase and deployment of the technology while
minimizing the budgetary impact.
The following are specific elements suggested for
consideration and inclusion:
Coverage--US business and residential taxpayers that
purchase fuel cell systems for stationary commercial and
residential applications should be eligible for the credit.
Basis for credit--The credit should be based on a ``per
kilowatt'' approach with no distinction made for the size of
Access to credit--No allocation of credit should be made to
specific categories of fuel cells on an annual or total basis.
Fuel Source--No premium or penalty should be imposed based
on the fuel source.
Definition of stationary fuel cell power plant--The term
``fuel cell power plant'' should be defined as ``an integrated
system comprised of a fuel cell stack assembly, and associated
balance of plant components that converts a fuel into
electricity using electrochemical means.''
Co-generation--No co-generation requirement should be
imposed since not all fuel cell technologies offer an effective
option for co-generation.
Efficiency--No efficiency criteria should be imposed. Fuel
cell systems in the early stages of development, such as
residential sized units, cannot predict the efficiency level at
this time. Establishing arbitrary efficiency criteria could
exclude early models for this important application, which are
exactly the units that require incentives. Efficiency levels
will vary based on whether proton exchange membrane, phosphoric
acid, solid oxide or molten carbonate fuel cell technology is
used. Designing fuel cell systems to maximize efficiency may
require tradeoffs resulting in more complicated, higher cost,
less fuel flexible and less durable units.
Floor/ceiling--No minimum or maximum kilowatt size criteria
should be imposed.
Amount of Credit--$1,000 per kW for all qualifying fuel
cell power plants. A five-year program with a $500 million
budgetary impact is proposed.
Contact Judith Bayer at 202-336-7436 or
[email protected] if you have questions.