```

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

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

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

                                HEARING

                               before the

                SUBCOMMITTEE ON SELECT REVENUE MEASURES

                                 of the

                      COMMITTEE ON WAYS AND MEANS
                        HOUSE OF REPRESENTATIVES

                      ONE HUNDRED SEVENTH CONGRESS

                             FIRST SESSION

                               __________

                             JUNE 13, 2001

                               __________

                           Serial No. 107-25

                               __________

         Printed for the use of the Committee on Ways and Means

                    U.S. GOVERNMENT PRINTING OFFICE
74-229                      WASHINGTON : 2001
For Sale by the Superintendent of Documents, U.S. Government Printing Office
Internet: bookstore.gpr.gov  Phone (202) 512�091800  Fax: (202) 512�092250
              Mail: Stop SSOP, Washington, DC 20402�090001.

                      COMMITTEE ON WAYS AND MEANS

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

                Subcommittee on Select Revenue Measures

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

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

                            C O N T E N T S

                              ----------                           Page
                                                                   Page
Advisory of June 6, 2001, announcing the hearing.................     2

                               WITNESSES

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. 
  MacFarlane.....................................................    42
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 
  attachments....................................................   100
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,
                                                    Washington, DC.
    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:]

ADVISORY

FROM THE COMMITTEE ON WAYS AND MEANS

                SUBCOMMITTEE ON SELECT REVENUE MEASURES

                                                CONTACT: (202) 226-5911
FOR IMMEDIATE RELEASE
June 6, 2001
No. SRM-3

   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.

BACKGROUND:

    The Internal Revenue Code provides several incentives for the 
domestic production of oil and gas including: (1) expensing of certain 
exploration and development costs, (2) depletion rules, and (3) a tax 
credit for enhanced oil recovery costs. The tax code provides 
incentives for the production of electricity from certain renewable 
resources, including wind and closed-loop biomass facilities, 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.

FORMATTING REQUIREMENTS:

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

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

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

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

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

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

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

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

                                

    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 
bipartisan basis.
    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 
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 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 
bipartisan support.
    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 
other issues.
    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 
entire country.
    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.
    Thank you.

                                

    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 year.
    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 
equation.
    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 
incentives.
    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 
marketplace.
    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.
Hybrid Vehicles
    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 
vehicles.
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 
payload capabilities.
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 
cell technology.
    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 
greenhouse gases;
     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 
United States.
    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 
capacity.
    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 
Island, Illinois.
    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 
test.
    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 
Clinton.
    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 
refineries.
    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 
loss.
    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 
refining companies.
    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 
spikes.
    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 
its assets.
    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 
desulfurization equipment.
    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 
be avoided.
    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.
    Mr. Saillant.

  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 
lines.
    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 
transmission problems.
    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 
system.
    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 
organizations).
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 
businesses.
    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 
customer.
    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 
equipment.
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 
generation technologies.
    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 
                           Mining Association

    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 
impact.
    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.
---------------------------------------------------------------------------
Background
    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 
        Electricity
    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 
affordable prices.\2\
---------------------------------------------------------------------------
    \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 
competitive.
    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 
Association.
    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 
technologies available.
    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, 
2001.
---------------------------------------------------------------------------
    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. 
Geller?

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 
Mr. Saillant.
    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 
energy needs.
    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 
                               Coalition

    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 
technologies;
     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 
barriers.
    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 
Coalition supports.
     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 
Bingaman-Daschle bill.
    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 
testify today.

                                

    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.
    [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 
vehicles.
    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 
available?
    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 
overall fleet.
    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 
changes.
    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 
nation.
    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 
this bill.
    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, 
market 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 
market.
    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 
significant.
    [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 
locations.
    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.
            Sincerely,
                                                      Roger Sallant

                                

    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 
Cooper?
    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 
that.
    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 
cells.
    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 
practical application.
    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 forth.
    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 
day.
    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 
                            Gas Association

    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 
towns.
    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 
or aggregators/marketers.

                     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.

                               IRS Action

    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 
Revenue Code.
    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 
markets.

                               H.R. 1986

    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.

                              Current Law

    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 
applicable regulations.
    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 
test if--
    (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 
their customers.
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 
municipal LDCs.
    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.
Commodity Swaps
    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.
Conclusion
    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 
proceeds.
    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 
these areas.
    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 
                              Association

I. INTRODUCTION
    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 
increase.
    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 
energy needs.
    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 
alone.
    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 
complex rules.
    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 
network.
    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
    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.
Percentage Depletion
    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. 
389.
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 
operations.
    Recently, the problems associated with the AMT have again been all 
too real for many domestic oil and gas producers. Oil and gas drilling 
activity has accelerated rapidly since 1999 in response to the 
phenomenal growth in demand for oil and natural gas. However, a portion 
of this activity had to be curtailed, not because of a lack of product 
demand, but, rather, because the AMT preference item for intangible 
drilling and development costs (IDCs) exposed those producers to the 
AMT and rendered 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.
EOR Credit
    The Enhanced Oil Recovery (EOR) credit provides a credit equal to 
15 percent of costs attributable to qualified enhanced oil recovery 
projects. Since the enactment of the EOR credit in 1990, new 
technologies have greatly enhanced the ability of oil producers to 
economically recover additional domestic reserves from existing wells 
with minimal environmental impact. By extending the EOR credit to 
certain nontertiary production methods such as horizontal drilling, 
gravity drainage, cyclic gas injection, and water flooding, the 
economic viability of these oil recovery methods would be greatly 
enhanced. In turn, the up to 70 percent of an oil well's reserves that 
otherwise would be left in the ground could be added to the nation's 
available energy supply.
Heavy Oil Production Credit
    So-called ``heavy oil'' is one source of domestic petroleum that is 
significantly less economic, but represents a key component of the U.S. 
energy base. Currently, heavy oil accounts for over 11 percent of U.S. 
production. However, its potential is far more significant because the 
measured U.S. heavy oil resource base is over 100 billion barrels. 
Heavy crude oil is generally characterized by its high specific gravity 
or weight, as well as its high viscosity or resistance to flow. Because 
of these characteristics, heavy oil is substantially more difficult and 
expensive to extract and refine than other types of oil. Additionally, 
this oil is less valuable because a smaller percentage of high-value 
petroleum products can be refined from a barrel of heavy oil than from 
a barrel of higher quality crude oil. A heavy oil production tax credit 
would help the nation maximize its domestic energy supply by making 
that resource economic to produce.
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 
refinery investments.
    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 
capacity expansion.
    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 
circumstances.
    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 
storage facilities.
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 
and partnerships.
Section 907: Foreign Oil and Gas Extraction Income and Foreign Oil 
        Related Income
    Under the separate basket rules, foreign oil and gas income falls 
into the general limitation basket. 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 
the government.
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, 
including stock.
    At the very least, taxpayers should be allowed to elect to use the 
E&P bases of assets, rather than the adjusted tax bases, for purposes 
of allocating interest expense. Use of E&P basis would produce a fairer 
result because the E&P rules are similar to the rules now in effect for 
determining the tax bases of foreign assets.
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 
partnership income.
Look-through Treatment for Interest, Rents, and Royalties with Respect 
        to Non-Controlled Foreign Corporations and Partnerships
    U.S. oil and gas companies are often unable, due to government 
restrictions or operational considerations, to acquire controlling 
interests in foreign 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.
IV. SUMMARY
    Our industry strongly supports tax law changes designed to 
encourage increased domestic petroleum activity, which, in turn, will 
help to expand overall product supply in the United States. Expansion 
of available supply is critical to meeting DOE projections of a 33 
percent increase in U.S. petroleum demand and a 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 
sources.
    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 
proposition.
    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 
your questions.
    [The prepared statement of Mr. Van Son follows:]

  Statement of Vince T. Van Son, Manager, Business Development, Alcoa 
         Energy Division, Alcoa Inc., Pittsburgh, Pennsylvania

I. Introduction
    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 
        Strategy
    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 
        Technologies
    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 
basis.
    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 
lowest.
    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 
sources.
    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 
historically adopted.
    Thank you for the opportunity to testify. I look forward to your 
questions.

                                

    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 
hearing.
    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 
marginal wells.
    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 
testimony.)
    Second, there is wide support for a countercyclical marginal well 
tax credit. This approach was recommended by the National Petroleum 
Council in its 1994 Marginal Wells study. This tax credit today can be 
crafted with a negligible impact on the federal budget, but at the same 
time create an important safety net for the most vulnerable American 
producing wells--wells that produce petroleum roughly equivalent to 
imports from Saudi Arabia--wells that are the nation's true strategic 
petroleum reserve. (An IPAA Fact Sheet detailing this issue follows 
this testimony.)
    Third, Congress has suspended the property taxable income 
limitation on percentage depletion for marginal wells through 2001. The 
tax bill passed by the 106th Congress would have suspended this 
provision through 2004. The suspension that was in place in 1998 and 
1999 saved many marginal wells during the price crisis. This provision 
should be permanently eliminated to provide domestic producers of these 
wells an incentive not to plug the wells during a low price cycle. Once 
the well is plugged, the potential to produce the remaining reserves is 
lost forever. (An IPAA Fact Sheet detailing this issue follows this 
testimony.)
    Fourth, the 106th Congress' tax bill 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 
testimony.)
    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.
Next Steps
    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.)
Conclusion
    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

                               FACT SHEET

Geological And Geophysical Costs
    Geological and geophysical (G&G) surveys are used to locate and 
identify properties with the potential to produce commercial quantities 
of oil and natural gas, as well as to determine the optimal location 
for exploratory and developmental wells.
Proposal
    Allow current expensing of geological and geophysical costs 
incurred domestically including the Outer Continental Shelf.
    G&G expenses include the costs incurred for geologists, seismic 
surveys, and the drilling of core holes. These surveys increasingly use 
3-D technology rather than the conventional 2-D technology used for 
most of the last seven decades. Previously only very large companies 
were able to utilize this state-of-the-art, computer-intensive, 3-D 
technology because of its high cost and the considerable technical 
expertise it requires. However, as the costs of computer technology 
have declined, more and more domestic independent producers are making 
use of this technology. Still, while 3-D seismic provides a vastly 
superior tool for exploration, it is far more expensive than 2-D 
technology. 3-D seismic surveys usually cost between five or six times 
more per square mile onshore than the older technology and, in some 
instances can account for two-thirds of the costs of some wells. 
Encouraging use of this technology has many benefits:
     More detailed information. Conventional 2-D seismic is 
only able to identify large structural traps while 3-D seismic is able 
to pinpoint complex formations and stratigraphic plays.
     Improved finding rates. Producers are reporting 50-85% 
improvements in their finding rate. In prior years a producer might 
have to drill three to eight wells in order to find commercially viable 
production.
     Reduced environmental impact. Because the use of advanced 
seismic technology significantly improves the odds of drilling a 
commercially viable well on the first try, this reduces the number of 
wells that are drilled and, thus, reducing the footprint of the 
industry on the environment.
     Investment capital. Many investors are requiring producers 
to provide 3-D seismic surveys of potential development before 
committing their capital to the project in order to minimize their 
risk.
Current law treatment
    G&G costs are not deductible as ordinary and necessary business 
expenses but are treated as capital expenditures recovered through cost 
depletion over the life of the field. G&G expenditures allocated to 
abandoned prospects are deducted upon such abandonment.
Reasons for change
    These costs are an important and integral part of exploration and 
production for oil and natural gas. They affect the ability of domestic 
producers to engage in the exploration and development of our national 
petroleum reserves. Thus, they are more in the nature of an ordinary 
and necessary cost of doing business.
    These costs are similar to research and development costs for other 
industries. For those industries such costs are not only deductible but 
a tax credit is available.
    Crude oil imports are at an all-time high, which makes the U.S. 
vulnerable to sharp oil price increases or supply disruptions. The 
National Petroleum Council Natural Gas study concluded that natural gas 
supplies need to increase by over 30 percent by 2010 to meet demand. 
Domestic exploration and production must be encouraged now to offset 
this potential threat to national security, to meet future needs, and 
to enhance our economy. Allowing the deduction of G&G costs would 
increase capital available for domestic exploration and production 
activity.
    The technical ``infrastructure'' of the oil services industry, 
which includes geologists and engineers, has been moving into other 
industries due to reduced domestic exploration and production. 
Stimulating exploration and development activities would help rebuild 
the critical oil services industry.
    Encouraging the industry to use the best technology available and 
to reduce its environmental footprint are important public policy 
reasons to clarify that these ordinary and necessary business expenses 
for the oil and gas industry should be expensed.
Status
    The Taxpayer Refund And Relief Act Of 1999 included a provision to 
allow expensing of G&G costs, but the bill was vetoed. Congress needs 
to pass legislation now to implement this common objective to enhance 
and preserve domestic oil and natural gas production.

              Independent Petroleum Association of America

                               FACT SHEET

Tax Treatment of Delay Rentals
    Delay rental payments are made by producers to an oil and gas 
lessor prior to drilling or production. Unlike bonus payments (made by 
the producer in consideration for the grant of the lease) which 
generally are treated as an advance royalty and thus capitalized, 
producers have historically been allowed to elect to deduct delay 
rental payments under Treasury Regulations 1.612-3(c). However, in 
September 1997, the IRS issued a coordinated issues paper stating that 
such payments are preproduction costs subject to capitalization under 
Section 263A of the Internal Revenue Code. The legislative history of 
Section 263A is unclear and subject to varying interpretation.
Proposal
    Clarify that delay rental payments are deductible, at the election 
of the taxpayer, as ordinary and necessary business expenses.
Reasons for change
    In passing the Section 263A uniform capitalization rules, Congress 
broadly intended to only affect the ``unwarranted deferral of taxes.'' 
Congress did not intend to grant the IRS the authority to repeal the 
well-settled industry practice of deducting ``delay rentals'' as 
ordinary and necessary business expenses.
    Treas. Reg.1.612-3(c) states that, ``a delay rental is an amount 
paid for the privilege of deferring development of the property and 
which could have been avoided by abandonment of the lease, or by 
commencement of development operations, or by obtaining production.'' 
Such payments represent ordinary and necessary business expenses, not 
an ``unwarranted deferral of taxes.'' Given the clear disagreement over 
the legislative history and the likelihood of costly and unnecessary 
litigation to resolve the issue, clarification would eliminate 
administrative and compliance burdens on taxpayers and the IRS.
Status
    The Taxpayer Refund And Relief Act Of 1999 included a provision to 
clarify that delay rental payments could be expensed, but the bill was 
vetoed. Congress needs to enact legislation to implement this common 
position if the Administration is unwilling to correct the current 
confusing interpretation of the tax code.
                                                         March 2001

              Independent Petroleum Association of America

                               FACT SHEET

Marginal Well Tax Credit
Summary of Legislation
    The Marginal Well Production Tax Credit amendment to the Internal 
Revenue code will establish a tax credit for existing marginal wells. 
Marginal oil wells are those with average production of not more than 
15 barrels per day, those producing heavy oil, or those wells producing 
not less than 95 percent water with average production of not more than 
25 barrels per day of oil. Marginal gas wells are those producing not 
more than 90 Mcf a day. The amendment will allow a $3 a barrel tax 
credit for the first 3 barrels of daily production from an existing 
marginal oil well and a $0.50 per Mcf tax credit for the first 18 Mcf 
of daily natural gas production from a marginal well.
    The tax credit would be phased in and out in equal increments as 
prices for oil and natural gas fall and rise. Prices triggering the tax 
credit are based on the annual average wellhead price for all domestic 
crude oil and the annual average wellhead price per 1,000 cubic feet 
for all domestic natural gas. The credit for the current taxable year 
is based on the average price from the previous year. The phase in/out 
prices are as follows:
    OIL--phase in/out between $15 and $18;
    GAS--phase in/out between $1.67 and $2.00.
    The amendment would allow the tax credit to be offset against 
regular and the alternative minimum tax (AMT). In addition, for 
producers without taxable income for the current tax year, the 
amendment would provide a 10-year carryback provision allowing 
producers to claim the credit on taxes paid in those years. The 
carryback credit may be used to offset regular tax and AMT.
Reasons For Change
    The 1994 National Petroleum Council's Marginal Wells report 
concluded:
    Preserving marginal wells is central to our energy security. 
Neither government nor the industry can set the global market price of 
crude oil. Therefore, the nation's internal cost structure must be 
relied upon for preserving marginal well contributions.
    Marginal wells account for approximately 20 percent of domestic oil 
production, amount roughly equivalent to imports from Saudi Arabia. 
Producing an average of 2.2 barrels per day, these roughly 400,000 
wells are the nation's true strategic petroleum reserve. They are, 
however, particularly at risk during periods of low prices. Therefore, 
a principal recommendation of the Marginal Wells report was the 
creation of a countercyclical marginal well tax credit.\1\ The Dept. of 
Energy has evaluated the benefits of a tax credit and believes that it 
could prevent the loss of 140,000 barrels per day of production if 
fully employed during times of low oil prices like those of 1998 and 
1999.
---------------------------------------------------------------------------
    \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.
                                                         March 2001
                                 ______
                                 

              Independent Petroleum Association of America

                               FACT SHEET

Eliminate The Net Income Limitation On Percentage Depletion
    The net income limitation severely restricts the ability of 
independent producers to use percentage depletion, particularly with 
respect to marginal wells. Percentage depletion is already subject to 
many limitations. First, the percentage depletion allowance may only be 
taken by independent producers and royalty owners and not by integrated 
oil companies. Second, depletion may only be claimed up to specific 
daily production levels of 1,000 barrels of oil or 6,000 Mcf of natural 
gas. Third, depletion is limited to the net income from the property. 
Fourth, the deduction is limited to 65% of net taxable income. These 
limitations apply both for regular and alternative minimum tax 
purposes.
    The net income limitation requires percentage depletion to be 
calculated on a property-by-property basis. It prohibits percentage 
depletion to the extent it exceeds the net income from a particular 
property. The typical independent producer can have numerous oil and 
gas properties, many of which could be marginal properties with high 
operating costs and low production yields. During periods of low 
prices, the producer may not have net income from a particular 
property, especially from marginal properties. When domestic production 
is most susceptible to being plugged, the net income limitation 
discourages producers from investing income to maintain marginal wells.
Proposal
    Eliminate the net income limitation on percentage depletion.
Reasons for change
    Marginal oil wells--those producing on average 15 barrels per day 
or less or producing heavy oil--account for approximately 20 percent of 
domestic oil production, an amount roughly equivalent to imports from 
Saudi Arabia. The U.S. is the only country with significant production 
from marginal wells. Once wells are plugged, access to the remaining 
resource is often lost forever. Eliminating the net income limitation 
on percentage depletion would encourage producers to keep marginally 
economic wells in production and enhance optimum oil and natural gas 
resource recovery.
    The current requirement creates a paperwork and compliance 
nightmare for taxpayers and the Internal Revenue Service. Eliminating 
the net income limitation on percentage depletion would simplify 
recordkeeping and reduce the administrative and compliance burden for 
taxpayers and the IRS.
Current Status
    The Taxpayer Relief Act of 1997 created a two-year suspension of 
the net income limitation on percentage depletion; this suspension has 
been extended through 2001. However, it is time to make this suspension 
permanent. If the country learned anything from the high oil and 
natural gas prices of 2000, it is that America needs to maintain and 
enhance its domestic oil and natural gas production. This tax reform 
allows more capital to be retained by producers where it can do the 
most good--producing more domestic oil and natural gas.
    Legislation has been introduced to eliminate or further suspend the 
net income limitation provision for marginal wells. It should be 
enacted prior to 2002 when the current suspension ends.
                                                         March 2001

              Independent Petroleum Association of America

                               FACT SHEET

Percentage Depletion Expansion and Carryback Proposal
    Current tax law limits the use of percentage depletion of oil and 
gas in several ways. First, the percentage depletion allowance may only 
be taken by independent producers and royalty owners and not by 
integrated oil companies. Second, depletion may only be claimed up to 
specific daily production levels of 1,000 barrels of oil or 6,000 Mcf 
of natural gas. Third, the net income limitation requires percentage 
depletion to be calculated on a property-by-property basis.\2\ It 
prohibits percentage depletion to the extent it exceeds the net income 
from a particular property. Fourth, the deduction is limited to 65% of 
net taxable income. These limitations apply both for regular and 
alternative minimum tax purposes.
---------------------------------------------------------------------------
    \2\ The net income limitation for marginal wells is suspended 
through 2001.
---------------------------------------------------------------------------
    Percentage depletion in excess of the 65 percent limit may be 
carried over to future years until it is fully utilized. Many 
independent producers have been limited in the past because they have 
spent their income on continuing development of their properties, 
thereby reducing their taxable income. When oil prices dropped to 
historically low levels independent producers were unreasonably 
constrained by these tax provisions limiting their cash flow. They 
cannot use these carried over deductions. Now, when capital to develop 
oil and natural gas should be maximized, producers can be constrained 
due to the alternative minimum tax (AMT). Even if they could use the 
deductions, they may not benefit to the fullest extent possible from 
actual tax savings. This proposal would alleviate these limits by 
implementing the following changes:
     By annual election, the 65 percent taxable income 
limitation would be reduced or eliminated for current and future tax 
years.
     Carried over percentage depletion could be carried back 
for ten years subject to the same annual election on taxable income 
limitation.
Status
    Legislation has been introduced in the 107th Congress to eliminate 
or suspend the 65 percent net taxable income limit and to provide for 
carryback of carried over deductions.
    Congress needs to include such provisions in future tax reform 
bills and the Administration needs to support such provisions to 
enhance and preserve domestic oil and natural gas production.
                                                         March 2001

              Independent Petroleum Association of America

                               FACT SHEET

Enhanced Oil Recovery
    Section 43 of the Internal Revenue Code provides an enhanced oil 
recovery (EOR) credit equal to 15 percent of the qualified enhanced oil 
recovery costs incurred in 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 
recovery.
Proposal
    Have the IRS review and expand the definition of methods qualifying 
for the EOR tax credit.
Reason for Change
    The existing Treasury guidelines are based on 1979-vintage 
technology. This list has not kept pace with technology. A second 
rationale is the incentive generated by allowing domestic producers to 
position themselves to glean existing reservoirs in order to maximize 
production of existing reserves.
    Two additional categories to the EOR list are proposed. Those 
categories include Enhanced Gravity Drainage (EGD) and Marginally 
Economic Reservoir Repressurization (MERR). Included under EGD would be 
horizontal drilling, multilateral well bores and large diameter lateral 
well bores. Included in MERR would be natural gas injection and 
waterflooding. Certain qualifiers and limiting factors include economic 
criteria for approved projects and incremental production limitations 
on each project.
    By redefining the definition of EOR projects to include both EGD 
and MERR technologies, the EOR tax credit will encourage conservation 
measures to expand recovery of existing crude oil reservoirs and 
promote new drilling activity.
    The benefit of these changes is well stated in the National Energy 
Policy report:
    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.
                                                          June 2001

              Independent Petroleum Association of America

                               FACT SHEET

Plowback Incentive
    Fundamentally, the question facing the nation is how to marshal the 
capital to develop its domestic resources. The 1999 NPC Natural Gas 
study estimates that an additional $10 billion over and above the 
current expenditure level will need to be invested annually in domestic 
production over the next fifteen years to meet the expected demand. To 
date this target has not been met; 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 
investment.
Proposal Alternatives
    (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.
                                                           May 2001

                                

    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 
benefit us?
    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 
foreign governments.
    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 
overseas.
    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 
reinvestment.
    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 
selling point.
    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.
    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 
area.
    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 
energy needs.
    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 
Electric Institute.
    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 
                          ASSOCIATION

    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 
co-op.
    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 
test.
    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 
condemn territory.
    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 
test.
    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 
parties.
    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 
competitive marketplace.
    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 
of line.
    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 
residential consumers.
    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 
benefit.
    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 
status.
            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:
     Wheeling Income
    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.
Taxable Cooperatives
    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 
liability.
CONCLUSION
    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. 
1601.
    Thank you for the opportunity to appear before you today. I would 
be pleased to answer any questions that you may have.

                               Addendum A

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 
incentives.
     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 
user;
     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.

                               Addendum B

                                          ELECTRIC UTILITY COMPARISONS
----------------------------------------------------------------------------------------------------------------
                                                           Investor     Publicly
                                                            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 
private parties.
    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 
shortages.
    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 
permanent.
    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 
in 2004.
    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 
officials.
    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.
Sales Rules
    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 
the gross-up.
Other Provisions
    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 
seller's facilities).
    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 
generation units.
Conclusion
    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 
H.R. 1459.
    A detailed explanation of the private use provisions of the bill 
appears below.

      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 
described below.
            2. Tax-Exempt Bonds That May Be Issued After a Termination 
                    Election
    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 
refunded bonds.
    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 
FERC.
            2. Sales
    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 
        Distribution Facilities
            1. Transmission
    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 
siting agency.
            2. Distribution
    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.
Other Provisions
    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 
United States.
    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 
issues.
    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 
themselves.
    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 
company.
    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 
transmission companies.
    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 
occurs.
    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 
                               Institute

Introduction
    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 
facilities.
     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. 
1459 that:
    (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 
customer).
    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 
independent generators.
    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 
utilities,
    (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 
infrastructure.
    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, 
and
    (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 
needed infrastructure.
    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 
approximately 30-35%.
    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 
facilities.
III. AMEND THE NUCLEAR DECOMMISSIONING TAX LAW TO ADAPT IT TO A 
        COMPETITIVE MARKET
    Owners of nuclear power plants make contributions to external trust 
funds to ensure that monies are available to decommission plants when 
they are retired. Congress added Section 468A to the tax code in 1984 
to permit owners of nuclear power plants to currently deduct 
contributions that are made to these external funds. Section 468A, when 
enacted, was designed to operate within the structure of regulated 
rates. It depends on public service commissions authorizing 
specifically identified costs (i.e., decommissioning costs) that an 
electric utility can charge its customers.
    As a result of the Energy Policy Act of 1992, 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.
CONCLUDING COMMENTS
    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 
assets.
    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 
taxation.
    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 
Pennsylvania.
    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 
liability?
    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 
warranted.
    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 
this direction?
    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 
the co-ops.
    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 
efficiency.
    In most homes, the HVACR equipment is the largest energy user. In 
businesses, HVACR equipment is typically among the top three consumers 
of energy.
    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.
The Solution
    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 
efficiently.
    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 
conditioning equipment.
    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.
Conclusion
    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 
equipment.
    The benefits are real and lasting, with long-term savings, rather 
than costs, to the American taxpayer.
    Thank you.

                                

      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 
aisle.
    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 
following:
    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 
appliances.

                          AREA Members Include:
Alliance to Save Energy...........  City of Austin, Texas
American Council for an Energy-     Friends of the Earth
 Efficient Economy.
Association of Home Appliance       Natural Resources Defense Council
 Manufacturers.
Appliance Standards Awareness       Northwest Power Planning Council
 Project.
The Business Council for            Pacific Gas and Electric
 Sustainable Energy.
California Energy Commission......  The Sierra Club

                                

    Statement of the American Chemistry Council, Arlington, Virginia

INTRODUCTION
    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 
application.
    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 
facilities.
    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 
        POWER
    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 
catalytic reduction.
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.
CONCLUSION
    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 
Improvement Act.
    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 
top priority.
    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 
tax credit.
    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 
hydropower capacity.
    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 
improve efficiency.
    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 
complete.
    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 
credit program.
    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 
                            Smith, Arkansas

    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 
motors.
    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.
Summary
    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 
whole.
Background
    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 
industries.
    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 
partnerships.
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 
investment.
    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
----------------------------------------------------------------------------------------------------------------
Natural resources:
    Energy production, refining,             23   $11,929.8     64.2    $22,579.8     71.0    $35,116.9     89.7
     transport, etc....................
    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
                                        ========================================================================
Real estate:
    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 
include:
     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 
were created.
    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.
Conclusion
    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 
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.
    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.

                               EXHIBIT 1

            FEATURES OF 12 MIDSTREAM ENERGY/PIPELINE PUBLICLY TRADED PARTNERSHIPS AS OF MAY 29, 2001
----------------------------------------------------------------------------------------------------------------
                                                                                        Annual
                                                   Enterprise     2000     Current   distribution       2000
                                                      value     Revenue     yield       growth     distributions
                                                                          (percent)    (percent)
----------------------------------------------------------------------------------------------------------------
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.

                               EXHIBIT 2

 PUBLICLY TRADED PARTNERSHIPS OPERATING IN SUBCOMMITTEE MEMBERS' STATES

LOUISIANA                           Other
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
TEPPCO, L.P.

ARIZONA                             Other
Energy                              Alliance Capital Management 
                                    Holding, L.P.
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

TEXAS                               Other
Energy                              Crown Pacific Partners, L.P.
Amerigas Partners, L.P.
Buckeye Partners
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.

ILLINOIS                            Other
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.

TENNESSEE                           Other
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.

KENTUCKY                            Other
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.
TEPPCO, L.P.

WISCONSIN                           Other
Energy                              FFP Partners, L.P.
Kaneb Pipe Line Partners
Lakehead Pipe Line Partners

MASSACHUSETTS
Energy
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 
energy strategy.

                                

  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 
legislative incentives.
    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 
vehicles.
    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 
they provide.
    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 
ACT enjoys.
    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-
consuming businesses.
---------------------------------------------------------------------------
    \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 
efficiency.
---------------------------------------------------------------------------
    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 
of 9.5%.
    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).
---------------------------------------------------------------------------

                                Figure 1
[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 
energy efficiency.
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%.
    Examples include:
     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 
next summer.
    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 
2001.
     ``[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, 
2001.
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 
2001.
     ``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 
        Liabilities
    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 
problems.
    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 
industry.
---------------------------------------------------------------------------
    \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 
such transactions.
---------------------------------------------------------------------------
    \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.
V. Proposals
    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 
        transmission
    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 
the industry.
    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 
        the utilities
    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 
taxpayers.
    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. 
596.\6\
---------------------------------------------------------------------------
    \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 
        transmission
    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

Alstom Corporation
American Transmission Company LLC
PacifiCorp
Pepco
Xcel Corporation

                                

           Solid Waste Association of North America
                              Silver Spring, Maryland 20910
                                                      June 19, 2001
The Honorable Jim McCrery
Chairman
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 
and operated.
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 
methane projects.''
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.
Conclusion
    The Subcommittee has an opportunity to significantly impact the 
development of a new energy policy for the nation. Use of the tax code 
to encourage energy-related private investment is justified by the 
compelling energy security, economic and environmental concerns facing 
our nation currently and in the foreseeable future. Specifically, a tax 
incentive for energy production through the combustion of MSW or the 
utilization of LFG would allow the nation to not only benefit from 
increased domestic energy supplies, but to also realize the many 
consequent environmental and resource conservation benefits. SWANA 
urges the Subcommittee to support 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.
            Sincerely,
                                    John H. Skinner, Ph.D.,
                                        Executive Director and CEO.
    cc: All Members of the House Subcommittee on Select Revenue 
Measures

                                

            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 
Cells.
    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 
depreciation schedule.
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 
efficiency.
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--
outer space.
    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 
required.
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.
ENVIRONMENTAL BENEFITS
    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.
ENERGY SECURITY
    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.
IDEAL NEIGHBOR
    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.
DISTRIBUTED GENERATION
    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.
EMERGENCY POWER
    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.
GRID SUPPORT
    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 
power.
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.
PARTIAL LOAD/CO-GENERATION
    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.
RENEWABLE ENERGY
    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 
2003.
CONSTRAINTS
    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 
realized.
PRECEDENTS
    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 
Attachment A.
    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 
generation initiatives.
CARRIER OVERVIEW
    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 
equipment).
    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 COMMITMENT
    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 
decisions.
    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?

Overview
    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.
Credit Description
    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 
equipment.
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 
country.
     A credit will speed market introduction of fuel cell 
systems.
     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 
production increases.
     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 
power interruptions.
     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 
grid.''
     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.
Cost
    The five-year budgetary impact of the credit is less than $500 
million.
    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

Overview
    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 
unit.
    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.
    Duration--1/1/02--12/31/06.
    Contact Judith Bayer at 202-336-7436 or 
[email protected] if you have questions.

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