```

[Senate Hearing 109-503]
[From the U.S. Government Publishing Office]

                                                 S. Hrg. 109-503, Pt. 1
 
   IMPLEMENTATION OF THE PROVISIONS OF THE ENERGY POLICY ACT OF 2005

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

                                HEARINGS

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                       ONE HUNDRED NINTH CONGRESS

                             SECOND SESSION

                                   on

    COAL LIQUEFACTION TECHNOLOGY; COAL GASIFICATION TECHNOLOGY; AND 
                 LICENSING OF HYDROELECTRIC FACILITIES

                               __________

                             APRIL 24, 2006

                              MAY 1, 2006

                              MAY 8, 2006

                       Printed for the use of the
               Committee on Energy and Natural Resources

                                 ______

                    U.S. GOVERNMENT PRINTING OFFICE
28-983                      WASHINGTON : 2006
_____________________________________________________________________________
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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                 PETE V. DOMENICI, New Mexico, Chairman
LARRY E. CRAIG, Idaho                JEFF BINGAMAN, New Mexico
CRAIG THOMAS, Wyoming                DANIEL K. AKAKA, Hawaii
LAMAR ALEXANDER, Tennessee           BYRON L. DORGAN, North Dakota
LISA MURKOWSKI, Alaska               RON WYDEN, Oregon
RICHARD BURR, North Carolina         TIM JOHNSON, South Dakota
MEL MARTINEZ, Florida                MARY L. LANDRIEU, Louisiana
JAMES M. TALENT, Missouri            DIANNE FEINSTEIN, California
CONRAD BURNS, Montana                MARIA CANTWELL, Washington
GEORGE ALLEN, Virginia               JON S. CORZINE, New Jersey
GORDON SMITH, Oregon                 KEN SALAZAR, Colorado
JIM BUNNING, Kentucky
                     Bruce M. Evans, Staff Director
                   Judith K. Pensabene, Chief Counsel
               Robert M. Simon, Democratic Staff Director
                Sam E. Fowler, Democratic Chief Counsel
                        Kellie Donnelly, Counsel
                John Perschke, Professional Staff Member
                Patty Beneke, Democratic Senior Council
         Jennifer Michael, Democratic Professional Staff Member

                            C O N T E N T S

                              ----------                              
                                                                   Page
Hearings:
    April 24, 2006...............................................     1
    May 1, 2006..................................................    43
    May 8, 2006..................................................   105

                               STATEMENTS
                             April 24, 2006

Bunning, Hon. Jim, U.S. Senator from Kentucky....................     1
Geertsema, Dr. Arie, Director, University of Kentucky Center for 
  Applied Energy Research........................................    12
Hawkins, David G., Director, Climate Center, Natural Resource 
  Defense Council................................................    18
Miller, Clarence L., Director, Office of Sequestration, Hydrogen, 
  & Clean Coal Fuels, Office of Fossil Energy, Department of 
  Energy.........................................................     2
Ramsbottom, D. Hunt, President and CEO, Rentech, Inc., Los 
  Angeles, CA....................................................    26
Roberts, James F., President and CEO, Foundation Coal 
  Corporation, Linthicum Heights, MD, on behalf of the National 
  Mining Association.............................................    30

                              May 1, 2006

Alexander, Hon. Lamar, U.S. Senator from Tennessee...............    43
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................    46
Boycott, William A., General Manager, Kenai Nitrogen Operations, 
  Agrium U.S. Inc., Kenai, AK....................................    76
Bruce, William F., President, BRI Energy, LLC, New Smyrna Beach, 
  FL.............................................................    70
Douglas, William C., Senior Vice President, Business Development, 
  Econo-Power International Corporation, Houston, TX.............    72
Ferguson, Brian, Chairman and Chief Executive Officer, Eastman 
  Chemical Co., Kingsport, TN....................................    63
Garman, David K., Under Secretary, Department of Energy, 
  accompanied by George Rudins, Deputy Assistant Secretary for 
  Coal and Power Systems.........................................    47
Herzog, Antonia, Staff Scientist and Climate Advocate, Climate 
  Center, Natural Resources Defense Council......................    84
Murkowski, Hon. Lisa, U.S. Senator from Alaska...................    61
Thomas, Hon. Craig, U.S. Senator from Wyoming....................    45

                              May 8, 2006

Adamson, Dan, Vice Chair, Legislative Affairs Committee, National 
  Hydropower Association.........................................   116
Bingaman, Hon. Jeff, U.S. Senator from New Mexico................   106
Craig, Hon. Larry E., U.S. Senator from Idaho....................   105
Edison Electric Institute........................................   139
Fahlund, Andrew, Vice President for Conservation, American 
  Rivers, Steering Committee Member, Hydropower Reform Coalition.   122
Finfer, Lawrence, Acting Director, Office of Policy Analysis, 
  Department of the Interior.....................................   112
Robinson, J. Mark, Director, Office of Energy Projects, Federal 
  Energy Regulatory Commission...................................   107
Thomas, Hon. Craig, U.S. Senator from Wyoming....................   106

                                APPENDIX

Responses to additional questions:
    April 24, 2006...............................................   145
    May 1, 2006..................................................   164
    May 8, 2006..................................................   172

                      COAL LIQUEFACTION TECHNOLOGY

                              ----------                              

                         MONDAY, APRIL 24, 2006

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                     Washington DC.
    The committee met, pursuant to notice, at 2:30 p.m., in 
room SD-366 Dirksen Senate Office Building, Hon. Jim Bunning 
presiding.

   OPENING STATEMENT OF HON. JIM BUNNING, U.S. SENATOR FROM 
                            KENTUCKY

    Senator Bunning. The full committee hearing will come to 
order. First of all I'd like to welcome all of you to the first 
of a series of Monday afternoon energy committee hearings. 
After years of hard work in this committee, we finally passed a 
comprehensive energy piece of legislation last year. Each of 
these Monday hearings will examine provisions of the Energy 
Policy Act of 2005 and discuss their implementation and 
benefits.
    Today's hearing will focus on the coal-to-liquids or CTL 
technology. This promising technology transforms coal into 
liquid fuels such as diesel and jet fuel and while it has faced 
hurdles in the past, sustained higher energy prices have 
encouraged companies and their scientists to redouble their 
efforts to push this technology into the market place. With 
this in mind, the Energy Information Administration estimates 
by the year 2030, 180 million tons of coal will be used to 
produce high quality liquid fuels. That translates into 
production of between 800,000 and 1.7 million barrels per day 
of domestic CTL fuel. Looking at these numbers, I am proud to 
come from a coal State.
    Kentucky is home to large deposits of America's most 
abundant domestic fuel as well state-of-the-art clean coal 
research and development. I know that the people in my State 
would like to become part of the solution to our addiction to 
foreign oil. I believe coal-to-liquids technology offers 
America the chance to capitalize on a domestic resource that 
will provide the energy for economic growth and a new level of 
energy security required in today's world. With such a strong 
potential to provide a domestic alternative to imported oil, I 
want to make sure the Federal Government is doing all it can to 
push this coal technology into widespread implementation.
    On our first panel, the Department of Energy will testify 
about its role in the new technology. We will explore how loan 
guarantees granted under title XVII of the Energy Policy Act of 
2005 can help develop and deploy coal-to-liquid technologies. 
We will also examine that institutional barriers stand, what 
institutional barriers stand in the way of more rapid 
deployment and identify opportunities for the DOE and other 
Federal agencies to promote this technology. The second panel 
will help us address the transition from CTL technology into 
commercial viability facilities. Private companies who are in 
the process of building CTL plants will share their experiences 
and propose models for the Government's support and 
involvement.
    The director for the Center for Applied Energy Research at 
the University of Kentucky who oversees cutting edge 
experiments on CTL technology will discuss the state of the 
current research. I want to especially thank UK, for traveling 
here today so that we can hear their important testimony.
    Finally, the environmental community will share their 
thoughts as we discuss how implementation of this technology 
can be done in the most environmentally sound manner. I look 
forward to the testimony of the witnesses before the committee 
today.
    I guess you're on now, Dr. Miller.

     STATEMENT OF CLARENCE L. MILLER, DIRECTOR, OFFICE OF 
 SEQUESTRATION, HYDROGEN, & CLEAN COAL FUELS, OFFICE OF FOSSIL 
                  ENERGY, DEPARTMENT OF ENERGY

    Dr. Miller. Thank you, Mr. Chairman. I'd first like to 
express my thanks and appreciation for the opportunity to 
introduce the subject of coal-to-liquids. Coal is the most 
abundant fossil fuel resource in the United States. Recoverable 
coal reserves are estimated at 267 billion tons. As coal mining 
technology improves and additional geologic information becomes 
available, this reserve estimate will grow since it is based on 
current mining methods and the measured and indicated reserves 
within a total U.S. coal resource base estimated at nearly four 
trillion tons. These coal resources are widely distributed 
throughout the United States with recoverable reserves located 
in 33 States. Based on current annual production of nearly 1.1 
billion short tons, the United States has an approximate 250 
year supply.
    Utilizing this resource, the production of liquid fuels 
from coal has a long history and significant advances made in 
technology over the past two decades make it a potential 
component of a strategy to increase domestic production of 
liquid fuels. In the early 1900's, this coal was first reacted 
with hydrogen and process solvent at high temperature and 
pressure and produced a coal derived liquid or synthetic crude 
oil. This direct liquefaction approach was later improved and 
used by Germany in the Second World War to fuel the Luftwaffe 
with high octane aviation gasoline. In the 1920's, two German 
scientists, Fischer and Tropsch, passed a synthesis gas 
consisting of carbon monoxide and hydrogen over metallic 
catalysts and produced pure hydrocarbons. These hydrocarbons 
produced by the Fischer-Tropsch process proved to be excellent 
transportation fuels. This overall coal-to-liquids process 
known as indirect liquefaction, because it first involves 
complete breakdown of the coal to a synthesis gas, was used 
commercially in the 1950's by the South African Synthetic Oil 
Corporation, commonly known as SASOL, to produce transportation 
fuels, gasoline and diesel. Since then, SASOL has built two 
large facilities to produce over 150,000 barrels per day of 
transportation fuels.
    The U.S. Government, directly and through industrial 
partnerships and international cooperation, has, for over 30 
years, supported R&D on both direct and indirect coal 
liquefaction technology and processes. The Government programs 
resulted in improved processes, catalysts, and reactors which 
has contributed to reduced cost and improved product quantity 
and quality.
    Liquid fuels from coal are clean, refined products 
requiring little if any additional refinery processing, are 
compatible with petroleum products, and, therefore, can use the 
existing fuels distribution and in-use infrastructure. 
Preliminary studies indicate that a first plant cost utilizing 
this technology would have products in the $45 per barrel range 
but no U.S. commercial plants have been built making these cost 
estimates difficult. Still more difficult to estimate is the 
cost of production of subsequent plants but some studies 
indicate that coal liquids might eventually be produced in the 
$35 to $40 per barrel range as domestic construction and 
operational experience is gained.
    However, there are significant existing impediments to 
deploying CTL technologies. First and foremost is the 
uncertainty and volatility of the world oil price. Other 
impediments include high capital investment for the plants, 
technical and economic risks associated with first-of-a-kind 
plants, environmental concerns associated with increased coal 
production and utilization, and siting and ``not in my back 
yard'' issues for new plants.
    Environment concerns can be addressed by using clean coal 
technologies to reduce emissions of criteria pollutants and in 
the future to capture and sequester carbon dioxide to limit 
greenhouse gas emissions. At present, no requirements exist in 
the United States to manage carbon emissions from fossil fuel 
resources, however, in full recognition of the importance of 
carbon management an extensive research and development program 
is in progress to develop technology, processes, and systems to 
capture and store the carbon dioxide produced during the 
conversion process.
    Although past Department efforts and some congressionally 
directed funding has focused on production of liquid fuels from 
coal, the fiscal year 2007 budget does not support these 
activities. Coal-to-liquids is a mature technology receiving 
funding from the private sector for evolutionary advances and 
incremental improvements and, therefore, not consistent with 
the administration's research and development investment 
criteria. However, the fiscal year 2007 budget does support 
production of hydrogen from coal and some funding will be used 
for development of liquids that while not directly applicable 
for conventional internal combustion engines, could be an 
efficient way to move fuel for hydrogen applications through 
the existing infrastructure. The resource exists, current 
technology is available, and it is possible that continued 
evolutionary R&D will produce advanced processes that will 
continue to modify the economic and environmental performance 
of those processes used in the implementation of a coal-to-
liquid industry for the production of alternate fuels. These 
fuels could contribute to reducing our dependence on oil 
imports and significantly contribute to the Nation's energy 
security.
    This completes my testimony and I would be pleased to 
respond to your questions.
    [The prepared statement of Dr. Miller follows:]

     Prepared Statement of Clarence L. Miller, Director, Office of 
 Sequestration, Hydrogen, & Clean Coal Fuels, Office of Fossil Energy, 
                          Department of Energy

                                SUMMARY

    The United States' future economic security will remain linked to 
an efficient transportation system of air, rail, and highway vehicles 
that depend on a continuous supply of affordable liquid fuels with 
characteristics enabling vehicle manufacturers to meet increasingly 
stringent environmental regulations. In the current supply/demand 
situation, the Nation's transportation fuel requirements are met in 
part by crude oil and refined products from unstable regions of the 
world. Crude oil delivery and refining in the Untied States is 
concentrated in the Gulf Coast region, which presents concerns 
regarding destructive weather conditions. Additional challenges, 
including urban and regional air pollution, greenhouse gas emissions, 
and the availability and cost of transportation fuels, present unique 
issues that must be addressed to safeguard economic growth, social 
stability and public health.
    Technology is now in hand for producing synthetic oil, and oil 
products from coal. Liquid fuels from coal are clean, refined products 
requiring little if any additional refinery processing, are fungible 
with petroleum products and, therefore, can use the existing fuels 
distribution and end-use infrastructure. There are preliminary analyses 
[Mitretek Technical Report 2005-08, ``A Technoeconomic Analysis of a 
Wyoming Located Coal-To-Liquids Plan''] that indicate synthetic oil 
costs may drop into the $35 per barrel range after several initial 
higher cost plants are built. This estimate assumes near-zero 
atmospheric emissions of criteria pollutants, assumes reduced water use 
through air coolers instead of water cooling, and assumes carbon 
capture and sequestration. However, no commercial U.S. plants have been 
built. The primary barrier to commercial introduction of the technology 
has been the volatility and uncertainty of world oil prices. The 
private sector financial markets are best positioned to evaluate 
whether, when, and how to build coal to liquids plants given this 
market uncertainty.

                              THE RESOURCE

    Coal is the most abundant fossil fuel resource in the United 
States. Recoverable coal reserves are estimated (as of January 1, 2005) 
at 267 billion tons. As coal mining technology improves and additional 
geological information becomes available, this reserve estimate will 
grow, since it is based on current mining methods and the measured and 
indicated reserves within a total U.S. coal resource base estimated at 
nearly 4 trillion tons. These coal resources are widely distributed 
throughout the United States with recoverable reserves located in 33 
states.
    Based on current annual production of nearly 1.1 billion short 
tons, the United States has an approximate 250-year supply. However, 
this estimate needs to be placed within the context of the projected 
use of domestic coal in the United States and how coal reserves and 
resources are defined and quantified. To the first point, the Energy 
Information Administration (EIA) projects a steady rise in coal 
consumption to 1.78 billion short tons by 2030 in its reference case 
forecast. The increase is largely due to the projected increase in new 
coal-fired power generating capacity, projected to increase at 1.7% per 
year through 2030. To the second point, the EIA estimates the 
``demonstrated coal reserve base'' at 494 billion short tons. With 
anticipated advances in mining technology, there is the potential to 
access a significant portion of the reserve base, and support some 
degree of increased production of coal for a coal-to-liquids industry.

                 BACKGROUND: COAL TO LIQUIDS PRODUCTION

    Production of liquid fuels from coal has a long history, and the 
significant advances made in technology over the past two decades make 
it a potential component of a strategy to increase domestic production 
of liquid fuels. In the early 1900's coal was first reacted with 
hydrogen and process solvent at high temperature and pressure, and 
produced a coal-derived liquid or synthetic crude oil. This direct 
liquefaction approach was later improved and used by Germany in the 
second world war to fuel the Luftwaffe with high octane aviation 
gasoline. In the 1920's two German scientists, Fischer and Tropsch, 
passed synthesis gas--consisting of carbon monoxide and hydrogen--over 
metallic catalysts and produced pure hydrocarbons. These hydrocarbons 
produced by the Fischer-Tropsch (FT) process proved to be excellent 
transportation fuels. This overall coal-to-liquids process, known as 
indirect liquefaction because it first involves complete breakdown of 
the coal to synthesis gas, was used commercially in the 1950's by the 
South African Synthetic Oil Corporation (SASOL) to produce 
transportation fuels (gasoline and diesel) using synthesis gas produced 
by the gasification of coal. Since then, SASOL has built two large 
facilities that produce over 150,000 barrels per day of transportation 
fuels. The South African government enabled these plants to be built by 
providing a price floor safety net for SASOL's coal liquids. In both 
cases, Nazi Germany and Apartheid South Africa, the primary motivation 
for government support of coal liquids was that the countries were not 
able to access world oil markets.

                           TECHNOLOGY STATUS

    The U.S. Government--directly and through industrial partnerships 
and international cooperation--has for over 30 years supported R&D on 
both direct and indirect technology. The Government programs resulted 
in improved processes, catalysts and reactors. These indirect 
liquefaction of coal processes produce clean, zero sulfur liquid fuels 
that are cleaner than required under the EPA Tier II fuel regulations. 
These fuels are compatible with petroleum fuels and can utilize the 
same distribution infrastructure. Because these fuels are essentially 
refined products, very little if any additional refinery capacity would 
be needed for their upgrading. Indirect liquefaction technology has a 
proven track record and is technically viable. Although SASOL has 
successful commercial plants in operation, the integration of modem 
entrained-flow coal gasification with advanced slurry-phase FT 
synthesis has not yet been demonstrated. Preliminary studies [Mitretek 
Technical Report 2005-08] indicate that first plant costs would have 
products in the $45 per barrel range, but no commercial U.S. plants 
have been built, making cost estimates difficult. Still more difficult 
to estimate is the cost of production for subsequent plants, but these 
studies indicate that coal liquids might eventually be produced in the 
$35 per barrel range if domestic construction experience is gained. 
However the principal market barrier discussed would remain. China, 
with an increasingly large appetite for liquid fuels, scarce supply of 
domestic petroleum and large coal resources, is reportedly moving 
toward commercialization of coal-to-liquids technologies. In the U.S. 
demonstration plant to produce liquid transportation fuels from 
anthracite waste was competitively selected in January 2003 under DOE's 
Clean Coal Power Initiative. However, the project has been unable to 
obtain financing for the private sector cost share.

                     OPPORTUNITIES AND IMPEDIMENTS

    As noted, the U.S. is endowed with over 267 billion tons of 
recoverable coal reserves, equivalent to 250 years supply at current 
usage rates. The opportunity exists to use coal-to-liquids (CTL) 
technologies to produce clean transportation fuels that could 
supplement petroleum supply if world petroleum prices remained elevated 
over the approximately 30-year time horizon required to pay back the 
significant initial capital investment.
    Despite current world oil prices, there are significant existing 
impediments to deploying CTL technologies: first and foremost, the 
uncertainty and volatility of the world oil price; high capital 
investment for the plants; technical and economic risks associated with 
first-of-a-kind plants; environmental concerns associated with increase 
coal production and the coal to liquids industrial process; public 
attitude to increased coal use; siting and ``not in my backyard'' 
issues for new plants; and increasing the supply of coal given a supply 
chain that is already stretched to capacity. Over the long term, the 
capital cost of the plants could be reduced by the experience gained in 
the actual construction and operation of commercial facilities. It is 
well documented that first-of-a-kind plants are always significantly 
more costly than subsequent or Nth plants. While coal 
liquids technology is proven, the domestic construction industry has an 
opportunity to reduce its costs with increased experience. 
Environmental concerns can be addressed by using clean coal 
technologies to reduce emissions of criteria pollutants, and in the 
future to capture and sequester carbon dioxide to limit greenhouse gas 
emissions. Siting issues can be mitigated by maximizing retrofit 
opportunities at existing coal-fired power plants.

                          ENVIRONMENTAL ISSUES

    The technology that underlies CTL fuel production offers the 
potential for low emissions of criteria and toxic air pollutants, water 
quality, and solid wastes. Nonetheless, this promise of high 
performance needs to be verified during the design and initial 
operations of first-of-a-kind CTL plants and costs may be prohibitively 
expensive. Significant water demand will remain a constraint on CTL 
fuel production, particularly in regions with limited water resources. 
Other key environmental issues are the impacts on land, land use and 
watersheds caused by coal mining and the traffic and local development 
associated with CTL plant construction and operations. These 
considerations may prevent the construction of CTL plants in particular 
areas. However, coal resources suitable for CTL fuel production are 
widely distributed throughout the United States. The impact of site-
specific environmental constraints on the development of a 
strategically significant CTL industry will depend in part on how 
environmental regulations are applied on local, regional, and national 
levels. Permitting delays should be anticipated, especially in view of 
the large size of and lack of experience in operating CTL plants. Even 
if the environmental risks are addressed, there is a very good 
possibility of public reluctance to accept the need for large new 
industrial facilities, particularly those using coal.
    At present, no requirements exist in the United States to manage 
carbon emissions from fossil fuel sources. However, in full recognition 
of the importance of carbon management an extensive research and 
development program is underway to develop technology, processes and 
systems to capture and store the carbon dioxide produced during the 
conversion process. The carbon dioxide could be stored in deep saline 
formations or sold for use in enhanced oil recovery operations. It is 
possible that CTL plant emissions and the emissions from utilization of 
CTL products would be comparable to those associated with the 
production and consumption of petroleum-based fuels.

                               NEXT STEPS

    The greatest market barrier for CTL is the volatility and 
uncertainty of future world oil prices. The private sector is best 
positioned to evaluate market or oil price risk and respond accordingly 
with an appropriate deployment strategy.
    Although past department efforts and some Congressionally directed 
funding has focused on production of liquid fuels from coal, the FY 
2007 Budget does not support these activities. Coal to liquids is a 
mature technology receiving funding from the private sector for 
evolutionary advances and incremental improvements and therefore not 
consistent with the Administration's Research and Development 
Investment Criteria. Although the FY 2007 Budget does not directly 
support CTL technology, there are some overlapping activities directed 
at electricity and hydrogen generation that the private sector could 
apply to reducing production costs and technical risks, and improving 
environmental performance of coal to liquids plants. The FY 2007 Budget 
supports production of hydrogen from coal and some funding will be used 
for development of liquids that while not applicable for conventional 
internal combustion engines because their hydrogen content is too high, 
could be an efficient way to move fuel for hydrogen applications 
through existing infrastructure. The FY 2007 Budget promotes the goal 
of reducing dependence on foreign sources of oil through development of 
technologies consistent with the Research and Development Investment 
Criteria, such as cellulosic ethanol, battery technology, and hydrogen, 
among others. Over the mid to long term, these technologies could 
reduce demand for conventional sources of petroleum and ease pressures 
on world oil prices.
    The resource exists, current technology is available and it is 
possible that continued evolutionary R&D will produce advanced 
processes that will continue to modify the private sector's analysis of 
whether the economic and environmental performance of the processes 
used in the implementation of a coal-to-liquids industry for the 
production of alternate fuels justify plant construction, in tandem 
with the primary consideration of petroleum market risk.
    If economic, these fuels could contribute to reducing our 
dependence on oil imports and significantly contribute to the Nation's 
energy security.
    This completes my testimony, and I would be pleased to respond to 
your questions.

    Senator Bunning. Thank you, Dr. Miller. First question is 
one about the, since we passed the energy bill and I have not 
seen any movement on the part of DOE to implement the loan 
guaranteed program. What is the status of this program and what 
loan guarantees--are there any for CTL projects?
    Dr. Miller. I'm afraid I don't have the information to 
answer that particular question but I do know that there is 
considerable activity in progress and the Department is 
supporting the efforts of the Treasury Department and other 
relevant agencies in the preparation of the criteria that would 
be used in the application of those incentives.
    Senator Bunning. Well, I suggest that you go back to your 
Department of Energy and find out exactly what their program is 
going to be to implement the provisions in the energy bill for 
CTL projects.
    Dr. Miller. I'll be happy to and we'll submit that back for 
the record for you.
    [The information follows:]

    The Department of Energy (DOE) has established a loan 
guarantee office under the Department's Chief Financial 
Officer. In implementing the program, we will follow the 
Federal Credit Reform Act of 1990 (FCRA) and Office of 
Management and Budget (OMB) guidelines, and we will emulate 
``best practices'' of other federal agencies. Toward that end 
we are drafting program policies and procedures, establishing a 
credit review board, and plan to employ outside experts.
    Title XVII of EPAct 2005 authorizes DOE to implement loan 
guarantee programs for projects that avoid, sequester, or 
reduce air pollutants and/or anthropogenic emissions of 
greenhouse gases, and ``employ new or significantly improved 
technologies as compared to commercial technologies in service 
in the United States at the time the guarantee is issued.'' 
Projects that employ coal gasification or liquefaction may be 
eligible under the Act to apply for loan guarantees.
    Title XVII allows for project developers to pay the cost of 
loan guarantees issued by DOE. While this ``self pay'' 
mechanism may reduce the need for appropriations, it does not 
eliminate the taxpayer's exposure to the possible default of 
the total loan amount. Therefore, DOE's evaluations of 
applications will entail rigorous analysis and careful 
negotiation of terms and conditions.
    FCRA contains a requirement that prevents us from issuing a 
loan guarantee until we have authorization to do so in an 
appropriations bill. We do not believe we have authority to 
proceed with an award absent having the necessary explicit 
authorization in an appropriations bill.

    Senator Bunning. Thank you. I appreciate that. Dr. Miller, 
are the Department's resources sufficient to pursue rapid 
development and deployment of coal-to-liquid technologies?
    Dr. Miller. Mr. Chairman, we would expect that that will be 
the responsibility of industry. As noted in the testimony, the 
technology is commercial, it is being pursued by a number of 
potential industries that we are aware of and we would expect 
them to pursue and, when economic or appropriate, implement 
that kind of an industry.
    Senator Bunning. Then you are saying there are enough 
resources at DOE to assist a commercial development of CTL?
    Dr. Miller. You are correct. We are actively involved in 
assisting industry in doing a lot of estimates and assessments 
of the technology and in the application of the technology.
    Senator Bunning. When will DOE's guidance be issued and 
when will DOE's--DOE be accepting applications for the loan 
guaranteed program? What do you foresee as a timetable for this 
program?
    Dr. Miller. Once again, Mr. Chairman, that's an answer I'm 
going to have to submit to the record and it will be part of 
the other answer simply because the DOE is not responsible for 
producing the actual criteria for the implementation of those 
incentives. We wouldn't----
    [The following was received for the record:]

    We are in discussions with OMB regarding the guidelines and 
anticipate issuing them as soon as is practicable.

    Senator Bunning. But in the bill, didn't we specify that 
there would be guidelines set out by DOE?
    Dr. Miller. That is true and we are following the 
requirements of the EPAct precisely and in EPAct there are 
dates set for the delivery of each of those particular items 
and we're following that the Secretary has emphasized that his 
staff will meet those particular criteria and I know work is 
underway.
    Senator Bunning. As you know, the Department of Defense has 
expressed great interest in the CTL technology as a way to 
produce a secure domestic fuel source for our military. Section 
369 of the energy bill provided that DOE participate in the 
Department of Defense Assured Fuel Program to evaluate the 
potential of CTL for use by the military. What is the status of 
that program presently?
    Dr. Miller. I do know that that report has been prepared, I 
do know that it has been submitted to the department's 
concurrence process and that is----
    [The following was received for the record:]

    We have been working quite closely with representatives of 
the Department of Defense on their Assured Fuels Program/
Initiative. A draft report has been prepared in response to the 
requirements of Conference Report 109-360 and it does consider 
the status of the coordinated efforts on the initiative that 
have taken place between the Department of Defense and the 
Office of Fossil Energy.

    Senator Bunning. The Department of Energy or the Department 
of Defense?
    Dr. Miller. I'm sorry. To be more clear, we have--
Department of Energy has completed the draft report, we have 
submitted it to our management structure for concurrence, and 
it is somewhere in that process. We will meet the date.
    Senator Bunning. But DOD, Department of Defense, does not 
have that report currently?
    Dr. Miller. That I can't answer. I don't know whether it's 
been transferred over to them for their review or not.
    Senator Bunning. Senator Thomas, would you like to get in 
on the questions?
    Senator Thomas. Yes, I would. Thank you.
    Senator Bunning. Thank you.
    Senator Thomas. Thank you very much. Thank you for even 
being here, Dr. Miller. Appreciated your being in Wyoming a 
week or so ago for a conference we had there. And on this very 
topic, as a matter of fact.
    Dr. Miller. Correct.
    Senator Thomas. So we appreciate that very much. Since I 
wasn't here at the beginning, I just have to share with you a 
thought or two that I think as Senator has pointed out, I think 
we have a policy in place that moves this in this direction and 
now our challenge is to implement that policy and I think in 
some cases to differentiate between those alternative sources 
that are out there 30 years from now or 20 years from now and 
those that we know how to be able to do now, if we can put into 
place the initiatives and the operations to do some of those 
things. So, for instance, the energy policy, of course, 
establishes a loan guarantee program which covers 80 percent of 
the cost associated with some of these projects, authorizes a 
billion dollars over three years of conversion to coal-to-
liquids.
    So I guess that's really what I'm interested in is how we 
can move a little more quickly. There's quite a bit of the 
private sector that's ready to go. They're out there kind of 
wondering how can we get the approval, how can we get involved 
in the incentives that are available, and just kind of holding 
the thing up. So do you think the structure in the Department 
of Energy is sufficient to pursue this? Should there be a 
separate program specifically designed to pursue the coal-to-
liquid research development demonstration or is it lost in the 
bureaucracy of the total bureau?
    Dr. Miller. As I noted in my verbal testimony, we are 
participating, as we're being requested to by industry, in 
feasibility studies and in reports assessments of the 
technology. The Department considers that the technology is 
commercial and it is being pursued by a number of industries 
and it really is not in the investment criteria that we now are 
following as it is commercial and we're assuming that private 
sector will now make whatever technology advances are necessary 
to meet their goals and objectives.
    Senator Thomas. But these objectives and goals and this is 
a very expensive operation and one that needs to have some 
assurance that there's going to be a long-standing market here 
before making that tremendous investment. So I don't think 
we're talking about doing the research. I think we're talking 
about putting into place the incentives, the dollar incentives, 
whether they be loan guarantees or whether they be incentives 
that will give the people who already have the technology--
we've got a company in Wyoming waiting to make diesel fuel but 
we haven't gotten the criteria for the application, for the 
dollars to take advantage of what's in the bill at this time 
and I understand it's because the Department isn't ready to do 
that.
    Dr. Miller. Senator Thomas, we've always, even in the R&D, 
we've recognized for some time that the volatility and the 
price fluctuations in the world oil market is a major 
impediment to the implementation of any coal-to-liquids 
industry. We've gone through this on several cycles where we 
have started a coal-to-liquids industry and then had the floor 
of the world oil price drop out and not be able to continue. We 
consider, and after looking at EPAct 5, we recognize that that 
contains the mechanism for implementing a program of 
incentives, we recognize that they are there and I know that 
the Department--I am not part of that particular activity but 
aware of the fact that the Department--is moving very rapidly 
to implement the terms and the intent of EPAct 5. And as I've 
already mentioned, we will be back to the Congress with a memo 
to the record telling or stating exactly what the progress is, 
what the schedule is, to the best that we can and it will be 
submitted for the record.
    Senator Thomas. I appreciate that but I have to tell you 
that particularly given what the President's saying these days 
with respect to the oil business and the oil shortage and so 
on, committed to doing something of this kind. And the fact is 
that times have changed pretty clearly. In the past I know we 
did wonder whether we would be out of the oil thing but now 
that we see India and China going the way they are we know that 
this is a permanent problem, this business of relying--and 
fossil fuel is our greatest resource. From a technical 
standpoint now one of the issues is going to be the politics of 
setting up these plans, I suppose, and we as you know, I've 
specifically said in the bill that we want to have some of this 
gasification at an altitude of over 4,000 feet. And I hope that 
we can recognize that's where the coal is and that we ought to 
be moving along getting--the problem now, as you know, of using 
coal is that you get $15 for the coal and it costs $30 to get 
it to the market in a railroad car.
    Dr. Miller. I would concur.
    Senator Thomas. And so one of the things we can do is take 
advantage of our greatest resource by being able to modernize 
it. So I appreciate what you're doing but I just have to close 
by saying that I do think there doesn't seem to be quite the 
anxiety to get moving in the bureaucracy as there is in the 
private sector and I hope we can bring those two things 
together.
    Dr. Miller. I think as time goes on you'll see that that 
feeling of urgency is also in the Department as they complete 
the requirements under EPAct 5 and submit the documents that 
are requested in that particular document. As an aside, I feel 
it's important to note that with respect to your concern about 
technology, the R&D program is well-prepared with technology 
that can operate and under the conditions that are of some 
concern.
    Senator Thomas. Thank you.
    Senator Bunning. Dr. Miller, this is only one alternative 
we put in the energy bill. This is one of many alternatives for 
synthetic fuels or other fuels to get our dependency out of the 
Middle East and create a situation where we can do like Brazil 
has done. All of a sudden they have 85 percent of their own 
fuel being produced domestically and then used by alternative 
vehicles that have been produced domestically. So I want you to 
make sure that we only--not only do we need this alternative 
that we're talking about but we need many others whether it be 
bio-diesel, whether it be ethanol or whatever it might be.
    I gave you some information earlier about the energy 
information projections for coal-to-liquid technology usage for 
the next 25 years in my earlier statement. Do you believe these 
predictions of large scale CTL usage are attainable?
    Dr. Miller. I do.
    Senator Bunning. You do believe that?
    Dr. Miller. Yes.
    Senator Bunning. And that's why it's so important for the 
Department to get geared up so that those commercial usage 
people can--we're never going to have a stable oil price. You 
can mark it down. It's going the fluctuate between somewhere 
between $50 and $100. It may go over that. So unless we are 
positive about where we're heading with this program and the 
Department of Energy is ready to assist because of the 
instability of the price of oil. We're trying to take that 
instability away. That's the whole idea of the energy bill last 
year to make sure that we have a domestic source of something 
and we're not dependent on the Middle East for their petroleum. 
So this is very important for us.
    Could you explain your current TCL research efforts and 
discuss why past research initiatives failed to create a 
sustained marketplace for CTL products?
    Dr. Miller. Yes, I can. First, Mr. Chairman, let me go back 
to one of your assessments in the introductory comments. You 
are aware I'm sure that my expertise is coal-to-liquids and has 
been for a number of years, however, my other duties have made 
me aware and I'm sure you're aware that in our Office of Energy 
Efficiency and Renewable Energy there is a great experimental 
effort going on on each of those alternate fuels, that 
alternate technologies for the production of alternate fuels 
that must be made in order to accomplish the supply of liquid 
fuels that are required. We're also now looking at the 
production of hydrogen from coal. The technology for the 
production of hydrogen from coal is very similar and consistent 
with some of the work that has to be done to improve the 
efficiency, improve the quality and quantity of a coal-to-
liquids facility. So we are still working on those kind of 
advanced technologies, exciting technologies that have a great 
deal of opportunity to ensure that we arrive at an economic 
supply of alternate liquids from coal.
    Senator Bunning. My last question, I have some others I'll 
submit to you for the record but my last question is: section 
417 of the energy bill authorizes $85 million to test advanced 
technologies for the protection of transportation fuels 
manufactured from Illinois base coal. It also provides funding 
for the construction of testing facilities at the University of 
Kentucky's Center for Applied Energy Research, the Southern 
Illinois University Coal Research Center and the Energy Center 
at Perdue University. Could you provide an update on this 
initiative.
    Dr. Miller. That initiative has been addressed as one of 
the requirements of EPAct 5 and we have prepared a submission 
that is consistent with the associated date for that so I do 
know that there has been an analysis done, I do know that there 
has been some conversation with the Consortium of Universities 
and that report has been prepared. I will have to find out the 
status but I do know that we have addressed that, we have 
prepared a deliverable, and I'll just have to check where it 
is.
    Senator Bunning. Just so our energy committee staff gets a 
copy of that because it's essential that we know what's going 
on.
    Dr. Miller. Okay. I will certainly get back to you with 
that.
    [The information follows:]

    Section 417 authorizes $85 million for the period of fiscal 
years 2006 through 2010 to do R&D on transportation fuels from 
coal at specific universities using designated coals. This 
section further states that ``not later than one year after the 
date of enactment of this Act, the Secretary shall offer to 
enter into agreements . . .'' to do Fischer-Tropsch R&D and to 
modify/construct appropriate facilities at the referenced 
universities.
    However, the Department has not identified funding 
available to do the authorized work. The Department's FY 2006 
enacted appropriation and the FY 2007 budget request did not 
include funding for this effort. It should be noted that the 
Department has not asked for Coal-to-Liquid (CTL) R&D funding 
for several years. The earlier effort to develop CTL technology 
has been considered a success, as it lowered the cost of the 
coal derived product to a $35 per barrel range for large mature 
plants ($45 per barrel range for first-of-a-kind, commercial 
facilities). These costs are considered to be competitive with 
other forms of energy and an indicator of the commercial status 
of the technology. Further R&D to marginally reduce these costs 
would be costly.

    Senator Bunning. Senator Thomas, do you have any more?
    Senator Thomas. No.
    Senator Bunning. I want to thank you for coming today. 
We'll submit three other questions I have for the record and I 
appreciate you coming today.
    Dr. Miller. Again, I thank the committee for the 
opportunity to introduce you into coal-to-liquids and where the 
status of the technology is.
    Thank you.
    Senator Bunning. Thank you. If the second panel would come 
up and staff would get ready for them. I hope I don't destroy 
your name in the pronunciation of it. Dr. Arie Geertsema.
    Dr. Geertsema. Pretty close, Mr. Chairman.
    Senator Bunning. Pretty close. Okay. Mr. David Hawkins, Mr. 
Hunt Ramsbottom, and Mr. James Roberts. Doctor, you are our 
initial man so you start us off.

   STATEMENT OF DR. ARIE GEERTSEMA, DIRECTOR, UNIVERSITY OF 
          KENTUCKY CENTER FOR APPLIED ENERGY RESEARCH

    Dr. Geertsema. Thank you, Mr. Chairman, ladies and 
gentlemen. Thank you very much for the opportunity to be here 
and the invitation to talk to you this afternoon. As 
background, I've been with the South African company SASOL for 
about 20 years of which 3 years as a works manager of the SASOL 
I plant and the last 10 years as the person in charge of 
corporate research and development. I was in Australia involved 
with gas to liquids for a number of years before I joined the 
University of Kentucky as director for the Center for Applied 
Energy Research about 5 years ago.
    I wish to discuss how progress can be made to establish a 
viable, sustainable coal-to-liquids industry in the USA. And 
I'll focus on coal-to-liquids and gasification from a 
technology development and project execution perspective. In my 
written testimony I mentioned a number of factors which 
contributed to SASOL's success. In the interest of time, I will 
not dwell on those now but I'm pleased to note that provisions 
of the EPAct regarding loan guarantees and thick tax credits 
will similarly facilitate the early deployment of coal-to-
liquids in collaboration with industry. Also subsequent ongoing 
legislation will strengthen this approach. I think one should 
note that this applies not only to coal-to-liquids in a generic 
sense but specifically to fuels, chemicals, and also to 
industrial gasification facility and also synthetic natural 
gas.
    In support of implementing the intent of the Energy Policy 
Act, I suggest that serious consideration be given to 
reestablish official coal-to-liquids program in the DOE fossil 
energy budget. I say that with respect to the testimony that 
Dr. Miller has just submitted. In the DOE there are indeed 
components of CTL being addressed right now but CTL as such 
doesn't appear as a programmatic line any more. There are 
projects which proceed along the lines of the Clean Coal Power 
Initiative which involve Fischer-Tropsch technology in direct 
liquefaction but I believe we urgently need a broad-based 
research, development, and deployment program covering 
enabling, developmental, and piloting work. The benefits of 
such work are in my opinion clear. Human resources could be 
generated that way. They're urgently needed across the board at 
the moment in the coal field, coal technology field. It will 
provide a basis for process development and it will create 
facilities to provide test quantities of finished products of 
different grades. And the key thing here is that this will be 
open access research. At the moment, as Dr. Miller has 
indicated, companies can move forward but all that IP is so 
closely held that there is very little in the public domain and 
I think the sort of work that the DOE can fund and has funded 
in the past can open this up a bit.
    There's just been reference to section 417 by the chairman 
and I don't want to elaborate on that except to say that we 
have formed an alliance called the Coal Fuel Alliance and have 
submitted a request to the House Appropriations Committee for 
year one's appropriation to establish and expand the facilities 
in order to produce about half a barrel a day liquid fuels with 
the specific intents of coupling the synthesis with the 
refining to final products. That's a facility which doesn't 
exist anywhere and we at CAER have had experience with the open 
access type of research for quite a number of years, but that 
has not been put into the appropriations process formally yet.
    Going forward, I suggest that the emphasis should be first 
to establish larger scale facilities and, second, but in 
parallel to strengthen the R&D base by creating an aggressive 
Federal R&D program. I provided comments regarding cost 
estimates for project implementation. We all appreciate that 
large facilities generally provide an economy of scale whereas 
I also recognize that smaller facilities, and I'm talking of 
facilities in the range of maybe 5,000 or 10,000 barrels a day, 
might under specific circumstances also have a viable 
justification. That would have a sort of a penalty in terms of 
the capital cost outlay but circumstances are different from 
case to case.
    Looking ahead, I suggest that an initial target for coal-
to-liquids should be in the range of about a million barrels 
per day. I said initial and beyond that one can certainly take 
it further. A million barrels a day is only about 5 percent of 
the current consumption of liquid products in the United 
States. In going forward with this strategy, one should surely 
consider the construction capabilities, the coaling fact as was 
mentioned, and certainly also the human resource. All these 
things should be an integral part of that strategy.
    In this context I want to also alert you to the American 
Energy Security Study which was initiated through the Southern 
States Energy Board. The report is due by the end of June and 
this report will cover strategy, macro-economic impacts, and 
costs of the CTL and other technologies. Furthermore, it will I 
believe help to shape the paths to greater fuel self-
sufficiency.
    In conclusion, Fischer-Tropsch fuels are environmentally 
superior and as shown at the Great Plains facility in North 
Dakota CO2 capture and sequestration can be done 
successfully in a gasification facility. Second, the EPAct sets 
us on the right course. We need to pick up speed to facilitate 
together with industry the rapid building of facilities and 
simultaneously to broaden our R&D base. Third, I believe CTL 
economics support viable projects even at crude prices 
significantly below what we see today. And, lastly, commercial 
scale CTL has been done successfully and I believe it can be 
done again here in the United States.
    Thank you, Chairman.
    [The prepared statement of Dr. Geertsema follows:]

   Prepared Statement of Dr. Arie Geertsema, Director, University of 
           Kentucky Center for Applied Energy Research (CAER)

    Mr. Chairman and Members, thank you for the invitation to 
contribute to the discussion about gasification and coal to liquids 
(CTL) in the context of the Energy Policy Act of 2005.
    By way of introduction, I present some of my background. I was with 
the South African company Sasol, the world's only commercial coal-to-
liquids company, for 20 years. I was the Works Manager at the original 
Sasol One plant for three years and then led the corporate R&D of Sasol 
for a decade until the end of 1997. Then followed a period in Australia 
working on natural gas conversion to liquid fuels (GTL) before I joined 
the CAER in the beginning of 2001. I am therefore very familiar with 
both the theory and practice of CTL and gasification technologies.
    In this testimony I wish to share with you some of my views 
regarding the greater deployment of CTL technology and, more 
importantly, suggestions on how progress can be made to establish a 
viable and sustainable CTL industry in the USA. I do this on behalf of 
the CAER and also wish to note that I am a member of the executive 
panel for the Southern States Energy Board's ``The American Energy 
Security Study'' where I am the representative of the Kentucky Office 
of Energy Policy, a co-sponsor of the study. I am also representing the 
University of Kentucky in the three-university ``Coal Fuel Alliance''. 
I'll later comment on both these activities.
    I shall not dwell on the by now well-known compelling statistics 
regarding liquid fuels supply and projected demand coupled with 
strategic and security of supply considerations. I'd rather focus on 
CTL and gasification from a technology development and project 
execution perspective. I shall deal with CTL with emphasis on indirect 
(Fischer-Tropsch) rather than direct liquefaction.
    In Attachment A,* I present a brief review of aspects of the Sasol 
developments from which some pointers can be taken which have 
contributed to their known commercial success. Some of these aspects 
from especially the Sasol Two and Three experiences include:
---------------------------------------------------------------------------
    * Attachments A and B have been retained in committee files.

   A national will to reduce the import of crude oil for 
        transportation fuels existed
   The projects showed financial viability when started
   Government loan guarantees were provided
   A floor price mechanism (fuel prices are regulated in South 
        Africa) was established
   Timing, in retrospect, was ideal
   Rapid repayment of loans occurred and the company has long 
        been functioning financially independently in the private 
        sector and there are and were very significant macro-economic 
        benefits to the establishment of this industry
   Subsequent internationalization of the business and 
        diversification strengthened profitability
   Many further growth opportunities were implemented, and a 
        34,000 bbl/d Gas-to-Liquids plant in Qatar is due to be 
        inaugurated early in June 2006
   Ongoing significant investments in R&D are made and 
        technology developments improved profitability. ($60 million 
        for additional FT pilot units was announced this year.)

    Reflecting on the above considerations, one notices that the Energy 
Policy Act of 2005 provides a framework for establishing conditions 
which reflect spine of the mentioned Sasol success factors, such as 
loan guarantees and tax credits which will ease the financing of 
projects. The President clearly stated that the USA should move to a 
greater self-sufficiency regarding transportation fuels, with specific 
reference to coal derived fuels. Thus the strategic intent to promote 
CTL in the U.S. is developing and is set to gain further momentum as is 
reflected by legislation introduced by various senators since the 
enactment of the Energy Policy Bill of 2005.
    The latest DOE Fossil Energy budget contains some components for 
funding CTL related activities, like gasification, gas clean-up and 
CO capture with sequestration. However, CTL as such does not 
currently feature as a separate program. Although there are now 
commercial FT units, it is, in my opinion, justifiable to put CTL RD&D 
back into the DOE portfolio. The geopolitical and commercial 
circumstances now justify such a step. An increased level of funding at 
all levels of RD&D will greatly enhance future success, as will be 
discussed below. There has been support for projects of Syntroleum, 
Headwaters and WMPI (the latter two through the Clean Coal Power 
Initiative), some of which are still in negotiation. Demonstrations of 
this kind are appropriate but I believe a more broad-based program with 
a balance between enabling research, pilot units and demonstration 
facilities should be supported.
    In the deployment of CTL there is often an urge to deal with a 
perceived lack of commercial progress by promoting more Research and 
Development. Any technology can be improved by doing more R&D, as has 
been proven. In this case, I believe the short term thrust should be to 
get facilities built and to establish an experience base for the 
production of products and to simultaneously embark on a more 
aggressive R&D program. There is much to be gained by establishing an 
active FT CTL program in the U.S. again. There will be several 
substantial benefits from doing this:

   Currently the local human resources in this area, as in coal 
        technology in general, are scarce. By encouraging industrial 
        and DOE sponsored research, new human resources will be 
        cultivated at undergraduate and graduate level. Prototype pilot 
        plants can serve as valuable training grounds for operators and 
        technicians and can also be used for component level 
        development.
   The results from such R&D could be closely coupled to 
        operating facilities to ensure relevance to, optimize processes 
        and products further.
   Studies to improve product performance can be done much more 
        cheaply at a small pilot scale which needs to be a ``proof of 
        concept'' type facility where products of different 
        specifications could be produced for engine and turbine 
        testing. Especially with the great interest from the DOD in 
        ``single battlefield'' fuels, this could be an important asset.

    The Energy Policy Act of 2005, Section 417, authorized $85 million 
for the universities of Purdue, Southern Illinois and Kentucky to 
pursue the development of FT CTL based on Illinois basin coal.

   These universities entered into a Memorandum of 
        Understanding in October 2005 and have started collaborating 
        with seed funds made available by the respective state 
        governments. The name Coal Fuel Alliance (CFA) was chosen. A 
        request for the appropriation of funds for the first year was 
        submitted in March 2006 to the House Energy and Water 
        Appropriations Subcommittee. Attachment B is a copy of this 
        request. It outlines the rationale for the initiative with 
        emphasis on the first year's activities. A request of $14.5 
        million, which will be leveraged by contributions from the 
        universities and states to make $18.1 million available, was 
        submitted. The first step will be to establish a \1/2\ bbl/d FT 
        facility at CAER with a ``mini-refinery'' to produce products 
        for engine testing. This is on the critical path to generate 
        samples of different grades and qualities so that later, larger 
        facilities can be designed more specifically to meet targeted 
        specifications. These products will be tested in the engine 
        testing facilities at Purdue. Collaboration with the DOD to 
        make products in the ``mini refinery'' for their applications 
        is envisaged.
   The CFA wishes to carry on ``open'' research, such as the 
        CAER has done over many years. This implies not being locked in 
        to a single technology or having constraining IP limitations, 
        but rather to be available as a test bed for various 
        technologies and companies.
   The CFA has been in discussions with DOE NETL officers to 
        keep them informed of its plans. The CFA accepts that within 
        the current NETL programs and budget there is not provision for 
        the CFA activities but a profitable collaboration is foreseen 
        in the near future as appropriations might be made to the CFA.
   The plans for the next few years have started to take shape 
        although the CFA has not yet decided on details for the ``test 
        facility'' as foreshadowed in the Act.

    There are existing commercial technologies which could produce 
transportation fuels by using CTL. (This argument has been used in the 
past to terminate the DOE funded FT catalysis work.) However, FT 
technologies and applicable commercial experience are not necessarily 
readily available to all industrialists who wish to practice CTL. There 
are commercial reasons for this situation, which I do not want to go 
into now. I suggest that there will be great value in supporting a 
range of technological options for the various processes involved in 
CTL. For instance, various gasifier developments have been and are 
being supported. The same approach can be applied to CTL. By creating 
more options at the enabling, pilot and demonstration level, the market 
place and commercial realities can take implementation forward. Several 
factors are of importance and supported development of different 
approaches could help to address these matters:

   A CTL plant is comprised of a very complex integration of a 
        number of major process blocks such as coal gasification, air 
        separation (when an oxygen-blown gasifier is used), gas 
        cleaning, FT synthesis and FT product refining to final 
        products. There are also numerous infrastructural, 
        environmental control, ash handling and steam/power system 
        facilities which are essential. The full commercial integration 
        of these process steps for CTL has so far only been done by 
        Sasol. Building blocks at various levels of operational 
        readiness are offered commercially but more experience with 
        integrated facilities is needed to provide comfort to 
        financiers. A so-called ``wrap-around'' package from a 
        reputable company will greatly improve the bank-ability of CTL 
        projects. In this phase of uncertainty, support and 
        encouragement measures will be helpful.
   Recent estimates by the DOE, various consultants and Sasol 
        indicate that the capital outlay for a CTL facility could be 
        $60,000 per daily barrel or more provided it is of a meaningful 
        size, preferably about 50,000 bbl/d or larger to get good 
        economy of scale. These numbers are only indicative and the 
        actual cost will vary with the location, site-specific 
        conditions and other factors. This means that a 50,000 bbl/d 
        facility will cost at least $3 billion. It should however, be 
        noted that there are cases when smaller plants would suit the 
        needs of project developers or site specific circumstances 
        better. By accepting a certain ``dis-economy'' of scale, (a 
        higher capital cost per instilled capacity), the overall 
        project economics might still be attractive. There could for 
        instance, be a justification for facilities of 5,000 to 10,000 
        bbl/d to produce products for certification by the military for 
        special grades of fuel. There might also be developers who 
        prefer modular decentralized facilities rather than large 
        units.
   There are options for lowering the capital cost, such as 
        using a brown field site or co-locating with facilities and 
        sharing common infrastructure. Such cases are site specific and 
        generic economic numbers can be misleading and should be 
        avoided.
   The yield of liquid products in a CTL facility will depend 
        on the quality of the coal and also how much coal will be used 
        in a facility to co-produce the needed power for the plant, or 
        to produce additional power for export. A typical figure is 
        about 2 barrels per ton of coal. This implies that for a 
        100,000 bbl/d facility about 50,000 tons/day coal is required 
        or about 18.3 million tons per year.
   It seems on paper that a combination of CTL with IGCC (co-
        production) can be more attractive than only CTL. A few 
        considerations: Both CTL and IGCC plants should preferably be 
        running at high stable production levels and are not easily and 
        profitably suitable for short term ``peaking'' or load 
        following adjustments. For IGCC the profitability is very 
        dependent on the competitive price of power at the location of 
        the plant. From an operational perspective, this adds one more 
        level of complexity. However, for a CTL plant there is a 
        substantial amount of power required within the plant and 
        normally there will be on-site power generation using energy 
        resources from the process. Therefore, expanding such power 
        generation to a full-fledged IGCC facility should be considered 
        on a case-by-case basis. Synergies could well make this more 
        viable, albeit at a higher capital outlay.
   If one wishes to make a strategic impact, I consider about 1 
        million barrels/day as a meaningful initial target. (That is 
        less than 5% of the current 21 million barrels of oil and fuel 
        used in the U.S. daily). For this the coal supply would require 
        about a 20% increase above current coal consumption. The impact 
        of such a growth in coal production has to be considered 
        together with the ongoing projected growth in coal demand for 
        electric power generation.
   Reliable production cost figures are hard to come by since 
        such numbers are usually not provided in detail by operating 
        companies and are very specific to a chosen set of 
        circumstances. However, numbers recently made available by 
        Sasol indicate a direct operating cost of $10/barrel. If a coal 
        cost of $30/ton is added, that adds another $15/barrel. To this 
        amount the financing costs need to be added, which depends very 
        much on the particular project structure and financial 
        arrangements. It is clear that this provides a wide margin to 
        establish a feasible project, and viability is likely even at 
        crude oil prices as low as $45-$50/barrel.

    Environmental considerations favor FT CTL. It can be stated that 
CTL can truly be a Clean Coal Technology when modern commercially 
available processes are implemented. Furthermore:

   FT diesel is a premium product; even better in environmental 
        performance that CARB diesel and it can sustainably demand a 
        substantially higher price (conservatively about $8/barrel) 
        than crude oil. This differential between CTL diesel and 
        regular diesel above crude oil prices should be calculated into 
        viability analyses. The product qualities of FT diesel are well 
        known. The FT process requires total sulfur removal from syngas 
        (the sulfur is taken out of the process as elemental sulfur, as 
        sulfuric acid or as fertilizer grade ammonium sulphate) and 
        therefore the diesel is essentially sulfur free.
   The CO2 produced in a CTL plant can be readily 
        captured for sequestration (as is done in the Great Plains 
        synthetic natural gas facility in North Dakota).
   FT CTL diesel is compatible with current diesels and can 
        readily be blended into the existing infrastructure. For niche 
        applications, like for special military fuels, certification 
        would be required which could require hundreds of thousands of 
        gallons of products.

    A recent project has been initiated through the Southern States 
Energy Board (SSEB). It is called ``The American Energy Security 
Study''. This study has the support from the member states of the SSEB 
together with a number of other stakeholders. It will deal with 
strategic matters and present a plan to establish energy security and 
independence through the production of liquid fuels from various 
resources, including CTL. It will indicate measures for the rapid 
deployment of selected options to provide indigenous fuel supplies. 
Policy issues will be considered with macro-economic impact analyses. 
An analysis of the relative economics of CTL facilities as a function 
of the capacity of plants will be presented. The report is due to be 
available by the middle of the year. It is anticipated that this study 
will be a powerful tool to help shaping the path forward to greater 
fuel self-sufficiency.
    Numerous design case studies have been performed over the years to 
evaluate the viability of CTL technologies. With no CTL facilities 
erected after the Sasol Three in the early 1980's, these estimates are 
often on the basis of expected performance rather than on proven 
performance. This can be overcome by involving reputable engineering 
companies with relevant experience in the field to do a detailed level 
design to form the basis for a definitive cost and economic evaluation. 
Such studies can cost tens of million of dollars, depending on the size 
and scope of the project. These costs will come down in due time as 
more plants will be built and initial support from governments would 
assist in expediting earlier deployment of CTL.
    Establishing a major project requires getting appropriate partners 
together. This typically takes a long time for large projects. The team 
could typically include the owner of the coal resources, the company 
which has the ability to operate the facility (preferably an owner-
operator), a reputable engineering contractor and certainly a strong 
input to deal with financial, legal and permitting aspects at all 
levels of government. In this regard the government can and does 
facilitate some of these steps, but in practice it does not (normally) 
erect or own such a commercial facility. Under the current 
circumstances I would expect that such teams will start forming soon to 
take CTL forward. Indications from the DOD that they might provide 
product off take agreements will assist in this process.
    In conclusion I observe the following:
    1. At current crude oil prices and even if prices drop by as much 
as $20/bbl, I believe that large CTL plants can be economically viable 
propositions in the U.S.
    2. The basic diesel fuels from CTL are fungible and should be able 
to be introduced into the market without disruptions.
    3. The initiatives created by the Energy Policy Act of 2005 set the 
stage for encouraging CTL and gasification deployment and the momentum 
to firm up the support mechanisms for potential such projects should be 
maintained.
    4. Close collaboration between DOD and DOE to establish facilities 
for producing fuels of different grades for testing and certification 
should be encouraged and initial smaller plants could be supported to 
get the quantities needed for certifying, for instance, jet fuels.
    5. The DOE budget should be strengthened to again support aspects 
of FT CTL technology development in parallel with the current 
gasification developments.
    6. CTL has been done and can be done in the U.S.

    Senator Bunning. Thank you very much, Doctor.
    Mr. Hawkins, go ahead.

   STATEMENT OF DAVID G. HAWKINS, DIRECTOR, CLIMATE CENTER, 
                NATURAL RESOURCE DEFENSE COUNCIL

    Mr. Hawkins. Thank you, Mr. Chairman, and thank you for the 
opportunity to testify today on the subject of coal 
liquefaction or coal-to-liquids technology.
    My name is David Hawkins. I direct the climate center at 
the Natural Resources Defense Council. The idea of making 
liquid fuels out of coal is being promoted as a way of helping 
to solve the problem of U.S. dependence on oil. Let me say that 
NRDC agrees completely that we need aggressive action to reduce 
oil dependence. There are important questions that need to be 
asked about each proposal to reduce oil dependence, including a 
coal-to-liquids program. Is it technically feasible? How much 
oil consumption will it save? How soon? How much will it cost? 
What will be the impacts on the proposal of such proposals on 
health and the environment? And it's that last question that 
I've been asked to discuss today.
    Depending on how coal is produced and used, it can cause 
very large damages to health and the environment, as we all 
know. In discussing the coal-to-liquids processes today, I want 
to focus just on three areas, global warming pollution, 
conventional air pollution, and the impacts of mining 
production and transportation of coal. Let me say again that 
NRDC agrees wholeheartedly that reducing oil dependence should 
be a national priority and that we need new policies and 
programs to avert the mounting problems associated with today's 
dependence and the much greater dependence that will occur if 
we do not act.
    Now, if coal were to play a significant role in displacing 
oil, it's very clear that the enterprise will have to be very 
large. In fact, displacing 10 percent of U.S. oil demand would 
require nearly 500 million tons of additional coal production 
in the United States, over a 40 percent increase from today's 
1.1 billion tons of production. So the question is can that 
kind of a scale be compatible with our environmental needs and 
objectives?
    On the first question, can we implement a large scale coal-
to-liquids program and still get on a path of reducing global 
warming emissions? The context is to stabilize concentrations 
of global warming emissions we'll need to reduce emissions 
significantly from today's levels. Today we haven't settled on 
how much those emissions will need to be reduced so we need to 
assess new programs like coal-to-liquids to ask, one, how do 
they compare to today's crude oil system and, two, how do they 
compare to where we may need to go in terms of total reductions 
in emissions to avoid dangerous disruption of the climate?
    Now, processing coal to make liquid fuel produces large 
amounts of coal in the production plant, and then when the fuel 
is burned, it releases additional amounts of CO2. 
Available information today on the existing technologies that 
are being proposed to be deployed indicates that the total 
emissions from those two components of a CTL program are about 
80 percent higher than a crude oil based gasoline or diesel 
program, if the CO2 from the CTL production plant is 
released to the atmosphere. Now, if the CO2 
emissions are captured from the production plant, the 
assessment is that emissions from coal-to-liquids would be 
about the same as today's crude oil system. Now, these facts 
mean that a large scale program for CTL would not be compatible 
with achieving significant global warming emission reductions 
unless ways can be found to dramatically reduce emissions from 
the current technology. I'm not going to go into detail on the 
conventional air pollution and mining impacts in the interest 
of time. I have laid out in some detail in the prepared 
testimony the fact that we have very significant impacts 
associated with mining and transportation of today's 1.1 
billion tons of coal and if we're going to be talking about 
substantial increases in coal production in the United States 
we simply have to find a better way to deal with those very 
large impacts and commit ourselves to a real program to reduce 
those impacts from today's levels.
    Today's energy use patterns are responsible for two growing 
problems, oil dependence and global warming. It would be 
extremely unwise to try to solve one of these problems and 
ignore the other. Now, fortunately we don't have to. I lay out 
in my testimony a package of proposals that would cut oil 
consumption from today's levels in the next 10 years by three 
million barrels a day and by 2025 by over 10 million barrels a 
day. All of these measures will also achieve substantial cuts 
in global warming emissions and improve environmental quality.
    Thank you for your attention.
    [The prepared statement of Mr. Hawkins follows:]

   Prepared Statement of David G. Hawkins, Director, Climate Center, 
                   Natural Resources Defense Council

    Thank you for the opportunity to testify today on the subject of 
coal liquefaction, or coal-to-liquids technology. My name is David 
Hawkins. I am director of the Climate Center at the Natural Resources 
Defense Council (NRDC). NRDC is a national, nonprofit organization of 
scientists, lawyers and environmental specialists dedicated to 
protecting public health and the environment. Founded in 1970, NRDC has 
more than 1.2 million members and online activists nationwide, served 
from offices in New York, Washington, Los Angeles and San Francisco.
    Today's energy use patterns are responsible for two growing 
problems that require early action to keep them from spiraling out of 
control--oil dependence and global warming. Both are serious; both 
warrant much more proactive policy action than has occurred to date. 
But most important, both problems must be addressed together. Designing 
strategies that address only one of these problems and ignore the other 
is a recipe for huge and costly mistakes. Fortunately, we have in our 
tool box energy resource options that can dramatically reduce both oil 
dependence and global warming emissions.
    Proposals to use coal to make liquid fuels for transportation need 
to be evaluated in the context of the compelling need to reduce global 
warming emissions steadily and significantly, starting now and 
proceeding constantly throughout this century. Because today's coal 
mining and use also continues to impose a heavy toll on America's land, 
water, and air, damaging human health and the environment, it is 
critical to examine the implications of a substantial coal-to-liquids 
program on these values as well.

                        REDUCING OIL DEPENDENCE

    NRDC fully agrees that reducing oil dependence should be a national 
priority and that new policies and programs are needed to avert the 
mounting problems associated with today's dependence and the much 
greater dependence that lies ahead if we do not act. A critical issue 
is the path we pursue in reducing oil dependence: a ``green'' path that 
helps us address the urgent problem of global warming and our need to 
reduce the impacts of energy use on the environment and human health; 
or a ``brown'' path that would increase global warming emissions as 
well as other health and environmental damage. In deciding what role 
coal might play as a source of transportation fuel NRDC believes we 
must first assess whether it is possible to use coal to make liquid 
fuels without exacerbating the problems of global warming, conventional 
air pollution and impacts of coal production and transportation.
    If coal were to play a significant role in displacing oil, it is 
clear that the enterprise would be huge, so the health and 
environmental stakes are correspondingly huge. The coal company Peabody 
Energy is promoting a vision that would call for production of 2.6 
million barrels per day of synthetic transportation fuel from coal by 
2025, about 10% of forecasted oil demand in that year. According to 
Peabody, using coal to achieve that amount of crude oil displacement 
would require construction of 33 very large coal-to-liquids plants, 
each plant consuming 14.4 million tons of coal per year to produce 
80,000 barrels per day of liquid fuel. Each of these plants would cost 
$6.4 billion to build. Total additional coal production required for 
this program would be 475 million tons of coal annually--requiring an 
expansion of coal mining of 43% above today's level.\1\
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    \1\ Peabody's ``Eight-Point Plan'' calls for a total of 1.3 billion 
tons of additional coal production by 2025, proposing that coal be used 
to produce synthetic pipeline gas, additional coal-fired electricity, 
hydrogen, and fuel for ethanol plants. The entire program would more 
than double U.S. coal mining and consumption.
---------------------------------------------------------------------------
    In this testimony I will not attempt a thorough analysis of the 
impacts of a program of this scale. Rather, I will highlight the issues 
that should be addressed in a detailed assessment.

                        GLOBAL WARMING POLLUTION

    To avoid catastrophic global warming the U.S. and other nations 
will need to deploy energy resources that result in much lower releases 
of CO2 than today's use of oil, gas and coal. To keep global 
temperatures from rising to levels not seen since before the dawn of 
human civilization, the best expert opinion is that we need to get on a 
pathway now to allow us to cut global warming emissions by 60-80% from 
today's levels over the decades ahead. The technologies we choose to 
meet our energy needs in the transportation sector and in other areas 
must have the potential to perform at these improved emission levels.
    To assess the global warming implications of a large coal-to-
liquids program we need to examine the total life-cycle or ``well-to-
wheel'' emissions of these new fuels. Coal is a carbon-intensive fuel, 
containing double the amount of carbon per unit of energy compared to 
natural gas and about 50% more than petroleum. When coal is converted 
to liquid fuels, two streams of CO2 are produced: one at the 
coal-to-liquids production plant and the second from the exhausts of 
the vehicles that burn the fuel. As I describe below, with the 
technology in hand today and on the horizon it is difficult to see how 
a large coal-to-liquids program can be compatible with the low-
CO2-emitting transportation system we need to design to 
prevent global warming.
    Today, our system of refining crude oil to produce gasoline, 
diesel, jet fuel and other transportation fuels, results in a total 
``well to wheels'' emission rate of about 27.5 pounds of CO2 
per gallon of fuel. Based on available information about coal-to-
liquids plants being proposed, the total well to wheels CO2 
emissions from such plants would be about 49.5-pounds of CO2 
per gallon, nearly twice as high as using crude oil, if the 
CO2 from the coal-to-liquids plant is released to the 
atmosphere.\2\ Obviously, introducing a new fuel system with double the 
CO2 emissions of today's crude oil system would conflict 
with the need to reduce global warming emissions. If the CO2 
from coal-to-liquids plants is captured, then well-to-wheels 
CO2 emissions would be reduced but would still be higher 
than emissions from today's crude oil system.\3\
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    \2\ Calculated well to wheel CO2 emissions for coal-
based ``Fischer-Tropsch'' are about 1.8 greater than producing and 
consuming gasoline or diesel fuel from crude oil. If the coal-to-
liquids plant makes electricity as well, the relative emissions from 
the liquid fuels depends on the amount of electricity produced and what 
is assumed about the emissions of from an alternative source of 
electricity.
    \3\ Capturing 90 percent of the emissions from coal-to-liquid 
plants reduces the emissions from the plant to levels close to those 
from petroleum production and refining while emissions from the vehicle 
are equivalent to those from a gasoline vehicle. With such 
CO2 capture, well to wheels emissions from coal-to-liquids 
fuels would be 8 percent higher than for petroleum.
---------------------------------------------------------------------------
    This comparison indicates that using coal to produce a significant 
amount of liquids for transportation fuel would not be compatible with 
the need to develop a low-CO2 emitting transportation sector 
unless technologies are developed to significantly reduce emissions 
from the overall process. But here one confronts the unavoidable fact 
that the liquid fuel from coal contains the same amount of carbon as is 
in gasoline or diesel made from crude. Thus, the potential for 
achieving significant CO2 emission reductions compared to 
crude is inherently limited. This means that using a significant amount 
of coal to make liquid fuel for transportation needs would make the 
task of achieving any given level of global warming emission reduction 
much more difficult. Proceeding with coal-to-liquids plants now could 
leave those investments stranded or impose unnecessarily high abatement 
costs on the economy if the plants continue to operate.

                         CONVENTIONAL POLLUTION

    Conventional air emissions from coal-to-liquids plants include 
sulfur oxides, nitrogen oxides, particulate matter, mercury and other 
hazardous metals and organics. While it appears that technologies exist 
to achieve high levels of control for all or most of these pollutants, 
the operating experience of coal-to-liquids plants in South Africa 
demonstrates that coal-to-liquids plants are not inherently ``clean.'' 
If such plants are to operate with minimum emissions of conventional 
pollutants, performance standards will need to be written--standards 
that do not exist today in the U.S. as far as we are aware. In 
addition, the various federal emission cap programs now in force would 
apply to few, if any, coal-to-liquids plants.\4\
---------------------------------------------------------------------------
    \4\ The sulfur and nitrogen caps in EPA's ``Clean Air Interstate 
Rule'' (``CAIR'') may cover emissions from coal-to-liquids plants built 
in the eastern states covered by the rule but would not apply to plants 
built in the western states. Neither the national ``acid rain'' caps 
nor EPA's mercury rule would apply to coal-to-liquids plants.
---------------------------------------------------------------------------
    Thus, we cannot say today that coal-to-liquids plants will be 
required to meet stringent emission performance standards adequate to 
prevent either significant localized impacts or regional emissions 
impacts.

                MINING, PROCESSING AND TRANSPORTING COAL

    The impacts of mining, processing, and transporting 1.1 billion 
tons of coal today on health, landscapes, and water are large. 
Peabody's coal-to-liquids vision advocates another 475 billion tons of 
coal production. To understand the implications of such an enormous 
expansion of coal production, it is important to have a detailed 
understanding of the impacts from today's level of coal production. The 
summary that follows makes it clear that we must find more effective 
ways to reduce these impacts before we follow a path that would result 
in even larger amounts of coal production and transportation.
Health and Safety
    Coal mining is one of the U.S.'s most dangerous professions. The 
yearly fatality rate in the industry is 0.23 per thousand workers, 
making the industry about five times as hazardous as the average 
private workplace.\5\ The industry had 27 fatalities in 2002, an all-
time low,\6\ and there were 55 deaths in 2004 and 57 deaths in 2005.\7\ 
The first month of 2006 was particularly deadly, however, with 18 
fatalities through February 1st. Sixteen of these deaths occurred in 
West Virginia mines, leading the Governor to call for an unprecedented 
suspension of production while safety checks were conducted. Coal 
miners also suffer from many non-fatal injuries and diseases, most 
notably black lung disease (also known as pneumoconiosis) caused by 
inhaling coal dust. Although the 1969 Coal Mine Health and Safety Act 
seeks to eliminate black lung disease, the United Mine Workers estimate 
that 1500 former miners die of black lung each year.\8\
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    \5\ Congressional Research Service, U.S. Coal: A Primer on the 
Major Issues, at 30 (Mar. 25, 2003).
    \6\ Id.
    \7\ Melissa Drosjack, FoxNews.com, Congress to Examine Mine Safety 
(Jan. 20, 2006), online at www.foxnews.com/story/0,2933,182276,00.html 
(visited Feb. 1, 2006).
    \8\ http://www.umwa.org/blacklung/blacklung.shtml
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Terrestrial Habitats
    Coal mining--and particularly surface or strip mining--poses one of 
the most significant threats to terrestrial habitats in the United 
States. The Appalachian region,\9\ for example, which produces over 35% 
of our nation's coal,\10\ is one of the most biologically diverse 
forested regions in the country. But during surface mining activities, 
trees are clearcut and habitat is fragmented, destroying natural areas 
that were home to hundreds of unique species of plants and animals. 
Even where forests are left standing, fragmentation is of significant 
concern because a decrease in patch size is correlated with a decrease 
in biodiversity as the ratio of interior habitat to edge habitat 
decreases. This is of particular concern to certain bird species that 
require large tracts of interior forest habitat, such as the black-and-
white warbler and black-throated blue warbler.
---------------------------------------------------------------------------
    \9\ Alabama, Georgia, Eastern Kentucky, Maryland, North Carolina, 
Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.
    \10\ Energy Information Administration. Annual Coal Report, 2004.
---------------------------------------------------------------------------
    After mining is complete, these once-forested regions in the 
Southeast are typically reclaimed as grasslands, although grasslands 
are not a naturally occurring habitat type in this region. Grasslands 
that replace the original ecosystems in areas that were surface mined 
are generally categorized by less-developed soil structure \11\ and 
lower species diversity \12\ compared to natural forests in the region. 
Reclaimed grasslands are generally characterized by a high degree of 
soil compaction that tends to limit the ability of native tree and 
plant species to take root. Reclamation practices limit the overall 
ecological health of sites, and it has been estimated that the natural 
return of forests to reclaimed sites may take hundreds of years.\13\ 
According to the USEPA, the loss of vegetation and alteration of 
topography associated with surface mining can lead to increased soil 
erosion and may lead to an increased probability of flooding after 
rainstorms.\14\
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    \11\ Sencindiver, et al. ``Soil Health of Mountaintop Removal Mines 
in Southern West Virginia''. 2001.
    \12\ Handel, Steven. Mountaintop Removal Mining/Valley Fill 
Environmental Impact Statement Technical Study, Project Report for 
Terrestrial Studies. October, 2002.
    \13\ Id.
    \14\ EPA. Mountaintop Mining/Valley Fills in Appalachia: Draft 
Programmatic Environmental Impact Statement. 2003
---------------------------------------------------------------------------
    The destruction of forested habitat not only degrades the quality 
of the natural environment, it also destroys the aesthetic values of 
the Appalachian region that make it such a popular tourist destination. 
An estimated one million acres of West Virginia mountains were subject 
to strip mining and mountaintop removal mining between 1939 and 
2005.\15\ Many of these mines have yet to be reclaimed so that where 
there were once forested mountains, there now stand bare mounds of sand 
and gravel.
---------------------------------------------------------------------------
    \15\ Julian Martin, West Virginia Highlands Conservancy, Personal 
Communication, February 2, 2006.
---------------------------------------------------------------------------
    The terrestrial impacts of coal mining in the Appalachian region 
are considerable, but for sheer size they cannot compare to the impacts 
in the western United States.\16\ As of September 30, 2004, 470,000 
acres were under federal coal leases or other authorizations to 
mine.\17\ Unlike the East, much of the West--including much of the 
region's principal coal areas--is arid and predominantly unforested. In 
the West, as in the East, surface mining activities cause severe 
environmental damage as huge machines strip, rip apart and scrape aside 
vegetation, soils, wildlife habitat and drastically reshape existing 
land forms and the affected area's ecology to reach the subsurface 
coal. Strip mining results in industrialization of once quiet open 
space along with displacement of wildlife, increased soil erosion, loss 
of recreational opportunities, degradation of wilderness values, and 
destruction of scenic beauty.\18\ Reclamation can be problematic both 
because of climate and soil quality. As in the East, reclamation of 
surface mined areas does not necessarily restore pre-mining wildlife 
habitat and may require scarce water resources be used for 
irrigation.\19\ Forty-six western national parks are located within ten 
miles of an identified coal basin, and these parks could be 
significantly affected by future surface mining in the region.\20\
---------------------------------------------------------------------------
    \16\ Alaska, Arizona, Colorado, Montana, New Mexico, North Dakota, 
Utah, Washington, and Wyoming.
    \17\ Bureau of Land Management, Public Land Statistics 2004, Table 
3-18.
    \18\ See, e.g., U.S. Department of the Interior, Bureau of Land 
Management, 1985 Federal Coal Management Program/Final Environmental 
Impact Statement, pp. 210-211, 230-231, 241-242, 282 (water quality and 
quantity), 241, 251, 257.
    \19\ Bureau of Land Management. 3809 Surface Management 
Regulations, Draft Environmental Impact Statement. 1999
    \20\ National Park Service, DOI. ``Coal Development Overview''. 
2003.
---------------------------------------------------------------------------
Water Pollution
    Coal production causes negative physical and chemical changes to 
nearby waters. In all surface mining, the overburden (earth layers 
above the coal seams) is removed and deposited on the surface as waste 
rock. The most significant physical effect on water occurs from valley 
fills, the waste rock associated with mountaintop removal (MTR) mining. 
Since MTR mining started in the United States in the early 70's, 
studies estimate that over 700 miles of streams have been buried from 
valley fills, and 1200 additional miles have been directly impacted 
from valley fills through sedimentation or chemistry alteration.\21\ 
Together, the waterways harmed by valley fills are about 80 percent as 
long as the Mississippi River. Valley fills bury the headwaters of 
streams, which in the southeastern U.S. support diverse and unique 
habitats, and regulate nutrients, water quality, and flow quantity. The 
elimination of headwaters therefore has long-reaching impacts many 
miles downstream.\22\
---------------------------------------------------------------------------
    \21\ EPA. Mountaintop Mining/Valley Fills in Appalachia: Draft 
Programmatic Environmental Impact Statement.
    \22\ Id.
---------------------------------------------------------------------------
    Coal mining can also lead to increased sedimentation, which affects 
both water chemistry and stream flow, and negatively impacts aquatic 
habitat. Valley fills in the eastern U.S., as well as waste rock from 
strip mines in the west add sediment to streams, as does the 
construction and use of roads in the mining complex. A final physical 
impact of mining on water is to the hydrology of aquifers. MTR and 
valley fills remove upper drainage basins, and often connect two 
previously separate aquifers, altering the surrounding groundwater 
recharge scheme.\23\
---------------------------------------------------------------------------
    \23\ Keating, Martha. ``Cradle to Grave: The Environmental Impacts 
from Coal.'' Clean Air Task Force, Boston. June, 2001.
---------------------------------------------------------------------------
    Acid mine drainage (AMD) is the most significant form of chemical 
pollution produced from coal mining operations. In both underground and 
surface mining, sulfur-bearing minerals common in coal mining areas are 
brought up to the surface in waste rock. When these minerals come in 
contact with precipitation and groundwater, an acidic leachate is 
formed. This leachate picks up heavy metals and carries these toxins 
into streams or groundwater. Waters affected by AMD often exhibit 
increased levels of sulfate, total dissolved solids, calcium, selenium, 
magnesium, manganese, conductivity, acidity, sodium, nitrate, and 
nitrite. This drastically changes stream and groundwater chemistry.\24\ 
The degraded water becomes less habitable, non potable, and unfit for 
recreational purposes. The acidity and metals can also corrode 
structures such as culverts and bridges.\25\ In the eastern U.S., 
estimates of the damage from AMD range from four to eleven thousand 
miles of streams.\26\ In the west, estimates are between five and ten 
thousand miles of streams polluted. The effects of AMD can be 
diminished through addition of alkaline substances to counteract the 
acid, but recent studies have found that the addition of alkaline 
material can increase the mobilization of both selenium and 
arsenic.\27\ AMD is costly to mitigate, requiring over $40 million 
annually in Kentucky, Tennessee, Virginia, and West Virginia alone.\28\
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    \24\ EPA Office of Solid Waste: Acid Mine Drainage Prediction 
Technical Document. December, 1994.
    \25\ EPA. Mountaintop Mining/Valley Fills in Appalachia: Draft 
Programmatic Environmental Impact Statement. 2003
    \26\ EPA. Mid-Atlantic Integrated Assessment: Coal Mining. http://
www.epa.gov/maia/html/coalmining.html
    \27\ EPA. Mountaintop Mining/Valley Fills in Appalachia: Final 
Programmatic Environmental Impact Statement. 2005
    \28\ Id.
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Air Pollution
    There are two main sources of air pollution during the coal 
production process. The first is methane emissions from the mines. 
Methane is a powerful heat-trapping gas and is the second most 
important contributor to global warming after carbon dioxide. Methane 
emissions from coal mines make up between 10 and 15% of anthropogenic 
methane emissions in the U.S. According to the most recent official 
inventory of U.S. global warming emissions, coal mining results in the 
release of 3 million tons of methane per year, which is equivalent to 
68 million tons of carbon dioxide.\29\
---------------------------------------------------------------------------
    \29\ DOE/EIA, 2005. Emissions of Greenhouse Gases in the United 
States 2004. (December).
---------------------------------------------------------------------------
    The second significant form of air pollution from coal mining is 
particulate matter (PM) emissions. While methane emissions are largely 
due to eastern underground mines, PM emissions are particularly serious 
at western surface mines. The arid, open and frequently windy region 
allows for the creation and transport of significant amounts of 
particulate matter in connection with mining operations. Fugitive dust 
emissions occur during nearly every phase of coal strip mining in the 
west. The most significant sources of these emissions are removal of 
the overburden through blasting and use of draglines, truck haulage of 
the overburden and mined coal, road grading, and wind erosion of 
reclaimed areas. PM emissions from diesel trucks and equipment used in 
mining are also significant. PM can cause serious respiratory damage as 
well as premature death.\30\ In 2002, one of Wyoming's coal producing 
counties, Campbell County, exceeded its ambient air quality threshold 
several times, almost earning non-attainment status.\31\ Coal dust 
problems in the West are likely to get worse if the administration 
finalizes its January 2006 proposal to exempt mining (and other 
activities) from controls aimed at meeting the coarse PM standard.\32\
---------------------------------------------------------------------------
    \30\ EPA. Particle Pollution and Your Health. 2003
    \31\ Casper [WY] Star Tribune, January 24, 2005.
    \32\ National Ambient Air Quality Standards for Particulate Matter, 
Proposed Rule, 71 Fed. Reg. 2620 (January 17, 2006); Revisions to 
Ambient Air Monitoring Regulations, Proposed Rule, 71 Fed. Reg. 2710 
(January 17, 2006).
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Coal Mine Wastes
    Coal mining leaves a legacy of wastes long after mining operations 
cease. One significant waste is the sludge that is produced from 
washing coal. There are currently over 700 sludge impoundments located 
throughout mining regions, and this number continues to grow. These 
impoundment ponds pose a potential threat to the environment and human 
life. If an impoundment fails, the result can be disastrous. In 1972 an 
impoundment break in West Virginia released a flood of coal sludge that 
killed 125 people. In the year 2000 an impoundment break in Kentucky 
involving more than 300 million gallons of slurry (30 times the size of 
the Exxon Valdez spill) killed all aquatic life in a 20 mile diameter, 
destroyed homes, and contaminated much of the drinking water in the 
eastern part of the state.\33\
---------------------------------------------------------------------------
    \33\ Frazier, Ian. ``Coal Country.'' On Earth. NRDC. Spring, 2003.
---------------------------------------------------------------------------
    Another waste from coal mining is the solid waste rock left behind 
from tunneling or blasting. This can result in a number of 
environmental impacts previously discussed, including acid mine 
drainage (AMD). A common problem with coal mine legacies is the fact 
that if a mine is abandoned or a mining company goes out of business, 
the former owner is under no legal obligation to cleanup and monitor 
the environmental wastes, leaving the responsibility in the hands of 
the state.\34\
---------------------------------------------------------------------------
    \34\  Reece, Erik. ``Death of a Mountain.'' Harper's Magazine. 
April, 2005.
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Effects on Communities
    Coal mining can also have serious impacts on nearby communities. In 
addition to noise and dust, residents have reported that dynamite 
blasts can crack the foundations of homes,\35\ and many cases of 
subsidence due to the collapse of underground mines have been 
documented. Subsidence can cause serious damage to houses, roads, 
bridges, and any other structure in the area. Blasting can also cause 
damage to wells, and changes in the topography and structure of 
aquifers can cause these wells to run dry.
---------------------------------------------------------------------------
    \35\Id.
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Transportation of Coal
    Transporting coal from where it is mined to where it will be burned 
also produces significant quantities of air pollution and other 
environmental harms. Diesel-burning trucks, trains, and barges that 
transport coal release NOX, SOX, PM, VOCs 
(Volatile Organic Chemicals), CO, and CO2 into the earth's 
atmosphere. Trucks and trains (barge pollution data are unavailable) 
transporting coal release over 600,000 tons of NOX, and over 
50,000 tons of PM 10 into the air annually.36, 37 In 
addition to health risks, black carbon from diesel combustion is 
another contributor to global warming.\38\ Land disturbance from trucks 
entering and leaving the mine complex and coal dust along the transport 
route also release particles into the air.\39\ For example, in 
Sylvester, West Virginia, a Massey Energy coal processing plant and the 
trucks associated with it spread so much dust around the town that 
``Sylvester's residents had to clean their windows and porches and cars 
every day, and keep the windows shut.'' \40\ Even after a lawsuit and a 
court victory, residents--who now call themselves ``Dustbusters''--
still ``wipe down their windows and porches and cars.'' \41\
---------------------------------------------------------------------------
    \36\ DOT Federal Highway Administration. Assessing the Effects of 
Freight Movement on Air Quality, Final Report. April, 2005
    \37\ Energy Information Administration: Coal Transportation 
Statistics.
    \38\ Hill, Bruce. ``An Analysis of Diesel Air Pollution and Public 
Health in America.'' Clean Air Task Force, Boston. February, 2005.
    \39\ EPA. Mountaintop Mining/Valley Fills in Appalachia: Draft 
Programmatic Environmental Impact Statement. 2003
    \40\ Michael Schnayerson, ``The Rape of Appalachia,'' Vanity Fair, 
157 (May 2006).
    \41\ Id.
---------------------------------------------------------------------------
    Almost 60 percent of coal in the U.S. is transported at least in 
part by train and coal transportation accounts for 44% of rail freight 
ton-miles.\42\ Some coal trains reach more than two miles in length, 
causing railroad-crossing collisions and pedestrian accidents (there 
are approximately 3000 such collisions and 900 pedestrian accidents 
every year), and interruption in traffic flow (including emergency 
responders such as police, ambulance services, and fire departments). 
Local communities also have concerns about coal trucks, both because of 
their size and the dust they can leave behind. According to one report, 
in a Kentucky town, coal trucks weighing 120 tons with their loads were 
used, and ``the Department of Transportation signs stating a thirty-ton 
carrying capacity of each bridge had disappeared.'' \43\ Although the 
coal company there has now adopted a different route for its trucks, 
community representatives in Appalachia believe that coal trucks should 
be limited to 40 tons.\44\
---------------------------------------------------------------------------
    \42\  http://nationalatlas.gov/articles/transportation/a--
freightrr.html
    \43\ Erik Reece, Lost Mountain: A Year in the Vanishing Wilderness 
112 (2006).
    \44\ Personal communication from Hillary Hosta and Julia Bonds, 
Coal River Mountain Watch (Apr. 7, 2006).
---------------------------------------------------------------------------
    Coal is also sometimes transported in a coal slurry pipeline, such 
as the one used at the Black Mesa Mine in Arizona. In this process the 
coal is ground up and mixed with water in a roughly 50:50 ratio. The 
resulting slurry is transported to a power station through a pipeline. 
This requires large amounts of fresh groundwater. To transport coal 
from the Black Mesa Mine in Arizona to the Mohave Generating Station in 
Nevada, Peabody Coal pumped over one billion gallons of water from an 
aquifer near the mine each year. This water came from the same aquifer 
used for drinking water and irrigation by members of the Navajo and 
Hopi Nations in the area. Water used for coal transport has led to a 
major depletion of the aquifer, with more than a 100 foot drop in water 
level in some wells. In the West, coal transport through a slurry 
pipeline places additional stress on an already stressed water supply. 
Maintenance of the pipe requires washing, which uses still more fresh 
water. Not only does slurry-pipeline transport result in a loss of 
freshwater, it can also lead to water pollution when the pipe fails and 
coal slurry is discharged into ground or surface water.\45\ The Peabody 
pipe failed 12 times between 1994 and 1999. The Black Mesa mine closed 
as of January 2006. Its sole customer, the Mohave Generating Station, 
was shut down because its emissions exceeded current air pollution 
standards.
---------------------------------------------------------------------------
    \45\ NRDC. Drawdown: Groundwater Mining on Black Mesa.
---------------------------------------------------------------------------
                       A RESPONSIBLE ACTION PLAN

    The impacts that a large coal-to-liquids program could have on 
global warming pollution, conventional air pollution and damage from 
expanded coal production are substantial. Before deciding whether to 
invest scores, perhaps hundreds of billions of dollars in a new 
industry like coal-to-liquids, we need a much more serious assessment 
of whether this is an industry that should proceed at all.
    Fortunately, the U.S. can have a robust and effective program to 
reduce oil dependence without rushing into an embrace of coal-to-
liquids technologies. A combination of efficiency, renewable fuels and 
potentially, plug-in hybrid vehicles can reduce our oil consumption 
more quickly, more cleanly and in larger amounts than coal-to-liquids 
even on the massive scale advocated by Peabody Energy.
    A combination of more efficient cars, trucks and planes, biofuels, 
and ``smart growth'' transportation options outlined in report 
``Securing America,'' produced by NRDC and the Institute for the 
Analysis of Global Security, can cut oil dependence by more than 3 
million barrels a day in 10 years, and achieve cuts of more than 11 
million barrels a day by 2025, far outstripping the 2.6 million barrel 
a day program being promoted by Peabody.
    The Securing America program is made up of these sensible steps 
that will cut oil dependence, cut global warming emissions, and reduce 
other harmful impacts of today's energy production and consumption 
patterns:
    Accelerate oil savings in passenger vehicles by:

   establishing tax credits for manufacturers to retool 
        existing factories so they can build fuel-efficient vehicles 
        and engineer advanced technologies, and
   establishing tax credits for consumers to purchase the next 
        generation of fuel-efficient vehicles; and raising federal fuel 
        economy standards for cars and light trucks in regular steps.

    Accelerate oil savings in motor vehicles through the following:

   requiring replacement tires and motor oil to be at least as 
        fuel efficient as original equipment tires and motor oil;
   requiring efficiency improvements in heavy-duty trucks; and
   supporting smart growth and better transportation choices.

    Accelerate oil savings in industrial, aviation, and residential 
building sectors through the following:

   expanding industrial efficiency programs to focus on oil use 
        reduction and adopting standards for petroleum heating;
   replacing chemical feedstocks with bioproducts through 
        research and development and government procurement of 
        bioproducts;
   upgrading air traffic management systems so aircraft follow 
        the most-efficient routes; and
   promoting residential energy savings with a focus on oil-
        heat.

    Encourage growth of the biofuels industry through the following:

   requiring all new cars and trucks to be capable of operating 
        on biofuels or other non-petroleum fuels by 2015; and
   allocating $2 billion in federal funding over the next 10 
        years to help the cellulosic biofuels industry expand 
        production capacity to 1 billion gallons per year and become 
        self-sufficient by 2015.

                 TECHNOLOGICALLY ACHIEVABLE OIL SAVINGS
                        [Million barrels per day]
------------------------------------------------------------------------
                   Oil savings measures                      2015   2025
------------------------------------------------------------------------
Raise fuel efficiency in new passenger vehicles through       1.6    4.9
 tax credits and standards................................
Accelerate oil savings in motor vehicles through
    fuel efficient replacement tires and motor oil........    0.5    0.6
    efficiency improvements in heavy-duty trucks..........    0.5    1.1
Accelerate oil savings in industrial, aviation, and           0.3    0.7
 residential sectors......................................
Encourage growth of biofuels industry through                 0.3    3.9
 demonstration and standards..............................
                                                           -------------
    Total oil saved.......................................    3.2   11.2
------------------------------------------------------------------------

    To cut our dependence on oil we should follow a simple rule: start 
with the measures that will produce the quickest, cleanest and least 
expensive reductions in oil use; measures that will put us on track to 
achieve the reductions in global warming emissions we need to protect 
the climate. If we are thoughtful about the actions we take, our 
country can pursue an energy path that enhances our security, our 
economy, and our environment.

    Senator Bunning. Thank you very much.
    Mr. Ramsbottom.

 STATEMENT OF D. HUNT RAMSBOTTOM, PRESIDENT AND CEO, RENTECH, 
                     INC., LOS ANGELES, CA

    Mr. Ramsbottom. Thank you, Mr. Chairman, distinguished 
Senators and guests.
    I'm Hunt Ramsbottom, president and CEO of Rentech. We're a 
publicly held company listed on the American Stock Exchange. 
For 23 years Rentech has engaged in R&D on clean fuels from 
natural gas and coal. Right now we are creating a commercial 
coal-to-liquid industry in the United States.
    I'd like to summarize my testimony.
    The basic chemistry behind our fuel products has been known 
for over seven decades. The technology has been used 
extensively in other countries. We have tested our innovations 
in six pilot plants for over 20 years. We plan to have a fully 
commercial plant up and running by 2010. Our seventh plant, our 
process demonstration unit, will be operating by the first 
quarter of 2007. It will produce 10 barrels a day for 
demonstration, analysis, and further training.
    This week Rentech will announce the purchase of the East 
Dubuque Fertilizer Plant. We will convert it in phases to 
produce three products, clean fuels, ammonia fertilizer, and 
electricity. The conversion will change the plant from 
expensive natural gas over to affordable Illinois coal. We will 
demonstrate that fertilizer production can still be a thriving 
domestic industry but the real innovation at East Dubuque will 
be the production of our ultra-clean fuels. I have a sample of 
Rentech's diesel with me. It is clear, refined to a high degree 
of purity and has almost no particulates or sulphur. Rentech's 
fuel can be used with no engine modifications in trucks, buses, 
and barges and processed into jet fuels. In 2010 East Dubuque 
will produce 2,000 barrels per day in phase one. Phase two will 
be close to 7,000 barrels per day.
    As we manufacture our fuel we remove most harmful regulated 
pollutants seeing up to 33 percent reduction after conversion 
in East Dubuque. The sulphur and mercury, for example, drop out 
as elements in the gasification stage. Our fuels run cleaner 
than traditional diesel, is more stable, is biodegradable. I'd 
like to enter for the record analysis showing our environmental 
benefits.
    Our commitment to the environment brings me to our second 
plant proposed in Natchez, Mississippi, which will produce 
11,000 barrels per day, again, in phase one. There we're 
pursuing opportunities for 100 percent capture and storage of 
carbon. That would allow us to pump our carbon dioxide into 
local fields increasing production and trapping the carbon 
underground.
    We've worked extremely hard to overcome the many hurdles to 
becoming the first commercial CTL plant in the United States. 
We're planning to make full use of the EPAct 2005 incentives, 
designed to jumpstart the clean fuels industry. Let me note 
that the States are also being very helpful in this process. 
Illinois helped us complete feasibility and engineering studies 
in assisting with the conversion to coal. Mississippi just 
passed a $50 million bond for the Natchez facility. What you've 
been doing at the Federal level is absolutely vital to our 
efforts. We intend to seek DOE self-pay loan guarantees in the 
first quarter of 2007. We commend the Secretary of Energy for 
quickly moving to implement the authorized programs. The self-
pay guarantees are integral to financing the first CTL plants 
in the United States. We appreciate your efforts to fully fund 
and expedite the DOE loan programs. We would also apply for the 
industrial gasification investment tax credit provided by the 
energy bill. The recent initiative by Senators Grassley and 
Baucus to raise the current $350 million cap to $850 million is 
very helpful. Allow me to offer an observation. Even the larger 
cap only helps three to four more new plants and we spend 
currently $850 million on foreign oil every 2 days. To make a 
real difference, Congress should lift these caps entirely. 
Another way to help is make the 50 cent per gallon fuel excise 
tax credit available to coal-to-liquids fuels. To do that we 
should extend the expiration currently in 2009 when no CTL 
plants will be operating to at least 2014.
    Senator Bunning, I recognize your unique position as a 
member of both energy and finance and support from the other 
members of the finance committee will certainly be appreciated.
    Finally, long-term DOD contracts for military use could 
assist with the financing of these facilities. CTL fuel is 
economically competitive, we can produce finished fuels for $36 
to $42 per barrel, the equivalent of buying raw crude at $30 to 
$35 per barrel. We're not asking the Government to subsidize an 
industry. We need your help to get the CTL clean fuel 
manufacturing industry launched with private sector funding.
    Thank for what you've done so far with EPAct 2005 and thank 
you for your time today.
    [The prepared statement of Mr. Ramsbottom follows:]

 Prepared Statement of D. Hunt Ramsbottom, President and CEO, Rentech, 
                         Inc., Los Angeles, CA

    Thank you, Mr. Chairman. Distinguished Senators and guests, I'm 
Hunt Ramsbottom and I'm the President and CEO of Rentech, Inc. We are a 
publicly held, Denver-based firm and we are listed on the American 
Stock Exchange. For 23 years, Rentech has engaged in research and 
development, focusing on enhancing the production of ultra-clean fuels 
made from natural gas and coal, through a chemical process known as 
Fischer-Tropsch. We hold 20 U.S. patents and 4 foreign patents.

                     THE HISTORY OF RENTECH AND CTL

    I'm here today to share how, right now, we are moving to establish 
a commercial coals-to-liquid--CTL--industry. The basic chemistry behind 
our fuel products has been known for 7 decades. The basic technology 
has been developed and used extensively in other countries. We have 
tested our Rentech innovations in the lab and in pilot programs, and 
deployed small-scale production.
    We now have developed our technology around Coals-to-Liquids--or 
CTL--gasification, and for Rentech, the future of CTL in the United 
States is no longer a theoretical, what-if, conversation. We plan to 
have a fully commercial, fully operational CTL plant up and running by 
2010.
    Even before that, we will be operating our Process Demonstration 
Unit (PDU). By the first quarter of 2007, we will have that up and 
running in Colorado. It will produce 10 barrels per day of our fuel 
basis for demonstration and analysis by potential end users. And it 
will allow us to optimize our technology for variations in coal and 
other factors.

  EAST DUBUQUE, ILLINOIS: THE FIRST CTL CLEAN-FUELS PLANT IN THE U.S.

    Within the next month, Rentech will announce the purchase a 
fertilizer plant in East Dubuque, Illinois, and we plant to convert it 
in phases to CTL poly-generation over the next 3 to 4 years. By poly-
generation, I mean that we will ultimately produce 3 products: ultra-
clean transportation fuels, ammonia fertilizer and electricity.
    The plant currently makes ammonia fertilizer from natural gas, and 
it already incorporates basic technologies that are critical to 
successfully implementing CTL. The conversion will include changing the 
feedstock from natural gas to Illinois coal. It will also entail adding 
a gasification unit to produce synthesis gas; adding a Rentech Reactor 
so that we can produce the basis of our ultra-clean fuels; and a 
finishing plant to produce the final fuel products. We chose our final 
planned product mix carefully.
    Fertilizer will still be made in large quantities. As I'm sure all 
of you know from our friends in the farm states, domestic fertilizer 
plants are shutting down rapidly because of high natural gas prices--
the current primary feedstock for fertilizer. Since 1999, the U.S. has 
switched from producing all its own fertilizer to becoming a net 
importer. We will demonstrate that fertilizer production can still be a 
thriving domestic industry using clean coal technologies.
    Electricity will be produced in small quantities, primarily for the 
plant's own use. A small surplus, however, will be provided to the 
local grid.

                      RENTECH'S ULTRA-CLEAN FUELS

    But the real innovation at East Dubuque will be the production of 
our ultra-clean fuels. I'm passing around a sample of Rentech's ultra-
clean diesel. Please look at it closely--it is very different than the 
diesel made from petroleum. This is clear, refined to a high degree of 
purity, and has almost no particulates--which is what causes the 
belching cloud you see when a diesel truck or bus starts to accelerate. 
When the Air Force tested our fuels and similar fuels made by 
competitors, the tests showed reductions in particulates of up to and 
over 80%.
    The Rentech fuel is also extremely low in sulfur--less than 1 part 
per million, far under the new EPA standard of 15 ppm. The finished 
fuel can be used with no engine modifications in any standard diesel 
engine--including trucks, buses and barges. It can even be processed 
into jet fuel. Under our timeline, the East Dubuque plant will be first 
commercial scale plant in the U.S. to produce quantities of this fuel--
about 2000 barrels per day in 2010.
    You should also smell the product. It has none of the typical odor 
of diesel. There are two other critical differences between this and 
typical diesel. Our fuel has a shelf life of at least 8 years, rather 
than 3-4 months for petroleum diesel--meaning that for the strategic 
reserve, for emergency first-responders, and the military, our fuel has 
incredible advantages. Next, our fuel is biodegradable. If it spills, 
it does not cause irreparable damage to waterways or wells.

                         ENVIRONMENTAL BENEFITS

    Let me take a moment to highlight the environmental policies that 
we intend to pursue. Rentech is committed to being environmentally 
friendly--and both our production and fuels have environmental 
benefits.
    As we manufacture our fuel, we remove most of the harmful regulated 
pollutants in the gasification stage. Sulfur and mercury come out as 
elements--they do not go up a smokestack to be scrubbed out, and do not 
leak into the environment. Once conversion is complete, regulated 
criteria pollutant emissions will be reduced about 33%. Some carbon 
dioxide emissions will be sequestered in products--in the fertilizer 
and in items like bottled sodas. Our fuel itself runs cleaner than 
traditional diesel, and as I mentioned earlier, it is much more stable 
and biodegradable. I would like to enter for the record an analysis 
that shows the environmental benefits of our CTL process.

             NATCHEZ, MISSISSIPPI: A POSSIBLE SECOND PLANT

    Our commitment to being environmentally-friendly brings me to our 
second proposed plant in Natchez, Mississippi, which would produce 
11,000 barrels per day. There, we are pursuing opportunities for 100% 
capture and storage of carbon. Our carbon dioxide output would be 
pumped into nearby older oil well fields, both helping to produce 
additional oil by forcing out additional supplies and trapping the 
carbon underground.
    As you can see, Rentech is aggressively pursuing commercial 
deployment. We have worked extremely hard to get over the significant 
financial hurdles that building--or as we are doing, converting--a 
plant takes. That is especially true of a first-of-its-kind-in-the-U.S. 
plant.

                       WHAT THE GOVERNMENT CAN DO

    We are planning to make full use of the EPACT 2005 incentives 
designed to jump-start this critical clean-fuel industry. Let me note 
that the States are also lending their assistance. The State of 
Illinois has been extraordinarily helpful--they helped us to complete 
feasibility studies, engineering studies and provided grants to assist 
with conversion to coal. The State of Mississippi has also been 
exceptionally supportive of the possibility of our second plant being 
located in Natchez, and they just passed a $15 million bond bill for 
the proposal.

                        FEDERAL LOAN GUARANTEES

    What you have been doing at the federal level, though, is 
absolutely vital to our efforts. We intend to seek the DOE self-pay 
loan guarantees for our conversion closing, planned for the first 
quarter of 2007. We understand that DOE's implementation has begun and 
we commend the Department and the Secretary of Energy for quickly 
moving to implement the authorized programs. The self-pay guarantees 
are integral to our financing of the East Dubuque conversion, so we 
appreciate and hope you will continue your efforts to ensure that the 
DOE loan programs are fully funded and implemented expeditiously.

             INDUSTRIAL GASIFICATION INVESTMENT TAX CREDIT

    To meet our aggressive timeline, we also will apply for the 
industrial gasification investment tax credit provided by the Energy 
Bill. The recent initiative by Senators Grassley and Baucus to raise 
the current $350M cap to $850 million is very helpful. If Congress is 
serious about trying to reduce our dependence on foreign oil import 
then allow me to offer an observation. Maintaining the current cap of 
$350M could slow the rollout of industrial gasification using coal to 
the point where the U.S. winds up losing more industry. Even an $850M 
cap will assist the development and deployment of only 6-7 plants--
hardly the creation of a full-fledged industry. At $75 per barrel, the 
price of oil last Friday, the U.S. is paying $850 million to foreign 
countries for oil every two days. To create a real incentive, it might 
be better to lift the caps altogether.

                         FUEL EXCISE TAX CREDIT

    There is another way for the federal government to help, by making 
the 50 cent-per-gallon fuel excise tax credit provided in the Highway 
Bill available to CTL fuels. To do that, you could extend the 
expiration of the current credit from 2009, when no CTL plants will yet 
be operational in the U.S., to at least 2014. Senator Bunning, I 
recognize your unique position a member of both the Senate Energy and 
Natural Resources Committee and the Senate Finance Committee, so any 
supportive words that you can pass on to other members of the Finance 
Committee would certainly be appreciated.

                     DEPARTMENT OF DEFENSE FUEL USE

    There are other ways that the government could catalyze commercial 
deployment of the CTL industry. Use by the military as diesel and jet 
fuel under long-term contracts could assist with financing the first 
plants--but it is going to take a realistic assessment based on the 
actual costs of production. Historically, the cost of generating fuel 
from CTL in the U.S. has been the major stumbling block to 
commercialization. Until recently the costs were not competitive with 
petroleum. Now they are. Today, fuels from CTL technology can be 
produced--finished--for $36 to $42 per barrel. That's the equivalent to 
purchasing raw crude at prices of $30 to $35 per barrel. EIA's AEO 2006 
projected long-term oil costs at $50 and above. The same forecast shows 
CTL production growing to 700,000 barrels per day by 2030. But the 
first plants must be financed and built, paving the way for the 
industry to flourish and add to the nation's energy security.

                               CONCLUSION

    I think the great potential of CTL is using American resources, 
American know-how, and American innovation to create both energy 
independence and American jobs. It's a big vision, but it starts with 
small steps. As I close, I'd like to let you know how Rentech is moving 
to commercial deployment.
    We intend to operate the first U.S. commercial-scale plant through 
the conversion I have outlined of the fertilizer plant in East Dubuque. 
We are pursuing a second larger scale plant in Natchez, Mississippi--
the Natchez Adams Strategic Fuels Center. We were invited by the local 
community to consider the possibility after Hurricane Katrina when 
Mississippi ran disastrously low on diesel. At Natchez, we can use two 
feedstocks--both coal and petroleum coke, a byproduct of the local 
petroleum industry. And as I have mentioned, there is the very real 
possibility of capturing and storing 100% of the carbon dioxide 
emissions through enhanced oil recovery in nearby oil fields. To our 
knowledge, this would be the first large-scale U.S. commercial capture 
and storage of man-made carbon emissions. Carbon dioxide injection is 
already being used in this oil-producing basin, but additional supplies 
are need.
    We are also exploring with several coal companies to create a 
replicable, iterative plant model that could be located at the mouths 
of mines. There, we would size a basic plant model that could be 
expanded. For twenty years, Rentech has researched and optimized our 
technology. We have refined our process to make it more effective and 
more environmentally-friendly. Now we are commercializing it.
    We aren't asking the government to subsidize the industry. We 
urgently need your help, though, to get a CTL clean-fuel manufacturing 
industry launched with private-sector funding. A robust clean-fuels 
sector is important so that we can meet our national energy needs, 
foster greater energy independence, and preserve a full measure of our 
energy security. At Rentech, we are ready. We are using American 
innovation to produce environmentally-friendly, energy-rich fuels to 
build America's future. And we are doing it using America's greatest 
natural energy resource, coal.
    Thank you for all that you have done to allow a jump-start of CTL 
in the Energy Policy Act of 2005, including the tax incentive. We 
intend to make use of your help to do just that--jump-start full scale 
utilization of CTL, and jump-start a new clean fuel manufacturing 
industry. Thank you as well for your time today.

    Senator Bunning. Thank you for your testimony.
    Mr. Roberts, you are our cleanup hitter.

 STATEMENT OF JAMES F. ROBERTS, PRESIDENT AND CEO, FOUNDATION 
   COAL CORPORATION, LINTHICUM HEIGHTS, MD, ON BEHALF OF THE 
                  NATIONAL MINING ASSOCIATION

    Mr. Roberts. Thank you, Mr. Chairman. I am James Roberts, 
president and CEO of Foundation Coal Corporation, one of the 
leading coal producers in the United States. I'm appearing this 
afternoon on behalf of the National Mining Association which I 
presently serve as vice-chairman. NMA and it's members applaud 
you and your colleagues for hosting this very timely and 
constructive hearing.
    Coal is meeting America's immediate energy needs and is 
poised to play a major role in the development of long-term 
technologies in a hydrogen based economy such as fuel cells. In 
short, coal is the energy of America's past, present, and 
future. It is about our Nation's energy future that I am most 
concerned. Increasingly today energy security has come to be 
viewed not just as one among many national goals but as a vital 
national imperative. Across the world energy has become the 
lynchpin of economic competitiveness, forcing the United States 
and its industrial competitors to strategically reassess their 
energy supplies and resources. We have so far avoided the dire 
consequences of our dependence on imported energy largely 
because the relative low price of oil sheltered us from them. 
However, at today's prices let alone projected prices, it is 
unlikely our economy will remain unscathed for much longer. 
America's coal reserves can provide us with an invaluable hedge 
against our growing addiction to imported energy and provide a 
significant source of fuel for a growing economy. Congress 
acknowledged this fact in the Energy Policy Act of 2005, but 
while Congress was farsighted last year in appreciating the 
need for more sustained and determined action to decrease our 
reliance on foreign energy, the response it proposed, while 
necessary, is not nearly sufficient to the challenge we now 
face.
    Consider the following circumstances that argue strongly 
for greater reliance on domestic fuels such as coal. First, 
even as after the Energy Act of 2005, the United States is 
projected to import a greater share of its growing oil needs. 
The result, according to the Energy Information Administration, 
is that net imports will make up 62 percent of our total oil 
supply by 2030. Bear in mind this is a very conservative 
estimate as EIA assumes a percentage of U.S. projected oil 
imports will be satisfied by liquid coal fuel. Absent large 
scale development of this fuel source, net imports will be 
significantly higher. Second, the oil we import will continue 
to come from unfriendly or unstable regimes. Third, oil imports 
from the region also force the United States to shoulder the 
burden of an enormous trade deficit as well. Fourth, energy has 
clearly become a central objective in the geopolitical struggle 
to secure global raw material supplies. China's energy demands 
alone are having and will continue to have a significant impact 
on global oil prices. In other words, no matter the perspective 
from which we examine our dependence on foreign oil, the 
unavoidable truth is that it makes our Nation less secure.
    In it's most recent energy outlook, EIA projects that coal 
derived fuels will constitute 8 percent of our expected oil 
import requirements by 2030, but NMA believes this projection, 
much like the Energy Act of 2005, is too timid a response given 
the more urgent circumstances the Nation now faces. A more 
appropriate target we believe comes from the Southern States 
Energy Board which expect alternative fuels such as liquified 
coal to replace approximately 5 percent of imported oil each 
year for 20 years beginning no later than 2010. This target 
stems not only from the rising prices of oil but also from the 
abundant supply of secure coal within our own borders. Illinois 
Basin coal reserves, including Kentucky's, boasts a greater Btu 
content than all the oil in Iran, Iraq, Kuwait, and Saudi 
Arabia, and this does not include the Btu content from the coal 
contained in the great State of Wyoming. This is a resource 
that no foreign government can nationalize, that requires no 
costly armed forces to protect and no exploration budget to 
locate. Nor does coal-to-liquids technology require R&D 
funding. The requisite gasification and liquefaction technology 
has been used for decades in oil deprived countries with coal 
reserves. In South Africa, for example, liquified coal has 
furnished as much as 60 percent of that nation's transportation 
fuels.
    Finally, and particularly appropriate for Earth Day this 
past weekend, the high grade diesel fuel produced from coal 
gasification is very clean. The low particulate, low mercury, 
and almost zero sulphur emissions profile of coal based fuel 
will mean reduced tailpipe emissions, cleaner running mass 
transit systems, and no measurable toxic pollutants.
    The argument for government support for coal liquefaction 
is a strong one. The strategic justification, the supply of 
coal required, and the technology for using it clearly are all 
in place to put the United States on the path to greater energy 
independence. We lack only the will, the determination to use 
it in response to the gathering risk we face from our growing 
dependence on imported energy. For despite higher global prices 
for oil and gas today, there is no guarantee that tomorrow the 
oil cartel will not manipulate the price of their resources 
long enough to discourage private sector investment in 
alternative fuels. The Government's participation will 
therefore be critical for offsetting the risk of marketplace 
manipulation by jump-starting domestic production on the scale 
we need.
    Certainly China appreciates the need for public sector 
participation. Like the United States, China boasts enormous 
coal reserves and also faces a growing oil import bill in the 
years ahead. But unlike the United States, China issues 
incremental solutions in favor of bold ones. China has 
evidently concluded that a different world calls for different 
approaches. I urge this committee to think not about the 
similarities between the oil issues today and those of the past 
years but about the differences that mark today's energy 
situation from that of the past and from these differences I 
hope you will draw the conclusion that we, too, must act more 
boldly than we have in the past.
    Thank you again for this opportunity and I'm happy to 
answer any of your questions.
    [The prepared statement of Mr. Roberts follows:]

 Prepared Statement of James F. Roberts, President and CEO, Foundation 
  Coal Corporation, Linthicum Heights, MD, on behalf of the National 
                             Mining Company

    Thank you, Mr. Chairman. I'm James F. Roberts, President and CEO of 
Foundation Coal Corporation, one of the leading coal producers in the 
United States. I'm appearing this afternoon on behalf of the National 
Mining Association, which I presently serve as Vice Chairman.
    NMA and its members applaud you and your colleagues for hosting 
this very timely and constructive hearing. We are confident that coal 
gasification can make America stronger through cleaner and more 
efficient use of its unrivalled coal reserves--leading to clean, high 
quality transportation fuel, an abundant feedstock to produce ethanol 
and affordable energy to power our industrial facilities.
    Coal is meeting America's immediate energy needs and is poised to 
play a major role in the development of long-term technologies in a 
hydrogen-based economy, such as fuel cells. In short, coal is the 
energy of America's past, present and future.
    It is about our nation's energy future that I am most concerned.
    Increasingly today, energy security has come to be viewed not just 
as one among many national goals but as a vital national imperative. 
Across the world, energy has become the linchpin of economic 
competitiveness, forcing the U.S. and its industrial competitors to 
strategically reassess their energy supplies and resources.
    In a way, we have all been here before. The call for greater energy 
security through lessening our dependence on foreign energy has 
resounded several times in recent decades. The call was first heard 
during the Arab oil embargo in 1973, when President Nixon launched 
Project Independence. It was echoed subsequently during the Ford, 
Carter and Reagan presidencies and during both Bush presidencies
    Unfortunately our repeated failure to break what President Bush so 
correctly called our addiction to foreign oil raises doubt amongst many 
of us that we will succeed this time. And yet never before has the 
price of failure been as great as it is today.
    We have so far avoided the dire consequences of our dependence on 
imported energy largely because the relatively low price of oil 
shielded us from them. However, at today's prices--let alone at 
projected prices--it is unlikely our economy will remain unscathed for 
much longer. We literally can no longer afford the complacency of past 
decades. The argument for concerted, bipartisan action to strengthen 
energy security is greater now than ever before.
    Increasingly, a secure America in the 21st century will mean energy 
security. This brings us to the nation's abundant and affordable coal 
reserves--and the purpose of this hearing.
    America's coal reserves can provide us with an invaluable hedge 
against our growing addiction to imported energy, and provide a 
significant source of fuel for a growing economy. Congress acknowledged 
this fact in the Energy Policy Act of 2005, which encourages the 
development of alternative fuels such as coal-to-liquid transportation 
fuels and coal-derived natural gas substitutes.
    But while Congress was far-sighted last year in appreciating the 
need for more sustained and determined action to decrease our reliance 
on foreign energy, the response it proposed--while necessary--is not 
nearly sufficient to the challenge we now face. Consider the following 
circumstances that argue strongly for greater reliance on domestic 
fuels such as coal.
    First, the U.S. is projected to import a greater share of its 
growing oil needs. While our daily oil requirements are projected to 
increase from 20 million barrels a day currently to 28 million by 2030, 
our domestic oil supply is projected to flatten after a modest rise to 
a mere 10 million barrels per day. The result, according to The Energy 
Information Administration (EIA), is that net imports will make up 62% 
of our total oil supply.
    Bear in mind this is a very conservative estimate, as EIA assumes a 
percentage of U.S. projected oil imports will be satisfied by liquefied 
coal fuel. Absent large scale development of this fuel source, net 
imports will be significantly higher. And as I believe others here will 
testify, this development is unlikely to materialize without additional 
incentives.
    Second, the oil we import will continue to come from unfriendly or 
unstable regimes--simply because these regimes have the oil we use. Our 
reliance on the Middle East alone obligates the U.S. to maintain and 
deploy armed forces at enormous cost. Oil imports from the region also 
force the U.S. to shoulder the burden of an enormous trade deficit as 
well.
    Third, energy has clearly become a central objective in the 
geopolitical struggle to secure global raw material supplies. China's 
energy demands alone are having--and will continue to have--a 
significant impact on global oil prices. The Congressional Budget 
Office recently estimated if China continues its current rate of 
growth, its unquenchable thirst for oil will force U.S. consumers to 
pay another 38 cents per gallon of gas in five years.
    In other words, no matter the perspective from which we examine our 
dependence on foreign oil, the unavoidable truth is that it makes our 
nation less secure.
    There is one consolation from the high oil and natural gas prices 
we are continuing to pay. It is the compelling incentives we now have 
to act decisively by developing energy alternatives from coal 
gasification--and from coal liquefaction. At even the most conservative 
levels projected, oil prices are expected to be high enough to make 
this technology economic to implement and the fuel it yields economic 
to produce.
    Certainly EIA believes so. In its most recent energy outlook, EIA 
projects that coal-derived fuels will constitute 8% of our expected oil 
import requirements by 2030. But NMA believes this projection, much 
like the Energy Act of 2005, is too timid a response given the more 
urgent circumstances the nation now faces. A more appropriate target, 
we believe, comes from the Southern States Energy Board, which expects 
alternative fuels such as liquefied coal to replace approximately 5% of 
imported oil each year for 20 years beginning no later than 2010.
    This estimate stems not only from the rising prices of oil, but 
also from the abundant supply of secure coal within our own borders. 
U.S. recoverable coal reserves of 275 billion tons is the energy 
equivalent of 550 billion barrels of oil. To put this enormous 
strategic resource into perspective, Illinois's coal reserves alone 
boast a greater BTU content than all the oil in Iran, Iraq, Kuwait and 
Saudi Arabia.
    This is a resource that no foreign government can nationalize--that 
requires no costly armed forces to protect--and no exploration budget 
to locate.
    Nor does coal-to-liquids technology require R&D funding. The 
requisite gasification and liquefaction technology has been in use for 
decades in oil-deprived countries with coal reserves. In South Africa, 
for example, liquefied coal has furnished as much as 60% of that 
country's transportation fuels.
    Finally--and particularly appropriate for Earth Day this weekend--
the high-grade diesel fuel produced from coal gasification is very 
clean. The low particulate, low mercury and almost zero sulfur emission 
profile of gasified coal will mean reduced tailpipe emissions, cleaner-
running mass transit systems and no measurable toxic pollutants. 
Moreover, the coal-to-liquid (CTL) process can capture carbon dioxide 
for use in enhanced oil and coal bed methane recovery, or for 
sequestration deep underground. The fuel will be produced domestically 
under the most comprehensive environmental laws in the world.
    The strategic justification, the supply of coal required and the 
technology for using it cleanly are all in place to put the U.S. on the 
path toward greater energy independence. We lack only the will--the 
determination to make this objective a strategic imperative 
commensurate to the gathering risk we face from our growing dependence 
on imported energy.
    One sign of this determination would be a commitment from Congress 
to provide the financial assistance required to cover the front-end 
engineering and design costs of building coal liquefaction plants. For 
despite higher global prices for oil and gas today, there is no 
guarantee that tomorrow the relatively small number of producing 
countries will not manipulate the price of their resources long enough 
to discourage private sector investment in alternative fuels. The 
government's participation will therefore be critical for offsetting 
this risk of marketplace manipulation by jump-starting domestic 
production on the scale we will need.
    This is simply an acknowledgement that private sector financing in 
the face of such risks is unavailable for costly, unconventional 
technologies that have not been widely used in the U.S.
    Certainly China appreciates the need for public sector 
participation. Like the U.S., China boasts enormous coal reserves--
second only to our own. Like the U.S., it too satisfies most of its 
energy needs with imported oil, again second only to the U.S.--and 
consequently it also faces a growing oil import bill in the years 
ahead.
    But unlike the U.S., China eschews incremental solutions in favor 
of bold ones. It plans to secure its future prosperity by investing 
some $30 billion in coal gasification and liquefaction technology. It 
understands that government participation is the only way to insulate 
its fledgling liquefaction industry against a concerted effort by OPEC 
to destroy it.
    China has evidently concluded that a different world calls for 
different approaches.
    I urge this committee to think not about the similarities between 
the oil issues today and those of past years, but about the differences 
that mark today's energy situation from that of the past. And from 
these differences, I hope you will draw the conclusion that we too must 
act differently than we have in the past.
    Thank you, again, for this opportunity. I'm happy to answer any 
questions you may have.

    Senator Bunning. Thank you, Mr. Roberts.
    There's a long history of CTL research in Kentucky, and for 
that matter, for the rest of the United States of America. Most 
if it's dating back to the 1970's when we got the first red 
flags. I mean, they couldn't have sent a bigger message in the 
early 1970's when we had our first boycott. America's 
recoverable coal reserves of 275 billion tons are the energy 
equivalent of 550 billion barrels of oil, unless I'm mistaken. 
That is more than all of the oil estimated in Saudi Arabia, 
Iraq, and Iran.
    Could you discuss the reasons why this vast supply has not 
been previously used and why CTL plants were never planned in 
Kentucky in the 1970's that were planned but were never 
completed? It's a jump ball. Go.
    Dr. Geertsema. Could I as somebody who was not here at that 
time.
    Senator Bunning. Oh, thanks. Call me on it.
    [Laughter]
    Dr. Geertsema. But I was involved in direct liquefaction at 
SASOL. My first job at SASOL was as a group leader of the 
direct liquefaction facilities there and since that time I've 
been at DOE meetings very often. I'm rather familiar with the 
developments going on here. My main focus in those years, as 
Dr. Miller indicated, was on direct coal liquefaction and in 
short the direct liquefaction technology which is much more 
complex, much harsher process conditions than indirect 
liquefaction. So economically it was a risky one. The pilot 
plants which were built here in United States, as you know the 
one in Kentucky, others at Wilsonville. In Europe there was the 
Bottropp plant. There was a Japanese plant actually built in 
Australia. All those plants could eventually, technically 
produce products but the economics were just not there to 
support it. On the indirect route, after SASOL two and three 
have been built in the early 1980's one should keep in mind 
that SASOL didn't build SASOL four either, even though they had 
a lot of reasons perhaps to do so, and again it was a matter of 
economics. Now that the price is sustained for quite a while 
above the $40, $45 a barrel, I think things have changed quite 
a bit but I think it's a matter of revisiting what was done in 
those years and learn from it and to move forward.
    Senator Bunning. Anybody else want to take a shot?
    Mr. Ramsbottom. Yes, I would concur. I've spent a lot of 
time recently on Wall Street in the capital markets and I think 
it comes down to the economics and instability of the commodity 
pricing. I think there is a wave of change going on out there 
but I think clearly from the financing community, that's been 
the issue.
    Senator Bunning. Also the price domestically or 
internationally of domestic crude--international crude----
    Mr. Ramsbottom. Absolutely right.
    Senator Bunning [continuing]. Obviously when you can buy it 
at $8 a barrel or $12 a barrel, I don't think we're going to 
see that anywhere in the near future.
    Kentucky sits at a unique position in America. We are home 
to state-of-the-art coal-to-liquids research as well as the 
coal mine production needed to fuel these new plants. I see 
significant investment in Kentucky but could you describe what 
kind of facilities would be interested in adopting CTL 
technology? Where in the countries would these plants be built, 
do you think? Well, obviously, one in Illinois and one in 
Mississippi.
    Mr. Ramsbottom. Yes, and being on the technology side of 
the equation, we're seeing where most plants are being proposed 
around the country so in our view, Kentucky and all the States 
that are mentioned. We're involved in the Wyoming project and 
thank you for your support, Mr. Thomas. So we're seeing the 
projects going on in most States that have coal supply today 
and I think from my perspective we're seeing a big ramping up 
of those States getting energized about it and the coal 
companies also getting energized about it. So I think from my 
perspective, you know, the States that have the coal, we won't 
see any barriers.
    Senator Bunning. Presently though those States that have 
coal are having a tremendous time just producing enough coal 
for the coal market. Now, give me an idea of how we're going to 
produce enough to take coal to liquified and be able to produce 
that much more coal.
    Mr. Ramsbottom. The gentleman to my left could probably 
address that better than I can.
    Senator Bunning. Okay.
    Mr. Roberts. Well, let me just fall a little bit back on 
your previous question as to where the CTL plants might be 
located, and I would add that along with the technical side of 
that, I would suggest that a better place to locate the plants 
would be obviously near the coal so that the coal doesn't have 
to be transported to the CTL plant. As we all know, the 
problems that we're currently having in transporting the coal 
from our operations today just to meet the demands for our 
electricity base.
    On the second part of that question, I'm fully confident 
that given the directive from the Federal Government on what 
the requirements will--a serious commitment from the Federal 
Government on the coal-to-liquids process, Senator, is that the 
coal industry is very capable of increasing the production of 
coal over the next 10 to 20 years to meet the demand. It can't 
do it, we can't do it without some certainty that the demand 
for our product will be there and that also issues such as 
transportation and permitting aren't streamlined. And I would 
just give a small example of that. Today, for us in the 
industry to develop a new coal mine, let's talk about the 
Eastern part of the United States in Northern App. or Central 
App., for us to develop a mine that would produce about seven 
to eight million tons a year will take us anywhere from 7 to 10 
years to develop that mine most of which of that time is 
obtaining the necessary permits to develop the--before we even 
get to the development of the mines. So we can meet the demand 
for production for coal in the future but we have to look at 
other aspects that relate not only to the coal-to-liquids but 
also on how we can accelerate the process of developing the 
mines that are necessary.
    Senator Bunning. This is off the subject but it is very 
similar and I want to bring it up because in the energy bill we 
changed the rules for siting nuclear plants. Now we have 19 
applications for siting of nuclear plants because of that 
change in the law. Maybe we need to take a look at the siting 
of mines and the development of mines and modernize the 
regulations so that it doesn't take 8 years because by the time 
you get it done maybe it won't be as good as it was, or at 
least the company thought it would be, 8 years prior. And that 
is a major problem commercially.
    Mr. Roberts. No, and I agree, and I want to point out also 
that the mines that I was talking about were green field 
projects that we would be starting from scratch on them. To add 
additional production or capacity does not quite take that long 
but we still are measuring the time in years and not months. 
But I think a comprehensive view on the entire subject would be 
very helpful for our industry.
    Senator Bunning. Thank you.
    Senator Thomas.
    Senator Thomas. Thank you. I appreciate the testimony. I 
think clearly some of it is kind of interesting. We all 
recognize the problem that we have and yet I think most of us 
recognize that there are some solutions available but we seem 
to be having a little trouble making the move. Clearly, I hope 
we don't end up in the politics of siting these plants. I think 
they ought to be sited where they are the most efficient, where 
the source of the fuel is, and, of course, we're looking at 
ways to be able to transmit that fuel more economically than 
you do in the case of coal. I might say that we're in a 
position in Wyoming, where we can't market all that we can 
produce largely because of the restraints on the shipping of 
railroads. So that's an opportunity.
    Doctor, do you think the policies and incentives that are 
available now are sufficient to get the private sector moving 
in these projects?
    Dr. Geertsema. Senator Thomas, I think the framework is 
there but as was sort of discussed a bit earlier I think the 
rules for how this should be done need to be fleshed out and 
made very clear to potential investors. I think what is also 
very important is that this is an exercise, and I mentioned 
that in my written testimony, that calls for an integrated team 
of players. Obviously, the coal suppliers would be key. You 
need the technology suppliers, but you also need to have what I 
call an owner-operator partner in this whole exercise. At the 
moment utilities are not the sort of people who would easily 
step into running a CTL facility. It's more like a chemical 
plant than a power station. The chemical industry, by name, 
Eastman of course has done this sort of processing for their 
facilities in Kingsport so they have that framework for running 
a coal-to-liquids facility but besides that and of course the 
North Dakota people have done it in a different way but I think 
one needs to be pushing, facilitating's perhaps a better word, 
to get the owner-operators that can really take care of doing 
these things and have substantial resources at their disposal 
to take this forward. So it's a combined team effort to do it.
    Senator Thomas. It is, no question. And a lot of financial 
investment involved.
    Mr. Roberts, you indicated the private sector needs more 
incentives. We provide $500 million in the form of 20 percent 
tax credits, authorized a billion dollars worth of tax credits 
to finance clean coal facilities, title XVII issues a loan 
guarantee up to 80 percent, what additional incentives are 
there to get the private sector ready to move?
    Mr. Roberts. Well, I think they were a good step, Senator, 
and I think they addressed issues that maybe were not as 
imperative as the issues we have today. The Energy Policy Act 
that was passed in 2005 I think was developed and addressed 
matters that didn't really, I think, materialize from the 
national security side or the energy independence side until 
post-2005 and, for example, I think that Katrina showed us the 
vulnerability of our domestic sources of production and 
refining oil. I think that we have finally recognized as a 
country the increased demands that countries like China and 
India are placing on the same sources of oil that we use. So my 
point is that we need more--we need a much bolder approach. The 
EIA's forecast for coal-to-liquids is 8 percent. I don't think 
that's enough. Our energy demand for the next 20 years is going 
to increase by 27 percent. I think we need more than just the 
incentives that are in the current policy act. I think we need 
a much broader, much bigger. If you look at some of the numbers 
in the National Coal Council's report to the Department of 
Energy, in that report they have a proposal that spends about 
$500 billion over a period of time to increase coal production 
by 1.3 billion tons over the next 20 years which would not only 
be for coal-to-liquids but it would be also for coal to be used 
as a feedstock for ethanol, for coal bed methane, for the 
CO2 capture and sequestration to be used for 
increase extraction of oil, so it's a much larger issue today 
that we need to address and I think the incremental approaches 
that we have taken in the past are not going to be enough to 
meet the energy demands that we're going to see this country 
will require over the next 20 years.
    Senator Thomas. I expect that's right, however, if you see 
yourself in the position that oil companies are in now, the 
profits look pretty good, don't they?
    Mr. Roberts. I wish we were an oil company, Senator.
    [Laughter]
    Senator Thomas. Mr. Ramsbottom, you mentioned you're 
removing sulphur and mercury as you convert to fuels. What do 
you do with the sulphur and mercury that's removed?
    Mr. Ramsbottom. The sulphur comes out in a pure stream and 
that is sold commercially into the marketplace to make 
feedstock for seeds, for ammonia fertilizer, again, back into 
the marketplace. And the mercury, again, same thing. The vapor 
is removed from the gasification, captured in beds, and that is 
sold back out commercially.
    Senator Thomas. I see. Just very quickly then, Mr. Hawkins, 
you in your testimony provided examples of the well to wheels 
carbon dioxide emissions from the current transportation fuels 
and so on. What are the well to wheels numbers for hydrogen 
produced by electronics?
    Mr. Hawkins. Senator, the well to wheel emissions from 
hydrogen would depend on what source of energy is used to 
produce that hydrogen. If one used electrolysis made from wind, 
then the well to wheels would be close to zero. If one used 
electrolysis made from coal, then the numbers would be similar 
to what it is for coal-to-liquids, that is similar to crude 
oil.
    Senator Thomas. Similar. Okay. All right. Well, I just hope 
that we can move forward. Obviously, we, I think, have some 
potential solutions there, long-term solutions, and we need to 
be able to move it as quickly as possible.
    So, thank you for being here.
    Senator Bunning. A couple more questions and I'm going to 
then submit to you some questions in writing and I would like 
for you to respond for the record.
    I understand the CTL fuel needs no alternations to be 
blended into current diesel stock. How compatible is CTL fuels 
with existing American infrastructure? Could CTL fuels be 
readily transformed into jet fuel or a DOD single battlefield 
fuel? Anyone.
    Dr. Geertsema. Gentlemen, I'll start by responding with the 
South African experience. Already when the SASOL one plants 
were commissioned in the mid-50's, exactly this happened, both 
gasoline and diesel were blended into products from 
conventional refineries. The composition is different. They 
were small adjustments in terms of additives and the motorist 
in South Africa at the moment would not know whether he or she 
is driving on synthetic fuels or crude oil refinery based 
fuels. So there's this full compatibility in that sense.
    On the jet fuel side, it's not as straightforward as that 
because the requirements for jet fuel are more stringent than 
for normal automotive fuels. For quite a while already at the 
Johannesburg International Airport a number of the airlines 
there would be using 50/50 blend of SASOL derived fuels blended 
with crude oil based fuels.
    So, again, full blending as a neat fuel or just a pure syn 
fuel, the requirements are a bit more tricky to reach, 
especially in terms of lubricity and those sort of things, but 
I think with further development it can certainly be achieved. 
What is at the moment a challenge, and the DOD has been also 
speaking to us on this topic, the single battlefield fuel is a 
fuel which doesn't exist yet. It's----
    Senator Bunning. It's different than this.
    Dr. Geertsema. It's different from that, sir. We do need to 
work on that and that's why I stressed in my testimony the 
issue of getting a Fischer-Tropsch technology with what I call 
a mini refinery to follow products for testing. Most current 
Fischer-Tropsch facilities of a larger scale have a fixed 
refinery to meet say diesel specifications. It's hard to play 
around at that level to tailor-make fuels for the military, 
whereas if we go for what I propose--the half a barrel a day 
facility--one can really optimize those processes to start with 
test quantities of say half a barrel a day and then from there 
eventually go to the next scale. But that will take time.
    Senator Bunning. Okay. Mr. Hawkins suggests in his 
testimony that a coal-to-liquids plant with an annual output of 
80,000 barrels will cost about $6.4 billion to build. Do any of 
the other witnesses agree or disagree with that? Do you think 
that's a high price or do you think that's in line with about 
what it will cost?
    Mr. Ramsbottom. I can speak to 10,000 barrels up to 50,000 
barrels.
    Senator Bunning. Okay.
    Mr. Ramsbottom. Ten thousand barrel a day facility is 
around a billion dollars and a 50,000 barrel a day plant is 
around $3 to $3.5 billion.
    Senator Bunning. Okay.
    Dr. Geertsema. I'd concur with him.
    Senator Bunning. That's just slightly less. And what about 
you?
    Dr. Geertsema. I concur with those numbers.
    Senator Bunning. You concur with those numbers? Okay.
    Mr. Hawkins. Just to clarify, Mr. Chairman, those numbers 
are not NRDC's estimates. They come from a National Coal 
Council report.
    Senator Bunning. Well, I just was trying to get a better 
opinion, if there was one, and there are similar and dissimilar 
opinions.
    Mr. Ramsbottom, would you please explain how your process 
manages carbon emissions? Oh, you already have.
    Mr. Ramsbottom. Right.
    Senator Bunning. Excuse me.
    Mr. Ramsbottom. Sir, if I may go back on the blending.
    Senator Bunning. Go ahead.
    Mr. Ramsbottom. These fuels require no new infrastructure. 
And I think we talked about that earlier and since we have 
announced two plants, we have gotten tremendous interest from 
local refiners for blending our products into their products, 
to answer your question.
    Senator Bunning. Whether it be regular gasoline, whether it 
be jet fuel----
    Mr. Ramsbottom. Diesel products.
    Senator Bunning. Diesel products. Okay. In other words, we 
can blend similar diesel products whether they were made out of 
soy or----
    Mr. Ramsbottom. Current diesel products on the market today 
we can blend.
    Senator Bunning. Thank you. Okay. Mr. Hawkins, I want to 
ask another question. The loan guaranteed program envisioned by 
the 2005 Energy Act specifies, specifically suggests that 
projects funded by the program seek to address the carbon 
emissions that would be produced by products such as coal-to-
liquids plants. While this would not necessarily address the 
carbon that would be emitted by vehicles, it does seek to 
substantially reduce the carbon emissions from the liquids 
produced through carbon sequestration. Do you agree that this 
effort has substantial merit from a national security 
standpoint and that it seeks to reduce our dependency on 
foreign sources of petroleum?
    Mr. Hawkins. Mr. Chairman, as I indicated in my statement, 
we support the priority of reducing our dependence on foreign 
sources of petroleum. And the question that we think is the 
right question to ask from a policy standpoint is which are the 
best options? Which options will deliver us the most oil 
savings the fastest in the most secure way and that will leave 
us with an environment that we all treasure. And we think 
certainly that when coal is used, it will be critical that coal 
have its carbon dioxide captured and so we support provisions 
in the law that encourage, and indeed, we would support 
provisions that require that capture and we hope the Congress 
will move in that direction very soon.
    Senator Bunning. I wish you'd been around in 1974 when we 
needed this technology to be advanced a lot quicker and we got 
into the problem of the cartel manipulating the price and 
stopping and boycotting and all those things that started and 
sent a red flag and nobody paid any attention for 25 to 30 
years. We finally got an energy bill last year and now we're 
trying to refine that energy bill.
    That's what this is all about. That's what this hearing's 
about, the first of many, and I appreciate your participation 
and I want to thank you for being here and we will submit some 
more questions to you for the record. Thank you. We're 
adjourned.
    [Whereupon, at 3:45 p.m., the hearing was recessed, to be 
reconvened on May 1, 2006.]

                      COAL GASIFICATION TECHNOLOGY

                              ----------                              

                          MONDAY, MAY 1, 2006

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                   Washington, D.C.
    The committee met, pursuant to notice, at 2:31 p.m., in 
room SD-366, Dirksen Senate Office Building, Hon. Lamar 
Alexander presiding.

 OPENING STATEMENT OF HON. LAMAR ALEXANDER, U.S. SENATOR FROM 
                           TENNESSEE

    Senator Alexander. The hearing will come to order.
    This is one in a series of hearings of the Committee on 
Energy and Natural Resources, authorized by our chairman, Pete 
Domenici, and Senator Bingaman, the ranking Democrat, to review 
the energy bill that the Congress passed last summer, and to 
make sure the provisions we adopted to try to provide a supply 
of clean energy for this country in large amounts at a 
reasonable cost are working.
    We hear a lot today about the high price of gasoline. The 
hearing today is about gas, a different kind of gas, natural 
gas. I can recall that in 2005, when, along with Senator 
Johnson, I introduced the Natural Gas Price Reduction Act, we 
were startled by the increase in the price of natural gas. Many 
of the provisions that were included in our Natural Gas Price 
Reduction Act found their way into the Energy Act that the full 
Congress adopted nearly a year ago. Natural gas had a price of 
about $2.50 per unit in the year 2000. The economy of the 
United States was geared to operate at about that level. But 
the price of natural gas got as high as $15 per unit last 
December.
    We had testimony at that time that if the price of gasoline 
were going up as fast as the price of natural gas, the price of 
gasoline at that time would be $7 a gallon. So, while we hear 
more about gasoline and the effect of it on the ordinary 
American is a major effect, the price of natural gas has as 
large an effect on farmers, on homeowners, and on keeping jobs 
in this country that might otherwise go overseas, as does the 
price of gasoline.
    The price of natural gas, fortunately, has dropped back 
down to a level of about $7 per unit. But that's still too 
high, and it's higher than most of our economy is geared to 
work on. So, it's still hurting farmers, it's still hurting 
homeowners who are using natural gas, and it's still an 
incentive to drive American manufacturing jobs, especially, 
overseas. And I don't have the exact figure, but if the price 
of gasoline had gone up as much as the price of natural gas 
today, it would be higher than $3. It might be $4. And maybe 
someone on the panel can tell me what that comparative price 
would be.
    One of the most interesting provisions in the Energy Act of 
last year dealt with the idea of turning coal, of which we have 
a lot in this country, into synthetic gas as a substitute for 
natural gas. Increasing the supply of synthetic gas would help 
stabilize, and maybe even bring down, the price of natural gas.
    Coal can be turned into a synthetic gas, which is then used 
to make chemicals. That is exactly what, for example, Eastman 
Chemicals does. We're familiar with that in Tennessee, because 
Eastman has, for generations, provided a stable source of 
thousands of jobs. It's as much as a part of our landscape in 
Upper East Tennessee as the mountains are. And when the price 
of natural gas threatened jobs at Eastman, that got the 
attention of everybody in our State, just as it did in a 
similar way all across our country. But Eastman has been using 
coal since 1974 to make specialty plastic products. We'll hear 
more about that today.
    But it's not just coal that can be gasified. Petroleum 
coke, heavy oils and waste, seemingly anything with carbon in 
it can be gasified. Gasification is very flexible. It can 
convert these into valuable products, including hydrogen, 
electricity, steam and chemicals. Gasification produces 
significantly fewer emissions, uses less water, generates less 
waste than other technologies. And gasification facilities can 
be designed to capture carbon dioxide for further industrial 
use or for sequestration.
    Finally, gasification is a link to the hydrogen economy. 
Because of these many positive attributes, and because of the 
high price of natural gas in recent years, the Energy Policy 
Act of 2005 contains two provisions which we, in Congress, hope 
will speed the development and deployment of industrial 
gasification technologies.
    The first is a tax credit for qualifying industrial 
gasification projects. We authorized these tax credits for a 
total of $350 million. The deadline for applying for these 
credits is June 30 of this year. Projects must be certified by 
Treasury, in consultation with the Department of Energy. A 
competitive bidding process will be used by the Government.
    The second provision in the Energy Policy Act to speed 
development and deployment of industrial gasification 
technologies is the Federal loan guarantee provision. I just 
saw Senator Domenici on the Senate floor. He was the principal 
sponsor of that loan guarantee provision. He's very interested 
in its progress, how the Department is coming, looking forward 
to the results of this hearing.
    So, this is an oversight hearing. We're here to hear from 
the Under Secretary of Energy--we're delighted that he has 
taken the time to be here--about the status of the 
administration's implementation of these two provisions of the 
Energy Policy Act. And we'll also hear from companies on the 
cutting edge of industrial gasification. And we'll hear from 
the Natural Resources Defense Council. It ought to be an 
interesting afternoon. We'll have two panels. We'll hear from 
Secretary Garman first, then from the companies and from the 
Natural Resources Defense Council.
    But, first, I'd like to ask Senator Thomas if he has 
comments he'd like to make before we begin our hearing.

         STATEMENT OF HON. CRAIG THOMAS, U.S. SENATOR 
                          FROM WYOMING

    Senator Thomas. Thank you, much, Mr. Chairman. I appreciate 
having this hearing.
    Of course, this is the second in a series of hearings to 
talk about implementing our policy. And that's really where we 
are. We hear a lot of people talking about the trouble with 
energy, Do we need some new laws? The fact is, probably more 
than anything, we need to implement the laws that are now in 
place. And we have an opportunity to do that.
    There's lots of details, Mr. Chairman, and you've covered a 
lot of those. So, I'll submit my statement for the record.
    But I just want to make a couple of points. One, of course, 
as we all know, is that our greatest source of future fossil 
fuels is coal. And what we need to do is find ways to use that 
coal in an environmentally sound way, sounder than we have in 
the past, if we can. Also, the cost to get it to the market. 
Much of the coal supply we have is in Wyoming and Montana and 
that part of the world; and much of the market, somewhere else. 
So, we have to work at getting those things there. And we can 
do that.
    Half of our electricity is generated by coal. And, quite 
frankly, it ought to be more, because the other fuels are more 
flexible and can be used for other things.
    We had a hearing in April. The Secretary was there. Thank 
you, Secretary Garman, for being there in Wyoming to talk about 
the conversion of coal to other sources. And, of course, this 
gasification is certainly one of those. And I appreciate that.
    Relatively inexpensive for coal--and I was amazed at the 
kind of facts that came out of that, in terms of how you can 
really increase the efficiency and the cost of converting coal 
and getting it to the market in other forms. And we can do 
something about CO2, we can do something about the 
corridors and the movement to them. And, really, that's a great 
thing to do.
    I hope we can be realistic about developing some of these 
operations where the coal is. Now, I know there's always going 
to be debates about where the plants go, and particularly the 
early ones that have some incentives. But we ought to really 
put the facilities where the coal is. And we just recently had 
a memorandum of understanding between Wyoming and California 
for the purpose of using coal and getting it produced there in 
the West, having a corridor to get it to California, and also, 
as you know, they've been a little fussy about electricity made 
out of coal. But if this can be--this conversion, then they're 
more willing to do that.
    I think it's a very important point. And, again, we need to 
just find a way to get on with it. People know how to do this. 
We just need to get the incentives on the ground and move.
    Thank you, Mr. Chairman. I'm glad we're having this 
hearing.
    [The prepared statement of Senator Thomas follows:]
   Prepared Statement of Hon. Craig Thomas, U.S. Senator From Wyoming
    Good afternoon and welcome. I'd like to thank all of the witnesses 
for appearing before the Committee today. This is the second in a 
series of hearings on implementation of the Energy Bill that was signed 
into law August of last year.
    Last week we received testimony on the conversion of coal-to-liquid 
fuels. Today, we're talking about gasification, which is an important 
part of the coal-to-liquid fuels process.
    Our conversation today has important implications not only for the 
United States, but for the international community as well. Coal is a 
significant potential feedstock for the gasification process. In the 
next ten years, global use of coal is projected to double. Coal 
accounts for 90 percent of the United States' total energy reserves.
    The challenge is to meet our nation's environmental, economic, and 
security goals while developing this resource. Gasification is an 
incredible technology, and capable of helping us meet this challenge 
and overcome it.
    As we heard last week, you can create liquid diesel and jet fuels 
from coal. You can even make plastics, epoxies, and other advanced 
materials from coal using gasification. Obviously, you can also 
generate electricity from coal. Over half of the electricity generated 
in the United States comes from coal.
    Gasification will allow us to generate more energy from domestic 
fuels including coal, refinery by-products, and biomass.
    One of the most significant benefits of gasification though, is our 
ability to produce the energy our consumers and businesses need in an 
environmentally sound manner.
    On April 12th of this year, we had a chance to discuss coal issues 
at a Field Hearing that this Committee held in Casper, Wyoming. On 
April 13th, I also convened a forum on a broader set of energy issues 
in Casper. Undersecretary Garman joined us at that forum and his 
remarks were greatly appreciated by myself and the audience. I would 
like to thank you for making the trip to Casper Dave, and I would like 
to thank Chairman Domenici for scheduling the Field Hearing as well.
    I am glad to be re-visiting these issues today.
    Coal is a relatively inexpensive fuel and is abundant here in the 
United States. Wyoming is our nation's largest supplier of coal. Last 
year, 36 percent of domestic coal production came from Wyoming.
    I've said before that Wyoming's ability to not only mine coal, but 
to use it in innovative projects is limited only by our capacity to get 
those value-added products to market. For this reason, we need to 
increase pipeline, rail, and electrical infrastructure.
    We will do these things, and provide the necessary conditions for 
IGCC technologies to move forward in states like Wyoming where the coal 
reserves are located.
    Of course, we must pursue these new technologies in conjunction 
with greater efficiency and conservation.
    These Monday afternoon hearings are about implementing the Energy 
Bill, which contains provisions to address all of these things.
    The private sector and state governments are ready to move forward 
with these projects. There is increasing evidence of this desire to get 
underway. A Memorandum of Understanding was recently signed by the 
Governors of Wyoming and California to use electricity produced in 
Wyoming from clean coal and renewable resources.
    This is not a partisan issue, it cuts across party lines, and I 
look forward to working with Senators from the four states involved in 
the Frontier Line to move these IGCC projects, and the transmission 
necessary to deliver their electricity, forward.
    In achieving these goals, we'll improve the nation's security and 
environment, while creating jobs and strengthening our economy.
    I'll be interested to hear our witnesses' perspective on the issue 
of gasification technology and the opportunities that exist for us to 
move forward.
    Thank you Mr. Chairman, that concludes my opening statement.

    Senator Alexander. Thank you, Senator Thomas. And your 
statement will be made a part of the record.
    Senator Bingaman, would you like to make a statement before 
we begin the hearing?

         STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR 
                        FROM NEW MEXICO

    Senator Bingaman. Mr. Chairman, I appreciate Secretary 
Garman being here, and the other witnesses.
    As I understand, this hearing is designed to look at issues 
related to syngas production; and, particularly, there's 
testimony talking about the section 48(b) tax credits that are 
found in section 1307. I guess the IRS comment period's about 
to close those tax credits, that section, and the DOE Loan 
Guarantee Programs that we authorized in title XVII of the 
bill. So, I'm anxious to learn more about the concerns that 
people have on both of those issues.
    Thank you.
    Senator Alexander. Thank you, Senator Bingaman.
    And we'll now proceed to the testimony of the Under 
Secretary of the Department of Energy, David Garman.
    Secretary Garman, thank you for coming. If you could take 5 
minutes or so, or if you need a little more, to present what 
you would like to say, and that'll leave us time to ask you 
questions. Then we'll go to the second panel.

 STATEMENT OF DAVID K. GARMAN, UNDER SECRETARY, DEPARTMENT OF 
    ENERGY, ACCOMPANIED BY GEORGE RUDINS, DEPUTY ASSISTANT 
              SECRETARY FOR COAL AND POWER SYSTEMS

    Mr. Garman. Thank you, Mr. Chairman.
    And you said it very well, we really believe that 
gasification technology is poised to make a revolutionary 
impact in the United States and the global marketplace. It's 
appropriate that we transition toward large industrial and 
utility-scale gasification in the quest for greater efficiency 
and the cleaner use of combustible energy resources, 
particularly in light of the abundant supplies of coal and 
renewable biomass that we have available in this country.
    Gasification-based power systems have the potential to 
almost double the efficiency of the current combustion-based 
fleet. Moreover, near-zero emission, gasification-based power 
systems are within our technical reach. Gasification-based 
systems can also produce clean hydrogen or liquid fuels or a 
variety of petrochemicals, synthetic natural gas, or any 
combination of these products and electricity. Thus, they could 
provide us with supply options we do not have today.
    The diagram to my right, your left, describes gasification-
based system concepts. A variety of feedstocks, including coal, 
biomass, petroleum coke, petroleum residuals, or even waste, 
can be gasified into a synthesis gas, or syngas, comprised 
mainly of carbon monoxide and hydrogen. From there, a variety 
of pathways leading to a variety of different products are 
possible. But whether you are generating liquid fuels, 
electricity using combustion turbines, electricity using steam 
turbines, electricity using fuel cells, or hydrocarbon-based 
chemicals and products, gasification is the common technology 
at the heart of all of those processes.
    Of course, the prototype for the ultimate gasification-
based power system, FutureGen, is now underway, led by a 
government/industry consortium that is dedicated and committed 
to its success. We're working to have FutureGen operating by 
2012.
    We're confident in the underlying technology behind 
gasification plants. Indeed, some gasification plants in 
certain applications have worked for many years, and worked 
well. But gasification powerplants, in particular, face early-
mover issues, such as permitting delays, longer shakedown 
periods, and higher costs, since the learning curves in 
fabrication, construction, and operation have not yet taken 
hold. Therefore, the business risks of the first plants remain 
greater than conventional plants. Comparative costs are 
somewhat higher, as well, although we expect they will decline 
with time and experience. Since gasification systems, like most 
energy projects, have substantial upfront capital costs, 
financing remains a challenge, in light of the business risks 
and the higher costs just mentioned.
    We're encouraged, however, by the fact that manufacturers 
of gasification-based powerplants are beginning to offer 
performance warranties, management and operating contracts, 
fixed-price construction contracts, and other instruments to 
diminish risk.
    Consistent with the new authorities provided to the 
Department of Energy in the Energy Policy Act of 2005, we are 
also establishing a Loan Guarantee Program within the 
Department that we expect to be available for gasification-
based technologies. Thus far, we have established a Loan 
Guarantee Office under the Department's chief financial 
officer, and we're currently recruiting a permanent director. 
We have detailed staff from other programs, and expect to be 
detailing staff from other agencies that have some of the 
necessary experience in Federal loan guarantee programs. We're 
drafting program policies and procedures. We're establishing a 
Credit Review Board. We're going to employ top outside experts 
for financial evaluation, construction engineering evaluation, 
and credit market analysis to assist us in our evaluations of 
applicants.
    We're proceeding, but we're doing so with no small measure 
of caution and prudence. While the provisions of the Energy 
Policy Act provide a self-pay mechanism that, in theory, 
reduces the need for appropriations, it does not eliminate the 
taxpayers' exposure to the possible default of the total loan 
amount. It is also our view that the Federal Credit Reform Act 
of 1990 contains a requirement that prevents us from issuing a 
loan guarantee until we have an authorization to do so in an 
appropriations bill. We do not believe we have the authority to 
proceed with an award, absent having explicit necessary 
authorizations in an appropriations bill, and we'll look 
forward to working with Congress to address this issue.
    I will end there, Mr. Chairman. I appreciate this 
opportunity to appear today. This is a very relevant and timely 
subject for the committee to cover, and we commend you for 
that.
    Thank you very much.
    [The prepared statement of Mr. Garman follows:]

        Prepared Statement of David K. Garman, Under Secretary, 
                          Department of Energy

    Thank you for this opportunity to testify before the Committee on 
the subject of industrial scale gasification in the context of 
implementation of the Energy Policy Act of 2005.
    Gasification technology is poised to make a revolutionary impact in 
the U.S. and global marketplace, so this is an extremely timely topic 
for the Committee's consideration. Simple combustion technologies have 
served us well since early humans first employed fire for warmth, 
light, and cooking. But it is appropriate that we in the 21st century 
transition toward large industrial and utility-scale gasification in 
the quest for greater efficiency and the cleaner use of combustible 
energy resources, particularly in light of the abundant supplies of 
coal and renewable biomass we have available.
    The Department of Energy and industry have been investing in 
gasification systems research for decades. Very early in our work, we 
realized that commercially mature gasification-based power systems 
could nearly double the efficiency of the current combustion-based 
fleet. The average efficiency of today's combustion-based coal power 
plant fleet is 32 percent and state-of-the-art coal-fired power plants 
operate at about 38 percent efficiency. We believe commercially mature 
gasification-based power plants can achieve efficiencies in the 55 to 
60 percent range. To the extent that any of the remaining waste heat 
can be channeled into process steam or heat, perhaps for nearby 
factories or district heating plants, the overall fuel use efficiency 
of future gasification plants could reach as high as 70 to 80 percent.
    However, the potential efficiency gains only tell part of the 
story. Today, new gasification applications have emerged that were not 
even imagined at the start of our research efforts.
    For example, near-zero atmospheric emission systems, emitting 
minimal pollutants and carbon dioxide, are within our technical reach. 
In addition, gasification-based systems can be configured to produce 
clean hydrogen or liquid fuels, or a variety of petrochemicals, 
synthetic natural gas, or any combination of these products and 
electricity. Gasification-based systems are also projected as having 
the potential to produce these products at reasonable cost while using 
some of our most abundant domestic fuel resources--coal and biomass.
    This simple diagram describes gasification-based system concepts. A 
variety of feedstocks, including coal, biomass, petroleum coke and 
residuals, or even waste can be gasified into a synthesis gas (or 
syngas) comprised mainly of carbon monoxide and hydrogen. From there a 
variety of pathways leading to a number of products are possible. But 
whether you are generating liquid fuels, electricity via combustion 
turbines, electricity via steam turbines, electricity via fuel cells, 
or hydrocarbon based products, gasification is the common technology at 
the heart of the process.
    Of course, the prototype for the ultimate gasification based 
system, FutureGen, is now under way led by a Government/Industry 
Consortium that is dedicated and committed to its success. Other 
governments and international companies have expressed strong interest 
in joining the FutureGen effort (and some have already joined), which 
will pave the way for the global deployment of gasification based zero 
emission systems.
    In the State of the Union address, President Bush announced the 
Advanced Energy Initiative. The initiative's technology focus includes 
both power and transportation technologies, and it is important to 
stress that gasification has important contributions to make in each of 
these areas. For example, just as gasification can dramatically 
increase the efficiency and lower the environmental impact of power 
production as mentioned earlier, it can also be a pathway to the 
production of clean diesel, ethanol, synthetic crude, and other fuels 
and help reduce our dependence on foreign sources of energy--one of the 
key goals of the Advanced Energy Initiative.
    The challenge that confronts the broader introduction of 
gasification-based systems is the same challenge that confronts many 
energy systems the up-front capital costs are substantial. Lenders lack 
experience with these projects, so they are less willing to assume the 
extra risks involved in early generation commercial deployments of 
gasification technologies. In addition, combustion-based systems have 
been the beneficiary of centuries of incremental improvement and cost 
reduction, so they understandably enjoy some ``first cost'' advantages. 
We have every reason to expect that the costs of gasification-based 
technologies will decline as experience with the technology increases--
the 10th plant will be more affordable and reliable than the first. We 
are also encouraged by the fact that manufacturers are beginning to 
offer performance warranties, management and operating contracts, 
fixed-price construction contracts, and other instruments to diminish 
risk.
    Gasification technologies offer benefits such as lower emissions 
and greater efficiencies. The widespread deployment of utility and 
industrial gasifiers may provide an economic alternative to natural gas 
for consumers who are able to switch to syngas, thereby increasing 
availability of natural gas for other residential, industrial, and 
commercial consumers who find it more challenging to change fuel or 
feedstock.
    The industrial sector is the largest consumer of natural gas in the 
United States, accounting for a third of U.S. consumption. Bulk 
chemicals and petrochemical refining are the largest consumers of 
natural gas by volume, and natural gas is also a significant cost 
component of many other industrial sectors. Natural gas is used in the 
industrial sector as a feedstock in the production of chemicals, 
fertilizers, and refined petroleum products, and in the production of 
process heat. Among the industries that rely heavily on natural gas for 
process heat are paper and other forest products; food and beverage; 
primary metals, including steel, aluminum, and metal castings; and 
glass and other non-metallic production industries. All of these 
commodity industries are characterized by globally competitive markets 
with low margins. Thus for some plants, rising natural gas prices have 
increased the cost of domestic operations.
    Much of industry is looking to gasification as an important element 
in reducing the impact of rising natural gas prices on their production 
costs. They believe that gasification of the Nation's abundant domestic 
energy feedstocks can play a significant role in creating a more 
affordable substitute for natural gas. Gasification of coal, petroleum 
coke, black liquor, and biomass can be used to create a synthetic gas 
suitable for providing either process heat or as a feedstock source for 
chemicals and fertilizers.
    As mentioned earlier, gasification can be linked with other 
processes to produce liquid fuels. Liquid fuels used in transportation 
comprise about 27 percent of total U.S. energy use. Some industrial 
interests are looking at liquid fuels based on gasification as a source 
of energy. Co-production of some mix of power, chemicals, fertilizer, 
synthetic gas, process heat and steam, and liquid fuels may yield 
resilient business opportunities and greater energy security.
    The ongoing gasification RD&D program and complementary programs 
now underway across the Department of Energy have the potential to 
accelerate commercial use of gasification technologies in the 
industrial marketplace, providing a substitute syngas suitable for 
relieving pressure on both fuel and feedstock availability and cost. 
These programs are actively pursuing advancements in membranes for more 
efficient separation of gas mixtures, catalysts for conversion of 
syngas into substitute natural gas, and fuel gases for combined cycle 
power production. At the same time, we support R&D underway in the 
hydrogen fuel initiative, which is looking at technologies for the 
production of hydrogen. The gasification program also is coordinated 
with major efforts now underway to address the issues of carbon 
management. It is the goal of the long term program to develop 
essentially emission free processes for the production of power, 
industrial feedstocks, and substitute fuels.
    We are fulfilling our responsibilities with respect to EPAct 2005 
tax credits that provide incentives to help bring these technologies 
into early commercial use and, eventually, widespread adoption across 
the American economy if they prove economic. In this regard, working 
with industry, the Department of Defense, and the Environmental 
Protection Agency, we are studying the business risks associated with 
industrial gasification and are performing financial modeling to 
understand the impact of EPAct 2005 incentives on early commercial 
plants.
    Let me turn now to the topic of loan guarantees. Loan guarantees 
are only one part of a toolkit--one best used after the technology 
development cycle is complete. The toolkit established in EPAct 2005 
contains several tools, including authorization of R&D for developing 
technologies, tax credits to reduce the cost of plants that utilize 
them or improve cash flows, and loan guarantees.
    We are confident in the underlying technology behind gasification 
plants. Indeed, some gasification plants in certain applications have 
worked well for years. But early gasification plants face ``first 
mover'' issues such as permitting delays, longer shakedown periods, and 
higher costs since learning curves in fabrication, construction, and 
operations have not yet taken hold. Therefore, the business risks of 
the first plants remain greater than combustion plants.
    Therefore, consistent with the new authorities provided us in the 
Energy Policy Act of 2005, we are establishing a loan guarantee program 
within DOE. We are mindful that the Department does not have an 
enviable record of accomplishment with loan guarantees issued in the 
past, but we will follow the Federal Credit Reform Act of 1990 (FCRA) 
and Office of Management and Budget (OMB) guidelines issued since our 
last experience with loan guarantees, and we will emulate the best 
practices of other federal agencies. We will move prudently to ensure 
that program objectives are achieved while meeting our responsibilities 
to the taxpayer. Toward that end:

   We have established a small loan guarantee office under the 
        Department's Chief Financial Officer.
   We have detailed staff from other programs and may soon be 
        detailing staff from other agencies with some of the necessary 
        experience in Federal loan guarantee programs.
   We are drafting program policies and procedures.
   We are establishing a credit review board.
   We will employ top outside experts for financial evaluation, 
        construction engineering evaluation, and credit market analysis 
        to assist us in our evaluations of applicants.

    We are proceeding, but we are doing so with no small measure of 
caution and prudence. While the provisions of the Energy Policy Act 
provide a ``self pay'' mechanism that, in theory, reduces the need for 
appropriations, it does not eliminate the taxpayer's exposure to the 
possible default of the total loan amount.
    It is possible that the ultimate cost to the taxpayer could be 
significantly higher than the cost of the subsidy cost estimate. 
Therefore, DOE's evaluations of loan guarantee applications will entail 
rigorous analysis and careful negotiation of terms and conditions.
    It is also our view that the Federal Credit Reform Act of 1990 
contains a requirement that prevents us from issuing a loan guarantee 
until we have an authorization, such as a loan volume limitation, to do 
so in an appropriations bill. We do not believe we have the authority 
to proceed with an award absent having explicit necessary 
authorizations in an appropriations bill.
    Again, I thank you for this opportunity to appear today, and I 
welcome your questions either today or in the future.

    Senator Alexander. Thank you very much, Mr. Secretary.
    I'll take 5 minutes, and then we'll go to Senator Thomas 
and then to Senator Bingaman, if that's all right.
    What you just said about the appropriations bill, is that 
new, or is that--``Does Senator Domenici know about that?'' I 
guess is my question.
    Mr. Garman. Yes. We have communicated.
    Senator Alexander. Are we making provisions so that we can 
have an appropriate provision in the appropriations bill this 
year to do what needs to be done, in your opinion?
    Mr. Garman. We have provided the staff with our view of the 
kind of language that would be necessary. The relevant 
provision in the Federal--in FCRA, as we call it, basically 
states that notwithstanding any other provision of law, no new 
direct loan obligations can be made unless there is new budget 
authority to cover the costs provided in advance in an 
appropriations act or a limitation on the use of funds, or some 
other authority otherwise provided in an appropriations act.
    Senator Alexander. Thank you. I may come back to loan 
guarantees if I have time. But let me switch to the tax credit 
provision. Will the guidance be in place by June 30 so that 
applicants for the tax credits will be able to make a proper 
application?
    Mr. Garman. Well, actually, yes. June 30 is the date that 
the applications are due. On the Internal Revenue Service Web 
site, there is information continuously being updated and made 
available to would-be applicants, to make sure that they have 
the latest information. And the guidelines, I understand, have 
been established.
    The Department plays a supporting role to the Department of 
the Treasury in this regard. Treasury has the lead on the tax 
credits. We support them. We will assist them with evaluating 
projects, but they will have the final say.
    Senator Alexander. So, as far as you know, is the guidance 
that an applicant would need in order to comply with the June 
30 deadline available from the Department of Treasury or----
    Mr. Garman. That is my understanding.
    Mr. Rudins. Yes.
    Mr. Garman. Yes.
    Mr. Rudins. They, in fact, have published the guidelines.
    Senator Alexander. Thank you. And there is another date, 
November 2006, which was in the Energy Policy Act, which I 
believe is the final decision date. Is that still a date that 
you intend to honor?
    Mr. Garman. For the tax credits?
    Senator Alexander. For the tax credits.
    Mr. Garman. For the tax credits, that is my understanding, 
and we see nothing that would prevent us from meeting that 
obligation.
    Senator Alexander. So, applicants should be able to apply 
properly by June 30, and the Department should be able to make 
decisions by November of this year.
    Mr. Garman. The Department of Energy is making its 
recommendation, and the Department of the Treasury will be 
making their decision in November, yes, that's correct.
    Senator Alexander. Okay. In the original legislation for 
tax credits, I believe that our number was $850 million. It was 
eventually $350 million. I would suppose there could be many 
applications here. What will you do to try to resist the 
temptation to spread what is a relatively small amount of money 
by--for these kinds or projects--out among a great many 
projects and concentrate them on those that show the greatest 
merit?
    Mr. Garman. That's a very real concern, because there is 
some language in the act urging us to almost do just that, 
considering different types of coal, bituminous, subbituminous, 
and lignite, as well as geographical considerations. And I 
understand the balancing act that we have to weigh there. We 
want--it seems to me, that we would want to be able to provide 
a tax incentive that is meaningful enough to help a project go 
forward. Our interest, in the Department, is that we have been 
working on these technologies, from an R&D point of view, for 
decades. And we would very much like to see them out in the 
marketplace. And they need a little help to get through the so-
called ``valley of death.'' So, we want to make it work, and we 
want to work with Treasury and use all of the authorities to 
help us get those technologies out the door.
    Senator Alexander. I understand that it's not unprecedented 
that Congress would sometimes give conflicting signals, or 
signals that might fit a larger tax-credit number. But, as one 
Senator, I would hope that the attitude of the Department would 
be what you concluded your statement with, which is to take 
into account the broad range of suggestions that were made, but 
make sure that we fund--that we have enough money for a handful 
of projects that have a chance to succeed and demonstrate the 
technology.
    Mr. Garman. That's correct.
    Senator Alexander. My time is up. Let me go to Senator 
Thomas.
    Senator Thomas. Thank you.
    Obviously, there are a number of different kinds of 
conversions of coal that could be made. Are there any 
priorities in the Department with respect to whether it's gas 
or electricity or diesel fuel or whatever? What's the status on 
that?
    Mr. Garman. We have merely had some conversions. Title XVII 
is extremely broad. Almost any technology that one could 
conceive of that results in an advanced energy technology that 
reduces overall greenhouse gas outputs or meets any number of 
other criteria, could be considered under title XVII loan 
guarantee authority. And the question arises, should we, in the 
early going, constrain applications for loan guarantees to 
self-payers, and constrain it some other way, to meet the most 
pressing needs--for instance, coal to liquids, or biomass to 
liquids--to try to offset petroleum? Those kinds of discussions 
are underway at the Department, as we ask ourselves, what's the 
policy priority for us right now? I could argue, and have 
argued internally, that technologies that displace foreign 
petroleum should be weighing heavy on our minds right now. And 
that would include coal-to-liquids and cellulosic biomass to 
ethanol as top priorities.
    But the Secretary has stated that he wants us to get this 
right. We view this as a long-term authority for the 
Department, and a tool we would like to keep in our toolkit to 
help us engage in technology transfer in the future. And, as 
you know, the track record of the Department of Energy on loan 
guarantees is not superb. And we want to get off to a very 
good, solid start with this program. It may mean that we're 
going a little more slowly than some would wish us to go, but 
we think it's very important to lay a very solid foundation for 
a solid program that's going to last for years and be very 
successful.
    Senator Thomas. Well, I'm sure most people would agree with 
that. On the other hand, we see a need to be moving on some of 
these things.
    Mr. Garman. That's right.
    Senator Thomas. I mean, after all, it's going to take a 
while to actually develop these facilities once the decisions 
are made. And so, it seems to me we're going to have to move 
along fairly quickly. And some of the ones that are--we hear, 
sometimes, that the eligibility for the incentives in the--are 
more based on R&D and not on commercial sales operations. Can 
you clarify for me what the Department is hoping to achieve 
through these programs?
    Mr. Garman. Well, through both the Loan Guarantee Program 
and the tax incentive authorities, the economic viability of 
the technology is extremely important, because we want these 
technologies to be replicated many times over. And an ideal 
project, from my point of view, would be one where we think the 
technology is very sound, yet the business risks or the fact 
that it is just new, and, therefore, financiers on Wall Street 
are a little skittish about it. This is the ideal project for 
us to be able to incentivize through one of these methods. But 
the fundamentals of the project, in terms of being able to 
demonstrate that it has a cash flow, that it is a sound 
business approach, and that it's something that can be 
replicated once----
    Senator Thomas. But that judgment generally come from the 
investor? They're the ones that are more concerned about the 
return. You're putting in a relatively small amount of money 
compared to what's involved there. I hope the agency isn't 
holding up what could be done, when you're putting in 5 percent 
of it and they're putting in 95, where they're going to be 
pretty careful about what they're doing.
    Mr. Garman. If we're talking about loan guarantees, it's--a 
typical project, say a billion-dollar project, it may come in 
with 40-percent equity, 60-percent debt, and we may be 
guaranteeing $600 million worth of----
    Senator Thomas. Not all the incentives are loan guarantees. 
There's other kinds of things, as well.
    Mr. Garman. That's correct.
    Senator Thomas. Finally, some witnesses have said that 
there has not been much dialogue with the private sector 
between the Department on how to implement. Is that a fair 
reaction?
    Mr. Garman. I think that's a fair--there's been a lot of 
informal discussion. In fact, among the witnesses on the second 
panel, I've met with at least two of the groups, myself, and 
there's been a great deal of informal dialogue that's taken 
place. Right now, we have not yet been appropriated any money 
to implement this program. We have a reprogramming request that 
has been developed and that is awaiting concurrence at OMB that 
I think's going to happen any day. And once we actually have--I 
mean, I--we are operating this program with no money, through 
the kindness of others and other program activities. And we're 
hoping that we will be able to have the kind of formal 
interfaces, workshops, symposia with the private sector to help 
them understand what we're thinking and help give us the 
benefit of their experience and thought once we have this 
reprogramming and we actually have money to do these things.
    Senator Thomas. That's interesting. I think we need to 
discuss that issue a little more. I mean, we've got our policy 
out there. There's a great press on doing something on energy. 
Clearly, we need to be using more coal, so these other fuels 
are available for other things. And if you're--haven't gotten 
any money, that's a kind of a surprise, so we'll need to work 
at that.
    Mr. Garman. Well, actually, the energy and water 
appropriations from fiscal year 2006 explicitly said that no 
incremental additional dollars were provided for Energy Policy 
Act implementation. And frankly, it's a matter of pride for me 
and the Department that, with no incremental dollars, of the 
363 deliverables in this act that I am tracking for the 
Department, we've been able to deliver 74 of them today, with 
no incremental dollars. Now, some of these are relatively easy 
things to do, reports, and some of them are more difficult 
things to do.
    Senator Thomas. Yes, I understand.
    Mr. Garman. But we take this act very seriously, and we're 
doing our very best to implement it, even though we haven't 
been given explicit resources to do it.
    Senator Thomas. Good. Thank you.
    Senator Alexander. Senator Bingaman.
    Senator Bingaman. Thank you very much.
    It occurs to me that if you needed resources to do it, this 
supplemental appropriation bill we're considering on the floor 
is a very likely opportunity to get those resources. I don't 
know of any requests from the administration for any funds to 
implement EPAct as part of this supplemental. Are you aware of 
any?
    Mr. Garman. I'm not aware, in the supplemental.
    Senator Bingaman. Yes. That would be a good place to do it. 
I'm sure that many of us on this committee would support 
funding in this supplemental, if you could tell us what you 
need.
    Mr. Garman. But you will very shortly see a reprogramming 
request using fiscal year 2006 dollars, reshifting dollars 
already appropriated and--you know, a request that allows us to 
spend funds for, for instance, the Loan Guarantee Office.
    Senator Bingaman. Okay. Well, let me ask about the loan 
guarantee proposals. As I understand it, you contemplate 
issuing draft regulations for comment on the Loan Guarantee 
Program that's in title XVII. When would that happen? Do we 
have a timeframe?
    Mr. Garman. Actually, because it would be a very long 
process, we are attempting to go with guidelines rather than 
regulations. We are trying to expedite the process to go with 
some guidelines, which we have drafted and which are under an 
interagency review right now.
    Senator Bingaman. Okay.
    Mr. Garman. And it is our hope that we get these out 
shortly, and folks will be able to take a look at those and see 
what we're thinking.
    Senator Bingaman. So, once the guidelines have been issued 
or released, there's not a comment period. I mean, there's no 
comment period required, or no formal procedure, since you 
would be using guidelines rather than regulations. Is that 
right?
    Mr. Garman. That is my understanding. I think there are 
some after-the-fact steps where we would have to do some 
regulations, but they're deferrable. We chose a path that would 
enable us to be able to accept applications, perhaps during 
this fiscal year, in the next 6 months.
    Senator Bingaman. Okay. So, that would mean you would have 
your guidelines finalized and usable, and people could actually 
make application between now and on October 1.
    Mr. Garman. Yes, sir.
    Senator Bingaman. And that's what you're expecting and 
working toward at this point. All right.
    Mr. Garman. Yes, sir.
    Senator Bingaman. I was struck by your comment that you've 
been able to implement 74 of the 380----
    Mr. Garman. Three hundred and sixty-three.
    Senator Bingaman [continuing]. 363 requirements that we 
laid on you, or obligations that we imposed on you, as part of 
EPAct. How are the others coming? There are a lot that aren't 
in that list, it would seem to me.
    Mr. Garman. Well, keep in mind that some of those 
deliverables aren't due yet, so--I'm trying to remember my math 
here--but--yes, a large tranche of those are due in August, 1 
year post the date of enactment.
    Senator Bingaman. Okay.
    Mr. Garman. So, 74 is a pretty good track record. There's a 
combination of deliverables that include rulemakings, 
miscellaneous mandatory items, and reports. We're doing pretty 
well on the reports. We're doing pretty well on the 
rulemakings. There are a number of provisions that we won't do 
as well on. As you know, this bill authorized a number of new 
programs, that, if I were to add up the authorizations in the 
bill, it comes out to about $16 billion. And, clearly, there 
are some provisions in that bill that are going to await funds 
before we're going to be in a position to implement them. But 
we've taken the position of trying to implement the maximum 
amount that's available to us. And we'll continue that path, 
that approach.
    Senator Bingaman. I think it would be useful. And you're in 
direct communication, I'm sure, with our chairman and others on 
the Appropriations Subcommittee on Energy and Water 
Appropriations, but it would be very useful, I think, for all 
of us to have an idea of what items are awaiting funding before 
you can actually go ahead and implement them. I mean, I realize 
we put an enormous burden on the Department when we passed this 
legislation. And I've not been critical about failure to get it 
all done in a hurry. I do think, though, that once a funding 
cycle comes and goes, there's going to be a lot less sympathy 
around here for pleas that we haven't adequately funded this 
thing. I mean--because I think we'll have a chance to correct 
that here pretty soon. I hope that you'll communicate any needs 
along those lines to the rest of us, as well.
    Thank you, Mr. Chairman.
    Senator Alexander. Secretary Garman, you alluded to this, 
but one of the interesting provisions of the loan guarantees is 
the idea of a risk premium that the applicants are the--those 
who are the beneficiaries of the loan guarantee would pay a 
risk premium that would be judged to be sufficient, so that the 
taxpayer doesn't lose any money. It's an interesting concept, 
but an important one to the passage of this provision. You 
said, I believe, in response to Senator Bingaman, that you hope 
that things would continue along so that you might be able to 
accept applications for the loan guarantees by October. How are 
you coming on the risk premium analysis? And what can you tell 
us about how you're approaching that?
    Mr. Garman. Let me clarify this. The self-payer loan 
applications, or ones who are offering to put up that risk 
premium, are the applications that we would be in a position to 
accept, hopefully this fiscal year, because that is--as you 
say, no explicit appropriations are needed, although there is 
some appropriation authorization needed, as we talked about 
earlier.
    I'll give you an example, and it's just a hypothetical 
example. If there is--let's say a project cost of a billion 
dollars, and the applicant is coming in with 40-percent equity 
funding, or $400 million, leaving debt of $600 million to 
cover, and, through the evaluation process that we developed, 
we decided that there was a 10-percent risk of default, meaning 
that the applicant would have to come up with a cash payment of 
$60 million, or 10 percent of $600 million, to go into a 
Treasury fund, and that fund would grow over time with other 
applicants and other self-payers, to be used to pay for loan 
guarantees that didn't pan out. And that's----
    Senator Alexander. Would that $60 million be an expense, an 
amount of money that was put in the Treasury, or would it 
simply be a credit?
    Mr. Garman. It would remain in the Treasury in a special 
dedicated fund, is my understanding, because the Federal 
Government would have a contingent--or the taxpayer would have 
a continent liability of $540 million on that project. If that 
project went belly up, and there was no means to save it, then 
the taxpayers would have to come----
    Senator Alexander. But if it doesn't go belly up, does the 
applicant--or the operator get the $60 million back?
    Mr. Garman. No. The $60 million remains in the fund. 
Inevitably, we anticipate that eventually one of these will 
fail, and this fund would be growing in the Treasury to pay the 
default costs for failed projects.
    Senator Alexander. So, to get that $600 million, the 
applicant would have to--would borrow it from the Federal 
Government for--I mean, I know this is an example, but--and 
then, in addition, pay $60 million fee, in effect?
    Mr. Garman. Well, instead of----
    Senator Alexander. An insurance fee?
    Mr. Garman. In other words--another way of thinking about 
it is, instead of bringing $400 million of equity to the table, 
the applicant would have to bring, in this example, $460 
million of equity to the table.
    Senator Alexander. Well, where does the $600 million come 
from? That's borrowed, right?
    Mr. Garman. That's borrowed. And that is the----
    Senator Alexander. So, the applicant would have to pay an 
interest cost on the $600 million, and then it would have to 
pay, in effect, an insurance fee that would amount to 10 
percent to the Government.
    Mr. Garman. In this example.
    Senator Alexander. In that example.
    Mr. Garman. But, of course, the interest costs would 
probably be lower, because the lender would--realizing that 
this was a federally guaranteed loan, would offer more 
favorable interest to the applicant. So, that is a tradeoff 
that an applicant would have to consider if they were using the 
self-payer pathway. Is the benefit to them resulting from the 
Federal loan guarantee worth the price? In this hypothetical 
example of 10 percent, the risk premium may be lower. We don't 
know.
    Senator Alexander. I can see a lot of financial minds 
whirring in the audiences to think about those numbers.
    Mr. Garman. Those are big numbers.
    Senator Alexander. That will be an important decision to 
make, both from the taxpayers' point of view and from the point 
of view of creating an insurance premium fee that is reasonable 
enough so that it makes a loan guarantee worth anything to the 
applicant.
    Mr. Garman. Correct.
    Senator Alexander. Otherwise--I mean, it might be such an 
expensive cost of money that the applicant might say, ``Well, 
that's not--I mean, that's interesting, but it's not even in 
the marketplace, in terms of what I'm willing to pay for the 
cost of money in order to go forward with a project of this 
kind.''
    Mr. Garman. That's right. Our measure of success would be, 
how many projects are going to closing? I mean, that is a 
measure of success. That shows that the negotiation between the 
Government and the applicant has been successful, and we've 
gone to closing, and that is the first stepping stone of 
success.
    Senator Alexander. I see the red light on, but another 
thing to be careful about, I can think of, is that someone who 
might be willing to pay too high a fee might be a less worthy 
applicant, or have a less worthy--a less worthy project which 
would be something to consider in the evaluation.
    Senator Thomas, do you have additional questions?
    Senator Thomas. No, let's go ahead and continue.
    Senator Alexander. Senator Dorgan and Senator Murkowski 
have arrived. Why don't we let you ask questions, if you'd 
like, of Secretary Garman, and then--we have five witnesses 
following him in the next panel, and then we'll go to those 
witnesses.
    Senator Dorgan.
    Senator Dorgan. Mr. Chairman, thank you very much.
    Mr. Secretary, thank you for being here. Just a couple of 
observations and a question. As you know, we have, I believe, 
the only coal gasification plant in operation north of Beulah, 
North Dakota. It's been in operation for a long, long while. It 
produces synthetic gas from lignite coal. It is really a 
technological marvel in many ways. It produces well above 
anything that was originally projected to produce. It produces 
valuable byproducts. And we are using the CO2 pipe 
to Canada to inject into oil wells to increase the productivity 
of marginal wells in Canada. It's pretty unbelievable. We 
sequester that CO2, we produce synthetic gas out of 
coal.
    I guess the point of my comment is, there's no question 
about whether this can be done. It is being done. And that 
plant, at the moment, is producing an enormous amount of 
profit, a substantial portion of which will be shared, because 
of the profit-sharing, with the Department of Energy. And I 
don't remember the exact amount. I think it's $60 or $80 
million that will be turned over soon. So, the question isn't 
whether this can be done. It is being done.
    Is the technology--and I think you have visited that 
plant--is the technology in that plant old technology or is 
there technology that is more modern than that technology in 
gasification?
    Mr. Garman. There are more modern technologies. I believe 
the CO2 scrubber at that plant is amine-based.
    Mr. Rudins. I believe it's Rectisol.
    Mr. Garman. Right, okay.
    But there are better and newer technologies. This Great 
Plains gasification plant was from an older synfuels loan 
guarantee program that we had.
    Senator Dorgan. It was?
    Mr. Garman. It was an example of an actual loan guarantee 
that defaulted. But efforts were made to recoup the investment. 
And I think both the Government and the project sponsors, the 
``white knights,'' if you will, came in and made a pretty good 
showing of it. They, although they had an opportunity--they 
decided not to avail themselves of some tax incentives that 
were available. And, thus, made it almost a wash for the 
Government--not quite, but it was a very, very good technology 
step for us, and it shows that this can be done. And we've 
learned a lot from it, and we continue to learn from it today.
    Senator Dorgan. I don't know the numbers of that plant, but 
I think that plant is producing synthetic gas from lignite coal 
at somewhere between $2 to $3 per Mcf. And if that's right, you 
know, at the market price by which they're now marketing the 
synthetic fuel from that plant, that plant is spinning off a 
great deal of money, and, again, with the profit-sharing with 
the Federal Government, is--has become a good bargain. And I 
applaud the Department of Energy. There was a time when the 
Department of Energy simply could have said, ``No, no, we're 
going to close that thing down. This is a default.'' But, 
because it didn't, and it stuck with trying to have the only 
research plant of this type of--commercially sized research 
plant of this type up and operating, we now know that we have 
the world's largest reserve of lignite coal, called Fort Union, 
that that large reserve of coal is available. We now know that 
we can gasify it, produce synthetic gas from it. We can 
sequester CO2. There a whole series of things that 
make a lot of sense for us here. The reason I wanted to come 
today was simply to describe the experience we've had, a pretty 
substantive experience.
    I was actually there the first day that Art Seder, from 
Michigan-Wisconsin Pipeline, came to North Dakota to describe 
his goal of building 21 coal--21 synthetic fuel plants. They 
eventually built one, and had financial difficulty doing that. 
But now--and having gone through two different visions of 
financial trouble, now that plant has--is quite a remarkable 
marvel with--hugely profitable. And the Federal Government is 
participating in that profit, which makes a lot of sense.
    So, I think what Congress did last year in this area, 
providing loan guarantees and moving in this direction, can be 
very helpful, and the experience we've had in the past with the 
Great Plains plant can be very instructive.
    So, Secretary Garman, thank you for being here, and thanks 
for your testimony. I had a chance to read it prior to coming 
here, but I'm sorry I wasn't here for all of your testimony.
    Mr. Garman. Thank you.
    Senator Alexander. Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman. Appreciate you 
chairing this hearing today. And, Secretary Garman, thank you 
for being here. And thank you and the Department for your 
efforts over the past many years, for all that you've done in 
the clean coal effort, in the coal gasification technology. 
You've taken an important role there, and we appreciate it.
    We specifically thank you for what has recently come out of 
the Arctic Energy Office. This is the review of the Alaska Cook 
Inlet coal resources for us to move forward with what we 
consider to be some pretty exciting initiatives, the 
information that you will get from that review will be vitally 
important, and we, again, appreciate your leadership on that.
    The first question that I've got--this is as it relates to 
the tax incentive and the loan guarantees, and I kind of came 
in on the tail end of the conversation, so if I'm asking 
something that you've already answered, I apologize--but in 
addition to the loan guarantees, the tax incentives, is there 
anything else out there, in terms of funding assistance, that 
could be made available either for research or for project 
grants to help advance this technology, to advance the 
commercialization of the coal gasification technology? Is there 
anything else beyond these two areas?
    Mr. Garman. Yes. There is of course, the Clean Coal Power 
Initiative, which is a demonstration program that can provide 
up to 50-percent cost share for demonstration plants of 
gasification technologies or other advanced coal technologies. 
For example, there is a plant under design in Orlando, Florida, 
with the Southern Company, to design, demonstrate, and operate 
an IGCC coal plant with the Government having a 50-percent, or 
thereabout, share in the demonstration of this technology.
    In addition to that, there is our general R&D activity in 
our coal budget, which is, oh, probably--the R&D portion of 
that, roughly $50 million a year, that's available for a much 
higher cost-share, with the Government--the Federal Government 
paying more along the lines of 80 percent of the costs of 
working R&D issues related to the use of coal in advanced 
gasifiers or in other means.
    So, they're out there. They're generally awarded on the 
basis of competitive solicitations, and there is often a 
solicitation on the street.
    Senator Murkowski. Let me ask you--in the second panel, 
we've got some representatives from Agrium who will be speaking 
to that project, and how the loan guarantee, and how the tax 
incentives, can help them if we understand a little bit better 
what the parameters are. The date that is set out there for the 
tax credits--and I understand that it's June 30, the 
applications need to be submitted--are these applications for 
projects that have been completed in the sense that they're all 
defined, or would it work if they have gone to prefeasibility 
of the project? I need to know how hard and fast this June 30 
application date on this----
    Mr. Garman. The June 30 date is hard and fast. This was set 
by Treasury. We're playing a supporting role on the tax 
incentives, and helping Treasury review the applications and 
see which we think have both technical and economic viability. 
We're looking at technical feasibility, suitability of the 
proposed site, economic feasibility. And we need to have a 
pretty good understanding of those factors, so that we can make 
the decision and meet Treasury's deadlines. I'm familiar with 
the Agrium project. I've sat down with them, and I understand 
what they have planned, and it is an exciting project, and I 
don't know that we're perfectly synced up in terms of what 
their prefeasibility information is providing and what we'll be 
requiring on the June 30 deadline. But we encourage them to 
provide us as much as they can. And we'll try to show whatever 
kind of flexibility we're allowed to. But we want you to know, 
we're under the gun from Treasury to stick to these dates.
    Senator Murkowski. Well, what's the December 31, 2007, 
deadline, then? Because it was my understanding that, up until 
that point in time, you were able to accept projects, or to 
qualify projects, perhaps.
    Mr. Garman. I think the December deadline relates to 
another provision having to do with nuclear powerplants, but we 
will check with you and get back to your staff on that.
    Senator Murkowski. Okay. If you could check on that, I'd 
appreciate it.
    Mr. Garman. Yes, Senator.
    [The information follows:]

    Applications for certification are due to the Department of 
Energy by June 30, 2006. DOE will determine feasibility and if 
the project qualifies, certify it by October 1, 2006. The IRS 
will accept or reject an application for certification by 
November 30, 2006. Applicants have two years from the date the 
application is accepted to provide evidence that they satisfy 
the criteria for certification. If the aggregate credit pool is 
not fully allocated in 2006, there will be similar allocation 
rounds in 2007 and 2008, following the same date guidelines in 
the future years. An applicant that receives a certification 
for an Advanced Coal Project has five years from the date of 
the certification to place the project in service. For 
Gasification Projects, the applicant has seven years. In both 
instances if the project is not in service at the end of the 
specified period, the certification is void.
    Another provision of EPAct 2005 provides for the Credit for 
Production from Advanced Nuclear Power Facilities. The deadline 
requirements for this provision differ substantially from those 
for Credit for Investment in Clean Coal Facilities.

    Senator Murkowski. Last question, then. This relates to the 
insurance premium fees. In terms of how this 10-percent figure 
was arrived at, is--what's the basis to that----
    Mr. Garman. Please understand that that was merely a 
hypothetical figure. The risk premium is somewhat analogous to 
the notion of, what do we think the risk of default of this 
project is? It may be 2 percent, it may be 20 percent. And, 
thus, the premium that we would require, based upon this risk 
of default, is really the driving factor. And that would be 
dependent on the individual project--the technical and the 
economic feasibility and other factors. If a project has, for 
instance, a power purchase agreement in place, or if the 
project has a guaranteed take of--you know, guaranteed off-take 
agreement with someone, that obviously lowers risk, and would 
lower the risk of default. So, it would pretty----
    Senator Murkowski. So, it really is judging it on a 
project-by-project type of an approach.
    Mr. Garman. That's correct.
    Senator Murkowski. Thank you, Mr. Chairman.
    And I do have an opening statement that I'll submit for the 
record, but I appreciate the opportunity to ask these few 
questions of Secretary Garman.
    Mr. Garman. Thank you, Senator.
    Senator Alexander. Thank you, Senator Murkowski, and it'll 
be made a part of the record.
    [The prepared statement of Senator Murkowski follows:]
  Prepared Statement of Hon. Lisa Murkowski, U.S. Senator From Alaska
    Thank you Senator Alexander for chairing this hearing, the second 
into how agencies are progressing in their efforts to implement the 
Energy Policy Act of 2005 that we passed last summer.
    This hearing focuses on, in my view, one of the important 
provisions of the Energy bill, its ability to promote the use of coal 
gasification technology to produce products, electricity and new fuels 
from America's abundant coal resources, and especially the ability of 
the process to allow us to produce energy without necessarily emitting 
any carbon into the atmosphere--instead sequestering it underground.
    We all know America is the Saudi Arabia of coal. Our half trillion 
tons of demonstrated reserves is the highest in the world. My state of 
Alaska has demonstrated reserves of 160 billion short tons, that would 
place it second in the world in coal reserves, only behind all of the 
former Soviet Union--if Alaska seceded from the Union. (And if we did 
then we could develop ANWR far more easily),
    The problem with coal in the past has been its pollutants and in 
the future the issue likely will be the amount of carbon dioxide 
produced when it is burned. Both are solved through gasification of the 
coal, which readily allows you to separate out carbon dioxide for use 
or capture and which also allows the removal of pollutants from sulfur 
and nitrogen to mercury. This could be our biggest environmental boon.
    And given our growing shortage of natural gas, and the skyrocketing 
prices for natural gas, coal gasification and the products it will 
generate, could be the savior for an American petrochemical and 
manufacturing sector. The prepared testimony today includes an 
eyepopping statistic: that the U.S. has lost $484 billion in domestic 
industrial production in the past six years because plants have moved 
overseas or lost business because of high natural gas prices here.
    For coal gasification to help our industrial sector to survive 
these price shocks, we have to immediately implement the provisions 
that we included in the Energy Bill to improve the economics of 
gasification by increasing the economies of scale in construction of 
such plants and by helping to perfect commercial-scale gasification 
technology.
    An example of why this help is needed comes from Alaska.
    In panel 2 Bill Boycott will be testifying. Welcome Bill thanks for 
coming a long distance to appear at this hearing. He is general manager 
of the Agrium fertilizer plant on the Kenai Peninsula in Alaska--the 
only year-round value-added manufacturing plant currently operating in 
all of Alaska, if you don't count a neighboring LNG plant.
    The huge price increases in natural gas, the company's current 
feedstock for fertilizer/urea production, is threatening to force the 
plant's closing--the 20th fertilizer plant in America to close in the 
past four years.
    Coal gasification would allow Agrium to make its nitrogen 
fertilizer from the 1.4 billion tons of coal located just across Cook 
Inlet from the plant. It would allow it to make badly needed excess 
electricity to power the Railbelt. It would also produce the tons of 
CO2 that could be readily piped underground into the 
neighboring Swanson River and Cook Inlet oil fields that could in turn 
help produce another 300 million barrels of oil from the aging Cook 
Inlet fields.
    That would not only allow Agrium's employees to keep receiving 
paychecks, it would produce domestic fertilizer for American farmers 
and produce another 25,000 barrels a day of oil from Cook Inlet. And 
given the prices at the pump this morning, we need every barrel of oil 
we can get to increase supplies and drive down prices in this nation.
    And Alaska clearly needs a coal product in Cook Inlet to proceed to 
propel the state's economy in the future.
    I truly look forward to the testimony and the suggestions we are 
going to receive today on how we can fully implement last year's bill 
NOW, and if there are ways to improve the bill and speed the 
gasification process along, I would welcome them too.
    Seemingly almost daily we hear concerns about global climate change 
stemming from greenhouse gas emissions. Since this is a process that 
would allows carbon sequestration. That alone should be grounds to 
really push economic development of commercial coal gasification 
technology to the front burner.
    Thank you.

    Senator Alexander. Secretary Garman, thank you for being 
here. And as--to summarize, as I understand it, what you have 
told us is that so far as you know, that the information to 
permit an application on the tax credits will be sufficient, so 
that applications can be made by June 30, 2006, as the 
legislation said; and, so far as you know today, that, by 
November of this year, the Department of Energy will be able to 
make its recommendations to the Department of the Treasury, so 
that it can make its decisions; and that, if things continue as 
they are, applications for at least some of the loan guarantee 
projects might be made by 6 months from now. Is that correct?
    Mr. Garman. Yes. We would hope to be able to be in a 
position to accept applications for self-pay loan guarantees by 
October 1.
    Senator Alexander. Self-pay loan guarantees. And that we 
should expect, very shortly, to learn more about a 
reprogramming request that will provide additional already 
appropriated funds, which will help you in implementing the 
provisions of the Energy Policy Act that were passed last year.
    Mr. Garman. Correct. And I would also hope that we should 
have guidelines out and available for public perusal very 
shortly, as well.
    Senator Alexander. And that you're using the procedure of 
guidelines so as to speed things along----
    Mr. Garman. Speed things up.
    Senator Alexander [continuing]. Rather than to go through 
regulations, which might take a year or two.
    Mr. Garman. Yes, sir. And I will monitor this hearing and 
the witnesses, and if we hear things that come up as a 
consequence of the second panel, you have my assurance that 
we'll work with you and with them to try to allay any concerns 
or fears they might have, as well.
    Senator Alexander. Thank you very much for your time.
    We have five interesting witnesses we'd like to hear from 
now, and I'll invite them to come to the table. I'll introduce 
all five of them, and ask them to present their testimony.
    [Pause.]
    Senator Alexander. Let me welcome all five of the witnesses 
to the hearing.
    What I would like to suggest--we have four Senators here. 
We've had Senator Bingaman here, as well, for part of the 
hearing. And I know all of those who are here would like to 
have a chance to ask you questions. So, we have your 
statements. We thank you for being here. And may I suggest that 
you try to summarize your statements within 5 minutes. There's 
a little machine here that'll report the 5 minutes with a 
yellow, and then red, light. And then, that will give us more 
time to ask you questions or to make comments on the things 
that you've said.
    Our witnesses today are Brian Ferguson, who's the chief 
executive officer of Eastman Chemicals, in Kingsport, 
Tennessee--welcome, Mr. Ferguson; Mr. William Bruce, president, 
BRI Energy, in New Smyrna Beach, Florida; Mr. Bill Douglas, 
vice president, Econo-Power International Corporation, in 
Houston, Texas, would be the third witness; Mr. Bill Boycott, 
general manager of Agrium U.S.A., Incorporated, would be the 
fourth witness; and then Dr. Antonia Herzog, who is the Climate 
Center staff scientist for the Natural Resources Defense 
Council, in Washington, D.C. Thank you for coming, Dr. Herzog. 
And we'll ask you to comment after the other four have, if 
that's all right with you.
    So, Mr. Ferguson, let's start with you, and we'll move 
right along through all five witnesses.

   STATEMENT OF BRIAN FERGUSON, CHAIRMAN AND CHIEF EXECUTIVE 
          OFFICER, EASTMAN CHEMICAL CO., KINGSPORT, TN

    Mr. Ferguson. Good afternoon. Thank you so much, Senator. 
It's a pleasure to be here. I want to thank the members for 
this opportunity to comment on my perspective on the Energy 
Policy Act. I appreciate the opportunity to discuss with you 
our concerns about certain provisions of the act, particularly 
those around the Federal industrial gasification tax credits 
and the self-pay Federal loan guarantees for industrial 
gasification, some of which were just discussed by Secretary 
Garman.
    And, as you said, I've submitted written comments. I'll be 
short and sweet in my personal comments, and I look forward to 
your questions.
    The corporation I represent, Eastman Chemical Company, has 
been operating an industrial gasification facility since 1983, 
and we've been competing with the largest chemical companies in 
the world successfully since that time with that facility. But, 
like many of my chemical brethren today, we are all under 
extreme pressure from rising costs of energy and raw materials. 
My industry has experienced a cumulative $60 billion--that's 
``billion,'' with a ``b''--a $60 billion increase in our 
natural gas bill since the beginning of this decade. And, as a 
result to that--let me give some quick examples. In a recent 
Business Week magazine, it was noted that there were 120 global 
chemical sites valued at more than $1 billion currently under 
construction in the world. Only one of those is located in the 
United States. The remaining plants, offering high wages and 
stable employment, are being constructed in places where energy 
costs are lower and less volatile. My friends over at Dow 
Chemical Company, for example, are currently building a $4 
billion plant in Oman. The Dow Chemical chairman and CEO, 
Andrew Liveris, went on record recently saying that he was 
originally going to build that plant in Freeport, Texas, but 
the high cost of natural gas in this country, which, at that 
time, was 12 times higher than it was on the Arabian Peninsula, 
forced him to choose Oman instead. It's important for all of us 
to remember that Dow's new plant will employ about 1,000 people 
in high-paying R&D, engineering, operations, and--those are 
1,000 employees that could have been U.S. employees if we had 
an energy policy that worked to help us and not punish us. And 
the ``us'' I'm talking about are industrial manufacturers, like 
Dow and Eastman.
    Now, the point is that Dow isn't alone. Every industrial 
company is facing the same dilemma, build in the United States 
or build overseas, invest where the energy policy is a 
liability or where it's an asset. And, frankly, Senators, I'm 
facing that same choice around the end of this year on a very 
large investment.
    That's why I was so pleased when I saw that Congress 
finally created, within the Energy Policy Act of 2005, the 
incentives that would help correct 20 years of problematic 
energy regulations, finally move us away from a costly and 
wasteful dependence on natural gas.
    As you know, Congress helped create the situation we're in 
now. Congress drafted regulations promoting the burning of 
natural gas to produce power at the expense of pretty much 
everything else. So, I'm pleased to see that Congress has now 
begun to correct that and put a renewed emphasis into the 
American industrial areas, examples such as chemicals, 
agriculture, glass, steel, and forest products.
    For both the industrial tax credits and the Federal loan 
guarantees to be effective if they're going to change the 
course of investment in energy and feedstock technology 
investments in this country, they need to address global market 
risks and support commercial-scale projects. While there is a 
separate need for demonstration projects to validate key 
technologies, the real need for America now is to assure that 
these incentives support investment in commercial-scale 
industrial gasification projects that are calculated to meet 
global competitors and are ready to deploy.
    The Federal industrial gasification tax incentives and the 
self-pay Federal loan guarantees in the Energy Policy Act are 
huge steps in the right direction, and I thank you for creating 
those. However, we have some serious concerns about the 
investment tax credit and the self-pay Federal loan guarantee 
implementation. And I'd like to just comment on those, very 
briefly.
    First, it is imperative that the process for implementing 
section 48(b) is more transparent and meritorious than we have 
seen so far. The primary objective should be to assure that 
these early projects be technically, financially, and 
commercially solid projects with experienced and capable owner-
operators. Recently issued industrial tax credit application 
guidance did not outline measurable selection criteria that 
would allow applicants to have confidence that this crucial 
objective would be met.
    Industry raised many important questions that were either 
politely dismissed or have gone wholly unanswered. And under 
the June 30 application deadline set forth in the guidance, 
time is running out for a serious applicant to submit a 
responsible project application in the face of the untimely 
answers or unanswered questions. I request that the Senate 
Energy and Natural Resources Committee, along with the Senate 
Finance Committee, ask IRS and DOE to seriously address the 
questions submitted by a wide cross-section of industrials.
    Second--and this is a concern I think you talked about with 
Secretary Garman--we're concerned that the Federal loan 
guarantee process itself is not moving quickly enough. We 
understand that there is some agreement to take applications by 
the end of the year, as was discussed, but the dialogue has 
really not happened between DOE and any intended beneficiaries 
to foster that at a formal level, maybe some at an informal 
level. It's imperative that the dialogue begin immediately if 
these projects are going to move forward in the timetable that 
you were discussing. And I'm confident that there are projects 
that will be ready to go as soon as this process is clarified, 
but we need to start with some active dialogue.
    Third, the focus for the incentives needs to be squarely 
aimed at domestic industries that are suffering under the 
burden of high natural gas prices. We anticipate that the 
availability of these incentives will attract a number of 
project developers who will try to claim qualification even 
though they are not in the intended group of recipients. It's 
extremely important that the focus of the incentives remain on 
the group of eligible entities that were defined in section 
48(b) of the Energy Policy Act.
    Senator Alexander. Please finish up. You're past 5 minutes.
    Mr. Ferguson. I'm sorry, I'm over? Let me close----
    Senator Alexander. Go ahead and finish your thought.
    Mr. Ferguson. Well, a fourth concern would be the budget 
issue that was raised by Secretary Garman. We support his 
initiative to have some money to work with. And we believe that 
by implementing these initiatives and these incentives 
properly, it can make a big difference to the country. And we 
hope you can support the implementation process.
    [The prepared statement of Mr. Ferguson follows:]

  Prepared Statement of Brian Ferguson, Chairman and Chief Executive 
              Officer, Eastman Chemical Co., Kingsport, TN

    Mr. Chairman, members of the Committee, I am Brian Ferguson, CEO 
and Chairman of Eastman Chemical Company, headquartered in Kingsport, 
Tennessee. I want to thank you for the invitation to come before you 
today and give you my perspective on the Energy Policy Act of 2005. And 
I appreciate the opportunity to discuss with you our concerns with 
certain provisions of the Act, particularly those around the Section 
48B Federal Industrial Gasification Investment Tax Credits in Title 13 
and the self pay Federal Loan Guarantees for industrial gasification 
projects under Title 17.

                        INTRODUCTION TO EASTMAN

    The corporation I represent is Eastman Chemical Company. Eastman 
manufactures and markets chemicals, fibers and plastics worldwide. It 
provides key differentiated coatings, adhesives and specialty plastics 
products; is the world's largest producer of PET polymers for 
packaging; and is a major supplier of cellulose acetate fibers. Founded 
in 1920 and headquartered in Kingsport, Tenn., Eastman is a FORTUNE 500 
company with 2005 sales of $7 billion and approximately 12,000 
employees. For more information about Eastman and its products, visit 
www.eastman.com.
    Eastman is not unlike many chemical companies in the United States 
today. That is to say that we are all under extreme pressure from 
rising costs of energy and raw materials. My industry has experienced a 
cumulative $60 billion--that's billion with a `B'--a $60 billion 
increase in our natural gas bill since the beginning of the decade.
    What's the result? Let me give you a quick example.
    One report in Business Week noted that there were 120 global 
chemical sites valued at more than $1 billion currently under 
construction in the world. Of those, only one was located in the United 
States. The remaining plants--offering high wages and stable 
employment--are being constructed in places where energy and raw 
materials not only cost less, but their availability and prices are 
more stable, too.
    Dow Chemical Company, for example, is currently building a $4 
billion plant in Oman. This plant was originally going to be built in 
Freeport, Texas. But the high cost of natural gas in this country--
which was 12 times higher in Texas than on the Arabian Peninsula--
forced Dow to site it in the Middle East instead.
    With that decision, America has lost a new plant that will employ 
1,000 people in high-paying science, engineering and operations jobs--
and we have taken on more step toward creating for our chemicals 
industry the same kind of dependence that we face with imported oil. 
One thousand employees who could have been U.S. employees and billions 
of dollars that could be flowing into--rather than from the U.S. 
economy--if we had an energy policy that worked to help--not punish--
industrial manufacturers like Dow.
    Dow isn't alone, of course. Every industrial company is facing the 
same dilemma. Build in the U.S. or build overseas. Invest where the 
energy prices are a liability--or go where they are an asset.
    That's why I was so pleased when I saw that Congress finally 
created within the Energy Policy Act of 2005 the incentives that would 
help correct 20 years of short-sighted energy regulations and finally 
begin to move us away from a costly and wasteful dependence on natural 
gas for electricity generation.

                       IMPORTANCE OF GASIFICATION

    Wide spread deployment of sound, proven gasification technology is 
an important tool that can help keep currently-natural-gas-dependent 
globally competitive American industries in America. Gasification 
provides the opportunity for American industry to use a wide array of 
feedstocks such as coal, petcoke, biomass and even many industrial 
waste materials in lieu of expensive natural gas. On the market side, 
creation of synthesis gas permits a very broad suite of products and 
uses. So, gasification technologies offer important flexibility to 
industry.
    Other benefits:

   Feedstock Diversity--Reduced cost and greater flexibility of 
        feedstock input. Industrial manufacturers operate in a globally 
        competitive market where their price of natural gas makes a 
        huge difference in final product prices. Unlike the electric 
        utility industry, for example, production costs largely 
        determine where our goods are manufactured.
   Jobs--Preservation of U.S. jobs, especially high-paying ones 
        in the chemical industry which has already lost more than 100 
        plants and 100,000 jobs between 1999 and 2005. But notably, 
        other natural gas dependent sectors have also suffered 
        dramatically, i.e., agriculture, paper, metals, iron and steel. 
        See Attachment 3 *
---------------------------------------------------------------------------
    * Attachments 1-3 have been retained in committee files.
---------------------------------------------------------------------------
   Avoids Mid-East Energy Dependency--Maintains U.S. economic 
        strength and avoids ``oil style'' dependence on Middle East--
        truly a slippery slope.
   Environment--Even using fossil fuels, emissions of 
        SO2 and NOX from gasification processes 
        are similar to sources using natural gas. Also, gasification 
        can capture mercury and CO2 for safe disposal-
        sequestration, etc.
   Trade balance--The U.S. has lost $484 billion in domestic 
        industrial production between 1999 and 2005, further 
        exacerbating our Nation's huge trade deficit in manufactured 
        goods. As capital costs decline with broad deployment of 
        gasification technology, new plants will produce synthesis gas 
        that permits domestic production to be competitive with foreign 
        plants.
   All Natural Gas Consumers--With industrial gasification, 
        natural gas prices for all domestic consumers (48A program also 
        contributes to this benefit) will fall. Facilities operational 
        under 48B tax credits will reduce costs to all American natural 
        gas consumers over the long term and pay for themselves in 
        about six months. This is a conservative estimate which assumes 
        only the output of the plants receiving the credit and does not 
        reflect the subsequent stimulation of additional, cheaper 
        gasification plants which will reduce natural gas demand and 
        prices further.

                         NEED FOR TIMELY ACTION

    There is suddenly a lot of hype regarding gasification 
technologies. Not a week goes by that I don't read or hear some story 
in the news about a new gasification technology that will be the 
panacea for the Nation's energy ills. Development of new technology is 
important--important in the next decade or the one after that. For 
gasification to make a difference to American industry now, when 
industry needs it most, we must deploy sound, proven, currently 
available technology.
    For both the Section 48B Investment Tax Credits and Federal Loan 
Guarantees to be effective in my industry--if they're to change the 
course of investment in energy and feedstock technology investments in 
this country--they need to support commercial scale projects that 
address global market risks, now. I want to emphasize that point. 
Industry needs deployment of proven, commercial scale gasification 
technology now, not just more research and more demonstration projects 
that may, or may not be adopted by industry ten or fifteen years from 
now. While there is a need for future demonstration projects to 
validate key technologies, the real difference for America now is to 
assure that these incentives support investment in commercial scale 
industrial gasification projects that are calculated to meet global 
competition so that these industries will still be contributing 
mightily to the American economy when those new technologies become 
available.
    America will need technology improvements in the future if we are 
to remain competitive in the global industrial marketplace, but only if 
we take the necessary steps now to ensure that the U.S. still has an 
industrial base in the next decade. That may sound like hyperbole until 
one considers the more than 2 million American manufacturing job losses 
overall since 1999, and particularly in the natural gas dependent 
industries--in chemicals, forest products, glass, steel, and even 
agriculture.

                  NEED TO MAINTAIN THE ORIGINAL FOCUS

    The Section 48B tax credits were added to HR 6 specifically for the 
gasification of coal, biomass, petcoke and waste materials to serve the 
fuel and/or feedstock requirements of certain globally competitive 
industries that were facing economic distress due to rapidly rising 
natural gas prices in the U.S. The focus for these incentives needs to 
continue to be squarely aimed at domestic industries that are suffering 
under the burden of high natural gas prices, as identified in the new 
law. We anticipate that the availability of these incentives will 
attract a number of project developers who will try to claim 
qualification even though they are not in the intended group of 
recipients.
    It is important that the focus of the incentives remain on the 
group of eligible entities that were listed in Section 48B of the 
Energy Policy Act. Now is not the time to dilute the impact of the 
incentives by spreading the relatively moderate amount of incentives 
across too many projects or to unintended projects. The selected 
projects should be adequately funded, should be focused on directly 
helping the intended industries, and should be ones deemed most likely 
to succeed in the near term.

                            HARD WORK AHEAD

    The subject of today's hearing: the passage of legislation (PL 109-
58) was only the first of many steps needed to realize the potential of 
gasification technologies.
    The hard work has just begun for both industry and government.
    The second step--the step that is in play right now--is the 
drafting of regulations to implement the authorities conveyed to the 
Administration by the energy bill.
    I have serious concerns about the implementation of the Investment 
Tax Credit and the self pay Federal Loan Guarantee programs.
    Congress passed Public Law 109-58 more than nine months ago (July 
29, 2005); yet, to date, there has been no formal dialogue between the 
private sector and the Department of Energy (or other federal agencies) 
regarding implementation of the loan guarantee provisions of Title 17. 
Of greater and more immediate concern is that the regulations published 
this February regarding the 48B industrial gasification tax credits 
need major revision if the credits are to be awarded effectively, 
fairly and for sound projects, as I believe Congress intended.
    The Section 48B tax credits were originally added to HR 6 as a 
Senate Finance Committee amendment totaling $850 million. As mentioned 
above, these funds were provided specifically for the gasification of 
coal, biomass, petcoke and waste materials to serve the fuel and/or 
feedstock requirements of certain globally-competitive industries that 
were facing economic distress due to rapidly rising natural gas prices 
in the U.S.
    Even at the $850 million amount, it was generally assumed that 
there would be many more applicants for the tax credit than available 
funds. Given the cost premium for the first generation of gasification 
projects to be built, parceling out the limited funding to all 
qualified applicants on a pro rata basis was recognized as potentially 
spreading the money too thinly to advance any projects. Consequently, 
industry proposed that DOE and Treasury jointly solicit tax credit 
applications on a single date after which DOE would evaluate and rank 
the projects according to technical and economic merits for Treasury's 
subsequent award of the credits on a ``competitive'' basis.
    When funding for Section 48B was cut to $350 million in Conference, 
the need for a strong DOE role to assess and rank applicants by merit 
became even more apparent to industry.
    The competitive award of the 48B tax credits is a novel way for 
Congress to target limited financial resources to the most meritorious 
applicants within a class. Such an approach might not be appropriate 
for many types of tax credits; but I believe it clearly is when the 
intent of Congress is to stimulate investment in technology to achieve 
broad public benefits with limited funds.
    Fortunately, even though there was no direct legislative 
requirement to do so, Treasury and the DOE did agree to establish a 
``competitive process'' for accepting, evaluating and awarding 
certificates of eligibility for the limited pool of 48B industrial tax 
credits.
    Both departments should be commended for the novel mechanism that 
has been crafted to promote the most effective use of taxpayer 
resources to spur the early introduction of gasification technology 
leading to the many benefits identified at the beginning of this 
testimony. But more can and must be done by both departments to ensure 
that fairness, process transparency, merit and technical readiness for 
deployment are the final determinants in the awards that are made later 
this fall.
    Government sources anticipate perhaps six or seven times [Note: if 
recent estimates of 48 projects are correct, that would be sixteen 
times] the number of project applications that can be supported by the 
$350 million available. And, each industrial applicant will spend, on 
average, more than $1 million developing their application. In such a 
competitive and expensive situation where industry is preparing to 
commit very large financial resources to build these gasification 
projects (greater than $1 billion in many cases), fairness, 
transparency and judgment on project merits seem like a small request. 
And, it is just ``good government.''

                 DETAILED CONCERNS AND RECOMMENDATIONS

    Eastman Chemical Company joined with numerous other companies and 
trade associations (also known as the Industrial Gasification 
Initiative) to present unified recommendations to both departments 
related to the process for awarding the 48B investment tax credits. 
Subsequently, the Department of the Treasury published guidelines in 
the Federal Register on February 21st for the joint conduct of the 48B 
Industrial Gasification Program with DOE. Certainly the intent of IRS 
and DOE to work together to award the tax credits on a competitive 
basis is a good first step. However, the process described in the 
February announcement ignored many constructive suggestions proposed by 
the Industrial Gasification Initiative.
    Specifically, the 48B process designed by Treasury will not utilize 
DOE's capability to evaluate, compare and rank multiple large projects 
applications, such as it does in the Clean Coal program. Instead, 
Treasury has asked DOE to simply determine whether a project meets a 
``pass-fail'' standard in several categories. Obviously, an evaluation 
process of this nature does not separate the simply good projects from 
the superior ones.
    Did Congress intend that the industrial gasification investment tax 
credits potentially be awarded to ``B'' grade projects over ``A+'' 
projects? I hope not.
    There is still time to fix this problem if key Members of Congress 
move quickly to do so. The Committee has jurisdiction over DOE; but of 
course Treasury, and specifically IRS, has the lead in determining the 
process for awarding the 48B industrial gasification tax credits. I 
urge the Senate Energy and Natural Resources Committee to collaborate 
with the Senate Finance Committee to ensure that the Industrial 
Gasification Initiative's recommendation for a transparent and 
competitive process for industrial gasification tax credit awards based 
on merit is achieved.
    Members of the Industrial Gasification Initiative would be pleased 
to work with the Congress and the agencies on these improvements.
    The Initiative members have many additional concerns about the 
criteria that may, or may not, be used by the DOE and IRS to evaluate 
projects. Mr. Chairman, you were one of the first Senators to recognize 
the need for legislation addressing the adverse impacts of rising 
natural gas prices on domestic manufacturing industries' ability to 
compete in world markets, in fact on their very ability to continue 
operations in the U.S.
    The Section 48B Industrial Gasification Investment Tax Credits were 
born of that very concern. Congress intended for the credits to 
stimulate investment in gasification plants that can use a wide variety 
of fuels to displace natural gas as a fuel and/or feedstock. The 
credits are intended to assist early adopters of gasification 
technologies to ``buy down'' the high price of these first plants to be 
deployed.
    This approach is quite different than DOE's usual mission of 
developing and demonstrating new technologies. Yet, there appear to be 
suggestions in the February IRS guidelines that novel technologies, not 
proven technologies, will be favored in the selection of projects. This 
``research'' bias is reflected in two of the three Program Policy 
Factors listed in Appendix B, section ``F'' of the February Notice: 1) 
``Diversity of technology approaches and methods, and 2) Geographic 
distribution of potential markets. These factors would be suitable for 
a technology demonstration program such as Clean Coal, but they are 
wholly inappropriate for the purposes of Section 48B--to deploy 
technically sound synthesis gas plants that can begin to reduce natural 
gas demand in globally competitive domestic industries, to reduce the 
cost penalty associated with those plants, to offer hope for saving 
U.S. industrial jobs, and to do so in an environmentally sound manner.
    So, the Industrial Gasification Initiative members ask the 
Committee to ensure that the 48B program is not hijacked to become just 
another extension of existing federal RD&D programs.
    Beyond these points, the Industrial Gasification Initiative is 
concerned by the process for obtaining clarification on many technical 
issues raised by the February Federal Register notice (IRS Notice 25-
2006). The Initiative submitted ten questions to the DOE more than one 
month ago. The DOE responses are underlined. Additionally, questions 
that appear in italics were also submitted to the IRS at that time. To 
date, no response has been received from the Service.
    The Initiative's questions and answers received to date follow as 
Attachment 1 at the end of my testimony.
    I call your attention to submitted question #4b and the ``non-
answer'' as an illustration of the confusion that still exists less 
than 60 days before applications are due. Although obviously a 
technical question, DOE deferred it to the IRS, which has provided no 
timetable of their response--nor is IRS likely to possess the technical 
background to appreciate the basis for this question. If this language 
were to remain, and depending on its interpretation, potentially, no 
project would qualify. All projects need start-up fuels, chiefly 
natural gas, in the testing and ramp-up period. These start-up fuels 
will be used in far less quantities during normal operations. As soon 
as a project uses the first molecule of natural gas for start-up, it 
fails this criterion based on current language. While this outcome 
might seem like a ridiculous scenario, unanswered, the question raises 
considerable doubts about how the notice will be applied. There needs 
to be an allowable and adequate start-up period before which such 
language is applied, or else there needs to be a more distinct boundary 
regarding its application to only the production of syngas from the 
gasification block (which is the primary boundary of the eligible 
property definition for application of the tax credit). Companies that 
are spending considerable time and money to develop applications and, 
more importantly, to develop projects that are essential to our 
nation's energy objectives, deserve a straight answer, especially to 
questions as purely technical as #4b.
    Another basis for concern is the non-response to question #5c and 
the second part of question #5b. This process-type question was again 
deferred to the IRS. Eastman and most of the companies that may apply 
for the ITC are public companies with extremely sensitive disclosure 
requirements. We need to know the process of public announcements in 
enough time so that we can be prepared with our concurrent public 
disclosure. This is a process question, not a policy question, so again 
it should be fairly straightforward to address.
    Both of these questions were raised according to the DOE procedure 
on March 25th. DOE indicated a response time of about five business 
days. It is now May 1, the closing date for questions. Any applicant 
that has follow up questions regarding any response, or non-response, 
to previous questions will not be allowed to seek further clarification 
after today.

                            CLOSING REMARKS

    Let me close by encouraging you to maintain the integrity of this 
process. It is crucial, not only for those beneficiaries who have 
projects in the pipeline, but crucial for the country as well.
    If the desire of this Congress continues to be one of providing 
help to the job-producing portion of the American economy--to keep jobs 
here in the U.S.--it is critical that you protect the funding for those 
sectors where it can do the most good: commercial, industrial projects.
    That's where American jobs are on the line and that's where the 
real power of the country's economic engine lies.
    For convenience, I have included a summary of the Industrial 
Gasification Initiative's recommendations under Attachment 2 of my 
testimony.
    Again, I thank you for the opportunity to share our concerns. And I 
thank you for the leadership you've already demonstrated on this 
important topic.

    Senator Alexander. Thank you very much.
    Mr. Bruce.

STATEMENT OF WILLIAM F. BRUCE, PRESIDENT, BRI ENERGY, LLC, NEW 
                        SMYRNA BEACH, FL

    Mr. Bruce. Thank you, Senator. Senators, good afternoon. 
It's a pleasure to be here. My name is William Bruce, and I am 
appearing on behalf of my company, BRI Energy. I appreciate the 
invitation to appear before this committee today and have the 
opportunity to share with you an exciting new technology my 
company intends to utilize to produce ethanol from coal syngas.
    This technology has been developed over the past 15 years 
by many dedicated scientists and engineers and aided 
financially by the Department of Energy. As one of your 
esteemed colleagues told me recently, ``Bill, you're really 
sitting on top of the right technology. You just need to get it 
to the appropriate people.''
    This technology, which I will refer to as ``syngas 
fermentation,'' is now ready to be commercialized. It has been 
validated in a pilot plant and can cost-effectively produce 
ethanol from any carbon material. This technology can use 
synthesis gas from any coal gasifier. It can also convert 
syngas from the gasification of petroleum coke, agriculture 
waste, and even municipal solid waste into ethanol.
    In the simplest of terms, the process uses heat in modern 
gasification equipment to break apart carbon compounds, 
creating carbon monoxide, hydrogen, and carbon dioxide, which 
is then converted biologically into a single product, ethanol, 
in approximately 1 minute. It is projected that the process 
will produce approximately 150 gallons of ethanol per dry, ash-
free ton of coal. Five-hundred million tons of coal per year, 
about 50 percent of our Nation's current coal consumption, 
would produce 75 billion gallons of ethanol, roughly half of 
our Nation's gasoline consumption. If we want to solve the fuel 
problem in this country, the gasification of coal and 
converting that into ethanol, I think, is a viable alternative.
    Utilizing this clean coal technology can help to make our 
Nation energy-independent. An important byproduct of the 
process is the ability to create large amounts of steam. For 
example, a plant processing 2,500 tons of coal per day could 
produce steam capable of powering steam turbines totaling 
approximately 100 megawatts of electric power, while at the 
same time producing 135 million gallons of ethanol.
    In short, the syngas fermentation technology is a 
breakthrough, for three reasons: the process is environmentally 
friendly, the process is economically viable, and the process 
uses homegrown feedstock resources.
    First, our commitment to the environment and reduction of 
greenhouse gases is to produce ethanol with little or no air 
emissions. Emission testing from the pilot plant demonstration 
has been successful in meeting that commitment.
    Second, the passage of last year's national Energy Policy 
Act has laid some very important foundation blocks for 
commercializing this process. The next step is to gain the 
approval of the financial community by building a commercial-
scale plant and demonstrating that this technology is a cost-
effective means to produce ethanol. It is hoped that grant and 
loan guarantee provisions in the current energy legislation 
will help us to achieve this goal. With the assistance of a 
Federal loan guarantee, a 7-million-gallon-per-year coal-to-
ethanol facility can be constructed and fully operational 
within 15 to 18 months. In light of the many challenges in 
today's fuel and energy economy, we are able to offer a viable, 
economic solution.
    Third, this process uses domestic sources of feedstock to 
produce ethanol. As I stated, any carbon-based material can be 
used, and the United States has 23 percent of the world's coal 
reserves. With the abundance of coal located throughout most of 
the Nation, along with other readily available carbon 
feedstock, our technology could allow each State to domicile 
ethanol production facilities.
    This technology has been technically studied and accepted 
by private engineering firms, and uses commercially available 
equipment. I can sit before you today and clearly state that a 
technological solution now exists to make a significant 
contribution towards solving our Nation's energy challenges.
    In closing, I would like to reiterate that our technology 
is a plausible energy solution, because it is environmentally 
friendly, economically viable, and uses homegrown feedstock 
resources. This technology is capable of removing our 
dependence on foreign oil.
    Again, I truly appreciate this opportunity, and would be 
happy to address any questions that you may have.
    [The prepared statement of Mr. Bruce follows:]

  Prepared Statement of William F. Bruce, President, BRI Energy, LLC, 
                          New Smyrna Beach, FL

    Mr. Chairman and Members of the Committee, good afternoon. It is a 
pleasure to be here. My name is William Bruce and I am appearing on 
behalf of my company, BRI Energy. I appreciate the invitation to appear 
before this Committee today and have the opportunity to share with you 
an exciting new technology my company intends to utilize to produce 
ethanol from coal syngas. This technology has been developed over the 
past 15 years by many dedicated scientists and engineers and aided 
financially by the Department of Energy. As one of your esteemed 
colleagues told me recently, ``You are really sitting on top of the 
right technology, you just need to get it to the appropriate people.''
    This technology, which I will refer to as Syngas Fermentation, is 
now ready to be commercialized. It has been validated in a pilot plant 
and can cost effectively produce ethanol from any carbon material. This 
technology can use synthesis gas from any coal gasifier. It can also 
convert syngas from the gasification of petroleum coke, agriculture 
wastes, and even municipal solid waste into ethanol. In the simplest of 
terms, the process uses heat in modern gasification equipment to break 
apart carbon compounds, creating carbon monoxide, hydrogen and carbon 
dioxide, which is then converted, biologically into a single product--
ethanol, in approximately one minute. It is projected that the process 
will produce approximately 150 gallons of ethanol per dry, ash free, 
ton of coal. 500 million tons of coal per year, about 50% of our 
nation's current coal consumption, would produce 75 billion gallons of 
ethanol, roughly half of our nation's gasoline consumption. Utilizing 
this ``clean coal technology'' can help to make our nation energy 
independent. An important by-product of the process is the ability to 
create large amounts of steam. For example, a plant processing 2500 
tons of coal per day could produce steam capable of powering steam 
turbines totaling approximately 100MW of electric power, in addition to 
producing 135 million gallons of ethanol.
    In short, this Syngas Fermentation technology is a breakthrough for 
three reasons:

          1. The process is Environmentally Friendly
          2. The process is Economically Viable
          3. The process uses ``Home Grown'' Feedstock Resources

    First, our commitment to the environment and reduction of 
greenhouse gases is to produce ethanol with little or no air emissions. 
Emission testing from the pilot plant demonstration has been successful 
in meeting that commitment.
    Second, the passage of last year's National Energy Policy Act has 
laid some very important foundation blocks for commercializing this 
process. The next step is to gain the approval of the financial 
community, by building a commercial scale plant and demonstrating that 
this technology is a cost effective means to produce ethanol. It is 
hoped that grant and loan guarantee provisions in the current energy 
legislation will help us to achieve this goal. With the assistance of a 
federal loan guarantee, a 7 million gallon per year coal to ethanol 
facility can be constructed and fully operational within 15 to 18 
months. In light of the many challenges in today's fuel and energy 
economy, we are able to offer a viable economic solution.
    Third, this process uses domestic sources of feedstock to produce 
ethanol. As I stated, any carbon-based material can be used and the 
United States has 23% of the world's coal reserves. With the abundance 
of coal located throughout most of the nation, along with other readily 
available carbon feedstocks, our technology could allow each state to 
domicile ethanol production facilities.
    This technology has been technically studied and accepted by 
private engineering firms and uses commercially available equipment. I 
can sit before you today and clearly state that a technological 
solution now exists to make a significant contribution toward solving 
our nation's energy challenges.
    In closing, I would like to reiterate that our technology is a 
plausible energy solution because it is environmentally friendly, 
economically viable, and uses home-grown feedstock resources. This 
technology is capable of removing our dependence on foreign oil.
    Again, I truly appreciate this opportunity and would be happy to 
address any questions that you may have.

    Senator Alexander. Thank you, Mr. Bruce.
    Mr. Douglas.

    STATEMENT OF WILLIAM C. DOUGLAS, SENIOR VICE PRESIDENT, 
 BUSINESS DEVELOPMENT, ECONO-POWER INTERNATIONAL CORPORATION, 
                          HOUSTON, TX

    Mr. Douglas. Thank you, Mr. Chairman, members of the 
committee.
    I'm pleased to be here today to share with you our views 
about the benefits which coal gasification systems technology 
can deliver, and, in specifics, the technology that we have 
developed. It's our belief that if coal gasification can 
achieve widespread adoption in the industrial sector, it's 
going to help the country displace the usage of scarce natural 
gas and put Americans to work mining, transporting, and 
converting coal.
    Use of synthetic fuel gas will also assist industry in 
meeting the environmental goals of reducing NOX, 
SOX, mercury, and other pollutants, while also 
advancing sound energy policy. Our company, EPIC, builds, owns, 
and operates industrial coal gasification systems to convert 
coal to a clean alternative to natural gas. We believe that the 
use of domestic coal offers a stable-priced, clean alternative 
to the volatile pricing inherent in domestic and imported 
natural gas and LNG.
    EPAct 2005 represents a major step forward in providing 
incentives to bring clean coal initiatives to the very large 
industrials and to utility companies. However, we believe it 
has a very select impact on the small-to-medium-sized 
industrial that is evaluating alternative energy, such as coal 
gasification. Major credit available to us, of course, is the 
investment tax credit. However, those credits are restricted to 
certain industries and require that the fuel be used for a 
specific purpose, such as the production of electricity. This 
restriction eliminates a large proportion of the U.S. 
industrial base as potential users of synthetic fuel gas. The 
small- and medium-sized industrials are the companies having 
the greatest difficulty in dealing with the high price of 
natural gas and electricity used in their facilities. These 
companies are rapidly--as the large companies have already--
becoming noncompetitive with other nations, because of high 
energy costs. These same companies are also reluctant to change 
their energy source from the tried and true natural gas and 
electricity. For them, a commitment to change to a coal-based 
syngas will likely require some type of financial incentive.
    Coal gasification provides a significant environmental 
advantage. When used to replace direct coal combustion in 
boilers or kilns, the following benefits are available: the 
elimination of particulate emission, the reduction of 
SOX emissions by at least 100 times over unscrubbed 
coal, reduction of NOX emissions by 90 percent or 
more, and the removal of mercury at greater than 90 percent.
    In the ICGS process, harmful pollutants are removed from 
the syngas stream before combustion, rather than in post-
combustion flue-gas treatment. The pressurizing gas stream 
represents less than 1/100th of the volume of the flue gas from 
direct coal combustion, and the contaminants in syngas are 
concentrated. Therefore, precombustion cleanup is far more 
effective, and at a much lower cost, than the post-combustion 
cleanup employed in direct-combustion coal steam-boiler plants.
    The nature of coal gasification requires a significant 
capital commitment to build the system. Past and present 
incentives have only been available to the gas supplier or coal 
converter, which is us. Coal gasification is nominally quite 
competitive with natural gas, as we've already heard; however, 
the requirement to commit to a long-term contract for the coal 
gasification system complicates the customer's decision. If tax 
incentives for ICGS were available to the user in the form of 
credits for Btus of syngas used, the economic benefits would be 
more obvious and promote more rapid ICGS implementation. For 
users that are currently combusting coal, tax incentives for 
coal gasification would expedite the fuel switch and offer more 
rapid environmental cleanup of these polluting systems, while 
minimizing the economic impact of the additional conversion 
cost of the coal to fuel gas.
    The current investment tax credit for the producer do help 
to minimize the conversion cost of the fuel-gas user, and, 
therefore, facilitate the acceptance by the financial 
communities for the conventional project financing. And we 
applaud that.
    Thank you very much.
    [The prepared statement of Mr. Douglas follows:]

   Prepared Statement of William C. Douglas, Senior Vice President, 
 Business Development, Econo-Power International Corporation, Houston, 
                                   TX

    Good morning, Mr. Chairman and members of the Committee. My name is 
Bill Douglas. I am the Senior Vice President for Business Development 
for Econo-Power International Corporation or EPIC. We also have Mr. 
John Keller, Vice-President and Chief Financial Officer. We appreciate 
the opportunity to testify this morning.
    We are pleased to be here today to share with you our views about 
the benefits that Industrial Coal Gasification Systems technology can 
deliver. ICGS can produce a synthetic fuel gas at prices below that of 
Natural Gas by converting solid fuels, such as coal, which are abundant 
and economically available in the U.S. If ICGS can achieve wide spread 
adoption in the industrial sector, it will help the country displace 
usage of scarce natural gas, put additional U.S. workers to work 
mining, transporting and converting coal. Use of economical synthetic 
fuel gas will assist industry in meeting environmental goals of 
reducing NOX, mercury and other air pollutants, while also 
advancing sound energy policy goals of retaining a secure and diverse 
mix of fuels for industrial process and electric power generation.
    EPIC, The Clean Coal Gasification CompanyTM, builds, 
owns and operates industrial coal gasification systems to convert coal 
to a clean alternative to natural gas. The use of domestic coal offers 
a stable-priced, clean alternative to volatile-pricing for domestic and 
imported natural gas and LNG.

            EFFECT OF EPACT 2005 ON INDUSTRIALS IN THE U.S.

    EPACT 2005 is a major step in providing incentives to bring clean 
coal initiatives to the very large industrials and Utility companies. 
It has a very select impact on the small to medium size industrial that 
is evaluating alternative energy such as Coal Gasification. The major 
credit available is the ITC. However, these credits are restricted to 
certain industries and/or require that the fuel be used for a specific 
purpose such as the production of electricity. This eliminates a large 
proportion of the U.S. industrial base as potential users of synthetic 
fuel gas. The small and medium sized industrials are the companies 
having the greatest difficulty in dealing with the high price of 
natural gas and electricity used in their facilities. They are rapidly 
becoming non-competitive with other nations because of high energy 
costs. These same companies are also reluctant to change energy sources 
from the tried and true natural gas and electricity infrastructure. For 
them, a commitment to change to a coal-based syngas will require some 
financial incentive. The most effective way to induce a company to 
change to Coal Gasification is through economic incentives. The way to 
provide these incentives is to modify EPACT to include the smaller 
industrials with incentives to use alternative energy sources such as 
Coal Gasification.

                      OVERVIEW OF ICGS TECHNOLOGY

    ICGS is a process that converts low value fuels such as coal, 
biomass, and municipal wastes into a high value, low Btu, 
environmentally friendly natural gas-type fuel, also called ``synthesis 
gas'' or simply ``syngas''. ICGS uses air-blown, modular gasifiers to 
accomplish the conversion.
    Coal gasification has undergone many evolutions and improvements. 
The EPIC system of gasification and sulfur removal is an updated 
version of a time tested method to convert coal to a low Btu fuel gas. 
The EPIC system is covered by U.S. patents (pending) and is 
manufactured in the U.S. There are dozens of similar systems in 
operation for many years in other parts of the word that provide fuel 
gas for varied industrial processes. The potential U.S. industrial 
users need some incentive to allow them to accept the system in the 
U.S.
    Industrial uses include virtually any natural gas fueled industrial 
process such as boilers, kilns, process furnaces, etc. The ICGS can 
also refuel older coal fired plants for environmental compliance 
without adding pollution control systems.
    EPIC has also worked with major gas turbine suppliers to gain 
acceptance of the fuel gas produced in EPIC's system. This acceptance 
opens the Integrated Gasification Combined Cycle (IGCC) area for even 
small and medium sized industrial plants.

                    ENVIRONMENTAL ADVANTAGES OF ICGS

    ICGS provides some significant environmental advantages. When ICGS 
is used to replace direct coal combustion in boilers or kilns, the 
following benefits are obtained;

   Elimination of particulate emissions.
   Reduction of SOX emissions by at least 100 times 
        over unscrubbed coal.
   Reduction of NOXemissions by 90% or more.
   Removal of mercury at greater than 90%.

    When ICGS is used to replace natural gas, NOX reductions 
of at least 50% are obtained.
    It is important to note that only minimal modifications are 
required to boilers, kilns or process furnaces to use ICGS. For most 
industrial boiler, kiln or furnace systems, major capital expenditures 
would be required to achieve compliance with even current environmental 
regulations. ICGS allows U.S. industrial companies to employ capital to 
improve process efficiency without having to dilute it for investing 
non-productive pollution control systems.
    In the ICGS process, harmful pollutants are removed from the syngas 
stream before combustion, rather than in post combustion flue gas 
treatment. The pressurized syngas stream represents less than 1/100 of 
the volume of the flue gas from direct coal combustion and the 
contaminants in syngas are concentrated. Therefore, IFGS pre-combustion 
clean-up is far more effective and much lower cost than the post-
combustion clean-up employed in direct combustion coal steam-boiler 
plants.
    In ICGS, coal ash is converted in the gasifier into a solid, which 
is similar to conventional coal fired ash which can be employed in the 
construction industry as road fill or as strengthening aggregate for 
building concrete. ICGS does not require secure landfill sites for ash 
storage.
    The sulfur is removed from the gas before combustion and is 
recovered in elemental, non-hazardous form. This sulfur may have 
economic in certain industrial processes and agriculture. Even if 
sulfur disposal is required, non-hazardous disposal is easily 
accomplished.

      ICGS SHOULD BE VIEWED AS A FUEL SWITCH AND NOT A NEW SOURCE

    In the case of retrofit for industrial boilers, kilns, furnaces, 
etc, the facility is normally permitted to operate on its present fuel. 
In general, the facility will continue to operate at the same 
production level (at a minimum) as with the existing fuel.
    ICGS should be viewed as merely a fuel change and not a major 
modification triggering NSPS standards. Expedited permitting would also 
help the industrial user to keep competitive advantages while 
maintaining domestic fuel sources.
    Consideration of ICGS's environmental benefits should lead to 
placing ICGS as PACT (Preferred Available Control Technology) for 
industrial energy users.
    PACT designation would allow industrial customers to more rapidly 
achieve energy cost stability and remove this aspect of the perceived 
permitting risk when using ICGS.

                               ICGS USES

    The EPIC ICGS is inherently ``modular'' and is easily applicable to 
most industrial processes. The number of gasification modules is 
determined to closely match the fuel gas needs for each individual 
user. There is no ``one size must fit all'' requirement, as is the case 
with larger oxygen-blown systems being offered for large IGCC plants.
    Gasification is a steady state chemical process and steady state 
industrial processes are the best candidates for its use. With modular 
ICGS, should the user's fuel gas needs expand, the ICGS is normally 
easily expandable to match the expanded needs.
    Another industrial strategy could be to co-fire ICGS gas with 
natural gas to obtain partial benefits. The ICGS system can be expanded 
in the future for increased coal gas use. This strategy could allow the 
user to more rapidly obtain some ICGS benefits while a larger system is 
being constructed.
    EPIC is working to improve the process and overall efficiency, 
thereby offering the user increased benefits from ICGS use.

                            ECONOMIC ISSUES

    The nature of ICGS requires a significant capital commitment to 
build the system. Past and present incentives have only been available 
to the gas supplier/coal converter. ICGS is nominally quite competitive 
to natural gas. However, the requirement to commit to a long-term 
contract for the ICGS system complicates the decision. If tax 
incentives for ICGS were available to the user in the form of credits 
for Btu's of syngas used, the economic benefits would be more obvious 
and promote more rapid ICGS implementation.
    For users that are able to directly combust coal, tax incentives 
for ICGS use would expedite the ``fuel switch'' and offer more rapid 
environmental clean-up of these polluting systems while minimizing the 
economic impact of the additional ``conversion'' cost of the coal to 
ICGS fuel gas.
    For the system provider of the ICGS, capital cost is a major issue. 
Investment tax credits would help to minimize the ``conversion cost'', 
to the fuel gas user and therefore, facilitate the acceptance by the 
financial communities for conventional project finance.

                   VALUE TO INDUSTRY AND THE COUNTRY

   Reduce industrial dependence on natural gas or foreign LNG.
   Use the 225 year supply of U.S. coal resources for a broad 
        base of industrial plants.
   Help U.S. industrial producers keep competitive with foreign 
        competitors with cheaper synthetic fuel gas.
   Reduce industrial emissions.
   Allow industrial producers to stabilize energy prices over 
        the long term without the high volatility of natural gas 
        prices.
   Keep and create new U.S. jobs.

             NEEDED TO ACCOMPLISH BROAD ICGS IMPLEMENTATION

   Broaden the base of industries and applications in which 
        EPACT 2005 and other legislation encourage the use of 
        gasification technologies by removing restrictions as to the 
        types of industry and ends use of the syngas produced
   Incent the ultimate gas user by providing incentives based 
        on the amount of energy in Btu's obtained from coal 
        gasification
   Adopt ICGS as Preferred Allowable Control Technology (PACT) 
        to allow environmental regulators to more easily issue permits 
        for fuel switching rather than the full new source reviews that 
        could be required without PACT designation.

                              CONCLUSIONS

   ICGS can benefit a broad spectrum of U.S. industries.
   ICGS can significantly reduce industrial pollution.
   Additional broad based tax incentives available to the fuel 
        user would expedite implementation of ICGS.
   ICGS can be a viable means of reducing U.S. dependence on 
        imported energy (oil and natural gas/LNG).

    Thank you for the opportunity to testify before your committee and 
we would be happy to provide additional information if required.

    Senator Alexander. Thank you, Mr. Douglas.
    Mr. Boycott.

    STATEMENT OF WILLIAM A. BOYCOTT, GENERAL MANAGER, KENAI 
        NITROGEN OPERATIONS, AGRIUM U.S. INC., KENAI, AK

    Mr. Boycott. Good afternoon, Mr. Chairman and members of 
the committee. Thank you for the opportunity to appear today to 
discuss the Energy Policy Act of 2005 and its applications to 
industrial coal gasification.
    As you mentioned, I'm responsible for Agrium's operations 
in Alaska. Those operations are a gas-based fertilizer-
production facility with the capability to produce 2 million 
tons a year of fertilizer. We are the second largest nitrogen 
complex in North America and one of the largest manufacturers 
in the State of Alaska. At capacity, we employ 230 people 
directly.
    As I mentioned, we're based on natural gas, and, 
specifically, natural gas produced in the Cook Inlet of Alaska. 
After 35 years of industrial usage, we're seeing this gas in 
significant decline. The natural-gas reserves that we are 
dependent on are no longer able to support contracts for the 
long-term supply into our facility. As a result, in November of 
last year we shut down half of our complex and laid off 85 of 
our employees. If we're not successful in contracting for 
additional supplies, we'll be forced to shut down entirely in 
November of this year.
    Closing the plant will have a devastating effect in the 
Kenai Peninsula area of Alaska. As I mentioned 230 direct jobs, 
420 indirect jobs, will be lost, along with more than $100 
million annually that we inject into the local economy through 
our activities.
    As we continue to pursue a short-term solution in natural 
gas contracts, we're also evaluating coal gasification. We've 
initiated a feasibility study to look at the potential for the 
utilization of large reserves located about 25 miles from our 
plant to support our ongoing operations. If this project proves 
to be commercially viable, it not only will protect and--the 
jobs and the economic impact of our business, but it also has 
the potential to supply low-cost power into the Alaskan grid, 
utilize sequestered carbon dioxide in the production of oil--
crude oil and enhanced oil recovery operations, and provide the 
anchor demand required to develop a world-scale coal resource 
that to date has not had an economic opportunity for 
development.
    As we've gone through the economic evaluation of this 
project, we're looking at a large project. Current estimates, 
$1.5 to $2 billion. As we look through the evaluation on the 
decisionmaking as to whether to move forward with this, just 
the decisionmaking is a daunting process. Our two-phase 
feasibility study of the economics of the project will cost in 
excess of $32 million. These expenditures are at-risk dollars, 
in that they're not recoverable if the project doesn't move 
forward.
    A key component of these plans in any decisions we make to 
put dollars at risk is the certainty of Federal Government 
assistance, if it is offered. Suffice to say that, at this 
point, if we determine that it is needed, then it will be 
imperative that the assistance be there when the time comes.
    After comprehensive analysis of the Energy Policy Act, 
we've concluded that the industrial gasification tax credits 
and the innovative technologies loan guarantee program have the 
potential to provide significant benefits to the project. The 
degree to which either of these programs is beneficial, 
however, will be determined by the manner in which the 
executive branch implements them.
    The Blue Sky project could be eligible for a maximum of 
$130 million in tax credits. Our preliminary analysis shows 
that these could be material in our decisionmaking process. As 
stated earlier by Secretary Garman, we have concerns that we're 
somewhat out of link, and--with trying to supply the level of 
definition required by June of this year. And so, that causes 
us some concern, and that concern has--you know, although we 
continue to move forward with this evaluation, at this point we 
aren't able to ascribe much benefit to the tax credits program 
in our project evaluation.
    Similarly, the loan guarantee program holds great potential 
to reduce the cost and risk of financing capital-intensive 
projects such as the Blue Sky project. That potential could be 
significantly limited, however, by its implementation--in 
particular, the evaluation and implementation of the risk 
premium, as previously discussed. I had an example here I was 
going to discuss, but I think it's been very adequately covered 
already. Suffice to say that if the risk premium is calculated 
in a way that the project implementor bears all the risk, then 
the value to the implementor of the project is greatly reduced 
or eliminated.
    In conclusion, I believe that the development of industrial 
gasification projects is crucial as we look to address our 
national energy issues. And I applaud you for the work that you 
have done in the development of the national energy program.
    I believe strongly that the opportunity we are evaluating 
in Alaska is a very sound opportunity supported by a very 
interesting cross-section of commercial opportunities through 
CO2, the fertilizer complex, and the coal resource 
that is there in place in Alaska.
    The national energy policy is on the right track. However, 
definition and certainty are required in order to support the 
decisionmaking that private industry is facing. What we're 
looking for is certainty and simplicity. And, currently, where 
we're at with the loan guarantee program and the tax credits, 
we don't see that, to this date, and we are afraid that they 
are not supporting the decisionmaking that is going on.
    Thank you.
    [The prepared statement of Mr. Boycott follows:]

   Prepared Statement of William A. Boycott, General Manager, Kenai 
            Nitrogen Operations, Agrium U.S. Inc., Kenai, AK

                              INTRODUCTION

    Good afternoon Mr. Chairman, Members of the Committee. Thank you 
for the opportunity to appear before the committee to discuss the 
Energy Policy Act of 2005 and its applications to industrial coal 
gasification. My name is Bill Boycott. I am the General Manager of the 
Agrium U.S., Inc. Kenai Nitrogen Operations (KNO). I am here to address 
how provisions of the Energy Policy Act of 2005 (EPAct 05) could 
potentially benefit Agrium's Blue Sky coal gasification project.
    KNO is a manufacturing facility located in Kenai, Alaska, that 
relies upon natural gas as a feedstock to produce ammonia and urea 
fertilizers. Like many U.S. fertilizer manufacturers, we are unable to 
assure ourselves of a reliable, long term, reasonably priced supply of 
natural gas the primary feedstock required for fertilizer production. 
As a result, KNO actively is evaluating the feasibility of constructing 
a coal gasification facility to produce the necessary hydrogen and 
carbon dioxide feedstocks for fertilizer production. As part of our 
feasibility evaluation, we have analyzed all of the provisions of the 
Energy Policy Act of 2005 that potentially could facilitate investment 
in and development of the Blue Sky coal gasification project. We have 
determined that two particular provisions--the Internal Revenue Code 
Sec. 48B industrial gasification tax credit and the Title XVII loan 
guarantee authority--could be of significant value to the project, 
depending on how they are implemented.

                                 AGRIUM

    Agrium is a leading global producer and marketer of agricultural 
nutrients. Our wholesale division manufactures, markets and distributes 
over 8 million tons of nitrogen, potash and phosphate fertilizers each 
year from 12 production facilities in the United States, Canada and 
Argentina. Agrium is also one of the largest agricultural retailers 
with more than 500 retail centers in 31 States and more than 30 stores 
in South America. These facilities are staffed by more than 8,000 
employees worldwide.

                       KENAI NITROGEN OPERATIONS

    Agrium acquired the Kenai facility from Unocal Agricultural 
Division in 2000. The facility was constructed in 1968 and expanded in 
1977. It is the second largest nitrogen complex in North America with 
the capacity to produce in excess of 2.0 million tons of fertilizer per 
year when operating at full capacity. KNO is one of the largest 
manufacturers in Alaska, employing 230 employees when operating at full 
capacity. It is one of Alaska's few value added industries--for every 
one thousand cubic feet of natural gas used, more than $9 in total 
economic output is generated.

                 COOK INLET NATURAL GAS SUPPLY & DEMAND

    The Cook Inlet region of Alaska has a variety of established 
industries that were built around an abundance of low cost natural gas. 
The local natural gas supply is finite. The once large reservoirs of 
natural gas have been depleted, the historic pricing structure has not 
promoted exploration for new reserves, and demand, principally for 
electric power generation and commercial and residential uses, has 
grown significantly. Gas dependent industries have ceased operations 
and the cost of natural gas to electric utilities and their customers, 
as well as end-users of the fuel, has risen dramatically. This 
combination of factors has created a situation in which we are unable 
to contract for a long-term reliable supply of natural gas.
    KNO has been confronted with ever deepening supply shortages since 
2002 and acquiring and maintaining a steady supply of natural gas has 
been a challenge. Because of these shortages, long-term natural gas 
contracts are not possible and we now operate on year-to-year gas 
contracts. Under these short-term arrangements we have been unable to 
acquire sufficient natural gas to meet our needs and, as a result, 
reduced our operations to 50% in 2005. This resulted in a reduction of 
85 of our 230 full-time employees. This January, during a cold spell 
that significantly increased residential and commercial demand for 
heating, we were forced to shut down the entire operations for almost 
two weeks. See Appendix A * for a depiction of the reduction in gas use 
at KNO over the last four years as a result of lack of available 
supply.
---------------------------------------------------------------------------
    * Appendixes A-C have been retained in committee files.
---------------------------------------------------------------------------
    We only have an assured supply of natural gas for another six 
months, until October 31, 2006. If we are not successful in arranging 
additional supplies beyond that date we will be forced to shut down the 
plant on November 1, 2006. Closing the KNO facilities will have a 
devastating effect on the Kenai Peninsula area of Alaska--230 high 
paying skilled jobs will be eliminated and another 420 indirect jobs 
will be lost along with the more than $100 million KNO injects into the 
Alaska economy each year. It will also add to the long list of domestic 
fertilizer production facilities that permanently have shut down due to 
feedstock pricing and supply issues.
    Mr. Chairman, I should explain here why the Alaska natural gas 
pipeline, which has been the subject of much discussion in this 
Committee over the last several years, is not a solution to KNO's 
dilemma. As you know, that pipeline will access the 35 trillion cubic 
feet of known natural gas reserves on Alaska's North Slope. To achieve 
the economies of scale necessary to finance the extraordinary capital 
costs of such a project, the pipeline needs to transport a very large 
volume of gas (4.5 billion cubic feet per day) to a market that can 
absorb such a large volume. The residential, commercial, utility and 
industrial consumers of the lower-48 states comprise the market for 
North Slope gas. As a result, none of the vast North Slope gas reserves 
will be available for consumption in the State of Alaska until a 
project to deliver that gas to lower-48 consumers is constructed. Even 
then, a small ``spur'' pipeline of approximately 340 miles would have 
to be constructed at an approximate cost of $750 million to deliver 
North Slope gas from the main trunk line to the Kenai Peninsula. Under 
the best-case scenario, KNO would not have access to Alaska North Slope 
natural gas before 2016. We can not last that long on current Cook 
Inlet supplies and need to find another solution if we are to keep the 
KNO facility operational.

                          THE BLUE SKY PROJECT

    To maintain operations at the KNO facility, Agrium must find a 
long-term supply of feedstock to substitute for natural gas. 
Fortunately, multi-year supplies of undeveloped Alaskan coal can be 
found some 25 miles from the KNO facility. Given the proximity of these 
coal reserves, coal gasification may be the answer to providing the 
long-term feedstock that is essential to keep KNO operational.
    In 2005, KNO initiated a two-year feasibility study to examine the 
use of gasification technology utilizing Alaskan coal and other 
appropriate indigenous fuel resources to produce the hydrogen, nitrogen 
and CO2 we need to manufacture fertilizer. We are calling 
the gasification project the Blue Sky Project. This project would 
utilize commercially offered gasification technology and capitalize on 
unique market conditions and strategic partnerships to provide a long-
term commercial alternative to natural gas reliance in the Cook Inlet 
region of Alaska. Our engineering work to date has led us to the 
conclusion that our project will not be designed as an IGCC facility. 
Rather, we plan to construct a state of the art gasification facility 
as well as a traditional pulverized coal-fired power plant, using the 
latest in emissions control technology. The power plant will provide 
needed electricity to the Kenai fertilizer facility as well as coal-
fired power to Alaska residences and other Kenai industries. If we move 
forward, the plan is for the facility to be commissioned in 2011. To 
date, Agrium has committed $3.3 million to this study.
    The benefits of the Blue Sky project are substantial: we could 
retain the annual production of 0.8 million tons of ammonia and 1.3 
million tons of urea, along with associated jobs, community support and 
business opportunities for Alaska companies. In addition, the project 
could provide low cost power for use in the population centers of 
Alaska, which currently rely heavily on natural gas fired generation. 
Blue Sky also could capture and supply excess CO2 to recover 
up to 300 million barrels of Cook Inlet oil through enhanced oil 
recovery. The project also provides the anchor demand necessary to 
develop a world-class coal mine. This will in turn assist in the 
economic development of other Alaskan communities and companies by 
supplying an alternative for by-products and demand for services.
    Given the cost and magnitude of Blue Sky, the current view is that 
the ultimate business structure will include several strategic partners 
with an interest in the overall structure or perhaps individual 
components with strong contractual ties. Agrium could bring nitrogen 
production experience and use its existing marketing capacity and 
network to market the product. Usibelli Coal Mine Inc. (UCM) brings to 
the project over 60 years of experience as the only operating Alaskan 
coal mining company. The proven experience of Agrium and UCM, combined 
with the excellent operating performance of the Kenai Nitrogen 
Operations, is a strong foundation on which to build Blue Sky. 
Ultimately this project will need additional equity participants to be 
successful. These participants could include power producers, 
gasification technology providers, and oil and gas companies interested 
in enhanced oil recovery.

                   COMPONENTS OF THE BLUE SKY PROJECT

    See Appendix B.
Gasifier Block
    The Blue Sky Project envisions constructing two Shell coal 
gasification trains to produce the hydrogen, nitrogen, steam and carbon 
dioxide required by KNO. The process dries and pulverizes delivered 
coal conveying it to the gasifier where the coal reacts with 
substoichiometric amounts of pure oxygen to form a gas stream rich in 
carbon monoxide and hydrogen (syngas). This gas is reacted with water 
in shift converters where the carbon monoxide (CO) is shifted into 
carbon dioxide (CO2) and hydrogen (H2). The 
CO2 is then removed from the syngas along with sulfur and 
other impurities. Finally a pure hydrogen stream is supplied to the KNO 
nitrogen plant where it will be combined with pure nitrogen from the 
air separation unit and then converted into ammonia (NH3).
Air Separation Unit
    The air separation unit (ASU) processes air directly from the 
atmosphere to generate the nearly pure oxygen required by the 
gasification block. The air separation unit is the largest power 
consumer in the envisioned complex due to the large compressors 
required to liquefy and separate pure oxygen and nitrogen from the air. 
The gasifier block requires pure oxygen to process the coal, all of 
which is supplied by the air separation unit.
Nitrogen Plant
    The nitrogen plant takes pure hydrogen from the gasifier and pure 
nitrogen from the air separation unit and combines them in a high-
pressure converter to form ammonia (NH3). Some of the 
ammonia is then refrigerated and sold into the global market. The 
remaining ammonia is combined with carbon dioxide (CO2) in a 
high-pressure reactor to form urea (NH2CONH2). 
The urea is sold as the highest grade of solid nitrogen fertilizer 
produced for agricultural and industrial markets.
Power Block
    The Blue Sky Project will require approximately 100 MW of 
electricity to power the gasifier block, the ASU and the nitrogen 
plant. Since there is not sufficient power generating capacity in the 
Kenai area to supply this amount of electricity, the Blue Sky Project 
envisions building a pulverized coal-fired facility to supply power to 
the Project. These units also have the potential to generate additional 
power for sale into the electrical grid that serves the population 
centers of the Kenai Peninsula, Anchorage and the Matanuska Valley. The 
project will use best available control technology (BACT) for emissions 
control. We are also considering the application of additional 
technology that could further reduce emissions.
Enhanced Oil Recovery
    CO2 not used in the fertilizer manufacturing process may 
be captured and sold to Kenai area oil producers who will inject it 
into the aging Cook Inlet oil fields to produce an estimated 300 
million barrels of additional crude oil from these fields. The 
potential daily oil production increase is estimated to be as much as 
25,000 barrels per day. The use of CO2 to enhance the 
recovery of oil from existing fields has been proven in many fields 
across North America. The unique properties of CO2 allow 
this gas to dissolve into the remaining heavy oil in the reservoir and 
change the oil's flow characteristics. The result is that more oil is 
able to flow from the reservoir, be recovered and CO2 
emissions to the environment are reduced. The Department of Energy has 
sponsored two studies that have identified the high potential for oil 
recovery in the Cook Inlet fields.
Coal Supply
    The Blue Sky Project could utilize up to five million tons of coal 
per year. The long-term nature, volume and location of this demand can 
support the development of new coal mining opportunities in Alaska. UCM 
is evaluating options associated with utilization of coal from the 
Beluga coal fields on the west side of Cook Inlet as well as from the 
existing coal mine at Healy, Alaska. UCM is also evaluating the 
transportation of coal to the Blue Sky facility. A draft report is 
expected by early summer 2006. Phase 2 of the project will continue to 
expand on this and will narrow the scope to identify the most viable 
strategic option. See Appendix C.

            EVALUATING THE ECONOMICS OF THE BLUE SKY PROJECT

    Our preliminary estimates are that the total cost of the Blue Sky 
Project will be between $1.5 and $2 billion. Determining whether Agrium 
and its partners should invest this amount of capital in the project is 
a challenging and expensive undertaking.
    Keep in mind that KNO is in a substantially different position than 
most other U.S. industrial firms that are reliant on natural gas and 
that are evaluating a gasification project. These other firms basically 
have three options from which to choose--continue current operations 
using high priced natural gas for energy and feedstock; convert to coal 
or another alternative source of energy and feedstock by installing 
gasification technology; or cease U.S. operations and move overseas. 
Because KNO does not have an assured supply of natural gas at any 
price, we in effect have only two options--develop a coal gasification 
capability or permanently close the facility.
    Our limited options do not mean, however, that we can construct the 
Blue Sky Project regardless of the economics. We still must market our 
ammonia and urea competitively. And, as production of fertilizer shifts 
from traditional industrialized nations to the areas of the world with 
low cost stranded natural gas, these areas are setting the world price. 
Thus, we are using very sharp pencils to determine if the Blue Sky 
Project makes sense.
    KNO is evaluating the economics of the Blue Sky Project through a 
two-phase feasibility study. Phase 1 began in October of 2004 and 
consists of preliminary engineering, commercial and environmental 
feasibility assessments. We anticipate having the results of Phase 1 
within the next four to six weeks. If the results of Phase 1 are 
positive, we will advance to Phase 2, in which we will develop a Front 
End Engineering and Design (FEED) package. We hope to complete Phase 2 
by late 2007 at which time we will be in a position to make the ``go/no 
go'' decision on the Project.
    We expect the total cost of Phase 1 to approach $4.0 million and 
that Phase 2 will cost at least another $28 million. Mr. Chairman, for 
the Committee to fully understand the difficulty in advancing one of 
these projects to the construction stage and the role EPAct 05 plays in 
that regard, it is important for the Members to appreciate that these 
Phase 1 and Phase 2 expenditures are ``at risk'' dollars. In other 
words, if we determine at the end of Phase 2 that the Blue Sky Project 
is not commercially viable, Agrium and its partners will have spent 
nearly $32 million and all we will have to show for those dollars are a 
number of studies and analyses. A key component of these plans and any 
decisions to put more dollars at risk is the certainty of the federal 
government's assistance if it is offered. Suffice to say at this point, 
if we determine that federal assistance is crucial once the studies are 
completed, then it is imperative that the federal assistance be there.

                       ENERGY POLICY ACT OF 2005

    A significant component of our Phase 1 work has been a 
comprehensive analysis of the EPAct 05 to determine whether any of the 
programs authorized by the Act could improve the commercial viability 
of the Blue Sky Project. We have concluded that there are two programs 
that could be beneficial--the industrial gasification tax credits 
authorized by Sec. 48B of the Internal Revenue Code and the innovative 
technologies loan guarantee program authorized in Title XVII of EPAct 
05. These programs have the potential to provide significant benefits 
to the Project. However, the potential value of these programs will be 
determined by the manner in that they are implemented by the Executive 
branch.
    That only two of the multiple programs authorized by EPAct 05 are 
relevant to our Blue Sky Project may be surprising to some. It was 
somewhat of a surprise to us. One of the basic reasons for this is that 
a significant majority of the EPAct 05 programs are applicable only to 
research and development projects, and are not available for commercial 
scale projects. While we believe it is appropriate for the federal 
government to support long-term research and development, we would 
suggest that, if development of capital intensive commercial scale 
projects utilizing innovative energy technologies is a priority, the 
Congress may want to consider focusing additional resources on 
assisting such projects to get over the financial risk hurdles that 
confront them.
    Before discussing the two specific programs, we would like to note 
that we have found EPAct 05 to be beneficial in an intangible way. It 
has been our experience that the enactment of EPAct 05 has sent a 
strong signal to government agencies, particularly the Department of 
Energy (DOE), and the commercial market place that supporting and 
promoting the development of these projects is a high priority of the 
Congress. This signal, in turn, has resulted in a more favorable 
environment for projects such as Blue Sky. It does not mean that we can 
ignore commercial realities, but it does mean that we have a greater 
opportunity to present the case for such projects.
    Under IRC Sec. 48B, the Blue Sky Project could be eligible for a 
maximum of $130 million in tax credits. Our preliminary analysis shows 
that these tax credits could improve the rate of return on investment 
in the project by up to one half of one (0.5) percent, which could be 
the difference between going forward and not. However, the manner in 
which the Internal Revenue Service (IRS) proposes to implement the tax 
credit authority creates some fundamental uncertainties, not only the 
Blue Sky Project, but also for other industrial gasification projects. 
The guidance issued by the IRS calls for DOE to determine which 
projects should receive the tax credits through a competitive process. 
Since the total amount of credits is currently limited to $350 million, 
it is highly likely that only two or three projects will be chosen to 
receive the credits. Applications for the credits must be submitted by 
June 30, 2006 with the final decisions regarding which Projects qualify 
for the credits to be made by November 2006. Given that our Phase 2 
detailed study will be just underway on June 30, we will, by necessity, 
have to submit an application for the tax credits that is somewhat 
contingent on the outcome of that analysis. We already have amassed a 
great deal of reliable information but the timing for tax credit 
applications may be a factor that works against the Blue Sky Project. 
While we understand the IRS's desire to expeditiously implement the 
Sec. 48B program, the proposed schedule does not match well with the 
timing of the Blue Sky Project and other projects being evaluated in 
the United States.
    Mr. Chairman, I understand that you played a significant role in 
the development of the Title XVII loan guarantee program. Thank you for 
your foresight. The policy behind Title XVII--that the federal 
government should share some of the risk of commercializing capital 
intensive projects such as Blue Sky--has the potential to be the most 
beneficial and far-reaching contribution of EPAct 05 to the development 
of innovative energy technologies. However, this potential may not be 
realized if the Administration takes an overly restrictive approach to 
implementation of the program.
    First, there does not seem to be a uniform commitment within the 
Executive branch agencies to this program. While DOE appears to be 
anxious to move forward and lay the groundwork for implementation, it 
is our understanding that the Office of Management and Budget (OMB) has 
not yet approved the funding necessary to staff and operate the 
program. Second, once the program is up and running, every project that 
hopes to take advantage of a loan guarantee must address the issue of 
the ``risk premium'' for the guarantee. Unlike other federal loan 
guarantee programs, Title XVII permits the DOE to collect funds for the 
project seeking a loan guarantee to ``cover'' the probability that the 
project will default on the guaranteed loan (so-called ``risk 
premium''). Other guarantee programs require that federal 
appropriations be provided to cover the risk premium in order to 
support the issuance of a guarantee. While the self funding device is a 
creative means to initiate the Title XVII program without impacting the 
federal budget, everything depends upon how the premium amount is 
determined.
    DOE, in consultation with OMB, will determine the amount of the 
required risk premium by estimating the probability of default on the 
guaranteed loan. This default probability determination will be the 
most important factor in whether the Blue Sky Project (or any other 
gasification project) will benefit from a Title XVII loan guarantee. If 
DOE and 0MB employ a very conservative approach designed to protect the 
federal government from virtually all risk, then the premiums for the 
loan guarantees are likely to be so large that either a federal 
appropriation will be infeasible or payment of the premium by the 
applicant will more than offset whatever financing cost benefits are 
gained by the loan guarantee. As an example, if the total cost of the 
Blue Sky project were $1.5 billion and we sought a loan guarantee for 
the maximum 80% of the cost allowed by Title XVII, the guaranteed 
amount of debt would be $1.2 billion. If the default probability were 
determined to be 10%, the risk premium would be $120 million. In light 
of the current federal budget situation, it is doubtful that Congress 
would appropriate this amount for one project. In the alternative, KNO 
and it partners would have to provide the $120 million thus increasing 
the overall cost of the project by 8 percent. This added cost is likely 
to make the project uneconomic.
    In addition to the risk premium issue, we understand that DOE is 
considering requiring ``risk sharing'' from lenders. It also appears 
that DOE has an expectation that the federal loan guarantee will only 
cover certain negotiated risks during project execution as opposed to 
providing 100% guarantee coverage on 80% of total project cost as 
authorized by Title XVII. Likewise, it appears that DOE may limit the 
applicability of the guarantee to certain identified periods of time 
rather than the life of the construction loan and/or the term of the 
permanent financing for a project.
    As noted earlier, the policy behind Title XVII is that the federal 
government will share some of the risk in order to move these new 
technologies into the marketplace. If DOE and OMB administer the 
program to eliminate virtually all of the government's risk exposure 
then the objective of the Title XVII program will be lost. We would 
encourage the Congress to provide special oversight to this portion of 
Title XVII implementation.
    Finally, I would note that we have not yet determined whether using 
the Title XVII loan guarantee program would force Agrium to comply with 
other federal requirements, specifically the Davis Bacon prevailing 
wage provisions or some type of domestic content requirements. Having 
to comply with one or more of these types of requirements will simply 
add to the overall cost of the project and diminish whatever benefit is 
gained from the loan guarantee.

                               CONCLUSION

    Thank you again, Mr. Chairman and Members of the Committee for this 
opportunity to present our Blue Sky Project. As you see, these projects 
are massive undertakings that involve a great deal of risk. Enactment 
of EPAct 05 has created an environment that is more favorable toward 
industrial gasification projects than in the past and certain programs 
authorized by the Act have the potential to improve the commercial 
viability of some projects. However, unless these programs are 
implemented in the manner that you intended they will not provide 
sufficient support to stimulate or sustain value added industrial 
manufacturing in the United States.

    Senator Alexander. Thank you, Mr. Boycott.
    Dr. Herzog, thank you for coming.

   STATEMENT OF ANTONIA HERZOG, STAFF SCIENTIST AND CLIMATE 
  ADVOCATE, CLIMATE CENTER, NATURAL RESOURCES DEFENSE COUNCIL

    Dr. Herzog. Thank you very much. Thank you for the 
opportunity to testify here today and discuss coal gasification 
and environmental impacts of this technology.
    My name is Antonia Herzog, and I work at NRDC in the 
Climate Center. NRDC is a nonprofit organization of scientists, 
lawyers, and environmental experts dedicated to protecting 
public health and the environment. We were founded in 1970, and 
have more than 1.2 million members and activists online.
    One of the primary reasons that people are interested in 
coal gasification that has been clear in the discussions here 
today is that it can be used as a substitute for natural gas. 
Coal certainly has advantages. It's affordable, and it's a 
domestic resource. However, we believe that affordable energy 
is certainly very important for the quality of life of all 
Americans, but I'm sure Senators on this committee equally well 
believe that clean air, clean water, clean lands, and a stable 
climate are also extremely important for our quality of life.
    Thus, unfortunately, the disadvantages of coal also need to 
be taken into account. It has underground accidents and 
mountaintop removal mining issues, air emissions of acidic, 
toxic, and heat-trapping pollution from coal combustion, water 
pollution from coal mining and combustion wastes, and the 
conventional coal fuel cycle is probably among the most 
environmentally destructive activities on our Earth today. But 
we can do better with both production and use of coal. And 
that's what I'd like to talk to you about today, especially 
because it seems unlikely that the world will continue to be 
using large quantities of coal in the near and longer terms.
    In particular, coal use and climate protection do not need 
to be at odds with each other. Our interest in coal 
gasification, in particular, is the fact that you can capture 
the carbon cost effectively and sequester it underground in 
geologic formations, thus reducing the global warming emissions 
from coal substantially.
    However, because of the long lifetime of carbon in our 
atmosphere, we need to get this technology, this carbon capture 
and disposal technology, out there as soon as possible, and we 
need incentives to do so. In addition, we strongly advocate for 
binding measures on global warming pollution.
    Reducing natural gas demand. As I said, this is an 
important issue to consider. However, we feel that, first and 
foremost, we need to consider energy efficiency. That's the 
cheapest, cleanest, most effective way to reduce our natural 
gas demand. Second, renewable energy is the best way to help 
supplement. Then we should turn to the issue of coal 
gasification, after we have addressed energy efficiency and 
renewable energy.
    Some can call coal ``clean.'' However, it is not likely 
ever to be a--the most clean option for energy production that 
we have. However, as I said, it appears inevitable that we will 
be using coal for some time to come. The good news is that with 
the right standards and incentives, it is possible to chart a 
future for coal that is compatible with protecting public 
health, preserving special places, and avoiding dangerous 
global warming.
    To address global warming, we have to get on a path quickly 
to start reducing our emissions for the long term. Any 
technologies that we start deploying today has to take this 
into account.
    Let's look specifically at coal gasification in the 
electricity sector. In this case, you can capture the carbon, 
and you can dispose of it in geological formations, and 
significantly reduce the global warming emissions, such that we 
could stay on a path to prevent dangerous impacts in the 
future. The other issue that has been brought up is using coal 
gasification to produce synthetic gas. We did a calculation. 
Remember, coal has about twice the amount of carbon content as 
natural gas. If you produce synthetic gas using coal, you are 
going to produce 2\1/2\ times the amount of carbon than you 
would if you just used synthetic gas. Now, if you capture the 
coal at the plant, you could reduce that substantially, yet 
you'd still be producing about 12 percent more carbon than just 
using natural gas. So, the issue here is: what is that natural 
gas going to be used for? And a second is: what are its 
lifecycle emissions, and is that compatible with stabilizing 
our climate and our atmospheric concentrations? That must be 
taken into account. We can't invest money in technologies that 
have lifetimes of 50-plus years and then say, 20 years down the 
line, ``We have to deal with our carbon emissions,'' and then 
have these sunk costs in these extremely expensive capital 
investments.
    Chemical products, for the most part, is the same issue. I 
believe that using coal gasification at a chemical plant, it 
would probably be mostly a wash, as far as the carbon emissions 
go, as long as you capture those carbon emissions. That is the 
critical point here. And, unfortunately, though, some mention 
of the fellow--my fellow witnesses made mention of the carbon 
capture. I would say perhaps not enough attention was put to 
that issue.
    Liquid fuels were discussed at last Monday's hearing, so I 
won't go into that. I will just say that creating a liquid fuel 
from coal, you produce twice as much carbon emissions as using 
gasoline. The transportation sector--we have to start reducing 
our emissions from the transportation sector significantly. 
Even capturing the carbon when you produce liquid fuel from 
coal, you'd still be--just about break even. And that's not a 
long-term solution.
    Finally, let me just turn quickly to the Energy Policy Act. 
There is the issue--and I'm glad to say, in it, they dealt with 
the issue of carbon-capture ready. Our concern, though, with 
the carbon-capture ready is, this is an extremely ill-defined 
term. What does it mean to have a plant that is carbon-capture 
ready? It means you have to put in equipment that separates the 
carbon out, that captures the carbon, and disposes of it. Does 
that mean you simply build an IGCC plant? Does that mean you 
build an IGCC plant with space for the capture equipment, or do 
you build it near a place to dispose the carbon? These are all 
questions that are not addressed by this term, and need to be 
addressed.
    I see my time is up, so I will stop here, and would be 
happy to answer any questions.
    Thank you.
    [The prepared statement of Dr. Herzog follows:]

   Prepared Statement of Antonia Herzog, Staff Scientist and Climate 
      Advocate, Climate Center, Natural Resources Defense Council

    Thank you for the opportunity to testify today on the subject of 
coal gasification technology. My name is Antonia Herzog. I am a staff 
scientist and climate advocate of the Climate Center at the Natural 
Resources Defense Council (NRDC). NRDC is a national, nonprofit 
organization of scientists, lawyers and environmental specialists 
dedicated to protecting public health and the environment. Founded in 
1970, NRDC has more than 1.2 million members and online activists 
nationwide, served from offices in New York, Washington, Los Angeles 
and San Francisco.
    One of the primary reasons that the electric power, chemical, and 
liquid fuels industries have become increasingly interested in coal 
gasification technology in the last several years is the volatility and 
high cost of both natural gas and oil. Coal has the advantages of being 
a cheap, abundant, and a domestic resource compared with oil and 
natural gas. However, the disadvantages of conventional coal use cannot 
be ignored. From underground accidents and mountain top removal mining, 
to collisions at coal train crossings, to air emissions of acidic, 
toxic, and heat-trapping pollution from coal combustion, to water 
pollution from coal mining and combustion wastes, the conventional coal 
fuel cycle is among the most environmentally destructive activities on 
earth.
    But we can do better with both production and use of coal. And 
because the world is likely to.continue to use significant amounts of 
coal for some time to come, we must do better. Energy efficiency 
remains the cheapest, cleanest, and fastest way to meet our energy and 
environmental challenges, while renewable energy is the fastest growing 
supply option. Increasing energy efficiency and expanding renewable 
energy supplies must continue to be the top priority, but we have the 
tools to make coal more compatible with protecting public health and 
the environment. With the right standards and incentives we can 
fundamentally transform the way coal is produced and used in the United 
States and around the world.
    In particular, coal use and climate protection do not need to be 
irreconcilable activities. While energy efficiency and greater use of 
renewable resources must remain core components of a comprehensive 
strategy to address global warming, development and use of technologies 
such as coal gasification in combination with carbon dioxide 
(CO2) capture and permanent disposal in geologic 
repositories could enhance our ability to avoid a dangerous build-up of 
this heat-trapping gas in the atmosphere while creating a future for 
continued coal use.
    However, because of the long lifetime of carbon dioxide in the 
atmosphere and the slow turnover of large energy systems we must act 
without delay to start deploying these technologies. Current government 
policies are inadequate to drive the private sector to invest in carbon 
capture and storage systems in the timeframe we need them. To 
accelerate the development of these systems and to create the market 
conditions for their use, we need to focus government funding more 
sharply on the most promising technologies. More importantly, we need 
to adopt reasonable binding measures to limit global warming emissions 
so that the private sector has a business rationale for prioritizing 
investment in this area.
    Congress is now considering proposals to gasify coal as a 
replacement for natural gas and oil (as discussed in testimony NRDC 
provided before this committee in the April 24th, 2006 hearing on 
``Coal Liquefaction and Gasification'').\1\ These proposals need to be 
evaluated in the context of the compelling need to reduce global 
warming emissions steadily and significantly, starting now and 
proceeding constantly throughout this century. Because today's coal 
mining and use also continues to impose a heavy toll on America's land, 
water, and air, damaging human health and the environment, it is also 
critical to examine the implications of a substantial coal gasification 
program on these values as well.
---------------------------------------------------------------------------
    \1\ David Hawkins, Testimony before the Senate Energy and Natural 
Resources Committee, ``Coal Liquefaction and Gasification'', April 
24th, 2006. http://docs.nrdc.org/globalwarming/glo--06042401a.pdf
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                      REDUCING NATURAL GAS DEMAND

    The nation's economy, our health and our quality of life depend on 
a reliable supply of affordable energy services. The most significant 
way in which we can achieve these national goals is to exploit the 
enormous scope to wring more services out of each unit of energy used 
and by aggressively promoting renewable resources. While coal 
gasification technology has been touted as the technology solution to 
supplement our natural gas supply and reduce our dependence on natural 
gas imports, the most effective way to lower natural gas demand, and 
prices, is to waste less. America needs to first invest in energy 
efficiency and conservation to reduce demand, and to second promote 
renewable energy alternatives to supplement supply. Gasified coal may 
have a role to play but in both the short-term and over the next two 
decades, efficiency and renewables are the lead actors in an effective 
strategy to moderate natural gas prices and balance our demand for 
natural gas with reasonable expectations of supply.
    We know that today's natural gas prices have had a particularly 
significant impact on the agricultural sector by raising the cost of 
making fertilizer among other products. We agree that effective steps 
should be taken to fix this problem. In our view a package of measures 
to increase the efficiency of current gas uses, substitution of 
renewable energy for other gas uses, and judicious use of coal 
gasification with CO2 capture and disposal would be the most 
effective program. With respect to the coal gasification component of 
this policy package, it is important to address and prevent the 
additional harmful impacts to land and water that would result if 
incremental coal production were carried out with current mining and 
production practices. As pointed out later in Appendix A, current 
practices are causing unacceptable and avoidable levels of damage to 
land, water and mining communities.
    Increasing energy efficiency is far-and-away the most cost-
effective way to reduce natural gas consumption, avoid emitting carbon 
dioxide and other damaging environmental impacts. Technologies range 
from efficient lighting, including emerging L.E.D. lamps, to advanced 
selective membranes which reduce industrial process energy needs. 
Critical national and state policies include appliance efficiency 
standards, performance-based tax incentives, utility-administered 
deployment programs, and innovative market transformation strategies 
that make more efficient designs standard industry practice.
    Conservation and efficiency measures such as these can have 
dramatic impacts in terms of price and savings.\2\ Moreover, all of 
these untapped gas efficiency ``resources'' will expand steadily, as a 
growing economy adds more opportunities to secure long-lived savings. 
California has a quarter century record of using comparable strategies 
to reduce both natural gas consumption and the accompanying utility 
bills. Recent studies commissioned by the Pacific Gas & Electric 
Company indicate that, by 2001, longstanding incentives and standards 
targeting natural gas equipment and use had cut statewide consumption 
for residential, commercial, and industrial purposes (excluding 
electric generation) by more than 20 percent.
---------------------------------------------------------------------------
    \2\ American Council for an Energy-Efficient Economy (ACEEE), Fall 
2004 Update on Natural Gas Markets, November 3, 2004. See also Consumer 
Federation of America, ``Responding to Turmoil in Natural Gas Markets: 
The Consumer Case for Aggressive Policies to Balance Supply and 
Demand,'' December 2004, pp. 28, 11 (``[V]igorous efforts to improve 
efficiency'' should be the first policy option pursued, because even 
small reductions in natural gas consumption can have a significant 
downward impact on prices.)
---------------------------------------------------------------------------
    Renewables can also play a key role in reducing natural gas prices. 
Adoption of a national renewable energy standard (RES) can 
significantly reduce the demand for natural gas, alleviating potential 
shortages. The Energy Information Administration (EIA) has found that a 
national 10 percent renewable energy standard could reduce gas 
consumption by 1.4 trillion cubic feet per year in 2020 compared to 
business as usual, or roughly 5 percent of annual demand.\3\
---------------------------------------------------------------------------
    \3\ EIA, Impacts of a 10-Percent Renewable Portfolio Standard, SR/
OIAF/2002-03, February 2002. EIA, Analysis of a 10-Percent Renewable 
Portfolio Standard, SR/OIAF/2003-01, May 2003. Union of Concerned 
Scientists, Clean Energy Blueprint: A Smarter National Energy Policy 
for Today and the Future, October 2001.
---------------------------------------------------------------------------
    Studies have consistently shown that reducing demand for natural 
gas by increasing renewable energy use will reduce natural gas prices. 
According to a report released by the U.S. Department of Energy's 
Lawrence Berkeley National Laboratory, ``studies generally show that 
each 1% reduction in national gas demand is likely to lead to a long-
term (effectively permanent) average reduction in wellhead gas prices 
of 0.8% to 2%. Reductions in wellhead prices will reduce wholesale and 
retail electricity rates and will also reduce residential, commercial, 
and industrial gas bills.'' \4\ EIA found that increasing renewable 
energy to 10 percent by 2020 would result in $4.9 billion cumulative 
present value savings for industrial gas consumers, $1.8 billion to 
commercial customers, and $2.4 billion to residential customers.\5\ EIA 
also found that renewable energy can also reduce electricity bills.\6\ 
Lower natural gas prices for electricity generators and other consumers 
offset the slightly higher cost of renewable electricity technology.\7\
---------------------------------------------------------------------------
    \4\ U.S. Department of Energy, Lawrence Berkeley National 
Laboratory, Easing the Natural Gas Crisis: Reducing Natural Gas Prices 
Through Increased Deployment of Renewable Energy and Energy Efficiency, 
January, 2005, p. 13.
    \5\ EIA, Impacts of a 10-Percent Renewable Portfolio Standard, SR/
OIAF/2002-03, February 2002.
    \6\ Id. at Figure 3.
    \7\ UCS, Renewable Energy Can Help Alleviate Natural Gas Crisis, 
June 2003, at 2.
---------------------------------------------------------------------------
    Implementing effective energy efficiency measures is the fastest 
and most cost effective approach to balancing natural gas demand and 
supply. Renewable energy provides a critical mid-term to long-term 
supplement. Analysis by the Union of Concerned Scientists found that a 
combined efficiency and renewable energy scenario could reduce gas use 
by 31 percent and natural gas prices by 27 percent compared to I 
business as usual in 2020.\8\
---------------------------------------------------------------------------
    \8\ UCS, Clean Energy Blueprint: A Smarter National Energy Policy 
for Today and the Future, October 2001.
---------------------------------------------------------------------------
    In contrast to these strategies, pursuing coal gasification 
implementation strategies that address only natural gas supply 
concerns, while ignoring impacts of coal, is a recipe for huge and 
costly mistakes. Fortunately, we have in our tool box energy resource 
options that can reduce natural gas demand and global warming emissions 
as well as protecting America's land, water, and air.

                     ENVIRONMENTAL IMPACTS OF COAL

    Some call coal ``clean.'' It is not and likely never will be 
compared to other energy options. Nonetheless, it appears inevitable 
that the U.S. and other countries will continue to rely heavily on coal 
for many years. The good news is that with the right standards and 
incentives it is possible to chart a future for coal that is compatible 
with protecting public health, preserving special places, and avoiding 
dangerous global warming. It may not be possible to make coal clean, 
but by transforming the way coal is produced and used, it is possible 
to make coal dramatically cleaner--and safer--than it is today.
Global Warming Pollution
    To avoid catastrophic global warming the U.S. and other nations 
will need to deploy energy resources that result in much lower releases 
of CO2 than today's use of oil, gas and coal. To keep global 
temperatures from rising to levels not seen since before the dawn of 
human civilization, the best expert opinion is that we need to get on a 
pathway now to allow us to cut global warming emissions by 60-80% from 
today's levels over the decades ahead. The technologies we choose to 
meet our future energy needs must have the potential to perform at 
these improved emission levels.
    Most serious climate scientists now warn that there is a very short 
window of time for beginning serious emission reductions if we are to 
avoid truly dangerous greenhouse gas reductions without severe economic 
impact. Delay makes the job harder. The National Academy of Sciences 
recently stated: ``Failure to implement significant reductions in net 
greenhouse gases will make the job much harder in the future--both in 
terms of stabilizing their atmospheric abundances and in terms of 
experiencing more significant impacts.'' \9\
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    \9\ National Academy of Sciences, Understanding and Responding to 
Climate Change: Highlights of National Academies Reports, p.16 (October 
2005), http://dels.nas.edu/dels/rpt_briefs/climate-changefinal.pdf.
---------------------------------------------------------------------------
    In short, a slow start means a crash finish--the longer emissions 
growth continues, the steeper and more disruptive the cuts required 
later. To prevent dangerous global warming we need to stabilize 
atmospheric concentration at or below 450 ppm, which would keep total 
warming below 2 degrees Celsius (3.6 degrees Fahrenheit). If we start 
soon, we can stay on the 450 ppm path with an annual emission reduction 
rate that gradually ramps up to about 2.4% per year. But if we delay a 
serious start by 10 years and continue emission growth at the business-
as-usual trajectory, the annual emission reduction rate required to 
stay on the 450 ppm pathway jumps almost 3-fold, to 6.9% per year. (See 
Figure 1.)9a Even if you do not accept today that the 450 
ppm path will be needed please consider this point. If we do not act to 
preserve our ability to get on this path we will foreclose the path not 
just for ourselves but for our children and their children. We are now 
going down a much riskier path and if we do not start reducing 
emissions soon neither we nor our children can turn back no matter how 
dangerous the path becomes.
---------------------------------------------------------------------------
    \9a\ Retained in committee files.
---------------------------------------------------------------------------
    In the past, some analysts have argued that the delay/crash action 
scenario is actually the cheaper course, because in the future 
(somehow) we will have developed breakthrough technologies. But it 
should be apparent that the crash reductions scenario is implausible 
for two reasons. First, reducing emissions by 6.9 percent per year 
would require deploying advanced low-emission technologies at least 
several times faster than conventional technologies have been deployed 
over recent decades. Second, the effort would require prematurely 
retiring billions of dollars in capital stock--high-emitting power 
plants, vehicles, etc.--that will be built or bought during the next 
10-20 years under in the absence of appropriate CO2 emission 
limits.
    It also goes without saying that U.S. leadership is critical. 
Preserving the 450 ppm pathway requires other developed countries to 
reduce emissions at similar rates, and requires the key developing 
countries to dramatically reduce and ultimately reverse their emissions 
growth. U.S. leadership can make that happen faster.
    To assess the global warming implications of a large coal 
gasification program we need to carefully examine the total life-cycle 
emissions associated with the end product, whether electricity, 
synthetic gas, liquid fuels or chemicals, and to assess if the relevant 
industry sector will meet the emission reductions required to be 
consistent with the ``green'' pathway presented in Figure 1.
            Electricity Sector
    More than 90 percent of the U.S. coal supply is used to generate 
electricity in some 600 coal-fired power plants scattered around the 
country, with most of the remainder used for process heat in heavy 
industrial and in steel production. Coal is used for power production 
in all regions of the country, with the Southeast, Midwest, and 
Mountain states most reliant on coal-fired power. Texas uses more coal 
than any other state, followed by Indiana, Illinois, Ohio, and 
Pennsylvania.\10\
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    \10\ http://www.eia.doe.gov/cneaf/coal/page/acr/table26.html
---------------------------------------------------------------------------
    About half of the U.S. electricity supply is generated using coal-
fired power plants. This share varies considerably from state to state, 
but even California, which uses very little coal to generate 
electricity within its borders, consumes a significant amount of 
electricity generated by coal in neighboring Arizona and Nevada, 
bringing coal's share of total electricity consumed in California to 20 
percent.\11\ National coal-fired capacity totals 330 billion watts 
(GW), with individual plants ranging in size from a few million watts 
(MW) to over 3000 MW. More than one-third of this capacity was built 
before 1970, and over 400 units built in the 1950s--with capacity 
equivalent to roughly 100 large modern plants (48 GW)--are still 
operating today.
---------------------------------------------------------------------------
    \11\ California Energy Commission, 2005. 2004 Net System Power 
Calculation (April.) Table 3: Gross System Power. http://
www.energy.ca.gov/2005publications/CEC-300-2005-004/CEC-300-2005-
004.PDF
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    The future of coal in the U.S. electric power sector is an 
uncertain one. The major cause of this uncertainty is the government's 
failure to define future requirements for limiting greenhouse gas 
emissions, especially carbon dioxide (CO2). Coal is the 
fossil fuel with the highest uncontrolled CO2 emission rate 
of any fuel and is responsible for 36. percent U.S. carbon dioxide 
emissions. Furthermore, coal power plants are expensive, long-lived 
investments. Key decision makers understand that the problem of global 
warming will need to be addressed within the time needed to recoup 
investments in power projects now in the planning stage. Since the 
status quo is unstable and future requirements for coal plants and 
other emission sources are inevitable but unclear, there will be 
increasing hesitation to commit the large amounts of capital required 
for new coal projects.
    Electricity production is the largest source of global warming 
pollution in the U.S. today. In contrast to nitrogen and sulfur oxide 
emissions, which have declined significantly in recent years as a 
result of Clean Air Act standards, CO2 emissions from power 
plants have increased by 27 percent since 1990. Any solution to global 
warming must include large reductions from the electric sector. Energy 
efficiency and renewable energy are well-known low-carbon methods that 
are essential to any climate protection strategy. But technology exists 
to create a more sustainable path for continued coal use in the 
electricity sector as well. Coal gasification can be compatible with 
significantly reducing global warming emissions in the electric sector 
if it replaces conventional coal combustion technologies, directly 
produces electricity in an integrated manner, and most importantly 
captures and disposes of the carbon in geologic formations. IGCC 
technology without CO2 capture and disposal achieves only 
modest reductions in CO2 emissions compared to conventional 
coal plants.
    A coal integrated gasification combined cycle (IGCC) power plant 
with carbon capture and disposal can capture up to 90 percent of its 
emissions, thereby being part of the global warming solution. In 
addition to enabling lower-cost CO2 capture, gasification 
technology has very low emissions of most conventional pollutants and 
can achieve high levels of mercury control with low-cost carbon-bed 
systems. However, it still does not address the other environmental 
impacts from coal production and transportation discussed in more 
detail in Appendix A.11a
---------------------------------------------------------------------------
    \11a\ Appendix A has been retained in committee files.
---------------------------------------------------------------------------
    The electric power industry has been slow to take up gasification 
technology but two commercial-scale units are operating in the U.S.--in 
Indiana and Florida. The Florida unit, owned by TECO, is reported by 
the company to be the most reliable and economic unit on its system. 
Two coal-based power companies, AEP and Cinergy, have announced their 
intention to build coal gasification units. BP also has announced plans 
to build a petroleum coke gasification plant that will capture and 
sequester CO2.
            Synthetic Gas
    Another area that has received interest is coal gasification to 
produce synthetic natural gas as a direct method of supplementing our 
natural gas supply from domestic resources. However, without 
CO2 capture and disposal this process results in more than 
twice as much CO2 per 1000 cubic feet of natural gas 
consumed compared to conventional resources.\12\ From a global warming 
perspective this is unacceptable. With capture and disposal the 
CO2 emissions can be substantially reduced, but still remain 
12 percent higher than natural gas.
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    \12\ The National Coal Council, ``Coal: America's Energy Future,'' 
March 22, 2006. This report actually assumes a less efficient coal to 
synthetic gas conversion process of 50% leading to three times as much 
CO2 per 1000 cubic feet of natural gas consumed compared to 
conventional resources.
---------------------------------------------------------------------------
    In Beulah, North Dakota the Basin Electric owned Dakota 
Gasification Company's Great Plains Synfuels Plant is a 900MW facility 
which gasifies coal to produce synthetic ``natural'' gas. It can 
produce a 150 million cubic feet of synthetic gas per day and 11,000 
tons of CO2 per day. However, it no longer releases all of 
its CO2 to the atmosphere, but captures most of it and pipes 
it 200 miles to an oil field near Weyburn, Saskatchewan. There the 
CO2 is pumped underground into an aging oil field to recover 
more oil. EnCana, operator of this oil field, pays $2.5 million per 
month for the CO2. They expect to sequester 20 million tons 
of CO2 over the lifetime of this injection project.
    A potential use for coal-produced synthetic gas would be to burn it 
in a gas turbine at another site for electricity generation. This 
approach would result in substantially higher CO2 emissions 
than producing electricity in an integrated system at the coal 
gasification plant with CO2 capture at the site (i.e., in an 
IGCC plant with carbon capture and disposal). Coal produced synthetic 
natural gas could also be used directly for home heating. As a 
distributed source of emissions the CO2 would be prohibitive 
to capture with known technology.
    Before producing synthetic pipeline gas from coal a careful 
assessment of the full fuel cycle emission implications and the 
emission reductions that are required from that sector must be carried 
out before decisions are made to invest in these systems.
            Chemical Products
    The chemical industry has also been looking carefully at coal 
gasification technology as a way to replace the natural gas feedstock 
used in chemical production. The motivator has been the escalating and 
volatile costs of natural gas in the last few years. A notable example 
in the U.S. of such a use is the Tennessee Eastman plant, which has 
been operating for more than 20 years using coal instead of natural gas 
to make chemicals and industrial feedstocks. If natural gas is replaced 
by coal gasification as a feedstock for the chemical industry, first 
and foremost CO2 capture and disposal must be an integral 
part of such plants. In this case, the net global warming emissions 
will change relatively little from this sector. However, before such a 
transformation occurs a careful analysis of the life cycle emissions 
needs to be carried out along with an assessment of how future 
emissions reductions from this sector can be most effectively 
accomplished.
            Liquid Fuels
    The issue of converting coal into a liquid fuel was explored in 
detail in testimony NRDC provided before this committee in the April 
24th, 2006 hearing on ``Coal Liquefaction and Gasification''.\13\ To 
briefly reiterate, to assess the global warming implications of a large 
coal-to-liquids program we need to examine the total life-cycle or 
``well-to-wheel'' emissions of these new fuels. Coal contains about 20 
percent more carbon per unit of energy compared to petroleum. When coal 
is converted to liquid fuels, two streams of CO2 are 
produced: one at the coal-to-liquids production plant and the second 
from the exhausts of the vehicles that burn the fuel. With the 
technology in hand today and on the horizon it is difficult to see how 
a large coal-to-liquids program can be compatible with the low-002-
emitting transportation system we need to design to prevent global 
warming.
---------------------------------------------------------------------------
    \13\ David Hawkins, Testimony before the Senate Energy and Natural 
Resources Committee, ``Coal Liquefaction and Gasification'', April 
24th, 2006. http://docs.nrdc.org/globalwarming/glo_06042401a.pdf
---------------------------------------------------------------------------
    Based on available information about coal-to-liquids plants being 
proposed, the total well to wheels CO2 emissions from such 
plants would be nearly twice as high as using crude oil, if the 
CO2 from the coal-to-liquids plant is released to the 
atmosphere.\14\ Obviously, introducing a new fuel system with double 
the CO2 emissions of today's crude oil system would conflict 
with the need to reduce global warming emissions. If the CO2 
from coal-to-liquids plants is captured, then well-to-wheels 
CO2 emissions would be reduced but would still be higher 
than emissions from today's crude oil system.
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    \14\ Calculated well to wheel CO, emissions for coal-based 
``Fischer-Tropsch'' are about 1.8 greater than producing and consuming 
gasoline or diesel fuel from crude oil. If the coal-to-liquids plant 
makes electricity as well, the relative emissions from the liquid fuels 
depends on the amount of electricity produced and what is assumed about 
the emissions of from an alternative source of electricity.
---------------------------------------------------------------------------
    This comparison indicates that using coal to produce a significant 
amount of liquids for transportation fuel would not be compatible with 
the need to develop a low-CO2 emitting transportation sector 
unless technologies are developed to significantly reduce emissions 
from the overall process. But here one confronts the unavoidable fact 
that the liquid fuel from coal contains the same amount of carbon as is 
in gasoline or diesel made from crude. Thus, the potential for 
achieving significant CO2 emission reductions compared to 
crude is inherently limited. This means that using a significant amount 
of coal to make liquid fuel for transportation needs would make the 
task of achieving any given level of global warming emission reduction 
much more difficult. Proceeding with coal-to-liquids plants now could 
leave those investments stranded or impose unnecessarily high abatement 
costs on the economy if the plants continue to operate.
            CO2 Capture and Disposal
    Methods to capture CO2 from industrial gas streams have 
been in use for decades. In the U.S., for example, they are used to 
separate CO2 from ``sour gas'' at natural gas processing 
plants and are even in use at a few coal-fired power plants to produce 
CO2 for sale to the food and beverage industries. As 
previously mentioned, in North Dakota a large coal gasification plant 
captures CO2 and ships it by pipeline to an oil field in 
Saskatchewan, where it is injected to produce additional oil. In 
Wyoming, a large gas processing plant captures CO2 for sale 
to oil field operators in that state and in Colorado. Smaller plants in 
Texas do the same thing to serve oil fields in the Permian Basin.
    Once captured, the CO2 must be disposed of and the 
currently viable approach is to inject the CO2 into deep 
geologic formations that are capable of permanently retaining it. 
Geologic injection of CO2 has been underway in the U.S. for 
a couple of decades as a method for producing additional oil from 
declining fields. Today, oil companies inject about 30 million tons 
annually into fields in the Permian Basin, Wyoming, Colorado and other 
states.
    Because industrial sources can emit CO2 for free under 
current U.S. policy, most of the injected CO2 is supplied 
from natural CO2 reservoirs, rather than being captured from 
emission sources. Ironically, due to the lack of emission limits and 
the limited number of natural CO2 fields, a CO2 
supply shortage is currently constraining enhanced oil recovery from 
existing fields. There is, of course, a huge supply of CO2 
from power plants and other sources that would become available to 
supply this market, but that will not happen as long as CO2 
can be emitted at no cost.
    Such enhanced oil recovery (EOR) operations are regulated to 
prevent releases that might endanger public health or safety but they 
are not monitored with any techniques that would be capable of 
detecting smaller leak rates. Small leak rates might pose no risk to 
the local surroundings but over time could undercut the effectiveness 
of geologic storage as a CO2 control technique. Especially 
in EOR operations, the most likely pathways for leakage would be 
through existing wells penetrating the injection zone.
    Much of the injected CO2 is also brought back to the 
surface with the oil produced by this technique. That CO2 is 
typically reinjected to recover additional oil, but when oil operations 
are completed it may be necessary to inject the CO2 into a 
deeper geologic formation to ensure permanent storage.
    In addition to these EOR operations, CO2 is being 
injected in large amounts in several other projects around the world. 
The oldest of these involves injection of about 1 million tons per year 
of CO2 from a natural gas platform into a geologic formation 
beneath the sea bed off the coast of Norway. The company decided to 
inject the CO2 rather than vent it to avoid paying an 
emission charge adopted by the Norwegian government--a clear example of 
the ability of emission policies to produce the deployment of this 
technology. The Norwegian operation is intensively monitored and the 
results from over seven years of operation indicate the CO2 
is not migrating in a manner that would create a risk of leakage. Other 
large-scale carefully monitored operations are underway at the Weyburn 
oil field in Saskatchewan and the In Salah natural gas field in 
Algeria.
    While additional experience with large-scale injection in various 
geologic formations is needed, we believe enough is known to expand 
these activities substantially under careful procedures for site 
selection, operating requirements and monitoring programs. The 
imperative of avoiding further carbon lock-in due to construction of 
conventional coal-fired power plants and the capabilities of 
CO2 capture and storage technologies today warrant policies 
to deploy these methods at coal gasification plants without further 
delay.
Conventional Air Pollution
    Dramatic reductions in power plant emissions of criteria 
pollutants, toxic compounds, and global warming emissions are essential 
if coal is to remain a viable energy resource for the 21st Century. 
Such reductions are achievable in coal gasification plants. In 
particular, integrated gasification combined cycle (IGCC) systems 
enable cost-effective advanced pollution controls that can yield 
extremely low criteria pollutant and mercury emission rates and 
facilitates carbon dioxide capture and geologic disposal. Gasifying 
coal at high pressure facilitates removal of pollutants that would 
otherwise be released into the air such that these pollutant emissions 
are well below those from conventional pulverized coal power plants 
with post combustion cleanup. These technologies will not be widely 
employed, however, without a sustained market driver, which requires 
vigorous enforcement of clean air standards, new limits on global 
warming emissions, and market oriented incentives to deploy carbon 
capture and disposal.
Mining, Processing and Transporting Coal
    The impacts of mining, processing, and transporting 1.1 billion 
tons of coal today on health, landscapes, and water are large. To 
understand the implications of continuing our current level of as well 
as expanding coal production, it is important to have a detailed 
understanding of the impacts from today's level of coal production. A 
summary is included in Appendix A and was also given in testimony NRDC 
submitted on April 24th, 2006 to the Senate Energy and Natural 
Resources full committee hearing on ``Coal Liquefaction and 
Gasification.'' \15\ It is clear that we must find more effective ways 
to reduce the impacts of mining, processing and transporting coal 
before we follow a path that would result in even larger amounts of 
coal production and transportation.
---------------------------------------------------------------------------
    \15\ David Hawkins, Testimony before the Senate Energy and Natural 
Resources Committee, ``Coal Liquefaction and Gasification'', April 
24th, 2006. http://docs.nrdc.org/globalwarming/glo_06042401a.pdf
---------------------------------------------------------------------------
     ``carbon capture ready'' and the ``energy policy act of 2005''
    Among the various environmental concerns associated with coal use, 
the global warming emissions are particularly critical as coal fired 
power generation emits more carbon dioxide per unit of energy than any 
other power generating process. It is clear that for coal to remain a 
major source of electricity generation within a carbon constrained 
world, carbon capture and disposal technologies will have to be 
deployed in conjunction coal fired power plants.
    The three required elements of a coal-based CO2 capture 
and disposal (CCD) system have all been demonstrated at commercial 
scale in numerous projects around the world. But there is large 
potential for optimization of each element to bring down costs and 
improve efficiency. In addition, the experience with large scale 
injection of CO2 into geologic formations is still limited.
    For coal, the first element of a CCD system is a method to convert 
coal into useful energy that produces a waste stream that makes 
CO2 capture relatively inexpensive. The method for doing 
this that is commercially demonstrated is through gasification of coal. 
In contrast to the conventional coal combustion methods used in 
electric power generation, gasification converts the coal under 
pressure and temperature to produce a smaller gas stream with higher 
CO2 concentrations. This approach significantly reduces the 
cost and energy required to capture CO2.
    In the ``Energy Policy Act of 2005'' (EPACT05), while there are 
myriad incentives for deploying coal gasification technology, there are 
no requirements to include CO2 capture and disposal. 
Scattered throughout the Act is language referring to the capability of 
coal gasification technology to capture its carbon emissions or to be 
``carbon capture ready''. However, nothing requires the facilities to 
actually capture and dispose of their CO2 emissions. Several 
examples are the following:

   Title IV--Coal--section 413(b)(3) Western Integrated Coal 
        Gasification Demonstration Project: ``Shall be capable of 
        removing and sequestering carbon dioxide emissions.''
   Title VIII--Hydrogen--section 805(e)(1)(A) ``Fossil fuel, 
        which may include carbon capture and sequestration;''
   Title XIII--Energy Policy Tax Incentives--section 1307(b) 
        ``Sec. 48A. (c) Definitions (5) GREENHOUSE GAS CAPTURE 
        CAPABILITY--The term `greenhouse gas capture capability' means 
        an integrated gasification combined cycle technology facility 
        capable of adding components which can capture, separate on a 
        long-term basis, isolate, remove, and sequester greenhouse 
        gases which result from the generation of electricity.''
                  ``Sec. 48B. (c) Definitions (5) CARBON CAPTURE 
                CAPABILITY--The term `carbon capture capability' means 
                a gasification plant design which is determined by the 
                Secretary to reflect reasonable consideration for, and 
                be capable of, accommodating the equipment likely to be 
                necessary to capture carbon dioxide from the gaseous 
                stream, for later use or sequestration, which would 
                otherwise be emitted in the flue gas from a project 
                which uses a nonrenewable fuel.''
   Title XVII--Incentives for Innovative.Technologies--Section 
        1703(c)(1)(A)(ii) ``that have a design that is determined by 
        the Secretary to be capable of accommodating the equipment 
        likely to be necessary to capture the carbon dioxide that would 
        otherwise be emitted in flue gas from the plant;''

    The issue I would like to address here is the definition of 
``carbon capture ready.'' Adding carbon capture capabilities to a coal 
gasification power plant is not a simple modification.\16\ Without any 
current regulatory or economic incentives for these facilities to 
capture and dispose of their carbon emissions the extent of the capture 
modifications that will be incorporated into the gasification 
facilities remains extremely unclear. I would, in fact, argue that due 
to the vagueness of this term the result will be a ``race to the 
bottom'', a minimal effort to incorporate the necessary design elements 
and equipment that would allow coal gasification plants to qualify for 
EPACT05 incentives.
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    \16\ Jennie Stephens, ``Coupling CO2 capture and Storage 
with Coal Gasification: Defining ``Sequestration-Ready'' IGCC'', BCSIA 
Discussion Paper 2005-09, Energy technology Innovation Project, Kennedy 
School of Government, Harvard University, 2005.
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    What are the required technical details associated with coupling 
coal gasification plants with carbon capture and disposal? Carbon 
capture in a coal gasification plant occurs after the coal gasification 
process. I will focus on the case for electricity generation (an IGCC 
plant) where the syngas produced then enters a gas turbine. It is at 
this stage that the chemical process can be inserted to separate and 
capture the CO2 and other pollutants from the syngas. Once 
the CO2 is separated it can be transported to a disposal 
location.
    In addition to adding the CO2 separation and capture 
equipment, changes in other components are also necessary for 
electricity generation case. The removal of CO2 prior to 
combustion in the turbine alters the composition of the gas to be 
burned, increasing the hydrogen content, which may affect the design or 
operational requirements of the turbine. In addition, the 
CO2 capture process may alter the optimal design of the 
desulphurization and other gas clean-up processes. For these reasons, 
an IGCC plant built without consideration for CO2 capture 
technology designed to produce power at a minimum cost and maximum 
efficiency will be significantly different than an IGCC plant designed 
to incorporate CO2 capture technology.
    ``Three major technological components need to be added to a basic 
IGCC plant to allow for separation and capture of the CO2: 
(1) the shift reactor to convert the CO in the syngas to 
CO2, (2) the process to separate the CO2 from the 
rest of the gas stream, and (3) a compressor to reduce the volume of 
separated CO2 before it can be transported.'' \17\ 
Furthermore, other components will require modification, as previously 
mentioned, including the gas turbine that will have to be capable of 
operating with a hydrogen enriched gas stream, the timing of the 
sulphur removal process, plus some scaling up to accommodate the larger 
quantities of coal needed to generate the same amount of power.
---------------------------------------------------------------------------
    \17\ Ibid.
---------------------------------------------------------------------------
    A further consideration is the CO2 transportation and 
disposal. Once the CO2 is captured and compressed at the 
plant it must be transported and injected into an underground geologic 
formation. Therefore, the location of the plant can also become a 
significant factor in the ease of transformation.
    What should be clear from this listing of requirements for 
integrating capture and disposal of CO2 into an existing 
IGCC plant is that the term ``carbon capture ready'' could encompass a 
whole host of definitions. Does it simply mean that one builds an IGCC 
plant? Does it mean that you leave space in the design for separation, 
capture and compression equipment? Does it mean you include the 
appropriate turbine to burn a high H2 gas stream? Does it mean you 
locate the plant within proximity to a geologic reservoir where the 
CO2 can be disposed of? The list and variations of the 
possibilities could go on and on, calling into question whether the 
term ``carbon capture ready `` has any real meaning.
    The likely result is that companies when taking advantage of the 
coal gasification incentives provided in the ``Energy Policy Act of 
2005'' will follow the least cost option, i.e., build an IGCC plant 
with little or no design elements necessary for the future integration 
of CO2 capture and disposal--unless there is a clear policy 
to reduce CO2 emissions or if it is required that they 
include all the necessary equipment to capture their CO2.
    NRDC strongly advocates that all government funds that leverage the 
building of coal gasification plants should only go to those facilities 
that actually capture their CO2. Subsidizing gasification by 
itself wastes taxpayers' money by subsidizing the wrong thing. 
Gasification is commercial and needs no subsidy but capture and storage 
is the primary policy objective and is likely to require subsidies 
pending adoption of CO2 emission control requirements.
    The first proposed coal gasification plant that will capture and 
dispose of its CO2 was recently announced on February 10, 
2006 by BP and Edison Mission Group. The plant will be built in 
Southern California and its CO2 emissions will be pipelined 
to an oil field nearby and injected into the ground to recover domestic 
oil. BP's proposal shows the technologies are available now to cut 
global warming pollution and that integrated IGCC with CO2 
capture and disposal are commercially feasible.

                            THE PATH FORWARD

    The impacts that a large coal gasification program could have on 
global warming pollution, conventional air pollution and environmental 
damage resulting from the mining, processing and transportation of the 
coal are substantial. Before deciding whether to invest scores, perhaps 
hundreds of billions of dollars in deploying this technology, we must 
have a program to manage our global warming pollution and other coal 
related impacts. Otherwise we will not be developing and deploying an 
optimal energy system.
    One of the primary motivators for moving toward coal gasification 
technologies has been to reduce natural gas prices. Fortunately, the 
U.S. can have a robust and effective program to reduce natural gas 
demand, and therefore prices, without rushing to embrace coal 
gasification technologies. A combination of efficiency and renewables 
can reduce our natural gas demand more quickly and more cleanly.
    Implementing effective energy efficiency measures is the fastest 
and most cost effective approach to reducing natural gas demand. 
Efficiency standards, performance-based tax incentives, utility-
administered deployment programs, and innovative market transformation 
strategies will bring energy efficient technologies to market and make 
efficient designs standard industry practice.
    Renewable energy provides a critical mid-term to long-term 
supplement to natural gas use. Potential renewable resources in the 
U.S. are significant and renewable electricity generation is expanding 
rapidly, with wind and biomass currently offering the most cost-
effective power in both countries. Some 20 U.S. states have adopted 
renewable portfolio standards requiring electricity providers to obtain 
a minimum portion of their portfolio from renewable resources. Federal 
tax incentives have also played an important role, particularly for 
wind.
    With current coal (and oil) consumption trends, we are headed for a 
doubling of CO2 concentrations by mid-century if we don't 
redirect energy investments away from carbon based fuels and toward new 
climate friendly energy technologies.
    We have to accelerate the progress underway and adopt policies in 
the next few years to turn the corner on our global warming emissions, 
if we are to avoid locking ourselves and future generations into a 
dangerously disrupted climate. Scientists are very concerned that we 
are very near this threshold now. Most say we must keep atmosphere 
concentrations of CO2 below 450 parts per million, which 
would keep total warming below 2 degrees Celsius (3.6 degrees 
Fahrenheit). Beyond this point we risk severe impacts, including the 
irreversible collapse of the Greenland Ice Sheet and dramatic sea level 
rise. With CO2 concentrations now rising at a rate of 1.5 to 
2 parts per million per year, we will pass the 450ppm threshold within 
two or three decades unless we change course soon.
    In the United States, a national program to limit carbon dioxide 
emissions must be enacted soon to create the market incentives 
necessary to shift investment into the least-polluting energy 
technologies on the scale and timetable that is needed. There is 
growing agreement between business and policy experts that quantifiable 
and enforceable limits on global warming emissions are needed and 
inevitable. To ensure the most cost-effective reductions are made, 
these limits can then be allocated to major pollution sources and 
traded between companies, as is currently the practice with sulfur 
emissions that cause acid rain. Targeted energy efficiency and 
renewable energy policies are critical to achieving CO2 
limits at the lowest possible cost, but they are no substitute for 
explicit caps on emissions.
    A coal integrated gasification combined cycle (IGCC) power plant 
with carbon capture and disposal can also be part of a sustainable path 
that reduces both natural gas demand as well as global warming 
emissions in the electricity sector. Methods to capture CO2 
from coal gasification plants are commercially demonstrated, as is the 
injection of CO2 into geologic formations for disposal. On 
the other hand, coal gasification to produce a significant amount of 
liquids for transportation fuel would not be compatible with the need 
to develop a low-CO2 emitting transportation sector. 
Finally, gasifying coal to produce synthetic pipeline gas or chemical 
products needs a careful assessment of the full life cycle emission 
implications and the emission reductions that are required from those 
sectors before decisions are made to invest in these systems.
    In the absence of a program that requires limits on CO2 
emissions IGCC systems with carbon capture and disposal will not be 
brought to market in time. We need to combine CO2 limits 
with financial incentives to start building these integrated plants 
now, because industry is already building and designing the power 
plants that we will rely on for the next 40-80 years.
    To reduce our natural gas demand we should follow a simple rule: 
start with the measures that will produce the quickest, cleanest and 
least expensive reductions in natural gas use; measures that will put 
us on track to achieve the reductions in global warming emissions we 
need to protect the climate. If we are thoughtful about the actions we 
take, our country can pursue an energy path that enhances our security, 
our economy, and our environment.

    Senator Alexander. Thank you, Dr. Herzog.
    And thanks to each of you for your comments. We know you 
have a lot to say, and you've said it in your statements, which 
we appreciate. And I thank you for summarizing it.
    Mr. Ferguson, you said that projects eligible for the tax 
credit--and I guess also for the loan guarantees--you suggested 
ought to be of a commercial scale. How do you define 
``commercial scale''?
    Mr. Ferguson. ``Commercial scale'' would be something that 
would be competitive in whichever sector--if--in the case of 
the chemical sector, a global-scale facility that is going to 
be globally competitive. These are typically, in the case of a 
powerplant, at least 500 megawatts in size; in the case of a 
chemical plant, we're talking about hundreds of millions of 
pounds. Typically, demonstration facilities are in the tens of 
millions of pounds, in, you know, very small quantities. So, I 
guess that's the kind of distinction I was talking about.
    Senator Alexander. Well, we're talking about an industrial 
gasification plant. Can you put a range of a dollar figure on 
it, to give us some idea of----
    Mr. Ferguson. We believe that a scale facility is on the 
order of half a billion dollars, $500 million, probably upwards 
of $750 million would be the kinds of things that we'd be 
looking at.
    Senator Alexander. You mentioned, and Mr. Boycott also 
mentioned, that the guidance you'd received so far from 
Treasury and Energy isn't sufficient to permit applicants to 
make the best possible application by June 30. Mr. Garman 
seemed to think that that was moving pretty well. What 
specific--there's a little polarity--advice would you have for 
the departments?
    Mr. Ferguson. The questions that have been referred to IRS 
and Treasury seem to be the ones that are the most troublesome. 
The dialogue with DOE has been pretty good, but there have been 
a number of questions that have been referred to the IRS, on 
the Treasury side of the house, and we have not heard answers, 
and we can't respond fully until we hear those answers.
    Senator Alexander. How many employees does Eastman 
Chemicals have today?
    Mr. Ferguson. Twelve thousand worldwide, 7,500 in the 
Tennessee facility, where we gasify coal.
    Senator Alexander. And how many employees did you have in 
the Tennessee facility 5-10 years ago?
    Mr. Ferguson. Probably on the order of 20,000.
    Senator Alexander. And what difference has the price of 
natural gas made in the smaller number of employees in the 
Tennessee facility?
    Mr. Ferguson. Like other companies of our kind, we've had 
to diversity our populations and our production around the 
world so that we can be competitive. And it certainly has 
helped to increase the numbers there.
    Senator Alexander. You're talking about a major decision 
coming up which might have to do with a number of jobs. Is it 
possible to produce enough synthetic gas from coal to 
substitute for natural gas, and to do it economically enough so 
that chemical jobs can stay in Tennessee or in the United 
States and not go to India and China?
    Mr. Ferguson. Absolutely, or I wouldn't be here, Senator. 
That's the choice that we make.
    Senator Alexander. Are you convinced that synthetically 
produced gas for, in your case, feedstocks is competitive? And, 
if it is, how would you describe what the price levels are to 
make it competitive?
    Mr. Ferguson. We have been doing this, as I said, since 
1983, going head to head with the biggest chemical companies in 
the world, like Dow and DuPont, Rohn and Haas, and BASF, and 
all of them. We judge that the typical price arbitrage between 
coal and gas during more normal times is about $1-a-million Btu 
for coal, and more like $3-a-million Btu for gas. And we're 
competing successfully at that level. When the arbitrage is 
wider between those two, of course, it favors coal.
    Senator Alexander. We make a lot of speeches around here 
about outsourcing jobs, jobs going overseas, and I'm constantly 
reminded that, if I'm not mistaken, we have, or had, about 1 
million chemical jobs, jobs in the chemical industry in the 
United States. They're mostly high-paying jobs, blue-collar/
white-collar jobs, the kinds that support families. And it is 
sobering to hear repeated the facts which we've often heard, 
that there are 120 new chemical plants scheduled to be built 
around the world, one of them in the United States. 
Consequences of that are significant, not just in upper east 
Tennessee, where Eastman has been there as long as the 
mountains, it seems, but to our entire country. And it seems to 
me that making gas from coal and other products is one very 
promising method for that.
    My time is up. Let me go to Senator Thomas.
    Senator Thomas. Thank you.
    Mr. Douglas, you produce what in your business? What do you 
produce?
    Mr. Douglas. We produce synthetic gas.
    Senator Thomas. From----
    Mr. Douglas. From coal.
    Senator Thomas. Okay.
    Mr. Douglas. We can also use a portion of petcoke. We can 
use MSW. But it is primarily from coal.
    Senator Thomas. If you're doing that, what is it that you 
need to do differently? What's going to change the world here?
    Mr. Douglas. What's going to change the world is widespread 
acceptance of the concept of coal gasification. To move 
industrial customers from a comfort zone of natural gas is a 
very, very large step for customers. It's not something that 
they take lightly when they look at a technology that, from--
maybe not from my viewpoint, but from theirs, is a new 
technology. It's a change. It's a paradigm shift for them.
    Senator Thomas. No question. What does the product that you 
sell cost, compared to natural gas produced otherwise?
    Mr. Douglas. In today's market--and I think the Senator was 
talking, earlier, about $7 gas--in today's market, we're going 
to be about a $1.50 under that.
    Senator Thomas. Really?
    Mr. Douglas. Yes. Understand that our technology, our 
process, is--if I were to make an analogy, when Senator Dorgan 
was speaking earlier, he was talking about the project in North 
Dakota--it would be analogous to say that our process is a 
newer version of that process, a more modern version of that 
process. But it is a proven process. I mean, we're not trying 
to introduce things that don't already exist in other parts of 
the world. So, in that sense, it's quite tried and true.
    Senator Thomas. Mr. Boycott, you mentioned running short of 
gas in Alaska. Is that right?
    Mr. Boycott. That's correct.
    Senator Thomas. Why are we building a pipeline from Alaska 
to the United States?
    Mr. Boycott. Well, the gas that we are dependent on is the 
Cook Inlet gas, and we're--the pipeline we're discussing is 
regarding North Slope gas. And we don't have access to that 
gas. There's on infrastructure to bring that gas to market. 
It's also, if you consider the timing of that pipeline, really 
not a solution for our production facility, because I believe 
the earliest we would consider a spur line into the Anchorage 
Bowl would be about 2016----
    Senator Thomas. I see.
    Mr. Boycott [continuing]. Somewhere in that neighborhood. 
And it's not realistic for us to expect that we could get gas 
contracts to support our business.
    Senator Thomas. What's the production area in Alaska on 
coal? Are you doing a good deal of that?
    Mr. Boycott. Yeah, we have one coal mine in Alaska that's 
currently operating, that's operated by Usibelli Coal mine in 
Healy, Alaska. Usibelli has been our partner in the development 
of this project. And we are looking to open a new mine in 
Beluga, which is just----
    Senator Thomas. Are there adequate resources of coal?
    Mr. Boycott. There is. Estimates are as much as 100 years 
of coal supply for a project of this magnitude.
    Senator Thomas. Open-pit mines or underground?
    Mr. Boycott. Open-pit.
    Senator Thomas. Open-pit? Hmm.
    Mr. Bruce, you're producing ethanol, is that right?
    Mr. Bruce. Correct.
    Senator Thomas. How does what you're doing compete with the 
other sources of ethanol, in terms of price and capacity?
    Mr. Bruce. In terms of pricing?
    Senator Thomas. Yes.
    Mr. Bruce. I think that we would be very competitive. I 
think we would be under the current costs of the farmers, for 
example, or any chemical catalytic process.
    The ingredient in our process which makes it unique is the 
fact that we biologically, through a natural bacteria, convert 
the synthesis gas into ethanol. That's a very important point. 
It's not that--there's no chemical catalytic reaction going on. 
It's a biological one.
    Senator Thomas. What do you do with the sulfur and mercury 
that's removed?
    Mr. Bruce. Well, we scrub them out. We have to clean the 
gas after it's gasified, we scrub it, and we clean out those 
impurities at that time. In our process, by the way, we also 
cool that gas. And when we cool it, we create steam. That steam 
can be used to create a byproduct of electric power. But we 
scrub it and then introduce it to the microorganism that 
converts it into ethanol.
    Senator Thomas. Dr. Herzog, the Under Secretary said IGCC 
technologies would double the efficiency of our current fleet 
of coal plants. What would the corresponding reduction in 
carbon, sulfur, and mercury, if the current supply were 
generated by ICC technologies that are now available?
    Dr. Herzog. If the conventional coal plants were replaced 
with IGC coal gasification technology, IGCC is slightly more 
efficient than conventional coal, the current conventional 
coal. The older plants, it's much more efficient. Exactly what 
the overall efficiency improvement is, I don't know off the top 
of my head, though I could certainly figure that out. The 
issue, though, is that it wouldn't substantially reduce our 
carbon emissions, and the only way to do that would be to 
capture the carbon, but you can do that much more easily and 
cost effectively from the coal gasification plants.
    Senator Thomas. Okay, thank you.
    Senator Alexander. Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    Mr. Boycott, I want to personally welcome you. I know 
you've made the long trek out a couple of different times to 
speak to the Agrium project, and I appreciate you coming and 
providing the testimony today. I think it is an opportunity for 
us in the State of Alaska, you know, to develop some very 
substantial coal resources in the State, to provide for an 
energy source for south central that needs it in a very 
pressing way, and to provide for the continuing employment of 
those in our only manufacturing industry there in the area. So, 
I appreciate the energy and commitment that you and others have 
made to this project.
    Now, I know that you heard Secretary Garman, just before he 
concluded his remarks. He said he was going to be listening 
attentively to this next panel to see what it was that you cite 
specifically that you may need, so that, if it's necessary, 
they're able to change things, or tweak things. And you 
specifically said that when it comes to the implementation of 
the loan guarantees, when it comes to implementation of the tax 
credits, you needed clarity in implementation--you need 
definition, clarity, and, I think, simplicity was the word that 
you used. What, specifically, does Agrium need to be able to 
take advantage of the tax credits, the loan guarantees? You've 
mentioned both of them will be key to the success of moving 
this project forward. What do you need from Secretary Garman 
right now?
    Mr. Boycott. I'll speak to the two, individually. And, 
thank you.
    Respecting the tax credits--we are concerned that the 
timing of our project is slightly out of step, that the June 
deadline--and Secretary Garman, I think, covered it very 
effectively--that the June deadline may put us somewhat at a 
disadvantage in having the sufficient project definition to 
compete for those opportunities. And so, specifically to that, 
we're looking through the flexibility to work with the 
Department and ensure that our opportunity is cast in a fair 
light.
    Relative to the loan guarantees, our concern there is a 
high level of complexity and basically a risk-elimination or 
risk-minimization strategy, as opposed to a risk-sharing 
strategy. And so, we would encourage, as we look to the loan 
guarantees, that we look to that on a risk-sharing basis to 
make it an attractive opportunity for industrial 
commercialization and that it doesn't simply become a 10-
percent adder on the financing of the project, but it actually 
encourages the investment, as I believe it's intended to do.
    Senator Murkowski. Do you think that you need an extension 
or perhaps an expansion of these tax credits?
    Mr. Boycott. I think that the tax credits is definitely a 
step in the right direction. As I think about the role of the 
Federal Government, I applaud that effort. And I think there 
are numerous opportunities in this arena that are coming to 
light. And so, I would encourage, irrespective of the Agrium 
opportunity, that we consider an expansion and an extension of 
that program to ensure that we encourage the development of 
these technologies and the use of this energy source.
    Senator Murkowski. Mr. Ferguson you also mentioned the need 
for some certainty in implementation. Would your answer be any 
different than Mr. Boycott's, in terms of what you are looking 
for?
    Mr. Ferguson. I share his concerns. We're trying to get a 
definition from both DOE and Treasury about what ``good'' looks 
like in the nature of an application, so we know what the 
criteria are they're judging us on, what we need to be 
responsive to. And I think in their defense, this is new for 
them, as well. And they're trying to decide who's got the ball, 
between Treasury and IRS, in determining some of these answers. 
So, I sympathize with their issue, but it leaves us in a bit of 
a quandary about: what does ``good'' look like in the form of 
an application? Once we know that, we can all respond properly. 
And I think Mr. Boycott shares some of those concerns.
    Senator Murkowski. Well, and June 1 is not too very far 
away.
    Mr. Ferguson. Only 2 months.
    Senator Murkowski. Okay.
    Thank you, Mr. Chairman.
    Senator Alexander. Thank you, Senator Murkowski.
    Mr. Bruce, this technology that you propose to use is to 
turn gas into ethanol--has been around awhile, except your 
biologic process. Is that the new part of your proposal?
    Mr. Bruce. Yes, Senator.
    Senator Alexander. As I understand it, you're proposing to 
build a new plant in Oak Ridge, is that correct? And how big 
would that be?
    Mr. Bruce. Yes, sir. We want to scale up to a commercial 
size. And our plants would be modular. What we are proposing to 
do is to build just two lines, two modules. So, initially we 
would only build a plant that would produce 7 million gallons. 
A full-scale commercial plant for us in the future would 
probably handle as much as 2500 tons of coal per day, producing 
maybe 135 million gallons of ethanol. But we want to prove the 
technology at a commercial level, and then modularize our way 
up from there.
    Senator Alexander. Would you say, in your opinion, that the 
technology is proven at a test level, but not yet proven at a 
commercial level?
    Mr. Bruce. Yes, I would, exactly. We've been--the Great 
Plains project, we ran syngas off that project for 3 weeks, and 
tested the project there. We've tested it in our own facility. 
We've built our own gas-fire a couple of years ago. It's a 
small one, ton and a half a day. But we can make synthesis gas 
out of municipal solid waste, auto shredder residue, 
cornstalks, any biomass, and convert that into ethanol.
    And I want to comment on something that was said earlier. I 
think that the perfect utilization of our technology would be a 
blend of coal with energy crops. If we're going to get a real 
handle on the CO2 problem, we're going to have to do 
it with biomass. And I think that blending, for example, one-
third coal and two-thirds energy crops--and I say ``energy 
crops,'' because I think we have a vast amount of idle land, 
arable land, also in this country that could be utilized to 
grow energy crops, such as energy cane that was developed at 
the University of Florida, many others, where you get a large 
amount of tonnage per acre--that would balance out the negative 
effect of the increased carbon from coal. However, because of 
our biological process, I think we're minimizing that carbon 
effect anyway.
    Senator Alexander. Well, I'm glad you said that. I want to 
have a chance to ask Dr. Herzog some more about CO2, 
but I was wondering, first, what you, or any of the other 
industrial witnesses, would say about what she said about 
carbon and coal gasification. The NRDC has--what interests me 
about their position as a leading environmental group in the 
country is, they're actually, for large-scale baseline 
production of electricity, after conservation and efficiency--
and she mentioned renewable, which is limited, in terms of what 
it can do for electricity--is a coal strategy, if it's--if the 
carbon's recaptured. So, what's your view of the 
technological--of the feasibility of carbon recapture?
    Mr. Ferguson. If I could comment?
    Senator Alexander. Mr. Ferguson.
    Mr. Ferguson. Sir, we're evaluating a process that would be 
relatively neutral to burning natural gas. It does require some 
sequestration.
    Senator Alexander. Now, explain, what do you mean by 
``relatively neutral''?
    Mr. Ferguson. The carbon emissions from the gasification 
process to make power--electric power--would be equivalent to 
making electric power from natural gas.
    Senator Alexander. Okay.
    Mr. Ferguson. There is some sequestrations required for 
doing that, and the--and how you sequester that, and what it's 
used for, is the next step of our journey here. We think we 
might be able to find a win-win solution to do that.
    Senator Alexander. Anyone else have a comment?
    Mr. Boycott.
    Mr. Boycott. Yes, Mr. Chairman. I'd just like to comment. I 
think the ammonia/urea process is somewhat unique in the 
integration with gasification, because urea is the combination 
of ammonia and carbon dioxide. So, as we're evaluating our 
project, the gasifier in this opportunity is estimated to 
produce 12,000 tons a day of carbon dioxide. We actually are 
forced to sequester that carbon dioxide and utilize 5,000 tons 
a day of it in the production of urea. And so, that type of 
complex lends itself directly to CO2 sequestration. 
And then, we're evaluating the utilization of the balance. We 
have oilfields immediately adjacent to our facility which are 
in significant decline. So, we're in the midst of evaluating 
the utilization of the balance of that carbon dioxide for 
enhanced oil recover.
    Senator Alexander. Mr. Douglas, anything to add?
    Mr. Douglas. Nothing to add, Senator.
    Senator Alexander. Okay.
    Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman. I just had a 
very quick question for you, Mr. Douglas. You were mentioning 
the best way to get the small industrials utilizing the coal 
gasification process.
    Mr. Douglas. Sure.
    Senator Murkowski. And you indicated that you felt that 
some financial incentives would be necessary. Can you expand, 
just a little bit more, in terms of what you think might be 
reasonable, in terms of incentives?
    Mr. Douglas. What might be reasonable, and what we've 
thought about quite a bit, is some type of Btu credit, a small 
Btu credit for the user for the replacement on a one-to-one 
basis from natural gas to syngas. We believe that it's going to 
take an incentive of that type, not unlike former credits that 
we have had in other legislation--that it would take that sort 
of a push to try and ensure that coal gasification is more 
widespread than just large IGCC, because it's our view that 
right now what we're seeing in the United States--and it's not 
a particularly bad thing--is that there's a very strong move 
toward large IGCC. I think the number that was quoted earlier 
was, what, four to five hundred megawatts. IGCC is just as 
valuable to America at 260 megawatts as it as at 500 megawatts. 
It's just a smaller scale. It's a downscale.
    And there are an awful lot of industrials that would like--
that could benefit from syngas, not only for their process--
that is, for their boilers, for their kilns--but also to do 
onsite generation. And there are going to be larger 
industrials, obviously, that are going to do this, that are 
going to produce, for example, 100 megawatts of their own, on 
their own site. We have that capability today. Okay?
    And all I'm trying to advocate for is that the limitation 
of credits at the very largest level is also going to serve as 
a limitation in America to the full introduction of the 
benefits of coal gasification. And that's my point.
    Senator Murkowski. Appreciate that.
    Dr. Herzog, you mentioned that as we move forward with any 
of the processes as they relate to coal, the importance of 
dealing with the carbon. So, I think it is important to hear 
what some of the proposals out there are that are out there.
    And, Mr. Boycott, I guess I look at what we are currently 
envisioning with the Agrium proposal, and, yes, we realize that 
there are a lot of dollars involved with this project, but when 
you look at something that can really provide a win for the 
consumer, a win for the environment, in the sense of figuring a 
way to take all--utilize all that carbon, whether it's 
sequestration into the oil fields--and I realize that there's 
still a lot of searching to determine if that's viable, but 
these are the things that we need to be looking to, to make 
sure that the process works every way that we can. And, 
unfortunately, these are expensive processes, expensive 
projects, and that's why the tax credits, and that's why the 
loan guarantees are going to be helpful.
    Mr. Chairman, I appreciate the testimony of the witnesses, 
and appreciate, again, you calling this hearing.
    Senator Alexander. Thank you, Senator Murkowski.
    I would just like to ask Dr. Herzog a question or two, and 
then we'll conclude the hearing.
    I was in India a couple of weeks ago. The people told me 
India needs 200,000 megawatts of electricity in the next 10 
years. And I asked several people in India if that could be 
possible, and no one really--you know, I suppose you could say 
it could be more, could be less, but it's a huge amount.
    I'm a supporter of the President's proposal on Indian 
civilian nuclear power, but even that, plus whatever else they 
do in India in civilian nuclear power, won't come close to 
producing 200,000 megawatts of electricity over the next 10 
years.
    I agree, as I think most members of this committee agree, 
that the first thing we ought to try to do is conservation and 
efficiency. And we did a good bit of that last year in the 
energy bill, and we probably should do twice as much, or three 
times as much. And on the renewables side, especially in the 
fuel area, the Congress is moving in that direction.
    But it looks to me like, in India, in China, other places 
in Southeast Asia, and in the United States, which are the big 
growing places, that the demand for electricity is going to 
require large amounts of baseline production of electricity, 
and that the only two places to get that are nuclear power--
after you do conservation, after you do some renewable, are 
nuclear and coal.
    I've been intrigued by the Natural Resources Defense 
Council's coal strategy and its willingness to recognize that 
fact. And, as you hear this testimony today, and as you look 
toward the future, thinking not just of the United States, but 
of India and China, what comments or suggestions do you have 
for these industries that would make it more likely that they 
could succeed in--and I don't want--and I want to ask you to 
also consider sulfur and nitrogen and mercury, because those 
are dangerous pollutants, as well, and we do want to sequester 
the carbon, recapture the carbon. That affects global warming. 
But I don't want to minimize the importance of India and China 
and in the United States over the next 20 or 25 years, having 
coal plants that produce no sulfur, nitrogen, and mercury, and 
begin to get carbon under control. So, what's a realistic way 
for us to look at this? What's your advice for them? What's 
your advice for us as we make additional policy on this 
question?
    Dr. Herzog. Right. All excellent questions, all excellent 
points, and certainly ones that we've been thinking about, 
struggling with, as well. As you said, the other pollutants are 
very important. I happen to be an expert on global warming, and 
I didn't have the time to discuss those other pollutants as--in 
addition to the global warming issue. Coal gasification, as you 
said, significantly reduces those other pollutants, and that's 
one of its advantages that we see and advocate for.
    As far as the India question--and China, as well, for that 
matter, even more so, much more so, actually--they both have 
large coal resources. And even though we'd love for efficiency 
or renewables to be the only efforts that move forward, we 
realize, as you've stated, that coal is here, and it's going to 
be here, and we need to deal with it. And that coal 
gasification is one of those technologies for the electricity 
sector that can deal with the criteria pollutants you 
mentioned--mercury--and also the global warming. So, I mean, in 
the United States, we feel that the plants that Government 
money is going towards right now, the gasification plants, 
those plants should be capturing their carbon. We need to get 
that technology out there now. We have about 10 years to really 
get started. We don't have time to wait. I'd love to see the 
United States lead the way. And so, then India and China can 
follow suit and use the technologies that we develop.
    So, we can capture our carbon. That technology is out 
there. Various projects are going on in this country and 
elsewhere around the world to dispose of the carbon, both for 
enhanced oil recovery and in deep saline aquifers. Do we know 
everything we need to know? No. But if we get started now, and 
we learn, and use government subsidies, leveraged by industry 
money, as well, we can get that knowledge we need in the 
timeframe we need it.
    Senator Alexander. Doesn't NRDC have some estimate of the 
pollution in the air in Los Angeles that comes from China and 
India? And do you know what it is, it does?
    Dr. Herzog. Off the top of my head, I don't. We do have a 
China program. They may----
    Senator Alexander. But it is true, is it not, that what 
happens in India and China affects the air in the United 
States, and what we do here affects the world, and what they do 
there affects us as well?
    Dr. Herzog. Absolutely.
    Senator Alexander. Well, this has been a very interesting 
hearing for the Senators who came. We appreciate your 
succinctness and your preparation and your questions. We had 
good attendance here.
    As we said at the beginning, the whole purpose of this 
hearing is oversight, to see whether what we enacted in July 
and August of last year is getting where we're going.
    One of the things we heard today was that some of the 
deadlines for tax credits and loan guarantees are moving right 
along. The other thing we heard that--is, those of you who 
might be applying for tax credits and loans, are still somewhat 
in the dark about how to make those applications. Hopefully, 
this hearing today will suggest to the Department of the 
Treasury and to the Department of Energy that they have some 
work to do. Our staff will follow up with them and convey these 
thoughts. Secretary Garman said he'd be monitoring what you 
said, and listening. And I'm sure he'll pay attention to that, 
as well.
    I want you to know that this entire committee is interested 
in industrial gasification, coal gasification, the idea of 
using coal in a cleaner way to produce homemade electricity 
that'll make us less dependent on dirtier and more foreign 
sources of energy. And so, we'll continue--this is not the 
last, by far, hearing that we'll be having on this subject.
    Other Senators may--or some of the Senators who were here--
may have additional questions. If they do, we'll get them to 
you by the close of business tomorrow, and I hope you'll answer 
those questions, as well.
    What was said here today may provoke you to want to say 
more to us, and we'd like to have your additional comments in 
the next 10 days to 2 weeks so that we can consider them 
specifically. If you want to be more specific about the kind of 
questions you'd like to have answered that would be helpful to 
you, in terms of applications that you might be making for tax 
credits or loan guarantees, let us know that. And part of our 
job is to pass that along to the Department for them to 
consider.
    So, unless Senator Murkowski has something else to add, 
thank you for coming. The hearing is adjourned.
    [Whereupon, at 4:28 p.m., the hearing was recessed, to be 
reconvened on May 8, 2006.]

                 LICENSING OF HYDROELECTRIC FACILITIES

                              ----------                              

                          MONDAY, MAY 8, 2006

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 3:01 p.m., in 
room SD-366, Dirksen Senate Office Building, Hon. Larry E. 
Craig presiding.

  OPENING STATEMENT OF HON. LARRY E. CRAIG, U.S. SENATOR FROM 
                             IDAHO

    Senator Craig. Good afternoon, ladies and gentlemen. The 
Committee on Energy and Natural Resources will convene, and 
thank you for your interest today in the oversight hearing on 
the implementation of the energy bill's hydropower licensing 
procedure.
    As most of you know, it is an extremely important issue to 
me personally. In this time of increased oil and gas prices, 
hydropower is a clean, renewable, and low-cost source of 
energy. My State of Idaho benefits greatly from the renewable 
resource, receiving almost 80 percent of its electricity from 
hydropower.
    Over the last several years I have worked to reform the 
hydropower relicensing procedure. The Federal resource 
agencies, with their authority to issue mandatory environmental 
conditions or fishway prescriptions, play a major role in 
FERC's licensing process. However, such conditions must be 
supported by facts and that, in my opinion, has not always been 
the case.
    Last year, with the enactment of the Energy Policy Act of 
2005, Congress finally brought much-needed reform to this area 
and we did it in a way that I was very proud of, a bipartisan 
way. If you had told me a couple of years ago that we would 
have had myself, Senator Domenici, Senator Cantwell, Senator 
Bingaman, Senator Feinstein, Representative Barton and 
Representative Dingell involved in a compromise on this issue, 
I think there are many in the audience, and myself among them, 
who would simply not have believed it. But that is exactly what 
we did. It does not get more bipartisan than that listing.
    The agreement provides full participation for all parties 
involved in a licensing procedure. Any party may request a 
trial-type hearing on disputed issues of material fact, to 
examine whether an agency's conditions are factually supported. 
Any party may propose alternatives. This is a sound policy 
which will provide much-needed accountability to the process.
    The resource agencies have established the new implementing 
procedure and, with a full 20 percent of the Nation's non-
Federal dams up for relicensing in the next decade, we will see 
it in action. It just so happens to turn out that the first 
trial-type hearing will take place this June in my State of 
Idaho to examine issues relating to the Hells Canyon complex. I 
hope to attend those hearings personally. I am fascinated to 
see how this process will work out.
    Now, before I ask our colleagues to make any statements, 
let me introduce the witnesses here today. I am pleased to 
welcome Mark Robinson from FERC, Larry Finfer from the 
Department of the Interior, Dan Adamson on behalf of the 
National Hydropower Association, and Andrew Fahlund on behalf 
of American Rivers. I look forward, gentlemen, to your 
testimony. Again, let me thank you for being here today.
    Now let me turn to the ranking member of the committee, 
Senator Bingaman of New Mexico, for any comments that he might 
have.
    Senator Bingaman.

         STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR 
                        FROM NEW MEXICO

    Senator Bingaman. Thank you very much, Mr. Chairman, for 
having this hearing. I think it is very useful too, as we were 
discussing before the hearing started, to have oversight about 
some of the provisions that we included in last year's energy 
bill. I am anxious to hear about the agency's efforts to 
administer these new provisions.
    During the course of considering that bill last year, I was 
glad to see that the hydroelectric relicensing provisions were 
revised and improved. Changes were made to ensure that all 
parties to a licensing proceeding, including States and tribes 
and third parties, are able to participate equally, and I think 
that was a good change.
    I do continue to have concerns that the new process for 
alternative mandatory conditions and fishway prescriptions and 
the new trial-type hearings that you were referring to may add 
complexity and delay to an already complex and slow process. So 
I hope that is not the case. I think this hearing may shed some 
light on that. I hope it does. I hope the new provisions are 
being implemented in a manner that maintains protections for 
Federal and Indian lands and fishery resources.
    I understand the goal of these provisions is to improve the 
cost effectiveness and efficiency of conditions and fishways 
and not--this is not seen as an opportunity to undermine the 
conditions and fishways that resource agencies determine are 
necessary.
    So once again, thank you for having the hearing. I look 
forward to learning something from each of these witnesses and 
then I may have a question or two. Thank you.
    Senator Craig. Jeff, thank you very much.
    Let me turn to Senator Craig Thomas of Wyoming for any 
comments you have.

         STATEMENT OF HON. CRAIG THOMAS, U.S. SENATOR 
                          FROM WYOMING

    Senator Thomas. Thank you, Mr. Chairman.
    I am pleased to have this meeting and I welcome the 
witnesses here. This is the third meeting of this kind we have 
had, one each week, and we are going to continue to do that, to 
seek to implement our energy policy that we put into place last 
year. Hydroelectric power, hydropower, of course is very 
important and produces about 7 percent of electricity generated 
in the United States, much higher than that, of course, in the 
Pacific Northwest. In Wyoming, about 5 percent of our 
electricity comes from hydro. About 10 percent of electricity 
in Wyoming comes from renewable sources, and that is good.
    As was mentioned, I think our bill last year did a good job 
of establishing a bipartisan process for relicensing hydro and 
that is a good thing. So I strongly feel we need to continue to 
implement the provisions of the policies as quickly as possible 
and as effectively as we can. So I look forward to the 
witnesses this afternoon, Mr. Chairman. Thank you.
    Senator Craig. Craig, thank you for being here.
    Now we will turn to our witnesses and I am proud to 
introduce Mark Robinson, Director of the Office of Energy 
Projects, the Federal Energy Regulatory Commission. Mark, thank 
you for being here and your full statement will become a part 
of the record. Please proceed.

   STATEMENT OF J. MARK ROBINSON, DIRECTOR, OFFICE OF ENERGY 
         PROJECTS, FEDERAL ENERGY REGULATORY COMMISSION

    Mr. Robinson. Thank you, Senator Craig. First I would like 
to make sure and pass along the sentiments of my boss, Joe 
Kelleher, and his desire to compliment you on the work that you 
did in getting the hydro provisions into EPAct 2005. They have 
made a difference, as I think my testimony states and hopefully 
I will confirm here today. But he wanted me to make sure and 
pass that on to you, and I join him in that.
    My name is Mark Robinson. I'm Director of the Office of 
Energy Projects. Our office authorizes the construction of LNG 
terminals, natural gas pipelines, and natural gas storage 
facilities. After EPAct 2005 we will be involved in electric 
transmission lines. But more significantly today, we are 
involved in the licensing, the administration, the safety and 
security of about 1600 hydroelectric projects across the 
country, constituting about half of the Nation's hydroelectric 
power.
    You hear statistics like you have already mentioned today 
about the hydropower and what it means to electric generation 
in this country, 7 percent, 6 percent. I hear different 
numbers. But that does not really reflect the significance of 
hydropower to the Nation's energy security. All you have to do 
is look back a few years when we had low water years in the 
Northwest, to how that can play out to ensuring the economy of 
this country. Or even more recently, look at the low water year 
in Spain and how that plays out with our getting LNG delivery 
into the United States. Hydropower in many instances is the 
base that everything else works from, regardless almost of the 
percent that hydropower represents in the Nation's energy 
portfolio.
    We have about 218 hydroelectric projects coming up for 
relicensing this decade, constituting 22 gigawatts of power. So 
it is a very important time frame for us to be looking at how 
we are licensing these projects and ensuring that that 
electricity is available to the public.
    About a year or so ago now, I guess a little longer than 
that, the Commission tried to prepare itself for these licenses 
that were coming in by the development and issuance of the 
integrated licensing process for handling the relicense 
principally of projects in this country. We spent a lot of time 
on that with all the agencies, people represented at this 
table, to make sure that we had it as right as we could at that 
time and to add discipline to a process that had gotten very 
long and very expensive.
    One of the challenges of EPAct 2005 in terms of taking the 
provisions that were provided, principally on the mandatory 
conditioning authority of the agencies, was making sure that 
that was integrated into our new integrated licensing process 
and would not add delay. Yes, there was going to be some more 
steps, principally with the agencies, but to make sure that it 
fit within our process. I think, with the work done by the 
Department of the Interior, the Department of Commerce, and the 
Department of Agriculture, and our own staff at FERC, we have 
accomplished that. We have a process that allows for those 
mandatory conditions to be developed, reviewed, and brought 
into the FERC licensing process without delay.
    Two things about those conditions, those provisions of 
EPAct 2005, I would like to mention: the trial-type hearing and 
the alternative conditions. I think both are important and they 
work in tandem to improve the conditions that the Commission 
gets. The trial-type hearing makes sure that the information 
base that everybody relies on to determine whether or not a 
fish ladder is needed, whether or not the minimum flow is 
correct, actually has a sound foundation, and I think that is a 
critical aspect of what EPAct 2005 did for hydro.
    EPAct also allowed alternative conditions to come that 
would be less costly and maybe allow for the project to operate 
better, but would also either adequately protect in terms of 
section 4(e) or give equal--I am sorry--no less protective of 
for section 18 for prescriptions, but allow for other ideas to 
come in and be tested in the FERC marketplace as well as with 
the agencies, to ensure that we have the right conditions in 
those licenses.
    I think the net result of those provisions is that, along 
with the responsibility that the agencies have to provide those 
conditions, they now have an accountability aspect to it. They 
have to take a hard look at what it is they are proposing to 
make sure that it does in fact serve the public interest. In 
many ways it aligns itself with the requirements that the 
Commission has always been under to ensure that the public 
interest is met, that the developmental and non-developmental 
values are both looked at and given equal consideration in 
providing for those conditions and imposing them in a license.
    The agencies now have that similar criteria in developing 
their conditions. I think the net result of that ultimately 
will be less conflict, fewer ALJ hearings after we get over 
this initial round, I think, and a greater conformance between 
what the agencies would provide through their mandatory 
conditioning authority and what the commission would require in 
any case, given the requirements that they have under the 
Federal Power Act. I think that is nothing but good in bringing 
all the Federal agencies into harmony in developing these 
licenses and will ultimately result in better stewardship both 
for the hydropower resources that we are all required to do, to 
take a look at, as well as the natural resources.
    [The prepared statement of Mr. Robinson follows:]

  Prepared Statement of J. Mark Robinson, Director, Office of Energy 
             Projects, Federal Energy Regulatory Commission

    Mr. Chairman and Members of the committee, I appreciate the 
opportunity to appear before you to discuss the provisions of the 
Energy Policy Act of 2005 (EPAct 2005) relating to the Federal Energy 
Regulatory Commission's hydropower licensing program. My name is J. 
Mark Robinson, and I am the Director of the Commission's Office of 
Energy Projects. Our office is responsible for the regulation of non-
federal hydropower projects; the certification of between 500 and 2,000 
miles of interstate natural gas pipelines annually; the certification 
of natural gas storage facilities; and the authorization, safety and 
security of liquefied natural gas (LNG) terminals. I appear today as a 
Commission staff witness speaking with the approval of the Chairman of 
the Commission. The views I express are my own and not necessarily 
those of the Commission or of any individual Commissioner.
    The Commission currently regulates over 1,600 hydroelectric 
projects at over 2,000 dams pursuant to Part I of the Federal Power Act 
(FPA). Together, these projects represent 57 gigawatts of hydroelectric 
capacity, more than half of all hydropower in the U.S. and over five 
percent of all electric generating capacity in the United States. 
Hydropower is an essential part of the Nation's energy mix and offers 
the benefits of an emission-free, renewable energy source.
    The Commission is in the midst of processing the 218 relicense 
applications being filed this decade. These projects include many large 
capacity and complex projects and have a combined capacity of about 22 
gigawatts, or 20 percent of the Nation's installed hydroelectric 
capacity. The Commission is faced with the challenge of licensing these 
projects in a reasonable time frame, while complying with statutory 
requirements under the jurisdiction of a host of federal and state 
agencies.
    Dependable and affordable hydroelectric energy requires a licensing 
process that is efficient and fair. As the Commission begins 2006, its 
hydropower staff is focused on pursuing various initiatives to meet 
current challenges, including implementation of the Commission's 
Integrated Licensing Process (ILP) to increase the efficiency and 
timeliness of licensing hydroelectric projects under its jurisdiction, 
while balancing stakeholder interests and improving the quality of 
decision-making.
    The Commission's hydropower activities generally fall into three 
categories. First, the Commission licenses and relicenses hydroelectric 
projects. Relicensing involves projects that originally were licensed 
30 to 50 years ago. The Commission's second role is to manage 
hydropower projects during their license term. This post-licensing 
workload has grown in significance as new licenses are issued and as 
environmental standards become more demanding. Finally, the Commission 
oversees the safety and security of licensed hydropower dams.
    My testimony today will address implementation of the hydropower 
provisions of section 241 of Subtitle C of Title II and section 1301 of 
Subtitle A of Title XIII of EPAct 2005 and provide examples of how 
these sections have already begun to positively affect the hydropower 
program.
    While the Commission's responsibility under the FPA is to strike an 
appropriate balance among the many competing developmental and 
environmental interests, as required by the public interest standards 
of sections 4(e) and 10(a) of the FPA, various statutory requirements 
give other agencies a significant role in licensing cases. Several 
entities have mandatory authorities that limit the Commission's control 
of licensing requirements and of the cost and timing of licensing. For 
example, section 4(e) of the FPA authorizes federal land-administering 
agencies to provide mandatory conditions for projects located on 
federal reservations under their jurisdiction. Further, section 18 of 
the FPA gives authority to the Secretaries of the Departments of the 
Interior and Commerce to ``prescribe'' fish ways.
    Prior to the passage of EPAct 2005, the other federal agencies were 
not required to consider or strike a balance among the many competing 
developmental and environmental interests, nor were they required to 
consider alternatives proposed to their mandatory conditions, even if 
those alternative conditions were less costly and achieved the same 
level of environmental protection.
    Section 241 of EPAct 2005 amends sections 4(e) and 18 of the FPA to 
provide that any party to a license proceeding is entitled to a 
determination on the record, after opportunity for an agency trial-type 
hearing of no more than 90 days, of any disputed issues of material 
fact with respect to any agency's mandatory conditions or 
prescriptions. Section 241 further mandates that, within 90 days of the 
date of enactment of EPAct 2005, the Departments of the Interior, 
Agriculture, and Commerce establish jointly, by rule and in 
consultation with FERC, procedures for the expedited trial-type 
hearing, including the opportunity to undertake discovery and cross-
examine witnesses.
    Section 241 of EPAct 2005 also adds a new section 33 to the FPA 
that allows the license applicant or any other party to the license 
proceeding to propose an alternative condition or prescription. The 
Secretary of the agency involved must accept the proposed alternative 
if the Secretary determines, based on substantial evidence provided by 
a party to the license proceeding or otherwise available to the 
Secretary, (a) that the alternative condition provides for the adequate 
protection and utilization of the reservation, or that the alternative 
prescription will be no less protective than the condition or fishway 
initially proposed by the Secretary, and (b) that the alternative will 
either cost significantly less to implement or result in improved 
operation of the project works for electricity production.
    New FPA section 33 further provides that, following the 
consideration of alternatives, the Secretary must file with FERC a 
statement explaining the reasons for accepting or rejecting any 
alternatives and the basis for any modified conditions or prescriptions 
to be included in the license. If FERC finds that the modified 
conditions or prescriptions would be inconsistent with the purposes of 
the FPA or other applicable law, it may refer the matter to its Dispute 
Resolution Service (DRS). The DRS is to consult with the Secretary and 
FERC and issue a non-binding advisory within 90 days, following which 
the Secretary is to make a final written determination on the 
conditions or prescriptions.
    Since enactment of EPAct 2005, Commission staff has worked with the 
U.S. Departments of Agriculture, Interior, and Commerce (Departments) 
to integrate the provisions of section 241 into the Commission's 
licensing process. We have reviewed the Departments' draft and interim 
final rules; met with the Departments several times to ensure that the 
timeframes for the trial-type hearings and alternate conditions and 
prescriptions fit within the licensing process and to consider how the 
rules affect pending (transition) and future projects; and commented on 
schedules for individual transition projects. We continue to coordinate 
on procedures for notices, for conducting the environmental review 
process, and priorities for holding hearings and/or considering 
alternative conditions.
    We wish to compliment the Departments for issuing a joint Interim 
Final Rule in a short timeffame. We are satisfied that the opportunity 
for a trial-type hearing and the filing of alternate conditions and 
prescriptions are appropriately integrated into the Commission's 
licensing time frames. The attached flow chart * shows the integration 
of section 241 of EPAct into our licensing process. Provided that the 
timelines established in the Interim Final Rule are met, section 241 
will not extend the Commission's licensing schedule.
---------------------------------------------------------------------------
    * The attachment has been retained in committee files.
---------------------------------------------------------------------------
    The Hells Canyon Project No. 1971 is the first case to follow these 
timelines. Almost 500 terms and conditions and recommendations were 
received on the relicense application, including land management 
conditions under section 4(e) of the FPA and fishway prescriptions for 
federally listed bull trout under section 18 of the FPA. The National 
Marine Fisheries Service did not require fishways for anadromous fish 
at this time because of poor upstream water quality, but rather 
reserved authority to prescribe fishways at a later date. In February 
2006, Idaho power filed a request for trial-type hearings with the 
Departments of Agriculture and Interior and provided alternative 
license conditions under the Energy Policy Act of 2005 in response to 
the land management conditions and fishway prescriptions. The 
administrative law judges' decisions on the trial-type hearings are due 
July 2006, Our draft environmental impact statement (EIS) is scheduled 
to be issued in July 2006. Decisions on alternative license conditions 
are due 60 days after issuance of the draft EIS.
    Currently, there are 15 ``transition'' projects with hearing 
requests and/or alternative conditions (these are projects for which 
license applications had been filed when EPAct 2005 was enacted, but 
with respect to which the Commission had not yet issued a license). The 
Departments have issued schedules for each of these projects. The 
attached table shows these transition projects and the Departments' 
schedules for initiating hearings and filing modified terms and 
conditions.
    Due to a scarcity of Departmental administrative law judges 
available to hear these cases, the Departments of Interior and 
Agriculture have stated that they are able to schedule only one hearing 
per month. We are concerned about the impact these schedules may have 
upon the Commission's ability to take final action on these transition 
cases. For example, for the Priest Rapids Project No. 2114 in Oregon, 
Interior does not expect to file modified terms and conditions until 
June 11, 2007. The Commission staff issued its Draft EIS Statement in 
February 2006 and has scheduled the Final EIS for August 2006. The 
application is expected to be ready for final Commission action by 
October 2006. As a result of Interior's bearing schedules and delayed 
filing of modified terms and conditions, final action on the 
application could be delayed by eight months or longer. Similarly, for 
eight of the remaining 14 transition projects, potential delays for 
taking final Commission action range from six to 14 months. We would 
hope that the Departments are able to obtain additional staff resources 
to expedite hearings and the filing of modified terms and conditions 
for these cases.
    Notwithstanding the potential for delays on the transition 
projects, there have been a number of positive outcomes that we surmise 
may have resulted from section 241 of EPAct 2005:
    For the Priest Rapids Project No. 2114 in Washington State, the 
licensee challenged the Bureau of Reclamation's (BOR) section 4(e) 
conditions under EPAct. Subsequently, BOR withdrew its mandatory 
conditions and refiled them as recommendations pursuant to section 
10(a) of the FPA.
    For the Upper North Fork Feather River Project No. 2105 and the Poe 
Project No. 2107, both located in California, the National Oceanic and 
Atmospheric Administration of the Department of Commerce (NOAA 
Fisheries) substituted a reservation of authority to prescribe fishways 
in the future for its previously filed specific section 1 
prescriptions.
    For the Rocky Reach Project No. 2145 in Washington, the licensee 
submitted alternatives to Interior's section 18 fishway prescriptions. 
Subsequently, the licensee and Interior's Fish and Wildlife Service 
(and others) entered into a comprehensive settlement agreement 
addressing, among other things, the licensee's fish passage concerns.
    As discussed previously, the FPA requires that the Commission 
authorize projects that are best adapted to a comprehensive plan for 
improving or developing a waterway for beneficial public purposes, 
including power generation, irrigation, flood control, navigation, fish 
and wildlife, municipal water supply, and recreation, giving equal 
consideration to developmental and non-developmental values. Based upon 
the above examples, it appears that section 241 of EPAct 2005, which 
more closely aligns the criteria that the agencies must use in 
formulating mandatory conditions with the Commission's ``equal 
consideration'' criteria for licensing projects under the FPA, is 
already reducing conflict between mandatory conditions and the 
conditions the Commission finds reflect the public interest.
    In addition, the above examples seem to indicate that EPAct 2005 
has provided an increased incentive for agencies to provide cost-
effective and factually supported mandatory conditions and has 
encouraged greater interaction between the resource agencies and the 
licensees in the development of environmental measures. EPAct 2005 has 
added a degree of accountability that previously did not exist, and the 
federal resource agencies are making a laudable effort to comply with 
Congress' mandate. I believe this will result in mandatory license 
conditions that are fairer and more balanced.
    A second important aspect of EPAct 2005 is section 1301 of Title 
XIII Subtitle A, which provides for renewable energy tax credits for 
incremental energy gains from efficiency improvements or capacity 
additions to existing hydroelectric facilities placed into service 
after August 8, 2005 and before January 1, 2008.
    Under that section, the Commission certifies the ``historic average 
annual hydropower production'' and the ``percentage of average annual 
hydropower production at the facility attributable to the efficiency 
improvements or additions of capacity'' placed in service after August 
8, 2005 and before January 1, 2008.
    We have issued a guidance document to help our licensees seeking 
tax credit certification. The document, which is posted on our web 
site, explains what information our licensees need to provide for our 
review and evaluation to certify incremental energy gain. We have also 
disseminated information about the tax credit at national conferences 
throughout the country, to encourage efficiency upgrades.
    These efforts have resulted in licensees initiating evaluation of 
possible upgrades at their projects. At this early stage, the 
Commission has already received 4 applications for a total capacity 
increase of about 17 megawatts that may qualify for the credit.
    Thank you. will be pleased to answer any questions you may have.

    Senator Craig. Mark, thank you very much.
    Now let me introduce Larry Finfer, Acting Director, Office 
of Policy Analysis, Department of the Interior. Welcome before 
the committee.

STATEMENT OF LAWRENCE FINFER, ACTING DIRECTOR, OFFICE OF POLICY 
              ANALYSIS, DEPARTMENT OF THE INTERIOR

    Mr. Finfer. Thank you, Mr. Chairman. Mr. Chairman and 
members of the committee, thank you for the opportunity to 
testify on the implementation of section 241 of EPAct. I would 
like to make brief remarks and request my full statement be 
included in the record.
    In issuing new licenses, it is important to ensure the 
significant natural resource and Indian tribal asset safeguards 
are in place. These are addressed in mandatory conditions and 
prescriptions that are developed by the Departments of 
Agriculture, Commerce, and the Interior and submitted to FERC 
for inclusion in a license.
    Historically, agencies have found it necessary to develop 
such conditions or prescriptions in a distinct minority of 
licenses. While intended to protect fish, wildlife, and other 
resources, we recognize they often entail additional costs for 
utilities and consumers. Licenses may be granted for 30 to 50 
years, so it is important to consider all relevant facts and 
issues and potential alternatives by which to achieve the 
intended goals.
    Section 241's implementation presented our three 
Departments with significant challenges. I am pleased to report 
we are meeting them and we believe we have a process that meets 
your expectations.
    Our first challenge was to promulgate rules for the trial-
type hearing process. EPAct required the Departments to 
establish rules jointly within 90 days in consultation with 
FERC and to include provisions for the opportunity to undertake 
discovery and cross-examine witnesses. It limited the length of 
hearings to 90 days and their scope to disputed issues of 
material fact.
    We formed an inter-agency team to draft the rules and 
consulted with FERC, whose staff was accessible and helpful and 
approved the final product. The main task was to create a 
process with a notably more rigorous time frame than usual for 
administrative appeals in order to comport with the time frame 
under which FERC must complete licensings.
    The Departments published the rules on November 17, 2005, 
as interim final rules with a request for comments. In 
publishing the rules, we indicated we would review the comments 
received and our initial experience in implementing the new 
process and consider issuing final rules in about 18 months. 
The rules set forth an efficient process for hearings and 
procedures for considering alternatives. Under the rules any 
party to a proceeding may request a hearing or submit 
alternatives. Hearings will be conducted by administrative law 
judges. Agencies have the option to consolidate hearing 
requests into a single proceeding. Once a hearing request is 
received, parties may file responses and/or notices of 
intervention, after which agencies file answers to the 
requests. In the answer, an agency may stipulate to some or all 
of the facts, which may preclude the need for a hearing on some 
or all issues. It may also consider whether an alternative 
should be accepted and of doing so might preclude the need for 
a hearing. If more than one agency receives a hearing request, 
they jointly determine whether to consolidate and who should 
hear the case.
    This pre-docketing phase takes 90 days, after which the 90-
day hearing clock begins. The 90-day hearing phase provides for 
discovery and other essential steps, followed by the hearing, 
post-hearing briefs, and the ALJ's decision, which is binding 
with respect to the facts. The hearing is timed to occur prior 
to FERC's issuance of a joint NEPA document in order to assure 
the results are considered in a manner that reduces licensing 
delays. We will strive to ensure deadlines are met.
    After the rules were published, parties to proceedings with 
proposed conditions and prescriptions had until December 17 to 
request hearings or propose alternatives. We received 19 
requests covering 17 projects, all of which were submitted by 
license applicants, and we consulted among ourselves and with 
FERC to develop schedules. Since then, new requests were 
received for the Hell's Canyon and Klamath projects. Klamath is 
the first for which requests for hearings and alternatives were 
received from parties in addition to license applicants.
    The first hearings will address the Hell's Canyon and 
Klamath projects. The current schedule calls for hearings on 
Hell's Canyon to be conducted in June and decisions by the 
respective ALJ's in July. The Klamath schedule is expected to 
result in hearings by Commerce and Interior, unless a decision 
is made to consolidate, in August, with a decision in 
September. Other proceedings have been scheduled for later this 
year and in 2007. In some cases, the Departments and involved 
parties are considering settlements and in two cases 
settlements have already been achieved and the hearing requests 
have been withdrawn.
    Each agency has identified ALJ's to conduct hearings. Ag 
and Interior have done so through their respective ALJ offices. 
Commerce has augmented an existing MOU with the Coast Guard to 
cover these requests, and training has been conducted.
    These initial steps in implementing section 241 are 
encouraging. We have a process in place to meet Congress's 
expectations. Cooperation continues to address hearing requests 
and alternatives. While inter-agency coordination and the 
consideration of alternatives are not new features, they act to 
enhance this level of cooperation and resulted in a heightened 
and more rigorous consideration of alternatives.
    Mr. Chairman, I am pleased to answer any questions you may 
have.
    [The prepared statement of Mr. Finfer follows:]

   Prepared Statement of Lawrence Finfer, Acting Director, Office of 
              Policy Analysis, Department of the Interior

    Mr. Chairman and Members of the Committee, thank you for the 
opportunity to testify on the implementation of Section 241 of the 
Energy Policy Act, which addresses the process by which Federal 
agencies develop conditions and prescriptions for hydroelectric 
licenses issued by the Federal Energy Regulatory Commission (FERC) 
pursuant to sections 4(e) and 18 of the Federal Power Act.
    Hydropower is an important part of our nation's energy 
infrastructure, providing about 7% of our electricity. By 2018, 
projects that include almost half of our non-Federal hydropower 
capacity and cover every region must receive new operating licenses. In 
issuing new licenses, it is important to ensure that significant 
natural resource and Indian tribal asset safeguards are put in place. 
These concerns are addressed in conditions and prescriptions that are 
developed by resource agencies, namely the Departments of Agriculture, 
Commerce and the Interior and submitted to FERC for inclusion in the 
license.
    Historically, agencies have determined it necessary to develop 
mandatory conditions or prescriptions only in a distinct minority of 
license proceedings. While mandatory conditions or prescriptions are 
intended to protect fish, wildlife, and other important resources, we 
recognize these protections often entail additional costs for utilities 
and consumers, and that it is important to consider all relevant facts 
and issues in the decision making process. Since licenses may be 
granted for periods covering 30 to 50 years, it is important to assure 
that the full range of issues associated with conditions and 
prescriptions, and potential alternatives by which to achieve their 
intended goals, are appropriately assessed.
    At the outset, it should be noted that several Congresses examined 
the conditioning process prior to the enactment of section 241. The new 
statute reflects Congress's desire to ensure that resource agency 
conditions and prescriptions which are included in hydroelectric 
licenses are carefully formulated. Further, key provisions of section 
241 provide stakeholders with the opportunity to raise concerns about 
the basis of proposed conditions and prescriptions and to propose 
alternative approaches.
    The implementation of Section 241 presented the three departments 
that have authority to file conditions and prescriptions, the 
Departments of Agriculture, Commerce, and the Interior, with 
significant challenges. I am pleased to report that we are meeting 
them, in large measure through the enhanced interagency coordination 
that Congress intended. Although we are still in the early stages of 
implementation and pre-hearing processes have just begun in the first 
two cases, the agencies have developed a process that meets Congress's 
expectations. We further believe that the Act highlights the importance 
of enhanced interagency cooperation and a high level of integrity in 
the agencies' conditions and prescriptions.
    The first major challenge we faced was the promulgation of rules to 
set forth the trial-type hearing process outlined in sections 241 (a) 
and (b). The Act required the three Departments to establish rules 
jointly within 90 days, in consultation with the Federal Energy 
Regulatory Commission (FERC) and to include specific provisions for the 
opportunity to undertake discovery and cross-examine witnesses. It 
further limited the length of hearings to 90 days and limited their 
scope to disputed issues of material fact.
    The Departments formed an interagency rulemaking team immediately 
upon the Act's approval by the President on August 8, 2005, in order to 
develop an adjudicatory process that met the Act's requirements. In so 
doing, the agencies consulted with FERC, whose staff was accessible and 
helpful, and approved the final product. The most substantive challenge 
was the need to create an adjudicatory process that assumed a notably 
more rigorous time frame than normally occurs for administrative 
appeals. This is essential to ensure that hearings comport with the 
time frame under which FERC must complete the licensing process. FERC 
sets forth licensing schedules under its rules to meet Congress's 
expectations for prompt completion of licensing actions.
    The three Departments published their rules in the Federal Register 
on November 17, 2005, as interim final rules with a request for 
comments. The rules, which are substantively identical, set forth an 
efficient process for the hearings. In addition, the rules also 
establish procedures for considering alternative conditions and 
prescriptions submitted by any party to the licensing proceeding. Under 
the rules, any party to a license proceeding may request a hearing on 
contested material facts and/or submit alternative conditions and 
prescriptions for assessment by the agencies. Hearings will be 
conducted by Administrative Law Judges (ALJs). The rules provide the 
respective Departments with the option to consolidate hearing requests 
for a particular license into a single proceeding that is conducted by 
one agency. Further, the rules allow hearing requests and alternatives 
to be filed for ongoing license proceedings where FERC had not issued a 
license as of November 17, 2005, as well as for those initiated after 
its publication. In publishing the rules, the agencies indicated that 
they would consider the comments received and their initial experience 
in implementing the new processes, and consider issuing revised final 
rules within approximately 18 months.
    The rules outline a rigorous process, beginning with the submission 
requirements for hearing requests and proposed alternatives. Once a 
hearing request is received, license parties may file responses and/or 
notices of intervention within 15 days, and agencies may file answers 
to the hearing request within the next 30 days. In formulating its 
answer, an agency may stipulate to some or all of the facts at issue, 
which may preclude the need for a hearing on some or all issues. In 
addition, it may consider whether an alternative condition or 
prescription should be accepted, and whether doing so might preclude 
the need for a hearing. If more than one agency receives a hearing 
request in a given case, the agencies will jointly determine whether to 
consolidate any hearings and, if so, determine whose ALJ will hear the 
case. This pre-docketing phase takes about 80 days to complete, after 
which the case is formally referred to an agency's hearings office for 
docketing, at which point the 90 day hearing ``clock'' begins.
    The 90 day hearing phase provides for discovery, pre-hearing 
conferences, pre-hearing motions, confirming witness lists, preparing 
exhibits and testimony, and the actual hearing, which is followed by 
the filing of post-hearing briefs and ultimately the decision by the 
ALJ. The ALJ's decision is binding with respect to the facts at issue. 
The hearing is timed to occur prior to FERC's issuance of a draft NEPA 
document, in order to assure that the results are considered in a 
manner that reduces the probability of delay in the overall license 
proceeding. The Departments will strive to ensure the deadlines are 
met.
    After the agencies promulgated the rules, parties to proceedings 
that already had proposed or modified conditions or prescriptions had 
until December 17, 2005, to request hearings and/or propose 
alternatives. The agencies received 19 requests (covering 17 projects), 
and all of these were submitted by license applicants:

                Agriculture (Forest Service)--11;
                Commerce (NMFS)--2;
                Interior--6

    Agencies have consulted among themselves and with FERC to develop 
schedules for addressing these requests. In addition, new requests have 
been received within the past few months for the Hells Canyon and 
Klamath projects. The latter project is the first for which requests 
for hearings and the consideration of alternative conditions or 
prescriptions have been received from parties in addition to license 
applicants. Based on the schedules that have been established, the 
first hearings will address the Hells Canyon and Klamath projects. The 
current schedule calls for individual hearings on the Hells Canyon 
Project to be conducted by Agriculture and Interior in June and 
decisions by the respective ALJs in July. The Klamath Project schedule 
is expected to result in hearings by Commerce and Interior (unless a 
determination is made to consolidate the proceedings) in August with a 
decision in September. Several other proceedings have been scheduled 
for later this year and in 2007. It is important to note that in 
several cases the Departments and involved parties are considering 
settlements that may preclude the need to pursue the requested 
proceedings. In two cases, settlements have already been achieved, 
resulting in the withdrawal of the hearing requests by the project 
applicants.
    As noted above, the three agencies made completion of the joint 
rules a high priority. This high level of attention continues as we 
implement section 241. Each agency has identified ALJs for potential 
availability to conduct hearings. In Interior's case, the Office of 
Hearings and Appeals has four ALJs, and in the Fiscal Year 2007 
President's Budget requested an additional $400,000 to support an 
additional ALJ and a staff attorney. Agriculture's Office of 
Administrative Law Judges has designated three ALJs who may be 
available. Commerce does not have an ALJ office, but the agency has 
augmented an existing Memorandum of Understanding with the Coast Guard, 
whose ALJs now conduct hearings for NMFS in other types of cases, to 
cover section 241 requests. In addition, a number of training sessions 
have been conducted for agency program specialists, attorneys and ALJs, 
and additional training is anticipated.
    These initial steps in implementing section 241 are encouraging. 
The agencies have put in place an expedited process to meet Congress's 
expectations. The cooperation among the agencies that occurred to 
complete the rulemaking has continued as we address hearing requests 
and proposed alternative conditions and prescriptions. It is important 
to note that interagency coordination and the consideration of 
alternatives are not new features. The Departments of Agriculture, 
Commerce, and the Interior have always coordinated among themselves and 
with other parties in exercising their authorities under the Federal 
Power Act, and in so doing considered alternatives by which to meet 
their objectives. Nevertheless, the Act has enhanced the level of 
cooperation among the agencies, as well as a resulted in a heightened 
and more rigorous consideration of alternatives. Further, it 
underscored the need for careful deliberation, justification, and 
documentation with respect to the formulation of conditions and 
prescriptions.
    In summary, the agencies believe we have an expedited process in 
place, and have developed strategies to comply with the Act's 
requirements. Since we are still in the early phase of implementation, 
and have yet to conduct a hearing or undertake an assessment of 
proposed alternatives, it is obviously too early to claim success. 
Indeed, our experience will indicate whether changes to the rules or to 
our management of the new process are required. Rest assured, however, 
that the agencies, having already demonstrated the commitment to 
implement section 241, will persevere to achieve positive results. 
Thank you for your consideration. I will be pleased to answer your 
questions.

    Senator Craig. Larry, thank you very much for that 
testimony.
    Now let us turn to Dan Adamson, vice chair, Legislative 
Committee, National Hydropower Association here in Washington. 
Dan, welcome.

   STATEMENT OF DAN ADAMSON, VICE CHAIR, LEGISLATIVE AFFAIRS 
           COMMITTEE, NATIONAL HYDROPOWER ASSOCIATION

    Mr. Adamson. Good afternoon, Senator Craig, Senator 
Bingaman, and Senator Thomas. I am Dan Adamson. I am an 
attorney with the law firm Davis, Wright, Tremaine. I am here 
today to testify on behalf of the National Hydropower 
Association, NHA. Our statement has also been endorsed by the 
Edison Electric Institute, American Public Power Association, 
and NRECA.
    Before I get into my statement, Senator, just on behalf of 
NHA and the other trade associations, we want to thank you for 
the efforts you have made. It took almost 10 years to get this 
enacted and I think you did an extraordinary job and it is a 
textbook example of how to get legislation passed on a very 
politically and technically complex subject. So we really 
appreciate what you have done, as well as that of all the other 
Senators and House members that made this possible.
    Licensing reform was needed because there were serious 
problems, as you have referred to, with the exercise of 
mandatory conditioning authority. The gist of the problem was 
this. If an agency issued a mandatory condition that either was 
not supported by the facts or ignored another more cost-
effective alternative, the licensee or any other party 
essentially had no recourse. That would just go into the 
license.
    I will give you one example. There is a project in 
Washington State called Box Canyon. In that case, which was 
pretty recent, the Fish and Wildlife Service prescribed fish 
passage for bull trout. That sounds good. The only problem is 
the field surveys all indicated there were no bull trout there. 
So the licensee had no recourse. Just as an example, 
establishing fish passage for fish that do not exist does not 
do anything for the environment. All it does is impose costs on 
ratepayers.
    NHA and its partners strongly support the interim rule that 
Larry Finfer and his colleagues and Mark Robinson and others 
put together to implement the new law. We think for the most 
part it really does a good job of being consistent with 
congressional intent. There are three provisions I want to 
highlight.
    First, they decided that the new reforms would apply to 
pending licensing proceedings. That was critical. If they had 
not done that, this law would essentially have no impact for 
about 5 years, and I do not think that is what Senator Craig or 
any of the other people that worked on this intended.
    They also clarified that the reforms apply to the exercise 
of reserve conditioning authority, which happens a lot. They 
also put independent ALJ's in charge of deciding whether or not 
a party has a right to a hearing. That is turning out to be 
very important.
    We do have a few concerns about the rule, however. The 
first is the rule provides for hearings on preliminary 
conditions, which are not the conditions that will actually be 
imposed on you as a licensee. So our preference would be that 
those hearings be on the final conditions because those are the 
ones that are actually going to apply if they go through.
    Another concern is we think it is very important to clarify 
that the new equal consideration requirement applies to all 
mandatory conditions.
    Finally, as far as the trial-type hearing, we are concerned 
that the timetable for the hearing is so tight and inflexible 
that when you hit a very complex proceeding with literally 
hundreds of factual issues it may be difficult to make the 
process work well.
    So although we are generally very happy with what the 
Departments have done and we think, considering the amount of 
time they had, it was really an extraordinary accomplishment, 
we would like to see a revised rule issued later this year to 
fix these problems and some others. Now that the rule has been 
issued, we are into early implementation and, as has been 
mentioned, a number of licensees have filed requests for 
alternative conditions and requests for a hearing. But we are 
still in an early stage. None of the alternative conditions 
have been acted on and only one hearing, the Hell's Canyon 
hearing that you referred to, has just started.
    Nevertheless, the early indications from our standpoint are 
positive. It looks to us like the Departments are trying to be 
more thorough and careful in their preparation of their 
conditions and make sure they are supported by the facts. That 
is very good news and that is consistent, I think, with the 
congressional intent.
    Just to mention one company, Avista Corporation, which has 
a project in Idaho and Washington State called Post Falls, 
Spokane River. They are trying to settle, as they always have. 
They settled in other hydro proceedings. But if they are not 
able to settle, these hydro reforms offer kind of an 
alternative path forward for them and many other licensees that 
is very positive.
    I just want to give a quick plug for extending the 
production tax credit for incremental hydro. This is very 
important to a lot of NHA's members and it is key to developing 
new hydro, and unfortunately the time frames in the current law 
are not well suited to hydro, which is a long lead time 
development.
    In conclusion, the hydro reforms are really making a 
difference. It is very positive. They are going to result in 
more economic energy production, they are going to preserve the 
environment, in some cases improve environmental protection. We 
really commend you, Senator Craig, and all the other folks that 
have worked on this legislation. Thank you very much.
    [The prepared statement of Mr. Adamson follows:]

  Prepared Statement of Dan Adamson, Vice Chair, Legislative Affairs 
               Committee, National Hydropower Association

                              INTRODUCTION

    Good afternoon, I am Dan Adamson, Partner with the law firm of 
Davis Wright Tremaine LLP and a Vice Chair of the Legislative Affairs 
Committee of the National Hydropower Association (NHA).\1\ Though I 
appear before this Committee today on behalf of NHA, our statement has 
been endorsed by the hydroelectric industry coalition, including the 
Edison Electric Institute (EEI), the American Public Power Association 
(APPA), and the National Rural Electric Cooperative Association 
(NRECA).
---------------------------------------------------------------------------
    \1\ NHA is a non-profit national association dedicated exclusively 
to advancing the interests of the U.S. hydropower industry. The 
association represents 61 percent of domestic, non-federal 
hydroelectric capacity and nearly 80,000 megawatts overall in North 
America. Its membership consists of more than 140 organizations 
including public utilities, investor-owned utilities, independent power 
producers, equipment manufacturers, environmental and engineering 
consultants, and attorneys.
---------------------------------------------------------------------------
    NHA and its coalition partners strongly support the hydroelectric 
provisions included within the Energy Policy Act of 2005 (EPAct 05)--
both the hydropower licensing reforms and the inclusion of certain 
hydropower development in the tax incentive provisions.
    NHA appreciates this opportunity to testify on behalf of the 
hydroelectric industry regarding the hydroelectric provisions within 
EPAct 05. Our message this afternoon is simple--while we are still in 
the early stages of implementation, there is no question that the 
hydroelectric provisions included within EPAct 05 are having a positive 
impact. To date, 10 companies have availed themselves of the new 
licensing tools in 18 different hydropower project relicensings. We 
anticipate others will take advantage of these opportunities in the 
coming months. Agencies appear to be rethinking their approach to 
conditioning projects, and incremental hydroelectric generation is 
being built. The EPAct 05 licensing reforms and the tax provisions are 
making a difference.
    We commend Congress for passage of these provisions and believe 
they will result in increased energy production and energy savings, all 
while preserving important environmental values. These are important 
goals, particularly now as our nation struggles to find near and long-
term solutions to the problem of the high price of natural gas and oil.
    We deeply appreciate Senator Craig's longstanding and effective 
leadership on the hydroelectric licensing reform issue. For nearly a 
decade, Senator Craig has worked with colleagues on both sides of the 
aisle to address serious problems inherent in the licensing process. We 
also thank Chairman Domenici for his leadership, as well as Senators 
Ben Nelson, Smith, Cantwell and Feinstein who worked with Senator 
Craig, and their House counterparts, to find a bipartisan solution that 
was included in EPAct 05. The compromise guarantees equal access to the 
new reforms for all of those involved in the hydroelectric licensing 
process. In addition, we are appreciative of Senator Smith's leadership 
on the Finance Committee in securing the inclusion of certain new 
hydropower development in the renewable energy production tax incentive 
provisions of the Internal Revenue Code.
    While it was a long road to enactment, the effort was well worth it 
because the provisions adopted by Congress in 2005 are a major 
improvement in the hydroelectric licensing process. The provisions will 
help to preserve the viability of our nation's domestic hydropower 
resource. Hydropower is an emissions-free technology that provides 
significant environmental, economic and energy security benefits to the 
nation, supplying the country with seven percent of our electric 
generation and 85 percent of our clean renewable energy.

                       NEED FOR LICENSING REFORM

    Legislative reform of the hydroelectric licensing process was 
needed because of problems that existed with respect to the exercise of 
mandatory conditioning authorities under Sections 4(e) and 18 of the 
Federal Power Act (FPA) by the Departments of Interior, Commerce and 
Agriculture (Departments). Although the Federal Energy Regulatory 
Commission (FERC) issues hydroelectric licenses and is in charge of the 
overall process, FERC generally has no authority to modify or reject 
the conditions imposed by the Departments, and licensees had no avenue 
to challenge the scientific bases of mandatory conditions other than 
seeking judicial review of a FERC license order in the federal Court of 
Appeals.
    The broad authority of the Departments to impose conditions without 
necessarily considering either their impacts on energy production and 
other project benefits or cost-effectiveness has led to serious 
problems. For example, the National Marine Fisheries Service insisted 
on proposing a mandatory fish passage requirement on the Enloe Dam 
Project, rendering it uneconomic even though such passage was opposed 
by a fish and wildlife agency, an Indian Tribe and the Canadian 
government. Salmon had not historically accessed the stream above the 
existing dam and introducing this species could also transmit diseases 
that would harm resident fish. Similarly, in the recent relicensing of 
the Box Canyon Dam, the U.S. Fish and Wildlife Service insisted on a 
mandatory condition requiring fish passage for bull trout even though 
extensive field research indicated that there were no bull trout 
attempting to pass the Box Canyon Dam.
    FERC has made significant strides to improve the hydroelectric 
licensing process, including the newly implemented ``Integrated 
Licensing Process'' (ILP). However, FERC is generally without the 
authority to address problems associated with mandatory conditions 
issued by the Departments under Sections 4(e) and 18 of the FPA. 
Several years ago, the Departments undertook initial steps to improve 
the mandatory conditioning process. A federal advisory committee was 
formed and a series of meetings was held. In addition, the Department 
of Interior initiated a rulemaking in September 2004 to establish an 
agency administrative appeal process. However, neither of these actions 
addressed the essence of the problem--the imposition of mandatory 
conditions that were not cost effective and/or not supported by the 
facts. The appeals rulemaking was a positive step and our industry 
supported it. However, a final rule was never issued. This further 
confirmed that legislative reform was needed to improve the mandatory 
conditioning process.

COMMENTS ON THE DEPARTMENTS' INTERIM FINAL RULES IMPLEMENTING THE EPACT 
                                  2005

    When Congress enacted EPAct 05 last year, it directed the 
Departments of Interior, Commerce, and Agriculture to issue a joint 
rule within 90-days to establish ``procedures for such expedited trial-
type hearings . . .'' In response, the Departments issued interim final 
rules on November 17, 2005. The agencies requested public comment on 
the rules and indicated that revised rules may be issued in 2007 based 
on the comments received as well as the experience gained from real 
world application of the provisions.
    NHA submitted joint comments with the Edison Electric Institute on 
the interim rule on January 17, 2006. Our comments are attached to our 
statement as Appendix A 1a and we ask that they be made part 
of this hearing record. NHA strongly supported the agencies' rules. In 
particular, we endorsed provisions making the trial-type hearing and 
alternative conditions processes applicable to pending licensing 
proceedings where no license had been issued as of November 17, 2005. 
Further, NHA supported the Departments' clarification that the rights 
to propose alternative conditions and to a trial-type hearing apply to 
the exercise of reserved conditioning authority. We believe that any 
other approach would undermine the intent of Congress because it would 
establish a mechanism by which the Departments could avoid their 
Section 241 obligations by simply deferring the exercise of their 
authority until after final issuance of the license. We believe these 
provisions were necessary to implement the new law as Congress 
intended.
---------------------------------------------------------------------------
    \1a\ The appendix has been retained in committee files.
---------------------------------------------------------------------------
    In addition, we applaud provisions in the rules that mandate that 
the administrative law judge (``ALJ'') determines whether there are 
disputed issues of material fact, and that the ALJ's factual findings 
are final. We believe that these provisions will help prevent agency 
staff, who may be proponents of a mandatory condition, from unduly 
limiting access to the trial-type hearing process. Treating the All's 
findings of fact as conclusive should assure that the relevant 
conditions/prescriptions issued by the Departments are supported by the 
facts.
    Despite our strong support for some of the provisions of the 
interim final rules, NHA does have serious concerns about certain other 
provisions contained within the interim rules. Primary among these 
concerns is the rules' lack of clarity regarding the ``equal 
consideration'' standard. Section 231 of EPAct 05 requires that 
agencies demonstrate in writing that they gave equal consideration to 
the effects of a mandatory condition on energy supply, distribution, 
cost and use, flood control, navigation, water supply and air quality, 
for every condition submitted to FERC. NHA views the equal 
consideration provision as one of the most important licensing 
improvements within EPAct 05. We strongly believe that the equal 
consideration requirement applies to the development of all mandatory 
conditions. However, the Department of Commerce, in a licensing 
proceeding concerning a project in Augusta, Georgia, has taken the 
position that ``equal consideration'' only applies to their mandatory 
conditions if an alternative condition is submitted. We believe that 
Commerce's interpretation is in conflict with the plain language of 
Section 241 and must be reversed. NHA also believes that the 
Departments need to clarify the interim final rules to make clear that 
the equal consideration requirement applies to all mandatory 
conditions, preliminary and final, regardless of whether alternatives 
are offered.
    In addition, NHA is concerned that the interim rules do not provide 
for a trial-type hearing of up to 90-days as required by Section 241. 
We believe that the hearing schedule simply will not provide the 
opportunity to develop an adequate factual record as well as provide 
due process in many proceedings where there are a multiplicity of 
highly complex issues. Moreover, we are troubled that the interim final 
rules provide for a trial-type hearing on preliminary conditions, 
rather than final conditions.\2\ NHA believes this clearly conflicts 
with the intent of Section 241. We believe conducting hearings on 
preliminary conditions, which are not necessarily the conditions that 
the Departments will ultimately seek to impose on a license applicant, 
is an inefficient use of the resources of the Departments, license 
applicants, and other parties. Instead, providing the right to a trial-
type hearing on final conditions would be much more efficient and would 
ensure that the license applicants only utilize a trial-type hearing 
after all other avenues are exhausted.
---------------------------------------------------------------------------
    \2\ The American Public Power Association, in its comments on the 
rules, approached the trial-type hearing procedure differently. Though 
not objecting to a hearing on preliminary conditions, APPA asked the 
Departments to clarify that a hearing on a final condition is allowed 
if the final condition submitted differs substantially from the 
preliminary condition and/or relies on different material facts.
---------------------------------------------------------------------------
    In light of these concerns as well as other issues raised in our 
comments on the interim rules, NHA recommends that the Departments 
issue revised final hydropower rules no later than November 1, 2006, in 
order to better ensure that the full benefits of the hydroelectric 
licensing reforms enacted by Congress are obtained.

             EARLY EXPERIENCE WITH THE LICENSING PROVISIONS

    Since the passage of EPAct 05, the hydropower industry has embraced 
the use of the trial-type hearing and alternative condition provisions. 
Ten companies have filed to either offer alternatives and/or request a 
trial-type hearing involving the licensing of 18 projects. The 
Departments have yet to act on any requests for alternative conditions 
and only one trial-type hearing process has begun to date. The general 
sense of the industry is that Section 241 appears to be causing the 
agencies to exercise more care in the preparation of license conditions 
and to perhaps refrain, in some instances, from proposing conditions 
that are not supported by the facts. This, of course, is a very 
positive development.
    The posture of one of our member companies, Avista Corporation, is 
typical. Because of EPAct 05, the company has the option of filing a 
request for a trial-type hearing and/or alternative conditions in the 
Spokane River/Post Falls Projects relicensing proceeding. Avista has 
expended a great deal of effort working to achieve a settlement in this 
proceeding and it continues to pursue every settlement opportunity that 
presents itself. However, if these efforts do not bear fruit, EPAct 05 
provides Avista and all of the other participants in the Spokane River/
Post Falls relicensing process an alternative means of resolving 
differences through either alternative conditions and/or a trial-type 
hearing. Avista believe this adds valuable flexibility and scientific 
rigor to the relicensing process that significantly increases the 
likelihood of positive relicensing outcomes.
    Since the interim hydropower licensing rule went into effect on 
November 17, 2005 license applicants have filed 17 requests for trial-
type hearings, in 13 project relicensings. Hearing requests have been 
filed before all three agencies--Interior, Agriculture and Commerce. 
The majority of the trial type hearing requests have been filed before 
the U.S. Forest Service within the Department of Agriculture (eight of 
17), six have been filed at the Department of the Interior, and three 
before the National Marine Fisheries Service.
    License applicants have also offered alternative conditions in 18 
project relicensings. In twelve projects alternatives were offered in 
response to mandatory conditions proposed by the U.S. Forest Service 
within the Department of Agriculture. In seven projects alternatives 
have been offered in response to conditions proposed by the Department 
of the Interior, and in three projects alternatives have been proposed 
to the National Marine Fisheries Service in the Department of Commerce.
    As these numbers clearly demonstrate, the licensing reform 
provisions addressed a significant need. These new tools are important 
and the industry is making full use of them. However, we are still in 
the very early stages of implementation of these provisions. NHA 
encourages this Committee to continue its oversight and recommends that 
another hearing next spring may be appropriate to review the experience 
of licensees, the agencies and stakeholders.

      INCLUSION AND EXTENSION OF HYDROPOWER PRODUCTION INCENTIVES

    While not the main focus of this hearing, it is critical to note 
the importance of the tax provisions included in the Act. We are 
particularly appreciative that EPAct 05 expanded the definition under 
the Section 45 production tax credit (PTC) to recognize certain new 
hydropower projects as eligible renewable resources. The credit for 
hydropower is 0.9 cents per kilowatt hour. In addition, for tax-exempt 
entities, EPAct 05 created a new category of clean renewable energy 
bonds (CREBs) that provide a financial incentive for public power, 
electric co-ops and others to issue modified, interest-free bonds to 
build qualified renewable energy projects.
    The PTC needs further revision to fully achieve its intent to bring 
new, clean electric energy online. Because of the time constraints 
placed on this program, its usefulness to industry is unnecessarily 
limited. The PTC limits application only to those projects that are 
placed in service by January 1, 2008. In many instances, this tight 
window of time does not give the hydropower industry the opportunity to 
license, site, and construct a qualified hydropower energy resource. 
Under good circumstances securing license amendments can take six 
months or more, designing and fabricating one-of-a-kind hydroelectric 
generators can take two to three years, and installation can take 
another year or more. Realistically, for licensees to take advantage of 
the PTC, the placed in service date needs to be extended this year 
through at least 2010, or longer, in order for anything close to the 
full potential to be realized.
    In addition, the amount of the Section 45 PTC for qualifying 
hydropower energy resources is at a level that is only one-half the 
level of most other renewable energy resources. NHA believes that new 
qualifying hydropower resources should receive the same tax benefit as 
other renewable resources, such as wind power.
    The clean renewable energy bond program functions somewhat 
differently from the PTC. The Energy Policy Act of 2005 provided $800 
million of authorization for CREBs from January 1, 2006 through January 
1, 2008. Although authorized for two years, the $800 million 
authorization is already oversubscribed by well over a billion dollars. 
Congress should extend the program immediately and ensure that it is 
funded at levels sufficient to unlock pent up demand among not-for-
profit utilities to finance new hydropower projects.
    Despite the limitations, some projects have been able to utilize 
these provisions. To date, FERC has received two requests from 
licensees to certify incremental hydropower for eligibility for the 
PTC, which will result in a 2.6 percent and 6.4 percent increase in 
generation for those projects. In addition FERC has recently received 
four license amendment applications for additional capacity totaling 17 
megawatts, which may qualify for the credit. A number of companies have 
also applied for clean renewable energy bonds for hydropower.
    For the most part, these companies were able to use the provisions 
for these projects because they ordered equipment and began the license 
amendment process well in advance of the enactment of EPAct 05. These 
companies took a financial risk that few companies are capable of 
undertaking. We know of many utilities and developers that are forgoing 
the development of clean, incremental hydropower either because of 
insufficient funding for the CREBs program or because they cannot meet 
the deadlines of the PTC or CREBs programs. As a result, our nation 
loses the opportunity to develop more emissions-free, domestic energy 
at a time when we need it the most. This simply does not make sense and 
we urge this Committee to work with the Senate Finance Committee to 
revisit, extend and revise these tax provisions.

                               CONCLUSION

    While it remains early in the implementation phase, the 
hydroelectric provisions contained within EPAct 05 have begun to make a 
difference. Hydropower owners are using these provisions in a 
responsible way to improve licensing outcomes that will result in more 
economic energy production while preserving environmental values. The 
National Hydropower Association commends Congress for its enactment of 
these provisions, and we look forward to working with you to ensure 
their effective implementation.
    Finally, we again thank you, Mr. Chairman, and many of the members 
of this Committee, for your leadership, perseverance, and steadfast 
support to make significant improvements in hydropower policy that will 
preserve our nation's hydroelectric resource while protecting our 
nation's rivers.
    Thank you.

    Senator Craig. Dan, thank you for that testimony.
    Now let us turn to Andrew Fahlund, vice president of 
protection and restoration, American Rivers. Andrew, welcome to 
the committee.

 STATEMENT OF ANDREW FAHLUND, VICE PRESIDENT FOR CONSERVATION, 
 AMERICAN RIVERS, STEERING COMMITTEE MEMBER, HYDROPOWER REFORM 
                           COALITION

    Mr. Fahlund. Thank you very much. Mr. Chairman, 
distinguished members: Good afternoon and thank you for 
inviting me to testimony at this important oversight hearing. 
My name is Andrew Fahlund and I am vice president for 
conservation programs with American Rivers, the leading 
national voice for rivers and river communities. I am also a 
member of the Steering Committee of the Hydropower Reform 
Coalition, a consortium of 130 groups from around the Nation 
whose common goal is ecological and recreational enhancement at 
hydropower dams.
    American Rivers staff have logged hundreds of hours 
collaborating with utilities, agencies, American Indian tribes, 
and others to improve the efficiency and effectiveness of the 
hydropower licensing process. These actions speak to the fact 
that we are not obstructionists, opposed to change. We are 
advocates for efficiency, fairness, and of course strong 
protections for public trust resources.
    Over the course of the debate surrounding the energy bill, 
American Rivers stated its consistent opposition to the 
hydropower title, cautioning that the proposed hydropower 
provisions would bias the process in favor of licensees who 
have vastly more resources than other parties. We also 
cautioned that it would lead to a steady erosion in the 
implementation of many vital and important environmental 
conditions.
    Although proponents claimed that the energy bill did not 
eliminate so-called mandatory conditions, fish passage, and 
protections for public lands, we warned that the imposition of 
overwhelming red tape on resource agencies and a hideously 
litigious process would provide enough incentive to curtail 
their use. While it is still early to be certain what the 
outcomes will be on many of these proceedings, it appears that 
our fears were not unreasonable. The mere request for a trial-
type hearing, no matter how trivial, imposes a significant 
burden on all stakeholders, including the agencies. Each party 
must gather evidence, line up witnesses, file interventions, 
meet onerous and complex service requirements, hire costly 
lawyers, and begin pretrial discussions, all within a few short 
weeks.
    Most licenses used to be decided through negotiation and 
settlement. These new rules mark the beginning of a war of 
attrition, one that will divert time and attention from 
negotiation and settlement toward litigation. The new process 
is extremely burdensome for agencies, which have been granted 
no additional time to participate in trial-type hearings. The 
alternatives process requires Federal resource agencies to 
consider 11 new factors in developing their environmental 
conditions. Congress needs to appropriate additional funding to 
the agencies to ensure that they can carry out these new 
mandates.
    Thus far there has been a proverbial gold rush of requests 
for this sort of administrative litigation, with high-priced 
lawyers appearing to be the only ones guaranteed to benefit. 
There have been 13 requests for hearings, addressing roughly 
100 separate disputes, and dozens of requests for alternative 
conditions. The rules invite hearing requests, trial-type 
hearing requests, that are not disputes over material facts, 
but are instead disputes over policy and law. Industry seems to 
consider almost anything these days a material fact.
    FERC, which has a process of requesting trial-type hearings 
on disputed issues of material fact, has the ability to screen 
whether a request is worthy of a trial or could be resolved 
through a paper process. We strongly urge the agencies to adopt 
similar discretion, that they strictly limit hearings to true 
disputes over facts, and that Congress support those changes.
    The FERC process was already complex, but with the passage 
of the Energy Policy Act 47 more pages were added to the rules. 
These rules establish a set of steps, timelines, and 
requirements so complex that license applicants, agencies, and 
non-governmental organizations alike are struggling to 
understand and comply with them, and it is no wonder. The 
agencies moved forward with implementing the new rules without 
any consideration of any public comment from any party. The so-
called interim final rules are not even complete. The rules 
fail to answer who has the burden of proof in a trial-type 
hearing, the hearing requester or the agency that proposed the 
conditions. This is fundamental. The rules seek comments on 
this question, ignoring the fact that perhaps dozens of trial-
type hearings will take place before the rules are re-issued. 
Hearing examiners will have to determine the burden of proof on 
an ad hoc basis during that period. In FERC's trial-type 
hearings, as in all administrative law, it is the hearing 
requester that has that burden of proof. We continue to urge 
the agencies to follow FERC's lead and for Congress to support 
them.
    I would like to commend the Senate Energy and Natural 
Resources Committee and you, Mr. Chairman, for exercising your 
oversight role and urge you to maintain this oversight to 
prevent the loss of reasonable and important environmental 
conditions to red tape, litigation, and political pressure. The 
committee also must ensure that the new process for hydropower 
licensing is adequately funded. Dams whose licenses expire 
today have never been subject to modern environmental laws. 
Hydropower licensing is a once in a lifetime opportunity to 
bring a 19th century technology up to 21st century standards. 
We hope that these rules and this law will not stand in the way 
of that.
    Thank you.
    [The prepared statement of Mr. Fahlund follows:]

Prepared Statement of Andrew Fahlund, Vice President for Conservation, 
American Rivers, Steering Committee Member, Hydropower Reform Coalition

                            I. INTRODUCTION

    Good afternoon, Mr. Chairman, and members of the Senate Energy and 
Natural Resources Committee. I appreciate the opportunity to appear 
before you today and am grateful that the Committee is exercising its 
oversight role in ensuring the effective implementation of the 
hydroelectric provisions of Energy Policy Act of 2005 (EPAct, P.L. 109-
58). My name is Andrew Fahlund and I am the Vice President for 
Conservation at American Rivers, the leader of a national river 
movement, dedicated to protecting and restoring the nation's rivers 
some of our greatest community assets. American Rivers has more than 
45,000 members, from every state across the country and has more than 
fifty staff members in ten different offices. As a steering committee 
member of the Hydropower Reform Coalition, I also speak for 130 
national and local organizations dedicated to improving rivers through 
the licensing of hydropower projects by the Federal Energy Regulatory 
Commission (FERC). Coalition members are active in more than 75 percent 
of the relicensing cases currently pending before FERC and have 
constructively contributed to numerous policy discussions concerning 
FERC regulated hydropower.
    More specifically, I am before you today to share the opinions of 
American Rivers and the Hydropower Reform Coalition on the 
implementation of the EPAct. My testimony addresses three basic points:

          1. Hydropower relicensing significantly improves 
        environmental quality at a negligible cost to power supply.
          2. The EPAct rules tilt the scales of justice in the favor of 
        industry and disadvantages states, tribes, local landowners, 
        irrigators, conservation groups, and other interested members 
        of the public who all have interests in how dams are operated.
          3. The outcome of the hydroelectric EPAct rules is regulatory 
        complexity, decreased certainty, a lengthened timeline for 
        licensing, increased costs for all parties, and diminished 
        environmental standards.

    I would like to stress that hydropower relicensing is a natural 
resources issue and not simply an energy issue, due to the enormous 
impacts dam operations have on hundreds of species, thousands of river 
miles, and millions of dollars in recreational opportunities for 
decades to come. Changes to dam operations that better conserve natural 
resources have a negligible impact on energy generation, electric 
rates, and industry viability.
    While hydropower has provided significant benefits to society over 
the past 100 years, this has not come without a cost to our rivers and 
the communities they flow through. Dams harm the physical, chemical, 
and biological function of rivers by disrupting flows, degrading water 
quality, and blocking passage of fish and other species. Simple changes 
in the operating procedures for these projects can significantly reduce 
these impacts without significantly reducing generation.
    When the scores of hydroelectric licenses scheduled to expire over 
the next decade were originally licensed decades ago, meeting 
environmental standards was not required and our understanding of 
complex ecological systems was in its infancy. For decades, these 
projects have operated with minimal environmental controls leading to 
significant and sometimes irreversible damage. Current relicensing 
represents our first opportunity to review these dams, reservoirs, and 
turbines, and to place environmental safeguards on them for the next 30 
to 50 years that will improve our rivers and protect fish and wildlife 
for our children and grandchildren.
    American Rivers and members of the Hydropower Reform Coalition wish 
to ensure that dams are operated to protect and restore river resources 
using best available technologies and best management practices. 
Coalition members including American Rivers have been involved in the 
relicensing of more than 300 dams over the past ten years, supporting 
the continued operation of more than 9,000 megawatts of electricity 
capacity. According to FERC, the relicensing of more than 140 
hydropower projects resulted in an average per project generation loss 
of only 1.6%.
    The Federal Power Act (FPA), although commonly considered an energy 
statute, also occupies an important role in environmental protection. 
The statute was amended in 1986 to require FERC to give ``equal 
consideration'' to power (electricity generation) and non-power (fish 
and wildlife protection, recreation, etc.) benefits of the river. 
However, Congress did reserve specific authorities to expert federal 
and state resource managers to establish basic conditions that form a 
floor above which FERC then establishes license conditions in the 
public interest. Sometimes referred to as mandatory conditions, the 
statutory requirements assure that:

          1. Fish can be passed upstream and downstream of a dam (FPA 
        Section 18); \1\
---------------------------------------------------------------------------
    \1\ Section 18 of the Federal Power Act grants authority to the 
Secretaries of Commerce and the Interior to mandate the construction 
and operation of fish passage. Section 4(e) grants authority to land 
management agencies to ensure that projects on their lands meet current 
management goals and objectives. These authorities have been upheld by 
the courts on a regular basis. Escondido Mutual Water Company et al. v. 
La Jolla Band of Mission Indians, et al., 466 U.S. 765, 777 (9th Cir. 
1984) (citations omitted); Bangor Hydro v. FERC, 78 F.3d 659 (1st Cir. 
1996); American Rivers v. Federal Energy Regulatory Commission, 187 
F.3d 1007, 1030 (9th Cir. 1999).
---------------------------------------------------------------------------
          2. If a nonfederal dam is located on federally owned land, 
        the purposes of the federal land are protected (FPA Section 
        4(e)); \2\ and
---------------------------------------------------------------------------
    \2\ More than 400 FERC regulated projects are located on Forest 
Service, Bureau of Land Management, and tribal lands. These projects 
have impacts on water resources, recreation, fish and wildlife, and 
cultural resources and also receive the benefit of below market rent. 
U.S. General Accounting Office, Federal Energy Regulatory Commission: 
Charges for Hydropower Projects' Use of Federal Lands Need to Be 
Reassessed, Washington, D.C., May 2003, GAO-03-383, p. 5.
---------------------------------------------------------------------------
          3. The dam complies with state-developed water quality 
        standards (Clean Water Act, Section 401).\3\
---------------------------------------------------------------------------
    \3\ The protection of water quality is a responsibility that has 
been delegated to the states since the Clean Water Act was adopted 30 
years ago. Section 401 ensures that private hydro projects will not 
conflict with state standards and requires each federally licensed 
project to obtain a state certification. The Supreme Court confirmed in 
PUD No. 1 of Jefferson County v. Washington Dep't of Ecology, 511 U.S. 
700 (1994), that these standards include chemical, physical, and 
biological parameters.

    These laws establish the simple rule that hydroelectric projects 
must meet basic environmental standards before operating on our rivers. 
Just as we should not allow coal-fired plants to operate without modern 
emissions control devices, hydro plants should not operate without use 
of best available technologies and practices.

     III. SOME IMPROVEMENTS TO THE RELICENSING PROCESS ARE WORKING

    For the last ten years, American Rivers and members of the 
Hydropower Reform Coalition have been working with industry, federal 
and state agencies, and FERC to make administrative improvements to the 
hydropower licensing process. We have made steady progress in a number 
of areas, including federal agency actions and procedures to ensure 
consistency, timeliness, and coordination. We are concerned that EPAct 
and its implementing rules threaten and undermine that progress and we 
ask that the Committee utilize its oversight role to prevent this from 
happening.
    Since 1997, FERC has undertaken two rulemaking efforts to 
streamline hydropower licensing. The first effort was the Alternative 
Licensing Process (ALP), established on October 29, 1997, designed to 
promote collaboration and settlement in hydropower licensing. From 2001 
through 2004, of the total 135 licenses issued by FERC, 51 licenses or 
38% were settlement agreements. Interestingly, settlements accounted 
for 71% of the total electrical capacity of licenses issued during that 
time, or 3,208 megawatts.
    Effective October 23, 2003, FERC established a positive new 
licensing process called the Integrated Licensing Process (ILP), 
designed to establish a single ``integrated'' environmental analysis. 
The proposal was the culmination of work by FERC staff and federal 
agencies as well as a parallel process initiated by hydropower 
licensees, conservation groups, state agencies, and Indian tribes. FERC 
estimates that the ILP will reduce the average time it takes to 
complete the licensing process by 60%. Further, it estimates that the 
proposed process will reduce the cost of licensing for a project below 
5 megawatts by $150,000 and for a project greater than 5 megawatts by 
$690,000.\4\ American Rivers supports the Integrated Licensing Process.
---------------------------------------------------------------------------
    \4\ Commissioner Nora Brownell, Federal Energy Regulatory 
Commission, Testimony before the Subcommittee on Energy and Air 
Quality, Committee on Energy and Commerce, House of Representatives, 
Washington, D.C., March 5, 12, and 13, 2003.
---------------------------------------------------------------------------
 IV. THE AGENCIES' EPACT RULES BIAS THE LICENSING PROCESS AND HARM THE 
                              ENVIRONMENT

    American Rivers and the Hydropower Reform Coalition opposed EPAct 
because we feared that it would increase regulatory complexity, 
decrease certainty, lengthen the timeline of license issuance, provide 
unjust advantages to hydropower dam owners, establish hurdles to the 
full participation of states, tribes, homeowners, businesses, and other 
members of the interested public, and diminish environmental quality. 
Moreover, we expressed repeated concerns that the new provisions of 
EPAct would undermine the increasingly common practice of local 
solutions developed through settlement. Rather than spending their time 
trying to reach resolution, we warned that parties would be forced to 
take sides, and spend scarce resources and time on drafting legal 
documents and participating in adversarial hearings. The publication of 
the new rules, as well as their initial implementation, suggests that 
our earlier fears were justified.
A. EPAct rules skew the processes to favor licensees
    The EPAct rules are skewed to favor those parties with substantial 
financial resources. To request a trial-type hearing and propose 
alternative conditions, one must act on deadlines as short as 15 days 
to hire expensive legal counsel and technically skilled witnesses, and 
gather new data. Only licensees have the financial resources to 
undertake that process over and over again and at the level of 
sophistication required for success. Because the agencies must conduct 
these trials upon request, any party with an interest in the conditions 
and prescriptions appealed must expend its limited resources to 
intervene and participate in the trial-type hearing, because the 
decision of the Administrative Law Judge is final with respect to the 
disputed issues of material fact (7 C.F.R. Sec. 1.660).
    Likewise, the process for requesting alternative conditions favors 
the license applicant. The entity most likely to file for an 
alternative condition is the license applicant because the law grants 
preferential status to alternative conditions that cost significantly 
less and generate more electricity. The rules however, magnify that 
inequity by failing to give other interested parties any clear venue in 
which to comment on the proposed alternatives. For proceedings in which 
the preliminary conditions or prescriptions were filed after November 
17, 2005, the rules imply that comments on alternatives should be filed 
through comments on FERC's National Environmental Policy Act (NEPA) 
document. The appropriate venue for comment should be the resource 
agency, not FERC, since it's the resource agency's alternative 
conditions.\5\ In retroactive cases, those with conditions filed before 
November 17, 2005 and for which the NEPA documents have already been 
published, the rules unfairly do not offer a clear avenue for public 
comment at all. Likewise, in cases in which the resource agency accepts 
the alternative condition or prescription as its own, the rules provide 
no clear opportunity for comments or appeals.
---------------------------------------------------------------------------
    \5\ FERC has a different mandate, balancing interests, schedule, 
and requirements. (70 Fed.Reg. 69,807, cols. 1 and 2. Also, see: 7 
C.F.R. Sec. 1.673)
---------------------------------------------------------------------------
    In addition to imposing severe hardships on nongovernmental, 
tribal, and state and local agency license parties, the rules are 
extremely burdensome for the federal agencies, which have been granted 
no additional funding authorization to participate in or administer 
trial-type hearings or to conduct the complex analyses envisioned in 
the alternative conditions process. According to the rules, the 
``Departments expect 47 requests for hearings per year under the rules, 
each requiring about 800 hours of additional work by the requesters and 
600 hours for other parties in the hearing process. The Departments 
expect about 351 alternative conditions and prescriptions to be 
proposed per year under the rules, each requiring 200 hours of 
additional work by the proponent and 120 hours for other parties to the 
alternatives process. Staff costs for 47 hearing requests and 351 
alternatives per year are estimated at $5 million.'' (70 Fed. Reg. at 
69815). A worst case scenario is double those amounts. It is clear that 
the hearings and alternatives processes could easily overrun the 
licensing process. This Committee should aggressively push for ample 
funding for agencies to engage in trial-type hearings and conduct the 
evaluations required in the alternative conditions process.
B. The EPAct rules invite frivolous filings
    During the debate over EPAct, we warned that the proposed trial-
type hearings would invite abuse and a new culture of litigation not 
seen in the relicensing process for the past decade. Again, the new 
rules and their initial implementation appear to confirm our concerns. 
The law requires hearings only on issues of material fact (Section 
241(a) of the Federal Power Act), yet the rules require agencies to 
move forward with initial preparations without even a threshold 
determination of whether a request for a trial-type hearing raises any 
such issues (7 C.F.R. Sec. 1.625). Further, the rules fail to grant the 
resource agencies the authority to determine which issues were 
appropriate for a trial-type hearing, which could be resolved through 
paper filings, and which fail to qualify at all as issues of material 
fact. It is the epitome of government waste to reflexively provide for 
trial-type hearings without determining whether one is warranted. The 
costs associated with convening an Administrative Law Judge hearing 
every time a party files a request will add up and will either result 
in needless taxpayer expense or surrender by agencies that don't have 
the resources to respond.
    This approach is also unreasonably burdensome for other parties who 
are forced to respond or live with the results. The mere request for a 
trial-type hearing, no matter how trivial, will impose a significant 
financial burden on all stakeholders with an interest in the condition 
or prescription to gather evidence, obtain witnesses, file 
interventions, meet onerous and complex service requirements, secure 
costly representation, and begin pre-trial discussions, all within 
short deadlines to prepare for a formal adjudicatory hearing that is 
not allowed and may not be necessary at all.
    FERC has the authority to hold hearings on disputed issues, but has 
largely abandoned the process in lieu of paper filings, except in rare 
cases, at significant savings of time and resources for all parties. 
Agencies should exercise similar authority in the rules.
    Several requests for trial-type hearings under EPAct already 
demonstrate the flaws in this automatic-hearing provision. One utility 
filed a petition for a hearing challenging assertions that were never 
even made by the agency.\6\ In response to another petition for a 
hearing, the U.S. Forest Service found that 24 of 26 alleged disputed 
issues of material fact do not qualify as such factual, disputed, and 
material.\7\ Worst of all, some companies have requested trial-type 
hearings for matters that could be resolved by a simple phone call or 
meeting. Instead, the implementation of the rules has fostered a 
culture of litigation.\8\
---------------------------------------------------------------------------
    \6\ Examples include ``factual issues'' as to whether sandbars are 
below the ordinary high water mark (this determination would not affect 
the agency condition) and whether Hells Canyon Complex is the sole 
cause of erosion (an assertion never made by the Forest Service). U.S. 
Forest Service, USDA Forest Service Answer to Idaho Power Company, 
Hells Canyon Complex (FERC Project No. 1971) Request for Hearing, April 
13, 2006.
    \7\ U.S. Forest Service, USDA Forest Service Answer to Idaho Power 
Company, Hells Canyon Complex (FERC Project No. 1971) Request for 
Hearing, April 13, 2006.
    \8\ PG&E requested a trial-type hearing on the ``reasonableness'' 
of the eradication of noxious weeds. In its request for alternative 
conditions, the company recommends that noxious weeds be ``controlled'' 
rather then ``eradicated.'' Pacific Gas and Electric Company, Pacific 
Gas and Electric Company's Request for Administrative Hearing on 
Material Issues of Disputed Fact on Certain Final Section 4(e) 
Conditions Submitted by the United States Forest Service for the Poe 
Hydroelectric Project, FERC Project No. 2107, December 16, 2005, p. 19; 
and Pacific Gas and Electric Company, Pacific Gas and Electric 
Company's Submittal to the USFS of Alternative Conditions for Certain 
preliminary Section 4(e) Conditions Submitted by the USFS for the Poe 
Hydroelectric Project, FERC Project No. 2107, December 16, 2005, p. 54.
---------------------------------------------------------------------------
C. The EPAct rules make a complex process more so
    At a time when everyone is working to streamline hydropower 
licensing, the EPAct rules add complexity and confusion to the process. 
The 47 pages of rules establish a set of steps, timelines, and 
requirements so complex that license applicants, agencies, and non-
governmental organizations alike are struggling to understand and 
comply with them. For example, the service requirements, which differ 
among the three relevant agencies establish different rules for serving 
documents to one group of stakeholders versus another. (7 C.F.R. 
Sec. 1.612 and 1.613) Agency staff can only be served with paper 
copies, ignoring the fact that we live in an electronic age. There is 
no central database or website to track filings or decisions made in 
the various trial-type hearings.
    The regulations are curiously silent on which side has the burden 
of proof in trial-type hearings or how such hearings will even be run. 
Although the rules are deemed ``final'' by the agencies, they still 
seek public comments on this question, ignoring the fact that perhaps 
dozens of trial-type hearings will take place before the rules may be 
re-issued in a year and a half and any clarifications or changes may be 
made. (70 Fed.Reg. at 69813, col. 3) Common sense and now experience 
show that this and many other provisions in the rules need such 
clarification. The agencies could have avoided this ambiguity if they 
had simply taken the time for a meaningful notice and comment process 
prior to issuance and implementation of an interim final rule.
    The alternatives process mandated by EPAct in Section 241 adds 
complexity through the mandate that federal resource agencies consider 
eleven new factors in developing their environmental conditions. 
Consideration of these factors places an enormous burden on the 
resource agencies. At present, the relevant state and federal agencies 
do not have sufficient staff or funding to meet these proposed 
requirements for new, complex analyses which are beyond historic scope 
of their resource protection responsibilities. Again, it is critical 
that Congress provide these agencies with the resources necessary to 
carry out these new unfunded mandates.
D. The EPAct rules lengthen the licensing timeline
    EPAct requires that the regulations must ensure compliance for the 
trial-type hearing ``within the timeframe established by the Commission 
for each license proceeding.'' (Section 241 of the FPA) However, the 
EPAct rules allow a waiver for all proceedings with preliminary 
conditions filed as of November 17, 2005, enabling them to apply the 
new rules and substantially altering the licensing schedule for these 
projects. (7 C.F.R. Sec. 1.601 and 1.604 and 70 Fed.Reg. at 69815, col. 
2) The rules unfairly allow the Departments to modify the sequence and 
timing of the new processes to accommodate these requests. The 
Departments, in clear violation of their own rules which precluded any 
further extensions, also granted an even longer extension of EPAct 
timelines for one project.\9\
---------------------------------------------------------------------------
    \9\ Letter to Magalie R. Salas, Federal Energy Regulatory 
Commission from Andrew L. Raddant, Regional Environmental Officer, U.S. 
Department of the Interior, re: Modified Fishway Prescription, Bar 
Mills Hydroelectric Project, P-2194, December 12, 2005; and letter to 
Magalie Salas, Secretary, Federal Energy Regulatory Commission from 
Patricia A. Kurkul, Regional Administrator, National Marine Fisheries 
Service, Northeast Region, National Oceanic and Atmospheric 
Administration, United States Department of Commerce, re: Bar Mills 
Hydroelectric Project (FERC No. 2194), December 12, 2005.
---------------------------------------------------------------------------
E. The EPAct provisions decreases environmental protection
    Our fundamental fear concerning EPAct was that the net result of 
the new provisions would result in less protection for environment. The 
addition of numerous procedural hurdles opens an array of new avenues 
for challenge and litigation of protections for fisheries and federal 
lands. The threat of a costly trial-type hearing, which agencies have 
not been given additional resources to hold, is a powerful incentive 
for agencies to not propose conditions to protect natural resources in 
the first place. It remains to be seen whether these fears will come to 
fruition but it is important Congress to monitor whether there is a 
decline in environmental conditions.

                             VI. CONCLUSION

    American Rivers, along with our colleagues in the conservation 
community, dozens of States and American Indian Tribes, and other 
stakeholders warned that the hydropower licensing provisions in EPAct 
would make the relicensing process more complex, litigious and threaten 
public trust resources that already bear the brunt of relicensing 
delays. The complexity of the implementing rules and our initial 
experience with implementation appear to confirm these fears. We 
strongly urge the Committee to continue to exercise its oversight role 
to evaluate whether the objectives of EPAct--a timely check and balance 
on resource agencies--are being met, or whether the complexity of the 
new provisions is effectively eliminating these critical resource 
protections. In particular, this Committee should pay close attention 
to whether the agencies are swamped by frivolous requests for hearings 
that do not raise disputes of material fact or matters that don't 
require the expense and formality of a ``trial-type'' hearing. Congress 
should also ensure that EPAct is not an unfunded mandate for the 
resource agencies and that they are able to meet their responsibility 
to participate in the licensing process, timely issue conditions and 
prescriptions, participate in trial-type hearings, evaluate alternative 
conditions, and undertake newly required analyses.

    Senator Craig. Andrew, thank you for your testimony. We 
appreciate it.
    We will follow a 5-minute rule here for our questioning 
today. Let me start that off, and let me ask this question of 
all of the witnesses. Regarding the new equal consideration 
provision that requires the respective Secretaries to 
demonstrate in writing that they give equal consideration to 
the effects of a mandatory condition on power and non-power 
issues, it is my understanding that the Department of Commerce 
has taken the position that equal consideration applies only if 
an alternative condition is submitted. Is that your 
understanding of the act or do you believe that the equal 
consideration requirement applies to all mandatory conditions 
regardless of whether alternatives are offered?
    Mr. Robinson. No, that is not my understanding. Equal 
consideration should be applied to both preliminary conditions 
and final conditions. It would make little sense to have two 
sets of criteria within the same agency to design different 
outcomes. In fact, it would be very helpful if under the 
preliminary conditions the agencies provided that equal 
consideration record with the preliminary conditions to 
demonstrate why it is in the public interest.
    Senator Craig. Anyone else? Yes.
    Mr. Finfer. Mr. Chairman, I cannot answer for the 
Department of Commerce, but I can say that in the Interior 
Department this issue has been raised to a policy level and is 
being considered now. What we hope is that we can have a 
position soon and discuss it with the other Departments and 
arrive at a consistent outcome.
    Mr. Adamson. I would say when in doubt read the statute, 
and the statute is very clear. It provides that equal 
consideration has to be documented, quote, ``with any 
condition'' under section 4(e) or, quote, ``any prescription'' 
under section 18. So I think it is pretty clear that equal 
consideration was intended across the board.
    Senator Craig. Andrew, any comment on this provision?
    Mr. Fahlund. Well, I guess my only comment is perhaps a 
little less responsive to your question and more just a general 
restatement of what I said in my testimony, which is that I 
think, however you slice it, these agencies are in dire need of 
support and additional funding for their participation. If you 
look across the board, agencies throughout the country are 
struggling to just keep up with the workload under the past 
rules and statute. To keep up with this additional burden I 
think is going to require some additional support.
    Senator Craig. Well, you make an excellent point. As I 
think we get into this, we will see the burden of the agencies, 
and it is their job to be forthcoming with the necessary 
requests for resources. This being the authorizing agency, we 
should be due diligent in that area. I appreciate that comment.
    Another question of all of you. In your opinion, what 
constitutes a disputed issue of material fact for purposes of 
invoking the right to a trial-type hearing? Is it not important 
that an independent administrative law judge make this 
determination?
    Mr. Robinson. I think a material issue of dispute of fact 
is one that is pertinent to the issue or to the condition, 
whatever stage it is in, preliminary or final. And it does seem 
appropriate to have an ALJ have the opportunity to decide 
whether or not in fact it is an issue of fact.
    Mr. Finfer. Mr. Chairman, that is exactly what the rules 
do. They do provide for the ALJ to make that determination. 
``Material fact'' is defined as a an issue which, if proved, 
would affect the Department's decision to affirm, modify, or 
even withdraw a condition. In so doing, the rule also states 
that it does not cover legal or policy issues.
    Senator Craig. Dan.
    Mr. Adamson. I think it is really important and, if you 
look at the early results in the hearing process, what the 
agency counsel have done is essentially state that every single 
issue raised, every single one, by industry is not a material 
fact. The judge just dealt with this issue in the Hell's Canyon 
proceeding and he said, no, you are wrong, to the agency 
counsel, you are pretending as if this statute has not passed. 
So he did not agree that every issue the company had raised was 
a material fact, but I would say about three-fourths of them.
    So if you let Interior staff that have actually worked on 
the condition, or Commerce--I do not mean to pick on Interior--
decide whether or not a license applicant or an environmental 
group or what have you has the right to a hearing, they have a 
lot of stake in that hearing not taking place. So you have to 
have the judge decide, and he or she will be the determinant as 
to whether or not you get a hearing.
    Senator Craig. Any additional comment, Andrew?
    Mr. Fahlund. I would urge that if the ALJ's are to decide 
whether an issue is a material fact, I think that reaching some 
form of summary judgment very immediately, before everybody 
pours enormous investment and time into a trial-type hearing, 
is really critical, because if you do not actually cut out the 
frivolous lawsuits, if you will, from the ones that are 
actually meaningful and probative, then you are simply just 
creating this war of attrition that I was talking about before. 
You are just going to overwhelm the agencies and the ALJ's.
    It is our understanding that, at least with the Department 
of Commerce and Interior, that it is the district offices that 
are going to pay for each one of these things. You can just 
imagine a district manager confronted with the threat of all of 
these potential trials is going to quickly back off and run 
away, despite the merits of their case. This is just the 
realities of doing business out in the field.
    Senator Craig. Thank you all.
    Let me turn to Senator Bingaman.
    Senator Bingaman. Thank you.
    Mr. Robinson, one of the points that is made in Mr. 
Fahlund's testimony--I believe this is made in his testimony--
is American Rivers has brought suit challenging what they call 
retroactive application of the rules, that is that the rules 
allow license applicants to challenge conditions and 
prescriptions that were final before the date that the rules 
were enacted, or before the date of the enactment of the 
statute.
    Is that an accurate statement as to what the rules provide 
and, if so, how is that justified?
    Mr. Robinson. I think--and Mr. Finfer can correct me if I 
am wrong here. I believe the rules apply to those projects that 
are still pending as of November 17, 2005, the projects that 
are pending at the Commission still, have not been licensed as 
of November 17, 2005.
    Senator Bingaman. That date was the date that the rules 
became----
    Mr. Robinson. Published.
    Senator Bingaman. Were published?
    Mr. Robinson. Correct.
    Senator Bingaman. Okay. But they are not--a person is not 
able to challenge retroactively with regard to license 
applications where they have already been finalized, is that 
right? I mean, where the rules have been finalized.
    Mr. Robinson. As long as the license had not been issued 
prior to November 17, 2005, anything that was in that licensing 
proceeding is still pending, was available for going for 
alternative conditions or ALJ hearing.
    Senator Bingaman. So even if the condition was final, if 
the license had not been issued you could go back and 
challenge?
    Mr. Robinson. We had final 4(e) conditions and section 18 
prescriptions that were within the proceeding which was not 
completed, that were then available to go back to the Interior, 
Commerce, and Agriculture for review.
    Senator Bingaman. Do you think that is an acceptable 
arrangement?
    Mr. Robinson. Absolutely.
    Senator Bingaman. To go ahead and challenge those, even 
though they were finalized?
    Mr. Robinson. Absolutely. The proceeding is still pending, 
and it is not unusual for us to have reservations of authority 
for section 18 or 4(e), to do those conditions after the 
license has been issued.
    Mr. Adamson. Can I respond, Senator?
    Senator Bingaman. Sure, go ahead.
    Mr. Adamson. Thank you, Senator. A mandatory condition has 
no force and effect until FERC issues a license, and it often 
happens in these proceedings that it is years after the 
condition has been submitted that it is in a license, and the 
Departments always reserve their right to change the condition. 
So there is nothing retroactive. They have no force and effect 
until a license is issued. They do not apply to you.
    Senator Bingaman. Let me ask another question. And again, I 
guess Mr. Fahlund has raised this argument about war of 
attrition and just the amazing burden that is being put on the 
various agencies here. As I understand it, in your testimony, 
Mr. Adamson, you say that the resource agencies appear to be, 
quote, ``rethinking their approach to conditioning projects.'' 
I believe that is what you said.
    Is that in fact happening? Are the agencies rethinking 
their approach to conditioning projects and, because of the 
fear that they have got this amazing legal challenge now 
available to them, essentially backing off on the issuance of 
conditions? Is that a real danger?
    Mr. Finfer. Senator, if I may, the act certainly 
underscored the fact that we need to provide for a foundation 
for the fact that there may be a trial-type hearing. Therefore, 
we have got to outline our facts in a very meticulous way, 
provide detailed documentation and a very clear pathway of how 
they led to a condition, that is to anticipate that indeed a 
hearing may happen.
    But it does not follow from that that we would necessarily 
pull our punches on protecting resources. In fact, I would say 
quite the contrary has occurred, at least so far. The best 
example I can point to is the Klamath project conditions that 
were proposed by Commerce and Interior. Those were developed 
with full knowledge of the new section 241 and the 
understanding that hearing and alternative requests might be 
received, in fact were likely to be received. Yet these 
conditions are very comprehensive across the range of resource 
issues and we are very confident in them and we believe they 
are sufficiently protective.
    We are not the only ones who feel that way. In fact, Earth 
Justice, an organization that has strongly criticized the 
resource agencies and which in fact is representing the 
plaintiffs in the lawsuit against the rules, commented very 
favorably to the Washington Post after those conditions were 
submitted to FERC on Klamath. Just to quote, their 
representative said: ``It feels hopeful and it feels different. 
Credit is due the Government scientists who are finally saying 
the right thing and the politicians who are allowing them to 
say it.''
    I do not believe Earth Justice would have said that if they 
felt we were skimping on protection.
    Senator Bingaman. Mr. Fahlund, did you have a comment on 
this same issue?
    Mr. Fahlund. Just a brief response, and that is that, while 
I very much appreciate, like Earth Justice, the example set in 
the Klamath, I think that what we are going to find is that the 
highest profile cases are going to receive those resources 
necessary to do their job and the ones that are not, that do 
not have those resources, are not. That is where that war of 
attrition is going to take place.
    So projects where groups like American Rivers and others 
are really pushing aggressively on one side and the industry is 
pressing on the other, those are certainly going to merit the 
attentions and the resources of the agencies, while others I 
think are going to fall by the wayside.
    Senator Bingaman. Thank you very much, Mr. Chairman.
    Senator Craig. Senator Thomas.
    Senator Thomas. Thank you.
    You know, it is kind of interesting, gentlemen. I 
understand your principal responsibility apparently is 
regulation and licensing, but do any of you have any discussion 
or any thought or is there anything going on in your industry 
about efficiency or more production or increasing? That is kind 
of what we are talking about on energy these days. Do you have 
any feeling about that, any of you?
    Mr. Robinson. I think there are some aspects of EPAct 2005 
which you have also seen the early evidence of, for efficiency 
upgrades and additional capacity of hydroelectric projects and 
incentives associated with those. We have had two applications 
so far for projects, and I am hopeful we will see more, for 
those efficiency upgrades that were based solely on those 
incentives that you have provided. We also have four 
applications for increases in capacity of projects that may 
qualify for those incentives as well.
    Along with that, we have seen an uptick in the number of 
applications for new projects. I have been involved with 
licensing projects now for 29 years and probably over the last 
15 years it has been rare that we would get an application. I 
think we have something on the order of 16 pending license 
applications now.
    Mr. Adamson. Senator Thomas, I think, on behalf of the 
industry, this legislation will make hydro more cost effective 
and it will probably preserve in certain cases hydro that might 
otherwise go away because of the licensing process. I mentioned 
briefly the production tax credit on incremental hydro. A 
number of our members are building projects, are upgrading 
projects in response to that. So we think it is very important 
to have more hydro resources at existing plants, to increase 
their capacity, and hopefully new projects, as Mark Robinson 
has mentioned.
    Senator Thomas. Thank you.
    Mr. Finfer, have the new rules impacted the agencies' 
method of setting conditions? How many alternatives have you 
granted or denied?
    Mr. Finfer. Senator, in answering Senator Bingaman's 
question I indicated that the early notice was that we were 
still proceeding as we had before in meeting our 
responsibilities. In terms of actual actions to date, we have 
not acted in a complete way on any of the conditions or 
alternatives that have been proposed to us. That process is 
just under way. We are just having the first two hearings in 
June and in August respectively, after which we will have the 
results of the hearings and the alternatives will be assessed. 
There will be more proceedings this fall and this winter.
    So as of now, no actual findings have occurred.
    Senator Thomas. So there have not been any settlements 
reached?
    Mr. Finfer. In terms of settlements, yes. Settlement 
processes are continuing even when these requests have been 
filed, and in fact in two cases for which hearings have been 
requested settlements have been arrived at and the hearing 
requests have been withdrawn. There are more settlements among 
this group that are under way which could potentially occur.
    Senator Thomas. How do the agencies intend to implement the 
equal consideration provision of 33(b)?
    Mr. Finfer. We mentioned some of that in our rule, and 
specifically that equal consideration does not mean equal 
treatment, but literally what it says in plain language, that 
we will weigh the various impacts and concerns and try and 
consider them faithfully and equitably. The new process puts in 
place a very structured requirement whereby the Secretary 
involved has to produce a finding and determine whether to 
accept the condition. In fact, the process of course requires 
us to accept the condition unless we can demonstrate why it 
should not be accepted.
    As I have mentioned, we have not gone through that process 
yet for any condition.
    Senator Thomas. Sounds pretty complicated.
    Mr. Robinson, has FERC invoked the dispute resolution 
process yet?
    Mr. Robinson. No, we have not. We have not gotten that far 
down the process.
    But if I could just make one comment about this war of 
attrition very quickly. I actually see this quite differently 
than the way it has been represented. I think over time what we 
will see is a coming together of these license conditions, 
mandatory or otherwise, because we are all now working under 
the same standards that Congress has set for us.
    We are going through a period here where people are feeling 
their way through, but, as Mr. Finfer said, we are seeing 
movement already towards settlement discussions, where 
previously it was just: here is your condition; take it. I 
think that is a really positive step, to try to work these 
things out, and will result in less conflict, not a war of 
attrition but less conflict, and more public interest licensing 
being done at the commission as a result of EPAct.
    Senator Thomas. It sounds like a pretty complicated 
process.
    Thank you, Mr. Chairman.
    Senator Craig. Thank you very much, Craig.
    Let me go right back to that question. Then under what 
circumstances will FERC invoke the new dispute resolution 
process?
    Mr. Robinson. Well, if the Secretary, after having a trial-
type hearing and alternative condition, comes to the Commission 
and says, here is our final conditions, and the Commission 
looks at those and believes that they are not consistent with 
the equal consideration standard, the Commission has the 
opportunity to refer that--it is not a must, but can--refer 
that to the dispute resolution process at the Commission.
    I think that is a 90-day period that we are allowed for 
that. Then that finding would be provided back to the Secretary 
for a final statement from the Secretary on whether or not 
those are in fact the final terms and conditions.
    Senator Craig. Mark, could FERC report back to this 
committee in about 6 months to see what additional progress is 
being made in implementing the hydro provisions of EPAct?
    Mr. Robinson. I think it is important that we do that. We 
are just at the early stages. There is very much promising. 
There is a lot promising going on that is not even in the ALJ 
or the alternative condition process, but the roll-out from 
this and the way the agencies are dealing with licensees, I 
think that is one of the real plusses here. But I think in 6 
months we will have a much better picture on how the actual 
process of the ALJ process and the alternative conditions 
process is actually working. So we would be happy to.
    Senator Craig. Well, I think it is important that we 
monitor it closely, because several expressions have been made 
as to what is believed might happen, but until it happens or we 
see clear evidence that there is difficulty I do believe we are 
at a bit of a rush to the line at the moment. Once this thing 
levels off and we get through this process several times, will 
we have a clear vision of what is or is not happening there.
    Senator Bingaman had asked you, Mr. Finfer, in relation to 
concern that American Rivers expressed as to would you do your 
job well. I think I heard Mr. Fahlund suggest that, depending 
on the profile of a project, it would be kind of pick and 
choose. I cannot let that one lie. Are you suggesting, Mr. 
Fahlund, there will be a double standard within the agencies as 
to how they would handle one licensing process versus another?
    Mr. Fahlund. I would posit that in any situation where you 
are managing scarce resources you have to allocate those 
resources in the best way that you see fit. I think that if you 
have a project that has higher profile I think that you are 
more likely to allocate those resources to that project if 
those resources are limited.
    So I do in fact stand by my statement and I think that--and 
again, this is just speculation at this point because we have 
not seen the results of too many of these things yet. But I 
fully expect to see agencies either never issuing conditions in 
the first place or backing off from them very, very quickly, 
simply because they cannot handle the cost of actually even 
trying to fight a frivolous petition for a trial-type hearing.
    Senator Craig. Then I have to come back again: Do you think 
American Rivers would allow that kind of action to stand 
without public exposure to it or bringing the attention of the 
Congress if this were to happen?
    Mr. Fahlund. Well, I think actually bringing it to the 
attention of the Congress is precisely why I was encouraging 
these continued oversight hearings. But American Rivers will 
try to bring it to the attention of the public. But of course, 
we cannot see what is going on in the minds and in the back 
rooms of the agency when they are making those kinds of 
decisions. All we can do is point to the fact that--we can 
point to the absence of conditions that we think should clearly 
be there. But unfortunately, EPAct did not set up a situation 
where an absence of a condition is very easily challenged. It 
certainly makes challenging existing conditions very easy, too 
easy in my view.
    Senator Craig. Well, we will monitor closely, as I am 
confident you will, as we go through this so that we get the 
necessary and appropriate effect.
    Mr. Fahlund. We would certainly appreciate that.
    Senator Craig. Mr. Finfer, as we were developing the hydro 
legislative piece some critics warned that the opportunity for 
the trial-like hearing would discourage settlements. Has that 
happened or are settlements, I think you have already said, are 
still under way? That has not happened?
    Mr. Finfer. Mr. Chairman, it is early, but we are not 
seeing that settlements are being discouraged. In fact, some 
settlements have already occurred among projects for which 
hearings have been scheduled, and more discussions are under 
way among a number of the ones that are still active. I would 
also add that since the Klamath conditions were submitted the 
stakeholder-driven settlement process that is taking place 
there for Klamath does not appear to have been deterred by the 
fact that the hearings were requested on Klamath.
    So the early indication is that settlements are not being 
deterred.
    Mr. Fahlund. Mr. Chairman, may I respond to that?
    Senator Craig. Yes.
    Mr. Fahlund. Because I think this brings up a really 
important point. That is, while I do not think that settlement, 
at least in the Klamath, has been derailed altogether, it has 
been postponed. It has essentially been frozen in place until 
the trial-type hearing process is completed, because we simply 
just cannot work on both tracks at the same time. No one can. 
It is just too resource-intensive for that period of time.
    And Mr. Adamson--and I might shock him right now, but he 
made a recommendation about the timeline or a suggestion that 
the timeline is tight. I think that we would encourage the 
agencies to have a provision, an ability to impose a stay on a 
trial-type hearing proceeding, just hold it in abeyance for a 
period of time to facilitate settlement agreement, particularly 
where folks have very limited resources and can only kind of 
work in one venue at a time.
    We have done that with the commission. I think it has been 
by and large effective. I do not think people have abused that 
stay process too much. But I think it would be helpful to 
consider as an addendum.
    Mr. Adamson. Senator, I agree that some type of limited 
stay, maybe 30 to 60 days just to figure out if you can sit 
down, work things out, so that you are not just thrust right 
into the hearing immediately.
    Senator Craig. Mr. Robinson.
    Mr. Robinson. Congress, I think quite rightly, when they 
passed this act put a 90-day provision in there to complete 
these hearings. We have worked hard with the agency to make 
this work within the ILP time frame. Keep in mind this is a 5-
year process we are talking about, and people have been talking 
for years and years and years by the time they get to the point 
that they would have a trial-type hearing and alternative 
conditions. To think that we need another 30 days at that 
point, it is just going to build in the expectation that we 
will get a stay or get another delay.
    I would encourage the agencies to stay with the time frames 
that are in the rule and in the law.
    Senator Craig. Well, gentlemen, one of the reasons you are 
before us today looking at a new law and how to implement it is 
because of the way the old law was handled--12 and 14-year 
processes that cost millions and millions of dollars. It was 
what drove this Congress to make change, hopefully the change 
to be transparent and open, but predictable, procedural, in a 
way that there is some relationship as we work through these 
kinds of processes.
    So I certainly do not believe people ought not have access 
or that there not be appropriate time. But time here has been 
so badly abused in the past, at least this Senator is very 
sensitive to it. Now, I understand startup. I understand 
getting into a new law and process and procedure and making it 
work well. I think all of us understand a little flexibility in 
that process. But that is why the Congress was specific as it 
relates to time.
    Mr. Finfer, why did not the resource agencies proceed with 
a notice of comment period before issuing the hydro rule?
    Mr. Finfer. Senator, we took a look at the issue and 
decided that these rules were actually procedural and 
interpretive, rather than substantive, and hence did qualify 
for the exemption from notice and comment under the 
Administrative Procedures Act. Further, the act included a 
mandate to put the rule in place in 90 days. It was a very 
emphatic mandate.
    So we decided that those two factors together gave us 
reason to publish as interim final, but with a request for 
comment. We are hoping that that offered the best, in that it 
allowed the parties to get into the process sooner, but still 
provided the opportunity for comment, which they ought to have 
the right to and which in fact we need because it is a new 
process.
    Senator Craig. Why is it appropriate that the rule apply to 
pending procedures? That was discussed earlier. For the record, 
how did Interior see that?
    Mr. Finfer. In the act, the phrase, the operative phrase 
that is used throughout, is ``license applicant.'' It does not 
say an applicant for a license who applies after the date of 
enactment. It said ``license applicant.'' Just reading the 
plain language, we believe that this was the appropriate 
reading of the statute and hence applied it accordingly.
    I should add, the opportunity for people with existing 
conditions and prescriptions to use the process was limited. 
They had to file in the first 30 days after the rule was 
published, that is by December 17. So that was a one-time 
opportunity. The window was not left open forever.
    Senator Craig. So how many are we talking about?
    Mr. Finfer. We received for these, 19 requests of various 
types, covering 17 projects. Those are the requests, along with 
the few new ones like Hell's Canyon and Klamath, that we are 
processing right now.
    Senator Craig. Mr. Adamson, from your perspective how is 
the ability to request a trial-type hearing and offering 
alternatives an improvement over the previous process, and how 
do you respond to the criticism that the new process will add 
additional time to an already lengthy process?
    Mr. Adamson. Well, as it is structured now it adds no time 
at all. Under any circumstance, the alternative conditions adds 
no time. Equal consideration adds no time. The problem you had 
before is that you could literally--and I have worked on 
proceedings where you get a condition and there are no facts 
identified at all, but you have no recourse except appealing 
the license order years later in the court of appeals.
    In fact, what this will do is give you or an 
environmentalist--I know Andrew is not happy with this law and 
not happy with this proceeding. But I predict that within 5 
years, I predict that American Rivers or some other 
environmental group will use this condition because they think 
that a decision is not supported by the facts.
    So it is going to go both ways over time. But right now you 
have an opportunity to solve this problem at the get-go instead 
of waiting for years and then having a Cushman-like situation, 
where a relicensing is sitting around in the court of appeals 
for 10 years, which is I think what we are trying to avoid.
    Senator Craig. In his testimony, Andrew asserts that 
environmental conditions present negligible costs to power 
supply. Would you agree and how will electricity ratepayers 
benefit from the hydro relicensing reform?
    Mr. Adamson. Well, I think that it definitely has an 
impact. I just think of a couple of proceedings. One is Box 
Canyon, where the price of power from that project has doubled, 
according to FERC, because of relicensing. So that is certainly 
a ratepayer impact.
    Another recent project, just to pick one out of the hat, is 
Baker River project. There has been a settlement there. It is 
another project in Washington State. So the licensee supports 
that, but that settlement did more than double the cost. So I 
think if you look, for example in the Northwest, over time at 
all the projects as they go through relicensing and add 
together cumulatively the increase in costs from every project, 
you get a pretty substantial impact.
    But sure, one proceeding, if it is a really large company, 
it is going to be spread out amongst a lot of people. But 
cumulatively it all adds up.
    Senator Craig. Andrew, when Congress first began to look at 
hydro licensing reform we developed language that American 
Rivers criticized as licensee applicant only. Your organization 
advocated that all parties to the proceedings be given the same 
opportunity to request a trial-type hearing and offer 
alternatives. In our bipartisan agreement, we did just that.
    Do you agree that any party, including an organization such 
as American Rivers, can trigger a hearing?
    Mr. Fahlund. Absolutely, Senator. And I guess what you are 
hearing from me today is that American Rivers may be able to 
participate as a practical matter in some of these proceedings. 
Again getting back to the prioritization issue, we will have to 
prioritize, as anyone does. My concern--and I am representing 
130 groups from around the country, most of whom have very 
limited resources. I think the ability of those organizations 
to keep up and participate as a practical matter, even though 
they have a legal possibility of participating, I think is 
going to be increasingly difficult.
    Senator Craig. Do you agree that any party can offer 
alternatives?
    Mr. Fahlund. Yes, sir. The problem there is that the 
alternatives that are offered--the way the alternative 
conditions language is written, only conditions that must be 
included by an agency--they have to be cheaper or no less, I 
guess better for power production, and no less protective. But 
what about if the agency low-balls the condition? I think that 
that was always a concern of ours and something that we always 
believed we should have the right to an equitable appeal on.
    Senator Craig. So now that American Rivers is beginning to 
see where the law is taking us with the agencies involved, and 
I gather by your testimony your continued opposition, is the 
opposition what you envision the process to become and be or is 
it, as you have said, a process that could become more costly 
to the least among us?
    Mr. Fahlund. I think that the way we view the--it is very 
hard to judge from sitting where we are right now. These things 
are just getting started and so we really have not launched 
into it. So it is, in all fairness, it is very hard to judge.
    But I do think that every indication is that our concerns 
have been realized and that this is going to be a lot messier 
than I thought it needed to be. I would have preferred an 
opportunity to get at what Dan has been describing his 
interest, at least, but doing it in a much more streamlined, 
efficient, and equitable way.
    Now, given that that is not an option before us and that we 
have to do the best with what Congress passed, I certainly hope 
that we can work with everyone here to make this work well and 
work effectively without any compromise to environmental 
protections. I would love to come back here in a year and eat 
crow, but----
    Senator Craig. I might give you that opportunity.
    Mr. Fahlund. You might. But I do not know that I will be. I 
might be crowing.
    Senator Craig. Well, I think Mr. Finfer and others in their 
testimony have stated it well. We are talking about a process 
that is valid for a period from 30 to 50 years and we ought to 
try to get it right.
    Mr. Fahlund. Yes.
    Senator Craig. At the same time, we ought not, in dealing 
with the Federal Government, make it such a phenomenally 
difficult process that it drives costs beyond where--unless you 
simply believe hydro ought to be extracted from the rivers and 
streams of America, then it ought not be so costly as to drive 
it through to the consumer, who is finally beginning to awaken 
to the new realities of energy costs in our country.
    So I think all of us are extremely concerned about that. I 
think you agree with me, as all of you do, that it is 
tremendously important that we get the facts and the conditions 
right. That is why a reasonable dialogue, trial-like 
proceedings where there is dispute, that there are alternatives 
that can be argued effectively--I became quite frustrated that 
agencies had in the name of the environment an absolute 
authority or dictatorial ability, when in fact they may not be 
the experts or their expertise may not be where it ought to be 
to arrive at the right environmental conditions to continue to 
maintain an effective, efficient, hydro operating facility.
    So we will stay tuned as all of you proceed. We will watch 
it very, very closely.
    Andrew, I would love to have you eat crow. But more 
importantly, I would also love to have you come back and say: 
No, they are getting it wrong and here is what we can do to 
improve it. That is going to be certainly our part of the job 
here also.
    But I must tell you, to date, gentlemen, I am pleased with 
what I see and I hope we can continue to move down this road 
toward an effective open process that brings this thing into a 
predictable timeline. And time is money, there is no question 
about it. And if time frames are shortened once this procedure 
is in place, maybe the cost concerns that you have will be 
lessened to some degree. But certainly there will be an 
obligation on the part of all parties involved.
    So I want to thank you all very much for being with us 
today, taking time. We will have you back before us. As I asked 
you, Mark, to report within 6 months as to where this procedure 
is taking us, by then we will have actually had a chance to see 
how it is working in a trial-like proceeding and whether in 
fact we are getting what we have asked for here.
    Gentlemen, thank you all very much for coming. We 
appreciate your time and your testimony.
    The committee will stand adjourned.
    [Whereupon, at 4:08 p.m., the hearing was recessed, to be 
reconvened on May 15, 2006.]

    [The following statement was received for the record:]

               Statement of the Edison Electric Institute

    The Edison Electric Institute (EEI) is submitting this written 
statement to the Committee for consideration during its May 8 hearing 
on implementation of the hydropower licensing provisions of the Energy 
Policy Act of 2005 (EPAct 2005). Under Section 241 of the new law, 
Congress amended the Federal Power Act (FPA) to require federal land 
and fish and wildlife agencies, when prescribing mandatory hydropower 
license conditions, to consider the impacts of those conditions on 
other hydropower project benefits. Section 241 also requires the 
agencies to consider alternative conditions suggested by license 
applicants and others that can achieve the same resource goals at lower 
energy or dollar costs. Finally, Section 241 requires the resource 
agencies to provide a trial-type hearing to resolve disputed issues of 
material fact relating to any mandatory condition and allows the 
Federal Energy Regulatory Commission (FERC) to refer any condition for 
a non-binding opinion by FERC's Dispute Resolution Service.
    EEI vigorously supported enactment of these EPAct 2005 hydropower 
licensing improvements, and we are strongly interested in their 
effective implementation. We deeply appreciate Senator Craig's 
longstanding and steadfast leadership on hydroelectric licensing 
issues, starting with the legislation he introduced in 1999 and 
extending through the comprehensive energy bills considered in the 
107th, 108th and 109th Congresses. We also thank Chairman Domenici for 
his leadership and Senators Smith, Nelson, Cantwell, and Feinstein for 
their roles in working with Senator Craig to develop the bipartisan 
compromise that was the basis for the provision ultimately enacted by 
Congress. The compromise assured that everyone involved in the 
hydroelectric licensing process has the same opportunity to obtain the 
benefits of the licensing improvements, which introduced greater 
accountability and transparency into the licensing process without 
compromising protection of the environment.
    The Section 241 provisions ultimately adopted by Congress are a 
significant improvement to the hydroelectric licensing process. They 
will help preserve the viability of our valuable domestic hydropower 
resource, which provides substantial economic, environmental, and 
energy security benefits to the nation.
    EEI is the trade association of United States shareholder-owned 
electric utility companies, international affiliates, and industry 
associates worldwide. Our U.S. members serve 71 percent of all electric 
utility customers in the nation and generate almost 60 percent of the 
electricity produced by U.S. generators. In providing these services, 
many EEI members rely on hydropower, and many own and operate 
hydropower projects licensed by FERC. In fact, EEI members comprise the 
largest group of FERC hydropower project license holders.
    Hydropower has played and will continue to play an important role 
in meeting the nation's need for electricity. Approximately 10% of the 
nation's generating capacity is hydropower, and it is by far the 
nation's largest domestic source of clean, affordable, renewable 
energy, providing more than 85% of our renewable energy. Also, 
hydropower projects are particularly valuable for maintaining the 
reliability of our nation's electricity system. If allowed by their 
licenses to do so, hydropower projects can provide quick start and stop 
capabilities that help electric system operators maintain the integrity 
of the nation's transmission grid and restore the system in cases where 
it may experience disturbances or even outages. Finally, hydropower 
generation provides communities across the country with other benefits 
besides electricity, including flood control, drinking water, 
irrigation, fish and wildlife, and recreation benefits.

                          MANDATORY CONDITIONS

    Legislative improvements to the hydropower licensing process were 
needed because of problems that arose in the exercise of mandatory 
conditioning authorities under FPA Sections 4(e) and 18 by the 
Departments of the Interior, Commerce, and Agriculture (Departments). 
Although FERC issues hydropower licenses and is in charge of the 
overall licensing process, under the FPA, as interpreted by a series of 
federal court decisions, the Departments write key parts of the 
licenses that relate to the ``adequate protection'' of certain federal 
lands under Section 4(e) and fish passage under Section 18. FERC 
generally has no authority to reject or modify these conditions, and 
prior to EPAct 2005 licensees had no avenue to challenge the scientific 
bases of the Departments' mandatory conditions other than requesting 
judicial review of a license order in the federal Court of Appeals. 
This interpretation of the FPA resulted in an extraordinarily broad 
exercise of conditioning authority by the Departments, which led to 
serious problems when exercised without consideration of the likely 
impacts on energy production and without regard to their cost-
effectiveness. In many cases, the Departments made clear that they 
could and would impose a broad array of license conditions, too often 
without regard to the cost or the impact on other project benefits 
including electricity production, without considering more efficient 
alternatives, and even without adequately demonstrating the need for 
the conditions in the license proceeding record.
    Although prior to EPAct 2005 FERC undertook several significant 
efforts to improve the hydroelectric licensing process, including the 
establishment of a new ``Integrated Licensing Process'' in 2003, it did 
not attempt to solve the generally recognized problems with the 
mandatory conditioning process. FERC believed it generally lacked 
authority to address the issue. Furthermore, though the Interior 
Department took a step in the direction of reforming the mandatory 
condition process when it issued a proposed rule to create an appeal 
process in 2004, it never issued a final rule. These developments 
confirmed the need for Congressional action to address mandatory 
conditioning if hydropower was to remain a viable element in the 
nation's generating portfolio.

              SECTION 241 OF THE ENERGY POLICY ACT OF 2005

    The licensing improvements adopted by Congress in Section 241 are 
designed to ensure that the mandatory license conditions and 
prescriptions issued by the Departments under FPA Sections 4(e) and 18 
are cost-effective, are supported by the facts, and take into account 
impacts on the wide range of benefits provided by hydropower projects. 
They were also designed to introduce accountability and transparency to 
the licensing process. As mentioned briefly above, the key provisions 
of Section 241 are:
1. Right to a Trial-Type Hearing
    The license applicant or any other party to a licensing proceeding 
has the right to an expedited ``trial type hearing'' on ``disputed 
issues of material fact'' regarding mandatory conditions. This 
provision of the legislation is critical to assuring that mandatory 
conditions are supported by sound science, not speculation. Prior to 
enactment of EPAct 2005, the only recourse a license applicant or other 
party had if they believed a mandatory condition was not supported by 
the facts was to seek review in the Court of Appeals of the offending 
condition, following the issuance of a license by FERC in a licensing 
process that took five to ten years. This remedy was too little too 
late, following as it did the investment of substantial effort and 
resources by all parties just to produce a license with conditions that 
raised serious concerns, for review by a court after-the-fact with 
deference to the agencies issuing the troubling conditions.
    Section 241 corrects this problem by giving license applicants and 
others the ability to contest the fundamental factual assertions that 
underlie an agency's mandatory conditions before a license containing 
those conditions is issued. This will have significant environmental 
and economic benefits. For example, it will advance environmental 
interests by helping to assure that fishways achieve their intended 
purpose of providing passage' for fish with a biological need for such 
passage. There is no environmental benefit to installing costly fish 
passage facilities that either do not work or are not used by targeted 
fish species, and such a result harms electricity consumers who must 
pay higher rates to cover the cost of the flawed condition.
2. Equal Consideration
    Under Section 241, when issuing any mandatory condition, the 
Departments must ``demonstrate that the Secretary gave equal 
consideration to the effects of the condition adopted and alternatives 
not accepted on energy supply, distribution, cost, and use; flood 
control; navigation; water supply; and air quality . . .'' If 
appropriately implemented by the Departments, this equal consideration 
requirement should lead to the issuance of more reasonable mandatory 
conditions that reflect consideration of all of the impacts of the 
conditions, both economic and environmental. It also corrects a 
longstanding problem with the licensing process where FERC was charged 
with assuring that a license reflected ``equal consideration'' of all 
relevant values, but the mandatory conditions submitted by the 
Departments were not based on the same ``equal consideration.'' This 
change in law will assure that all federal agency conditions included 
in a FERC license reflect ``equal consideration,'' regardless of 
whether they are imposed by FERC or by the Departments. This should 
result in the issuance of more balanced licenses that are in the public 
interest.
3. Alternative Conditions
    The license applicant or any other party to the license proceeding 
may submit an alternative mandatory condition, which must be adopted by 
the Department if the alternative meets the environmental goals of the 
mandatory condition proposed by the Department and will either ``cost 
significantly less to implement'' or result in improved power 
production. In the case of Section 4(e) conditions, the alternative 
must meet the existing ``adequate protection and utilization of the 
reservation'' standard. For Section 18 alternative fishway conditions, 
the alternative must be ``no less protective than the fishway'' 
prescribed by the Department.
    This change in law will give license applicants and others the 
opportunity to convince a Department that there is a more cost-
effective or energy-efficient way to address the environmental problem 
the Departments want to remedy by their mandatory conditions. Again, it 
should increase the likelihood that hydro licenses will be balanced and 
reasonable.

                        INTERIM SECTION 241 RULE

    Section 241 required the Departments to issue a joint rule within 
90-days of enactment of the EPAct 2005 to establish ``procedures for 
the expedited trial-type hearings . . .'' In response, the Departments 
issued an ``interim'' final rule on November 17, 2005, coming quite 
close to complying with the statutory deadline. The Departments 
requested public comment on the interim rule, however, and indicated 
that they might issue a revised rule in 2007 based on the comments 
received as well as the experience gained with the trial-type hearing 
process.
    EEI together with the National Hydropower Association (NHA) 
submitted extensive comments on the interim rule to the Departments on 
January 17, 2006. In those comments, EEI strongly supported the rule. 
In particular, we endorsed provisions contained in the rule that make 
the trial-type hearing and alternative condition processes applicable 
to pending licensing proceedings where no license had issued as of 
November 17, 2005. We believe that such an approach is required by law 
and prevents a long delay in obtaining the many economic and 
environmental benefits provided by EPAct 2005.
    Further, EEI supported the Departments' clarification that the 
rights to propose alternative conditions and to a trial-type hearing 
apply to the exercise of reserved conditioning authority in addition to 
conditions set during the licensing process. Any other approach would 
completely subvert the intent of the statute because it would permit 
the Departments to avoid their Section 241 obligations by simply 
deferring the exercise of any such authority until after a license is 
issued, through use of reserved authority or ``reopener'' conditions.
    In addition, we applauded provisions in the rule that mandate that 
the administrative law judge (ALJ) determine whether there are material 
disputes of fact, and that the ALJ's factual findings are final. This 
will prevent Department staff, who may be proponents of a mandatory 
condition, from unduly limiting access to the trial-type hearing 
process. The final nature of the All's findings of fact will assure 
that the relevant conditions/prescriptions issued by the Department are 
consistent with the facts.
    Notwithstanding EEI's strong support for the interim final rule, we 
do have concerns about certain provisions of the rule, and we expressed 
those concerns to the Departments in our comments. Primary among those 
concerns is that the interim rule does not provide for a trial-type 
hearing of up to 90-days as required by Section 241 because the hearing 
schedule set out in the interim final rule is unreasonably compressed. 
Instead of providing up to 90-days for the conduct of the hearing 
itself, the interim final rule requires that multiple other steps also 
occur during the 90 day period, including various preliminary 
procedural steps and the ALJ's ultimate decision. We are concerned that 
this approach to the hearing schedule simply will not provide the 
opportunity to develop an adequate factual record in many proceedings 
where there are one or more highly complex issues.
    Moreover, we are troubled that the interim final rule provides for 
a trial-type hearing on preliminary conditions, rather than final 
(modified) conditions, in conflict with Section 241. We are concerned 
that conducting hearings on preliminary conditions--which are not 
necessarily the conditions that the Departments will ultimately seek to 
impose on a license applicant--is an inefficient use of the resources 
of the Departments, license applicants, and other parties. Instead, 
providing the right to a trial-type hearing on final conditions would 
be much more efficient and would assure that the license applicants and 
others only use a trial-type hearing after other avenues for resolving 
issues are exhausted.
    EEI also believes that it is very important that the Departments 
clarify that the ``equal consideration'' standard applies to all 
mandatory conditions--both preliminary and final. This is necessary 
because the Department of Commerce has taken the position that ``equal 
consideration'' applies only to its mandatory conditions if an 
alternative condition is submitted. We strongly believe that Commerce's 
interpretation conflicts with the plain language of Section 241 and 
must be reversed.
    In light of these concerns, EEI recommends that the Departments 
issue a revised final hydropower rule no later than November 1, 2006 in 
order to better assure that the full benefits of the hydroelectric 
licensing improvements enacted by Congress are obtained. We hope that 
the Departments will respond positively to the concerns we have raised 
in commenting on the interim final rule, in particular the equal 
consideration, final condition, and 90 day concerns.\1\
---------------------------------------------------------------------------
    \1\ American Rivers along with other environmental groups have 
filed a complaint in the U.S. District Court for the Western District 
of Washington seeking ``to overturn the entire rule. Additional 
complaints have been filed by both Pend Oreille PUD and Ponderay 
Newsprint in the U.S. District Court for the District of Columbia 
seeking a determination that the rule incorrectly excludes the 
relicensing of the Box Canyon Project from being subject to the 
provisions of EPAct.
---------------------------------------------------------------------------
    We are still at a very early stage of implementation of the Section 
241 reforms, so it is difficult at this time to gauge the ultimate 
impacts of the legislation as well as additional implementation issues 
that may arise. The Departments have yet to act on any requests for 
alternative conditions, and only one trial-type hearing process has 
begun to date. The preliminary general sense of the industry is that 
Section 241 is causing the agencies to exercise somewhat more care in 
the preparation of preliminary license conditions, including ensuring 
that conditions are supported by the facts. If true, this is a very 
positive development.
    For projects where preliminary or final license conditions were 
issued prior to November 17, 2005, the Departments required requests 
for trial-type hearings and/or alternative conditions to be filed no 
later than December 19, 2005 (December 19th filings). Under the interim 
rule, the Departments have discretion regarding when they trigger the 
beginning of the trial-type hearing process for the December 19th 
filings. In March 2006, the Departments issued a series of notices 
regarding the December 19th filings that delay the first step in the 
trial-type hearing process, namely the Department's answer to the 
request for trial-type hearing, until at least June 2006 and in some 
cases until January 2007 or later.
    By contrast, the interim rule does not provide the Departments with 
discretion as to when a hearing process should begin for requests for 
trial-type hearings in proceedings where preliminary conditions were 
issued subsequent to November 17, 2005. For these hearing requests, the 
Department's answer must be made within 45 days after the deadline for 
filing the request. Then 5 days after the answer is issued, the case 
must be referred to the respective Department's ALJ office for hearing. 
This is why the trial-type hearings regarding the relicensing of the 
Hells Canyon Project are the first hearings to be conducted under the 
new law even though the preliminary conditions in this proceeding were 
issued in January, 2006 and Idaho Power's requests for trial-type 
hearing and alternative conditions were filed on February 27, 2006, 
months after the group of requests filed on or about December 19, 2005.
    EEI and many others are monitoring the Hells Canyon trial-type 
hearings, one of which is being conducted by the Department of the 
Interior on Bureau of Land Management Section 4(e) conditions and the 
other by the Department of Agriculture on U.S. Forest Service Section 
4(e) conditions. We expect that there will be many ``lessons learned'' 
from these pioneer trial-type hearings that can be applied in the 
future to maximize the broad benefits that we expect will result from 
the hydroelectric licensing improvements adopted by Congress in EPAct 
2005.

                               CONCLUSION

    In conclusion, EEI strongly supports the provisions of Section 241 
of EPAct 2005, and we appreciate the steps that Congress took to 
improve the FPA hydropower licensing process by including these 
provisions in the energy bill last year. We are optimistic that the 
provisions--if properly implemented--will improve the federal mandatory 
condition part of the licensing process. We support the Senate Energy 
Committee's continued oversight to ensure that the objectives sought by 
Congress in Section 241 are fulfilled.

                                APPENDIX

                   Responses to Additional Questions

                              ----------                              

                              Department of Energy,
               Congressional and Intergovernmental Affairs,
                                     Washington, DC, June 15, 2006.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Mr. Chairman: On April 24, 2006, Clarence L. Miller, Director, 
Office of Sequestration, Hydrogen, and Clean Coal Fuels, Office of 
Fossil Energy, testified regarding the economic and environmental 
issues associated with coal liquefaction technology and on 
implementation of the provisions of the Energy Policy Act of 2005 
addressing coal liquefaction.
    Enclosed are the answers to 11 questions that were submitted by 
Senators Bunning, Bingaman, and Wyden for the hearing record. The one 
remaining answer is being prepared and will be forwarded to you as soon 
as possible.
    If we can be of further assistance, please have your staff contact 
our Congressional Hearing Coordinator, Lillian Owen, at (202) 586-2031.
            Sincerely,
                                             Jill L. Sigal,
                                               Assistant Secretary.
[Enclosures.]
              Responses to Questions From Senator Bunning
    Question 1. It has been over a year since we passed the energy bill 
and I have not seen any movement on the part of D.O.E. to implement the 
loan guarantee program. What is the status of this program and loan 
guarantees for ``C.T.L.'' projects?
    Answer. The Department has established a small loan guarantee 
office in the Department's Office of the Chief Financial Officer. In 
implementing the program we will follow the Federal Credit Reform Act 
of 1990 (FCRA) and Office of Management and Budget (OMB) guidelines. 
Toward that end, we are drafting program policies and procedures, 
establishing a credit review board, and planning to employ outside 
experts.
    Title XVII of EPAct 2005 authorizes DOE to issue loan guarantees 
for projects that avoid, reduce, or sequester air pollutants and/or 
anthropogenic emissions of greenhouse gases, and ``employ new or 
significantly improved technologies as compared to commercial 
technologies in service in the U.S. at the time the guarantee is 
issued.'' Projects that employ coal-to-liquids technology may be 
eligible under the Act to apply for loan guarantees.
    Under Secretary Garman provided the Committee with an update on our 
progress in implementing the loan guarantee program at the May 1, 2006, 
SENR hearing on industrial gasification. In his testimony he stated,

          We will move prudently to ensure that program objectives are 
        achieved while meeting our responsibilities to the taxpayer. . 
        . . We are proceeding, but we are doing so with no small 
        measure of caution and prudence. . . . It is possible that the 
        ultimate cost to the taxpayer could be significantly higher 
        than the cost of the subsidy cost estimate. DOE's evaluations 
        of loan guarantee applications will entail rigorous analysis 
        and careful negotiation of terms and conditions.

    Title XVII allows for project developers to pay the subsidy cost of 
a loan guarantee issued by DOE. While this ``self pay'' mechanism may 
reduce the need for appropriations, it does not eliminate the 
taxpayer's exposure to possible default of the entire amount of the 
loan.
    FCRA contains a requirement that prevents us from issuing a loan 
guarantee until we have authorization to do so in an appropriations 
bill. We do not believe we have authority to proceed with an award 
absent having explicit authorization in an appropriations bill.
    Question 2. When will DOE's guidance be issued and when will D.O.E. 
be accepting applications for the loan guarantee program? What do you 
foresee as a timeline for this program?
    Answer. The Department has established a small loan guarantee 
office under the Department's Chief Financial Officer. In implementing 
this program we will follow the Federal Credit Reform Act of 1990 
(FCRA) and Office of Management and Budget (OMB) guidelines, and we 
will emulate ``best practices'' of other federal agencies. Toward that 
end we are drafting program policies and procedures, establishing a 
credit review board, and will employ outside experts.

                         COAL TO LIQUIDS (CTL)

    Question 3. As you know, the Department of Defense has expressed 
great interest in ``C.T.L.'' technology as a way to produce a secure, 
domestic fuel source for our military. Section 369 of the Energy Bill 
provided that D.O.E. participate in D.O.D.'s Assured Fuels program to 
evaluate the potential of ``C.T.L.'' for use by the military. What is 
the status of that program?'
    Answer. Section 369 of the Energy Policy Act of 2005 (PL 109-58) 
directs the Secretary of Energy, in coordination with the Secretary of 
the Interior and the Secretary of Defense, to establish a task force to 
develop a program to coordinate and accelerate the commercial 
development of strategic unconventional fuels, including, but not 
limited to oil shale and tar sands. This task force has been convened 
and coal-to-liquids technologies are being evaluated. Also, as Under 
Secretary Garman indicated in his testimony before the Committee on May 
1, 2006, ``working with industry, the Department of Defense, and the 
Environmental Protection Agency, we are studying the business risks 
associated with industrial gasification and are performing financial 
modeling to understand the impact of EPAct 2005 incentives on early 
commercial plants.''

                   PRODUCTION OF TRANSPORTATION FUELS

    Question 4. Section 414 of the Energy Bill authorizes $85 million 
to test advanced technologies for the production of transportation 
fuels manufactured from Illinois Basin coal. It also provides funding 
for the construction of testing facilities at the University of 
Kentucky's Center for Applied Energy Research, the Southern Illinois 
University Coal Research Center, and the Energy Center at Purdue 
University. Could you provide an update on this initiative and a 
timeline for funding?
    Answer. The Department has not identified funding to perform the 
work authorized in Section 417 of the Energy Policy Act of FY 2005. The 
Department's enacted budget for FY 2006 and the Department's budget 
request for FY 2007 did not include funding for this work. The 
Department has not requested Coal-To-Liquid (CTL) R&D funding for 
several years because the CTL technology is mature.

                   ENVIRONMENTAL IMPACT OF CTL FUELS

    Question 5. From your research experience, could you describe the 
environmental impact of ``C.T.L.'' fuels compared to petroleum-based 
fuels?
    Answer. The environmental impact of coal to liquids (CTL) fuels 
depends significantly on the technologies employed for pollution 
abatement, but pollution abatement technologies have been too expensive 
to implement to date. Commercially operating CTL facilities currently 
do not employ these technologies and consequently have much larger 
environmental impact than petroleum-based fuels. For example, one of 
South Africa's existing CTL plants switched to natural gas as its 
feedstock to reduce the environmental impact, rather than install 
pollutant control technologies for a coal feedstock process. A CTL 
facility using clean coal technology, maximum air cooling, and carbon 
capture and storage is technically capable of plant emissions 
comparable to those associated with the production of petroleum-based 
fuels, but may not be economic.

              Responses to Questions From Senator Bingaman

                           CTL RAIL TRANSPORT

    Question 1. Have you looked specifically at what the implications 
for our rail system will be in a scenario such as the EIA forecast of 
more than 2 million barrels per day equivalent of CTL fuel? I know that 
there are issues with regard to the transport of coal by rail right 
now. This was a topic of one of the panels at our Coal Conference last 
year. Will this problem (a shortage of rail capacity) be exacerbated by 
the further development of CTL? Do you know of any analysis on this 
subject specific to the development of CTL?
    Answer. It is possible that the implementation of a Coal-To-Liquids 
(CTL) industry of the size forecast by the Energy Information 
Administration (EIA) (i.e., 11% of total coal consumption in 2030) will 
have an impact on the associated infrastructure including the rail 
system. Currently, there is at least one study of the potential impact 
being performed by an industrial consortium.

                            LOAN GUARANTEES

    Question 2. Title XVII of the Energy Policy Act of 2005 instructs 
the Secretary to create a loan guarantee program for innovative 
technologies, which includes CTL. What is its current status?
    Answer. The Department has established a small loan guarantee 
office in the Department's Office of the Chief Financial Officer. In 
implementing the program we will follow the Federal Credit Reform Act 
of 1990 (FCRA) and Office of Management and Budget (OMB) guidelines. 
Toward that end, we are drafting program policies and procedures, 
establishing a credit review board, and planning to employ outside 
experts.
    Title XVII of EPAct 2005 authorizes DOE to issue loan guarantees 
for projects that avoid, reduce, or sequester air pollutants and/or 
anthropogenic emissions of greenhouse gases, and ``employ new or 
significantly improved technologies as compared to commercial 
technologies in service in the U.S. at the time the guarantee is 
issued.'' Projects that employ coal-to-liquids technology may be 
eligible under the Act to apply for loan guarantees.
    Under Secretary Garman provided the Committee with an update on our 
progress in implementing the loan guarantee program at the May 1, 2006, 
SENR hearing on industrial gasification. In his testimony he stated,

          We will move prudently to ensure that program objectives are 
        achieved while meeting our responsibilities to the taxpayer. . 
        . . We are proceeding, but we are doing so with no small 
        measure of caution and prudence. . . . It is possible that the 
        ultimate cost to the taxpayer could be significantly higher 
        than the cost of the subsidy cost estimate. DOE's evaluations 
        of loan guarantee applications will entail rigorous analysis 
        and careful negotiation of terms and conditions.

    Title XVII allows for project developers to pay the subsidy cost of 
a loan guarantee issued by DOE. While this ``self pay'' mechanism may 
reduce the need for appropriations, it does not eliminate the 
taxpayer's exposure to possible default of the entire amount of the 
loan.
    FCRA contains a requirement that prevents us from issuing a loan 
guarantee until we have authorization to do so in an appropriations 
bill. We do not believe we have authority to proceed with an award 
absent having explicit authorization in an appropriations bill.

                         CTL AS WATER RESOURCE

    Question 3. Water is a very important resource. CTL fuel production 
requires significant quantities of water. Given that fact (or perhaps 
constraint), how far do you think that we can take this on a national 
scale? What work has DOE done on looking at the potential impact of 
large-scale deployment of CTL for our national water supply?
    Answer. We agree that water is a very important resource, 
particularly in the West where some of the largest deposits of coal are 
located. Coal-To-Liquid (CTL) facilities will have to compete with 
other uses of water resources. Given a potentially tight water market, 
the private sector has the incentive to consider designs for CTL 
facilities in which water use has been minimized through the maximum 
use of air cooling equipment in the design and operation of the plant.

               Responses to Questions From Senator Wyden

                         COAL-TO-LIQUIDS (CTL)

    Question 1. If price volatility and crude oil prices are the two 
major impediments to bringing coal-to-liquids (CTL) fuels to U.S. 
markets, the ``tipping point'' to make CTL economically viable is at 
$40/barrel and the price of oil is now at $70 per barrel, why does the 
government need to continue subsidizing more CTL research? Why can't 
the private sector start building commercially viable production 
plants?
    Answer. The Department has not requested for Coal-to-Liquids (CTL) 
R&D funding for several years because CTL is a mature technology.
    If the private sector believed that investment in CTL production 
facilities were economic, they would make them. However, the private 
sector (and the private capital market) appear to have judged CTL 
facilities as too risky to invest in. The private sector is best able 
to determine the most efficient allocation of their financial 
resources. As a result of this efficiency, the U.S. economy prospers. 
Considering the past history of the price of oil (e.g., in 1986 and 
1998), investors must consider the likelihood that the price of oil 
could drop into a range that would make it impossible for investors to 
recover its capital. In addition, underscoring the risk of the 
projects, private lenders want CTL production projects to have off take 
agreements which match the term of the project debt. Such agreements 
are not commercially available because customers would have to book the 
value of a long-term purchase agreement on their balance sheet.
    Question 2. As a Westerner, I am concerned about the water 
resources that are needed to produce fuels from coal. I am also 
concerned about the increased air pollution and greenhouse gases that 
are emitted. Much of the water that would go into CTL production could 
be used to grow biomass and produce biofuels instead. Has anyone done a 
comparison of which types of energy production cause the least harm to 
the environment while delivering the biggest benefits to customers? Do 
you know of any analyses that have looked at the ``opportunity costs'' 
involved in producing water-intensive energy like CTL?
    Answer. We fully recognize the issues associated with water use in 
the production of liquid fuels from coal, particularly in the West. 
These issues have given the private sector an incentive to consider 
Coal-To-Liquid (CTL) facilities that incorporate the maximum amount of 
air cooling to reduce to a minimum the use of water. We are not aware 
of any specific analyses that have looked at the opportunity costs in 
producing products similar to those obtained from CTL facilities.
    Question 3. If the German and South African experience in producing 
coal fuels is any indicator, wouldn't you say that the only policy 
reason that justifies producing CTL fuels in the U.S. would be at a 
time when the U.S. no longer had access to world oil markets?
    Answer. Generally, the private sector will make those investments 
(and private capital markets will provide financing for those 
investments) that they believe will be economic and return a profit. 
The private sector is best able to determine the most efficient 
allocation of their financial resources. As a result of this 
efficiency, the U.S. economy prospers. If oil becomes scarce, market 
prices will incent additional, diversified oil production as well as 
alternative and unconventional energy production. The market is the 
most efficient mechanism for ``choosing'' those resources that would be 
developed. However, there may be reasons why the nation would be 
willing to incur economic losses which could result in reduced or 
negative economic growth, in order to support uneconomic synthetic fuel 
production.
                                 ______
                                 
      Responses of David Hawkins to Questions From Senator Bunning

    Question 1. The finished ``C.T.L.'' product is low particulate, low 
mercury and almost zero sulfur. Could you elaborate on the emissions 
characteristics of ``C.T.L.'' transportation fuels compared to current 
fuels?
    Answer. We have no reason to question the claims that the finished 
coal-to-liquids (CTL) fuel will have low particulate, low mercury, and 
very low sulfur characteristics. As I point out in my testimony, our 
concerns with CTL fall into three areas: the global warming emissions 
resulting from the production and use of CTL products; the need for 
performance standards for conventional air pollution from CTL 
production plants; and the impacts on land and water from expanded coal 
production.
    Question 2. As the Energy Information Administration forecast 
indicates, we have two choices: we can import ``C.T.L.'' fuels from 
foreign countries or we can produce it ourselves. I believe, and I 
think the witnesses here today have shown, that America can produce 
these fuels cleaner than anywhere else. Given the environmental and 
safety records of other coal countries, wouldn't you agree that the 
production of coal and ``C.T.L.'' in other nations would cause more 
environmental damage than if they are produced in America?
    Answer. We most certainly need to build new industries here in 
America to meet our transportation fuel needs. But it would be 
ineffective and very shortsighted to build industries that cannot meet 
the performance requirements that will be required to reduce global 
warming emissions in the near future. Today some may hold the opinion 
that limits on global warming emissions will not be put in place for 
some time but there is a growing consensus among industry leaders and 
others that such limits are inevitable. The new fuels industries that 
are being considered today need to be viable for decades if they are to 
provide us with real solutions.
    As my testimony stated, with the processes that we know of today, 
making liquid fuels from coal results in much greater global warming 
emissions than from the crude oil cycle if CTL production plant 
emissions are not captured. Even if production plant emissions are 
captured the system emissions are still as high as from crude oil. We 
conclude from those facts that deploying a CTL industry would make it 
more difficult and costly to achieve any given level of global warming 
emissions reduction in the future.
    Fortunately, as my testimony noted, the United States has many 
other options available to reduce oil dependence that are economically 
attractive and will assist us in achieving reductions in global warming 
emissions at lower costs. I outline these alternatives in my answer to 
your next question. Thus, our choices are not limited to producing CTL 
fuels here or importing them from other countries.
    Question 3. On page 17 of your written remarks, you make a number 
of recommendations regarding oil savings that relate to improvements in 
vehicle use and in industrial, aviation and residential building energy 
consumption. Would you please expand on your brief referral to these 
ideas?
    Answer. My testimony provided a very brief summary of the findings 
of the report ``Securing America,'' * produced by NRDC and the 
Institute for the Analysis of Global Security. The report identified 
technically feasible, cost-effective methods for reducing our 
dependence on oil in two broad program areas: improving the efficiency 
of our transportation system and of industrial processes and buildings 
that consume oil today; and replacement of oil in the transportation 
sector with fuels made from biomass.
---------------------------------------------------------------------------
    * The report has been retained in committee files.
---------------------------------------------------------------------------
    As my testimony notes, these measures can achieve oil savings of 
more than 3 million barrels a day within ten years and 11 million 
barrels a day by 2025:
    Accelerate oil savings in passenger vehicles by:

   establishing tax credits for manufacturers to retool 
        existing factories so they can build fuel-efficient vehicles 
        and engineer advanced technologies, and
   establishing tax credits for consumers to purchase the next 
        generation of fuel-efficient vehicles; and raising federal fuel 
        economy standards for cars and light trucks in regular steps.

    Accelerate oil savings in motor vehicles through the following:

   requiring replacement tires and motor oil to be at least as 
        fuel efficient as original equipment tires and motor oil;
   requiring efficiency improvements in heavy-duty trucks; and
   supporting smart growth and better transportation choices.

    Accelerate oil savings in industrial, aviation, and residential 
building sectors through the following:

   expanding industrial efficiency programs to focus on oil use 
        reduction and adopting standards for petroleum heating;
   replacing chemical feedstocks with bioproducts through 
        research and development and government procurement of 
        bioproducts;
   upgrading air traffic management systems so aircraft follow 
        the most-efficient routes; and
   promoting residential energy savings with a focus on oil-
        heat.

    Encourage growth of the biofuels industry through the following:

   requiring all new cars and trucks to be capable of operating 
        on biofuels or other non-petroleum fuels by 2015; and
   allocating $2 billion in federal funding over the next 10 
        years to help the cellulosic biofuels industry expand 
        production capacity to 1 billion gallons per year and become 
        self-sufficient by 2015.

    As you requested, I provide additional detail from that report 
below. I am also attaching the entire report. The report is available 
online at http://www.nrdc.org/air/transportation/oilsecurity/plan.pdf.

                   Excerpts from ``Securing America''

    We recommend the following actions:
    Establish a minimal national commitment to save 2.5 million barrels 
per day by 2015 and 10 million barrels per day by 2025.
    Saving oil requires mobilizing American ingenuity, factories, and 
farms around a clear goal. The first, most critical, step is for 
Congress to establish a national commitment to cut oil expenses and 
reinvest the resources-otherwise sent to oil producing countries-in 
American factories and farms. If the past is an indicator of success 
for such a commitment, this savings goal is achievable. During World 
War II, American factories converted in just months from building cars 
to building tankers and bombers that became the arsenal of democracy. 
And after the first oil crisis in the early 1970s, America cut its oil 
demand to keep our economy strong. Although some may doubt the ability 
to turn this ship around, history shows us that American efficiency and 
ingenuity can meet the challenge. Saving 2.5 mbd by 2015 and 10 mbd by 
2025 is well within our technical potential.
    We recommend the following policy measures to achieve the oil 
savings:
    Accelerate oil savings in passenger vehicles by:

   establishing tax credits for manufacturers to retool 
        existing factories so they can build fuel-efficient vehicles 
        and engineer advanced technologies, and for consumers to 
        purchase the next generation of fuel-efficient vehicles; and
   raising federal fuel economy standards for cars and light 
        trucks in regular steps.

    As oil prices have risen, so has the demand for fuel-efficient cars 
and trucks, especially hybrids. Unfortunately, the ``Big 3'' 
automakers, General Motors, Ford Motor Company, and DaimlerChrysler, 
have been slow to get into the hybrid market. As a result, they are 
losing the race for clean and efficient vehicles, automakers move 
faster to build hybrids, thousands of jobs could be lost. And with 
business as usual, the Big 3 will face a significant competitive 
disadvantage in the global auto market over the next few decades. 
Putting American innovation to work can reverse this course, saving 
jobs while saving oil.
    Tax credits for factories, consumers. Producing fuel-efficient, 
advanced technology vehicles will require automakers and their 
suppliers to retool their factories. Hybrid vehicles rely on advanced 
equipment such as battery packs, electric motors and generators, and 
electronic power controllers. Advanced diesel drivetrains require 
sophisticated fuel injection systems, turbochargers and advanced 
pollution control devices (to meet emission standards). Factories in 
Japan and Europe currently supply these components to the United 
States. Tax credits help expand market demand for these vehicles, aid 
manufacturers in making capital investments necessary to retool their 
factories, make advanced technologies more cost-effective, and 
stimulate job growth in the production of cleaner, more efficient 
vehicles.
    We endorse the proposals offered by a bipartisan group, the 
National Commission on Energy Policy (NCEP), which recommended a total 
of $3 billion over the next five to ten years in consumer and 
manufacturer tax credits. These tax credits will not only help reduce 
oil dependence but also will pay for themselves through increased tax 
revenue from new economic activity, including new jobs in the 
production of high-efficiency vehicles.
    Fuel economy standards. The NCEP also recommended that to ensure 
public benefits from these tax credits, federal fuel economy standards 
should be raised to ensure that the increased production of the most 
fuel-efficient vehicles translates into national oil savings. Fuel 
economy standards were highly effective in cutting oil use in the late 
1970s and the 1980s. According to a 2002 report from the National 
Academy of Sciences, Effectiveness and Impact of Corporate Average Fuel 
Economy (CAFE) Standards, the CAFE standards enacted in 1975 were a key 
factor in the dramatic rise of car and light-truck fuel economy between 
1975 and 1988. Fuel economy for new passenger cars nearly doubled, 
rising from 15.8 mpg in 1975 to a peak of 28.6 in 1988. Fuel economy 
for new light trucks increased 50 percent, rising from 13.7 mpg in 1975 
to 21.6 mpg in 1987.
    Although total fuel use by passenger vehicles has risen by 30 
percent since the federal fuel economy standards were enacted, the 
majority of this increase took place after the fuel economy standards 
leveled in the mid- and late 1980s. Adding to the growth in fuel use 
was the rise in sales of light trucks (such as SUVs, minivans, and 
pickups) for general passenger use. The increase in fuel consumption 
would have been even greater if fuel economy standards had not been in 
place.
    Accelerate oil savings in motor vehicles through the following:

   requiring replacement tires and motor oil to be at least as 
        fuel efficient as original equipment tires and motor oil;
   requiring efficiency improvements in heavy-duty trucks; and
   supporting smart growth and better transportation choices.

    Replacement tires and motor oil. We should adopt a program that 
ensures replacement tires are as fuel-efficient as original equipment 
tires. The program should follow the approach already being implemented 
in California, by developing tire efficiency and labeling standards 
(based on rolling resistance) that will enable consumers to purchase 
the most efficient models. This measure would achieve an overall 
decrease in gasoline consumption by all U.S. vehicles of approximately 
3 percent.
    Automakers already equip new cars with low rolling resistance, 
fuel-efficient tires in order to comply with federal fuel-economy 
standards. Rolling resistance is the measure of the amount of energy 
needed to move a tire, so the higher the rolling resistance, the more 
gas the car consumes. There are no efficiency standards or efficiency 
labels for replacement tires, so most consumers unknowingly buy high 
rolling resistance tires to replace originals. A set of four low 
rolling resistance tires would cost consumers just $5 to $12 more than 
conventional replacement tires, but the average driver would recoup the 
additional expense of tires in fuel savings in less than one year. The 
efficient tires would save the typical driver $50 to $150 over the 
50,000-mile life of the tires.
    A program similar to the tire replacement program should be 
implemented to encourage the use of fuel efficient motor oils. Like 
replacement tires, more efficient motor oil can provide fuel savings 
from on road passenger cars and light trucks. According to the U.S. 
Department of Energy, the use of specifically formulated low-friction 
motor oil can increase a vehicle's fuel economy by 1 to 2 percent. A 
producer of synthetic motor oil has projected that fuel economy 
benefits could be as much as 5 percent.
    Heavy-duty trucks. We should establish standards for the smallest 
and largest heavy trucks. The smallest of the heavy trucks, those from 
8,500 to 10,000 pounds can be improved with the same technology systems 
applied to other light-duty trucks. Improvements could be achieved by 
expanding the upper weight limit of the light-duty fuel economy 
standard from 8,500 to 10,000 pounds, which would bring the smallest 
heavy trucks into federal fuel economy program.
    Improving the fuel economy of heavy-duty trucks offers a major 
opportunity for oil savings. Today, vehicles ranging from 8,500 pounds 
to more than 33,000 pounds consume the equivalent of more than 2.8 
million barrels of oil each day. More than two-thirds of this energy is 
consumed by the heaviest trucks, such as tractor-trailers weighing more 
than 33,000 pounds. Lighter, shorter range trucks use the remaining 
third of trucking fuel energy. All truck classes can benefit from fuel-
efficiency gains from current and emerging technology. Technology 
assessments by the American Council for an Energy-Efficient Economy 
(ACEEE) found that truck fuel-efficiency advances up to 70 percent are 
cost-effective. The heaviest long range trucks can increase fuel 
economy through conventional technology improvements, including 
enhancements to aerodynamics, reduction of rolling resistance using 
tires, improved engine fuel injection and thermal management, and 
reductions in vehicle weight.
    Although medium, short-haul trucks can also benefit from 
conventional technology improvements, large fuel economy advances can 
best be achieved through hybrid gasoline-electric or diesel-electric 
drivetrains. Approximately 47 percent of the mileage covered by medium 
trucks is in urban stop-and-go traffic where hybrid designs offer 
significant fuel savings by shutting down combustion engines and 
driving short distances on electric motors.
    A wide range of technologies also exists to reduce the tremendous 
amount of fuel used during idling. Long-haul truckers travel the 
highways for days. During their rest stops, drivers commonly idle their 
diesel engines to warm or air condition their sleeping cab, to run 
electrical appliances and to keep their truck's engine block warm 
during cold weather. Large diesel engines are designed to move heavy 
loads, not run auxiliary systems. More efficient technologies are 
available to perform the needed idling functions. Auxiliary power units 
sip diesel fuel compared with engine idling and, in many cases, the 
idling services can be performed by electrical hookups and other non-
petroleum-fueled systems.
    Smart growth and better transportation choices. Saving oil is one 
more reason to pursue smart growth as an alternative to suburban sprawl 
and to expand Americans' transportation options. Federal strategies to 
support smart growth and better transportation choices save oil by 
reducing the total amount we are required to drive when we commute or 
run errands. The potential for smart growth oil savings is immense. If 
all new construction were built in a similar fashion to existing smart 
growth developments, the nation would save over half a million barrels 
of oil per day after 10 years of construction.
    Congress can overcome barriers to smart growth in several ways. 
First, it should direct federal agencies to revise their planning 
models so that they account for smart growth. Currently, when new 
highway projects or new transit projects are evaluated economically, 
they rely on models that all but ignore the influence of smart growth 
development. Upgraded models will save money in directing investment 
toward more cost-effective transit and highway projects and away from 
ones that do not justify their cost. Enhanced models can also be used 
in clean air planning and in the evaluation of transit service levels.
    One barrier to smart growth is that many homes located in efficient 
neighborhoods cost more, and the lending system treats such additional 
costs as barriers to affordability. The Location Efficient Mortgage 
solves these problems by allowing potential borrowers with low 
transportation costs to apply the savings to qualification for a 
mortgage. Congress could require agencies like Freddie Mac and Fannie 
Mae to offer Location Efficient Mortgages throughout the country in a 
way that allows dollar-for-dollar tradeoffs between lower 
transportation costs and higher housing costs.
    We should promote commuter choice with a tax-free benefit for 
employees who car-pool, use transit, bike to work, or telecommute 
(currently limited to $100 per month) equal to that provided in the 
form of free parking (which is at about $200 and is pegged to 
inflation). This can have a big effect: One recent study in 
Minneapolis-St. Paul found that more than one in 10 employees shifted 
from driving to some other way of commuting when offered tax-free 
commuter benefits equal to those provided in the form of free parking. 
We should also support cutting the red tape and streamlining financing 
for public transportation projects that significantly increase mobility 
of public-transportation-dependent populations and promote economic 
development in urban ``transit-oriented development zones.'' Projects 
to evaluate road user charges, which would make the portion that a 
driver pays for highway maintenance costs depend on how much a person 
uses the roads, are also worthy of support. This system of recovering 
costs, currently being researched by several experts, would ensure 
continued revenue to the highway trust fund.
    Accelerate oil savings in industrial, aviation, and residential 
building sectors through the following:

   expanding industrial efficiency programs to focus on oil use 
        reduction and adopting standards for petroleum heating;
   replacing chemical feedstocks with bioproducts through 
        research and development and government procurement of 
        bioproducts;
   upgrading air traffic management systems so aircraft follow 
        the most-efficient routes; and
   promoting residential energy savings with a focus on oil-
        heat.

    Approximately one-third of U.S. oil demand is consumed in 
industrial manufacturing plants, airplanes, and residential homes. 
Efficiency gains in these sectors can save America more than 300,000 
barrels per day in 2015 or 12 percent of the 2.5 millions barrels per 
day national target.
    Industrial process heating efficiency. The industrial sector 
includes manufacturers of diverse products including steel, cement, 
food, plastics, glass, paper, and chemicals. Heating fuel oil, diesel 
fuel, and liquefied petroleum gas are used by manufacturing companies 
for firing boilers and heating and reheating materials during the 
manufacturing process. Improving the efficiency of boilers and process 
heating can reduce oil consumption by 15 percent by 2020. We should 
expand industrial efficiency programs to focus on oil use reduction and 
adopt standards for petroleum heating efficiency and incentives to 
accelerate old, inefficient equipment.
    Bioproducts. Also in the industrial sector, using petroleum as a 
feedstock for chemicals and manufactured materials consumes four times 
the amount of oil used for heating. Oil savings can be achieved by 
substituting petroleum-based feedstocks with materials derived from 
crops, or biomass. Today, biomass is used in the production of 
solvents, pharmaceuticals, adhesives, resins, detergents, inks, paints, 
lubricants and plastics. According the U.S. Department of Energy (DOE), 
biofeedstocks could displace 13 percent of petroleum-based feedstocks 
by 2020. Continued funding of biomass research and development efforts 
and on-going requirements for government procurement of environmentally 
sustainable bioproducts will spur the production of substitutes to 
petrochemical feedstocks. In 2015, oil saving in the production of 
industrial chemicals could add up to 120,000 barrels per day.
    Air traffic management. Airlines use less jet fuel when they use 
the most direct traffic patterns and minimize idling time before and 
after landing. Advanced air traffic management technologies available 
today for aviation communications, navigation, and surveillance (CNS) 
systems improve airline fuel efficiency by enabling planes to take more 
direct routes (such as more great circle routes) between destinations, 
use more airspace at currently prohibited lower elevations, and 
minimize time waiting for landing and take-off strips. Improvements to 
CNS systems allow aviation control to migrate from groundbased, 
limited-range systems to less-constrained satellite-based systems.
    According to the U.S. DOE, CNS improvements can reduce commercial 
jet fuel consumption by 5 percent by 2020. CNS upgrades minimize 
aircraft rerouting (when conditions unexpectedly change in the air or 
at airports), control take-off and landing spacing and enable after-
flight aircraft and routing performance analysis. We should fund 
advancements to the air traffic management system that increase routing 
efficiency and therefore reduce per-passenger fuel consumption.
    Oil-heated homes. Petroleum products remain an important source of 
heating energy in homes. According to the EIA, approximately 8 million 
residences continue to burn fuel oil, liquefied petroleum gases (LPG), 
propane, and kerosene for space and water heating. 60 cost-effective 
home improvements to space and water heating systems such as insulating 
walls, ceilings and pipes, sealing drafts and especially sealing ducts, 
installing new windows, upgrading thermostats; updating furnaces; 
replacing old clothes washers and dishwashers with new efficient 
models; and replacing water heaters can reduce heating oil use by 30 
percent or more.
    We should promote residential energy savings with a focus on oil 
heat to help reduce the nation's oil dependence by adopting stringent 
efficiency standards for house and apartment building boilers and 
furnaces; by adopting performance-based tax incentives for home 
retrofits and for efficient water heaters; and by updating codes for 
new buildings. Together these measures can save 100,000 barrel of oil 
per day in 2015. We should promote residential weatherization and other 
energy saving programs to help achieve the national oil savings 
commitment.
    Encourage growth of the biofuels industry through the following:

   requiring all new cars and trucks to be capable of operating 
        on biofuels or other non-petroleum fuels by 2015;
   converting the federal oxygenate requirement, which is not 
        necessary to meet clean air goals, to a renewable fuel 
        standard; and
   allocating $2 billion in federal funding over the next 10 
        years to help the cellulosic biofuels industry expand 
        production capacity to 1 billion gallons per year and become 
        self-sufficient by 2015.

    Although fuel efficiency is critical to immediately reducing our 
oil dependence, we must also develop alternative, non-petroleum fuels 
that can be grown by American farmers. The biofuel feedstock with the 
potential to displace the largest amount of oil is cellulosic biomass, 
which includes agricultural residue (the leaves, stems, and stalks of 
plants), dedicated energy crops, and the biomass portion of the 
municipal waste stream. Ethanol and methanol, both alcohol fuels, can 
be made from cellulosic biomass.
    A market for biofuels already exists. In 2004, the United States 
produced more than 3.4 billion gallons of ethanol, almost all from 
corn, for use as an additive to gasoline. Because the gasoline oxygen 
additive methyl tertiary butyl ether (MTBE) has been found to 
contaminate water supplies, the chemical is being replaced by ethanol. 
Gasoline blended with 10 percent by volume ethanol can be used in 
unmodified vehicles, but it creates air pollution problems in today's 
on-road cars. Higher blends of these alcohol fuels, however, can be 
used only in vehicles specifically designed to burn high-oxygen fuel. 
So-called flexible fuel vehicles (FFV) can run on gasoline blended with 
almost any amount of alcohol fuel. The most common high-blend fuel is 
85 percent ethanol, E-85. Because high blend ethanol fuel is typically 
more expensive than gasoline, less than 1 percent of the FFVs on the 
road today burn gasoline with high ethanol content such as E-85 high 
blend ethanol from corn. Fortunately, ethanol made from other sources, 
called cellulosic ethanol, promises to substantially reduce this cost.
    Biofuels in new cars and trucks. We should require the use of 
higher-biofuel blends in gasoline. Higher ethanol blends not only 
displace more oil but also decrease harmful particulate air pollution 
associated with lower-ethanol blends in gasoline. To accomplish this, 
we should require all new cars and trucks to be capable of operating on 
biofuels or other non-petroleum fuels by 2012. To operate on E-85, and 
other high-ethanol and methanol blends, FFVs require low-cost 
technology improvements that generally make the FFV only slightly more 
costly to buy than its conventional, gasoline-only counterpart.
    Ethanol made from cellulosic biomass offers numerous advantages, as 
detailed in a recent report lead by NRDC for the National Centers for 
Environmental Prediction (NCEP). The technology for converting 
cellulose to biofuels is expected to be cost-competitive with 
petroleum-based fuels. Cellulosic biomass crops, such as switchgrass, 
have the potential to produce more biomass per acre than almost any 
other crop and as a perennial they require lower inputs of energy, 
fertilizer, pesticide, and herbicide, and is accompanied by less 
erosion and improved soil fertility. Cellulosic biomass also contains 
substantial amounts of non-fermentable, energy-rich components that can 
be used to provide energy for the conversion process as well as to 
produce electricity and other fuels using non-biological conversion 
processes. With the right policies in place, there is tremendous 
potential for biofuels to displace petroleum in our cars and trucks. By 
2050, biofuels could contribute the equivalent of 7.9 million barrels 
of oil per day, or 53 percent of our current demand.
    Federal oxygenate requirement. To facilitate the transition to 
cellulosic biofuels, the federal oxygenate requirement, which is not 
necessary to meet clean air goals, should be converted to a renewable 
fuel standard. Such a system would provide much needed flexibility to 
areas that are suffering from the nation's worst air quality to blend 
effective, low cost, cleaner burning gasoline formulations. To 
encourage cellulosic production, credits for biofuel production should 
be awarded based on the environmental performance of its lifecycle 
including its feedstock production, processing, refining and 
combustion. In addition to displacing oil consumption, the EPA should 
be required to ensure that biofuels are used in a way that maintains or 
improves air quality, water quality and water supply. As the capacity 
for biofuels production with cost-effective and sustainable practice 
grows, we should increase production targets of the renewable fuels 
standard only if it can be demonstrated that there will be no increase 
in air pollution.
    Biofuels funding. Two billion dollars in federal funding for 
biofuels over the next 10 years would spur innovation, development, and 
demonstration projects aimed at making biofuels cost-effective for 
consumers. The funding should supply incentives that will stimulate the 
growth of the cellulosic biofuel industry toward a production target of 
1 billion gallons per year and make the industry self-sufficient by 
2015. These funds should be used to achieve two major goals:

   Investing in a package of research, development, and 
        demonstration policies that create the innovations and advances 
        needed for a large-scale, competitive biofuels industry; and
   Funding deployment policies that drive the development of 
        the first billion gallons of cellulosic biofuels capacity at a 
        price approaching that of gasoline and diesel.

     Responses of David Hawkins to Questions From Senator Bingaman

    Question 1. Your testimony highlights the emissions implications of 
dramatically increasing our use of coal-to-liquids technology for 
transportation fuels. Doctor Miller's statement however talks about 
coal to liquids as a clean technology with near-zero atmospheric 
emissions of criteria pollutants and carbon capture sequestration. Are 
your assumptions different? How do you reconcile these two views?
    Answer. In fact, my testimony and Dr. Miller's are consistent. With 
respect to emissions, my testimony focused on emissions of conventional 
air emissions and of global warming emissions from CTL production 
plants. Regarding conventional emissions I stated, ``While it appears 
that technologies exist to achieve high levels of control for all or 
most of these pollutants, the operating experience of coal-to-liquids 
plants in South Africa demonstrates that coal-to-liquids plants are not 
inherently `clean.' Noting the absence of performance standard 
requirements today, I said ``we cannot say today that coal-to-liquids 
plants will be required to meet stringent emission performance 
standards adequate to prevent either significant localized impacts or 
regional emissions impacts.''
    Dr. Miller stated, ``The technology that underlies CTL fuel 
production offers the potential for low emissions of criteria and toxic 
air pollutants, water quality, and solid wastes. Nonetheless, this 
promise of high performance needs to be verified during the design and 
initial operations of first-of-a-kind CTL plants and costs may be 
prohibitively expensive.'' I believe these two statements are 
completely consistent: for conventional pollutants CTL plants have the 
potential to be low-emitting but that is not yet assured in practice.
    Regarding global warming emissions, I stated ``the total well to 
wheels CO2 emissions from such plants would be about 49.5 
pounds of CO2 per gallon, nearly twice as high as using 
crude oil, if the CO2 from the coal-to-liquids plant is 
released to the atmosphere.'' And further that, with ``CO2 
capture, well to wheels emissions from coal-to-liquids fuels would be 8 
percent higher than for petroleum.'' Dr. Miller did not provide a value 
for CO2 emissions from plants without capture but he cited a 
report ``Mitretek Technical Report 2005-08, ``A Technoeconomic Analysis 
of a Wyoming Located Coal-To-Liquids Plant'' whose estimates of 
CO2 emissions are similar to ours. Regarding CO2 
from plants that capture emissions Dr. Miller stated, ``It is possible 
that CTL plant emissions and the emissions from utilization of CTL 
products would be comparable to those associated with the production 
and consumption of petroleum-based fuels.''
    To summarize, our testimony agrees that CTL plants have the 
potential to achieve low emission rates for conventional emissions but 
achieving this performance in practice remains to be demonstrated; that 
CO2 emissions from the CTL system will be much higher than 
from the crude-oil system if CTL production plant emissions are not 
captured; and that CO2 emissions from the two systems would 
be about the same if CTL production plant emissions were captured.
    Question 2. Everyone is focused on the need for a demonstrated 
commercial scale and market for CTL in addition to an adequate coal 
supply in order to insure that CTL goes forward. Isn't the development 
of CTL somewhat tied to the development of the carbon market also? 
Please comment.
    Answer. The development of policies to limit CO2 
emissions, such as through the establishment of a market-based cap and 
trade program, will be a key factor in the comparative value of CTL-
based fuels compared to alternatives. Some advocates of CTL assert that 
the industry would need to be provided with government assurances about 
the future price of oil before the private sector is willing to make 
large investments in this technology. There is a strong argument that 
uncertainty about the future costs of managing CO2 emissions 
will be an impediment to private sector interest in this and other 
technologies as well.
    Some investors may be willing to guess about the pace and level of 
future CO2 requirements. The only certain thing one can say 
about that prospect is that some of those guesses will be wrong, 
resulting in economic waste and potentially large sunk costs in high-
CO2-emitting alternatives to conventional oil.
    The fact that the U.S. appears to awakening to the need to develop 
real alternatives to oil provides us with an enormous opportunity--to 
create the market signals and incentives that will stimulate oil 
alternatives that are selected because they improve energy security, 
create jobs at home and put us on a path to protect the climate. If we 
leave CO2 performance out of the picture in crafting 
policies to reduce oil dependence we would almost certainly produce a 
distorted set of responses by the private sector--mistakes that would 
cost us dearly to correct.

       Responses of David Hawkins to Questions From Senator Wyden

    Question 1. If price volatility and crude oil prices are the two 
major impediments to bringing coal-to-liquids (CTL) fuels to U.S. 
markets, the ``tipping point'' to make CTL economically viable is at 
$40/barrel and the price of oil is now at $70 per barrel, why does the 
government need to continue subsidizing more CTL research? Why can't 
the private sector start building commercially viable production 
plants?
    Answer. As Dr. Miller's testimony noted, the current administration 
agrees with this view. He stated, ``The primary barrier to commercial 
introduction of the technology has been the volatility and uncertainty 
of world oil prices. The private sector financial markets are best 
positioned to evaluate whether, when, and how to build coal to liquids 
plants given this market uncertainty.'' A case can be made for 
providing government support for key technologies that are well-suited 
to meet future needs but are currently discounted by the private 
sector. As my testimony argues, coal-to-liquids processes are not well-
suited to meet our needs for lower greenhouse gas emitting fuels. 
Accordingly, it is not a technology that we believe should be a 
candidate for these types of public subsidies. In general, public 
support for petroleum fuel replacements should be limited to fuels 
which, among other criteria, achieve substantial reductions in global 
warming pollution relative to the fuels they replace.
    Question 2. As a Westerner, I am concerned about the water 
resources that are needed to produce fuels from coal. I am also 
concerned about the increased air pollution and greenhouse gases that 
are emitted. Much of the water that would go into CTL production, could 
be used to grow biomass and produce biofuels instead. Has anyone done a 
comparison of which types of energy production cause the least harm to 
the environment while delivering the biggest benefits to consumers? Do 
you know of any analyses that have looked at the ``opportunity costs'' 
involved in producing water-intensive energy like CTL?
    Answer. Thank you for your question regarding comparative water use 
by coal to liquids (CTL) technologies. We do not believe that a 
comprehensive analysis of this issue has been completed. We urge the 
Committee to support a comprehensive analysis of the water supply 
implications of not only CTL technologies, but of all the leading 
alternative fuel sources and petroleum-based fuels. To be 
authoritative, such a ``Well to Wheel'' analysis must consider water 
use in all stages of fuel production. For CTL, biofuels and petroleum 
based fuels, this analysis must include:

   The amount of water required per unit of product to turn 
        coal into Fischer-Tropsch (FT) fuel, by technology type 
        (cooling process, etc)
   The water usage of turning raw material into usable 
        feedstocks (e.g. mining, refining)
   The efficiency with which the energy in feedstocks is 
        converted into usable fuel.
   The availability of existing waste material as feedstock for 
        ethanol production.
   The geographic distribution of ethanol feedstock production 
        (e.g. irrigation needs)
   The use of water to assist in the extraction of petroleum 
        from well fields with declining production.

    This analysis should also include a study of water quality impacts. 
Water quality impacts can, in turn, lead to significant water supply 
impacts. For example, the severe water quality impacts caused by coal 
mining and petroleum production and refining have had a significant 
impact on the ability of many downstream communities to use their water 
supplies.
    Some existing agricultural practices also result in significant 
water quality impacts. In the case of the emerging technology of 
biofuels, it is not yet clear what crops (e.g. switchgrass or corn) 
would provide the bulk of feedstock for cellulosic ethanol production, 
nor is it yet clear how those crops would be grown.
    As previously stated, there is not yet a substantive body of 
research on water use in CTL facilities. The only existing analysis 
that we are aware of--by Mitretek Systems of a possible Wyoming 
facility--states that ``complex conversion facilities like CTL plants 
usually require large quantities of water for process steam and for 
cooling and steam condensation.'' \1\ The same report notes that the 
equivalent of ``less than one barrel of water per barrel of FT 
product'' would be needed if dry-cooling technology was employed.
---------------------------------------------------------------------------
    \1\ Mitretek Systems, A Techno-Economic Analysis of a Wyoming 
Located Coal-to-Liquids (CTL) Plant, (April 2005).
---------------------------------------------------------------------------
    However, dry-cooled power systems are still a relatively immature 
technology and are significantly more expensive to build and operate 
than water cooled ones. According to a recent study using EPA 
calculations which analyzes the water used in the production of power, 
The Last Straw, Water Use by Power plants in the Arid West,\2\ 
operating and maintenance costs of a 700MW dry-cooled plant would be 
four times higher than for a similar water-cooled plant. The same study 
notes that total annualized costs for the dry-cooled plant would be 
more than four times higher ($13.1 million versus $3.1 million) than a 
water-cooled counterpart.
---------------------------------------------------------------------------
    \2\ Clean Air Task Force, The Land and Water Fund of the Rockies, 
The Last Straw: Water Use by Power Plants in the Arid West, (April 
2003), http://www.westernresourceadvocates.org/media/pdf/WaterBklet-
Final.pdf.
---------------------------------------------------------------------------
    Additional water use by the power sector in the West would come at 
a time when water resources in the region are already strained by 
drought and competing demands. According to the Energy Information 
Administration, coal and gas-fired electric power plants in the eight 
state Interior West withdraw over 650 million gallons of water per 
day.\3\ In a one year period, that's the same amount of water used by 
almost four million people, or six or seven cities the size of Denver, 
Tucson and Albuquerque.\4\
---------------------------------------------------------------------------
    \3\ ibid, p. 1.
    \4\ ibid.
---------------------------------------------------------------------------
    Western streams and rivers are also an important part of regional 
and local economies. Yet in many areas, years of drought and altered 
precipitation patterns have put heavy strains on these water bodies and 
their ecosystems, adversely affecting the economies they help support. 
According to recent data, almost 80 percent of the water used by power 
plants comes from fresh surface waters--mostly rivers.\5\ Substantial 
development of new power generating facilities would exacerbate strains 
on river and streamflow.
---------------------------------------------------------------------------
    \5\ Clean Air Task Force, Wounded Waters: The Hidden Side of Power 
Plant Pollution, (February 2004), p. 2.
---------------------------------------------------------------------------
    In contrast to energy efficiency projects and renewable energy 
facilities, water availability is proving to be a growing hurdle for 
new coal-based generating projects. Increased competition for water 
from other sectors of the economy and a growing understanding of the 
importance suitable water levels play in maintaining complex biotic 
systems have combined to lead permitting authorities to deny permits or 
condition them on addressing potential impacts to water resources.\6\ 
This is true even in non drought-ridden regions of the country.\7\
---------------------------------------------------------------------------
    \6\ ibid., p. 10.
    \7\ ibid., p. 10.
---------------------------------------------------------------------------
    Substantial development of CTL plants also will likely result in 
significant increases in upstream coal mining impacts, which in turn 
affect water resources. History is instructive. In the western U.S., 
estimates of the damage from acid mine drainage (AMD) range between 
five and ten thousand miles of streams polluted.\8\ AMD is the most 
significant form of chemical pollution produced from coal mining 
operations. In both underground and surface mining, sulfur-bearing 
minerals common in coal mining areas are brought up to the surface in 
waste rock. When these minerals come in contact with precipitation and 
groundwater, an acidic leachate is formed. This leachate picks up heavy 
metals and carries these toxins into streams or groundwater. Waters 
affected by AMD often exhibit increased levels of sulfate, total 
dissolved solids, calcium, selenium, magnesium, manganese, 
conductivity, acidity, sodium, nitrate, and nitrite. This drastically 
changes stream and groundwater chemistry. The degraded water becomes 
less habitable, non potable, and unfit for recreational purposes. The 
acidity and metals can also corrode structures such as culverts and 
bridges.\9\
---------------------------------------------------------------------------
    \8\ EPA. Mid-Atlantic Integrated Assessment: Coal Mining.
    \9\ EPA Office of Solid Waste. Acid Mine Drainage Prediction 
Technical Document, (December 1994).
---------------------------------------------------------------------------
    As previously stated, NRDC agrees that it is essential to consider 
the water-related implications of energy policy decisions, particularly 
in arid regions, such as the American West. In 2004, NRDC issued a 
report entitled Energy Down the Drain, which explores this relationship 
from a different perspective--the energy implications of water 
management decisions.\10\
---------------------------------------------------------------------------
    \10\ NRDC, Energy Down the Drain, (August 2004), http://
www.nrdc.org/water/conservation/edrain/edrain.pdf.
---------------------------------------------------------------------------
    NRDC has also studied water implications of renewable sources, most 
recently in our report Growing Energy. One promising potential fuel 
source highlighted in the report (and also by President Bush in his 
State of the Union address), switchgrass, could result in fewer water 
quality impacts than other potential feedstocks, because switchgrass 
requires less fertilizer, herbicide, insecticide and fungicide per ton 
of biomass than corn, wheat or soybeans. In addition, because 
switchgrass is a perennial plant, it could also reduce erosion-related 
water quality impacts compared with other crops.\11\ Federal incentive 
programs for the biofuels industry could encourage more sustainable 
agricultural practices with reduced water quality and water supply 
impacts.
---------------------------------------------------------------------------
    \11\ NRDC, Growing Energy, (December 2004), p. 28, http://
www.nrdc.org/air/energy/biofuels/biofuels.pdf
---------------------------------------------------------------------------
    NRDC has also determined that, nationally, assuming a value of $30 
per dry ton, existing mill waste, forest residues and agricultural 
residues could produce up to 68 million dry tons of feedstocks for 
biofuels.\12\ This feedstock could be provided with little additional 
water consumption prior to refining. Our modeling of the potential for 
switchgrass production also focused production in Appalachia, the Corn 
Belt and the Southeast, rather than the West, where a greater 
percentage agricultural water needs are met by irrigation, rather than 
rainfall. This approach would reduce potential water use 
implications.\13\
---------------------------------------------------------------------------
    \12\ ibid., p. 20.
    \13\ ibid., p. 27.
---------------------------------------------------------------------------
    In our Growing Energy report,\14\ NRDC also determined that ``The 
high level of water recycling also allows us to minimize the total 
amount of fresh water used. Approximately 2 kg water per kg dry biomass 
feedstock--about 1,700 gallons per minute--are required as make-up 
water to account for the treated discharge as well as water consumed 
during hydrolysis or lost to evaporation. Petroleum refineries, by 
comparison, typically use 1.8 to 2.5 kg process water per kg crude 
feedstock--4,400 to 6,200 gallons per minute for a 100,000 barrel per 
day refinery--and discharge between 1.7 and 3.1 times as much water.'' 
Thus, biomass refining may have the potential to reduce water usage in 
comparison with petroleum-based refineries.
---------------------------------------------------------------------------
    \14\ ibid., p. 43.
---------------------------------------------------------------------------
    A comprehensive analysis of water use by electricity and fuel 
supply production is required for another reason. Climate change has 
the potential to cause significant water supply impacts. Last 
September, NRDC, the Desert Research Institute and the Southern Nevada 
Water Authority co-sponsored a conference of water managers and climate 
scientists to explore the potential water management impacts of climate 
change. The consensus among scientists is that climate change could 
reduce available water supplies in the West and in other parts of the 
nation. The implications in this context are significant. Finding 
solutions that work in the future will require finding synergies that 
solve multiple problems. The wrong approach to meeting long-term fuel 
needs could worsen climate change, increase water use and increase 
conflicts over water. On the other hand, the development of appropriate 
technology could result in reduced climate change, lower water use and 
reduced water conflicts.
    Question 3. If the German and South African experience in producing 
coal fuels is any indicator, wouldn't you say that the only policy 
reason that justifies producing CTL fuels in the U.S. would be at a 
time when the U.S. no longer had access to world oil markets?
    Answer. As your question implies, the historical precedents for 
countries embracing coal-to-liquids (CTL) fuels involve countries which 
found themselves (more accurately put themselves) in circumstances 
where no other alternatives for transportation fuels were available. 
Obviously, pursuit of a technology by an evil regime does not make the 
technology evil. The relevant questions are whether CTL fuels are well-
suited for our country's needs and whether we have superior 
alternatives. In my testimony and my responses to your earlier 
questions and those from other Senators, I have pointed out why we 
believe CTL fuels are not well-suited to America's needs, especially 
with regard to the need to protect the climate from global warming 
emissions but also from the harms that expanded coal production would 
cause, given today's practices.
    Fortunately, our situation is in no way as desperate as that which 
confronted Nazi Germany or Apartheid South Africa. We have the capacity 
to meet our transportation needs and reduce oil dependence by producing 
homegrown fuels from biomass and by using American ingenuity to get 
more work out of every barrel of fuel we use, through application of 
known technologies to make more efficient cars, trucks and aircraft and 
to deploy more efficient industrial processes. In my response to 
Senator Bunning's question I describe these abundant opportunities in 
more detail. Coal has an important role in today's economy and will 
continue for years to come but we do not need to use it to address our 
addiction to oil.
                                 ______
                                 
     Responses of Arie Geertsema to Questions From Senator Bunning

    Question 1. Some people have argued that ``C.T.L'' technology 
exists and that the government should focus on deployment of those 
existing technologies. You seem to take a different approach, 
suggesting that more Research is required. Could you explain what 
research is needed?
    Answer. By urging for more R&D, I indicated this should be done in 
parallel to promoting the deployment of CTL. Deployment does not need 
to wait for R&D, but R&D will be a meaningful contributor to bringing 
costs down.
    CTL as an integrated combination of gasification of coal with the 
conversion of the syngas to liquid fuels is currently only practiced 
commercially by Sasol as indicated in my testimony. Several other 
companies have gasification facilities while some have Gas to Liquids 
(GTL) or Fischer-Tropsch technology. Shell is the only one besides 
Sasol with commercial FT technology. In all cases the technology, at 
whichever level of maturity, is very closely protected. An important 
consideration in funding FT R&D is to broaden the technological base 
and to provide alternatives and expertise which is outside of the 
closely protected IP areas of the commercial entities. ``Commercial 
technologies'' do not mean that these technologies are available to 
anyone wishing to apply it.
    It is not unusual for the Government through DOE to fund research 
in areas where there are commercial technologies available. To name but 
a few: Gasification, Fuel Cells and Turbines. These projects were 
supported to improve on existing commercial technologies or to get them 
to operate under more demanding circumstances. In the same way I 
believe that further R&D regarding CTL will provide opportunities to 
improve viability and to facilitate deployment. CTL is an issue of 
strategic dimensions, not merely one where small companies will put up 
small plants: we need to think big.
    Furthermore, I indicated that by funding research in CTL, a wider 
basis will be provided from which we can again grow a coal technology 
human resource capability which has nearly disappeared since the 
interest in coal technology waned in the 1980's. Industries currently 
do little in this regard and the few people who have expertise are very 
much in demand. We need to increase the size of the pool.
    An example of the ongoing need for R&D is that Sasol, even after 
more than 50 years of R&D, is still investing continuously in process 
improvements. This year it announced that additional FT R&D reactors 
will be erected at a cost of about $33 million. This will invariably be 
closely IP protected. The point is that we need to also do open 
research to promote the technology and even in commercial environments 
R&D is continuing.
    Specifically, the type of research which can be funded as ``open'' 
is similar to the catalysis research funded in the 1990's and which led 
CAER to now being the most significant open access R&D facility for FT 
catalysis. This can be witnessed by the fact that CAER does testing for 
national and international FT companies. This addresses the catalysis, 
but it takes much more than a good catalyst to make a good technology. 
Research can be done to firm up the understanding of the separation of 
catalysts from wax in slurry FT systems, understanding the complex 
physical properties of multiphase systems in slurry reactors at high 
temperatures and pressures, improving syngas cleaning processes 
specifically for FT and matching those processes with novel, more 
resistant catalysts, producing test quantities of refined FT fuels 
under different refining conditions for optimal product properties, 
etc. It will be of great benefit if such R&D could be done in small 
scale units which are fully integrated from the syngas to refined 
products to ensure that the system as a whole is optimized and not 
operated as sub-systems in isolation.
    Question 2. The finished ``C.T.L.'' product is low particulate, low 
mercury and almost zero sulfur. Could you elaborate on the emissions 
characteristics of ``C.T.L.'' transportation fuels compared to current 
fuels?
    Answer. The superior qualities of FT fuels have been widely 
investigated and reported. Institutions like the Southwest Research 
Institute (SWRI) did independent comparative tests on FT diesels from 
different sources and all showed similar excellent performance 
regarding emissions, cetane number, minimal sulfur with reduced 
hydrocarbon and particulate emissions. Mercury does not appear in the 
FT fuels as mercury is captured in the syngas cleaning process 
following gasification. As an example, results from SWRI tests were 
published in 1997 (``Diesel Exhaust Emissions Using Sasol Slurry Phase 
Distillate Process Fuels'' by Schaberg, P.W. et al. and co-authored by 
Starr, M.E. of SWRI, published as a SAE Technical paper 972898). This 
publication reports results from testing seven diesel fuels. There were 
different FT diesels, CARB and US 2-D fuels as well as three blends of 
FT fuels and 2-D fuels. The report shows improvements in all 
characteristics for the blends in proportion to the amount of FT fuel 
in the blend with the best results for pure FT fuels. This indicates 
the compatibility as a blending component or as a pure fuel. Similar 
results have been published by companies like Shell, Rentech and 
Syntroleum and can be accessed on their web sites.
    Question 3. As the Energy Information Administration forecast 
indicates, we have two choices: we can import ``C.T.L.'' fuels from 
foreign countries or we can produce it ourselves. I believe, and I 
think the witnesses here today have shown, that America can produce 
these fuels cleaner than anywhere else. Given the environmental and 
safety records of other coal countries, wouldn't you agree that the 
production of coal and ``C.T.L.'' in other nations would cause more 
environmental damage than if they are produced in America?
    Answer. The question raises the matter whether CTL should be 
practiced in the US (with tight environmental requirements) or whether 
developing countries could do it (with potential negative environmental 
consequences) and export the FT products to the USA. The need for the 
fuels is in the USA and it is economically advantageous to have local 
production. If we would promote the production in coal rich developing 
countries, this will not reduce our dependence on foreign fuel imports 
and secondly, there might indeed be a greater negative environmental 
impact than if we put up well regulated CTL facilities in the US.
    My preference is clearly to erect the CTL facilities in the USA.

      Responses of Arie Geertsema to Questions From Senator Wyden

    Question 1. If price volatility and crude oil prices are the two 
major impediments to bringing coal-to-liquids (CTL) fuels to U.S. 
markets, the ``tipping point'' to make CTL economically viable is at 
$40/barrel and the price of oil is now at $70 per barrel, why does the 
government need to continue subsidizing more CTL research? Why can't 
the private sector start building commercially viable production 
plants?
    Answer. The price of crude and its price volatility are certainly 
risk factors which impact the investment decisions. Several other risk 
factors enter into the investment decision, such as the maturity of 
technology under local conditions, environmental permitting, plant 
siting and the need for very large capital investments for plants which 
are large enough to have strategic impact. Which companies will step up 
to enter into CTL ventures as ``owner-operators'' is not yet clear. 
``Private sector'' is an amorphous concept in this case seeing that 
there is not yet a CTL industry in the US and there is uncertainty as 
to who will take the lead. Once a plant or two of meaningful capacity 
have been built, I believe more will follow.
    Regarding ``Why fund more R&D?'', I believe that this is to promote 
the capabilities and creative new concepts in this area while the 
commercialization should continue in any case. Please also refer to my 
answer to Senator Bunning's question number 1. above.
    Question 2. As a Westerner, I am concerned about the water 
resources that are needed to produce fuels from coal. I am also 
concerned about the increased air pollution and greenhouse gases that 
are emitted. Much of the water that would go into CTL production could 
be used to grow biomass and produce biofuels instead. Has anyone done a 
comparison of which types of energy production cause the least harm to 
the environment while delivering the biggest benefits to consumers? Do 
you know of any analyses that have looked at the ``opportunity costs'' 
involved in producing water-intensive energy like CTL?
    Answer. I am not personally informed about environmental or 
``opportunity cost'' studies which have been done to do the comparisons 
referred to and I cannot comment on the results of such studies. I do 
believe that the energy issue is so wide in its impact, that we should 
pursue multiple options for farther development across the spectrum of 
modernized traditional methods as well as the range of ``alternative'' 
and novel energy sources. Different technologies will have applications 
in different circumstances and diversity in the approaches will enable 
us to make responsible choices for the benefit of the environment and 
the consumer
    CTL facilities do in fact, like coal based power stations, require 
substantial amounts of water. Exactly how much depends on the design 
and complexity of the facility. Generic numbers can be misleading. For 
instance, the choice between water cooling versus air cooling greatly 
impacts water consumption.
    Regarding air pollution/green house gases: I indicated that the 
technologies are now available to make these facilities true ``Clean 
Coal'' facilities. Whether the CO2 will be captured and 
sequestered is a matter of permit requirements, mandated carbon trading 
and similar factors. These eventually boil down to whether a particular 
entrepreneur considers a project viable for a particular site.
    Question 3. If the German and South African experience in producing 
coal fuels is any indicator, wouldn't you say that the only policy 
reason that justifies producing CTL fuels in the U.S. would be at a 
time when the U.S. no longer had access to world oil markets?
    Answer. I believe that CTL is competitive at oil prices around $45 
to $50 per barrel. In my testimony I indicated that the decision to 
build Sasol Two was based on economic considerations. The Sasol Three 
decision had an additional consideration of security of supply but 
Sasol has for many decades been commercially competitive and very 
profitable as a private sector company.
    The German plants by all accounts had limited capacities 
(statistics differ and many of them were operating very sporadically 
during the war). That was clearly a war effort and economics did not 
come into the picture. However, already before the war there were 
commercial units operating in Germany and the South African case is a 
commercial success story from its early (pre-sanctions) years. Thinking 
of Germany and South Africa as cases where FT went ahead merely because 
of supply concerns is not doing justice to history.
    The main reasons for encouraging CTL in the US are that such 
ventures are likely to be profitable; it makes sense from a security of 
supply perspective; it reduces our import dependency and it will have a 
significant favorable economic multiplier effect. The sooner we start 
with CTL, the sooner we shall start reaping the benefits of this 
opportunity.
                                 ______
                                 
      Responses of James Roberts to Questions From Senator Bunning

    Question 1. You suggest that our efforts need to focus on the 
deployment of coal-to-liquids facilities rather than on research and 
development. You argue that the technology is proven and ready for 
deployment. How best can the Department of Energy fashion the load 
guarantee program established by the Energy Policy Act to foster 
deployment of such technology?
    Answer. NMA supports the use of federal loan guarantees, both self-
pay and traditional, for 10 CTL plants through 2015. This type of 
commitment (authorized by Title XVII of the Energy Policy Act of 2005) 
specifically focused on the financing of gasification projects 
dedicated to the producing synthetic gas from coal will serve as the 
basis for the production of liquid transportation fuels.
    Question 2. The finished ``CTL'' product is low particulate, low 
mercury and almost zero could you elaborate on the emissions 
characteristics of ``CTL'' transportation fuels compared to current 
fuels?
    Answer. Once the coal is gasified, virtually all sulfur must be 
removed from the gas prior to its entry into the Fischer-Tropsch (FT) 
reactor. The result is a near-zero sulfur fuel. Sulfur-based emissions 
are a primary drawback of conventional diesel fuels because sulfur 
decreases the effectiveness of control devices (like catalytic 
converters) that could otherwise further reduce harmful emissions. FT 
diesel therefore directly eliminates sulfur emissions and allows even 
greater control of other emissions.
    Largely because FT diesel contains very low aromatics, combustion 
results in very low PM. Recent tests conducted by the Department of 
Defense (DOD) showed particulate matter exhaust reductions using FT 
diesel as high as 90 percent.
    FT diesel results in fewer NOX emissions because the 
fuel itself makes no contribution to the formation of NOX in 
the engine cylinders. With FT diesel, thermal NOX emission 
levels have been found to be reduced by anywhere from 9 percent to 28 
percent when compared to low sulfur diesel or CARB (California grade) 
diesel.
    Tests have shown the use of FT diesel reduces hydrocarbon emissions 
by as much as 72 percent.
    FT diesel, because of its higher cetane and lower aromatics, 
significantly reduces the emission of harmful carbon monoxide as 
compared even to low sulfur diesel because it burns more cleanly and 
completely.
    While actual CO2 emissions of a given diesel fuel depend 
on a number of factors, including the quality of the fossil fuel 
feedstock (coal or oil), FT diesel should produce no more tailpipe 
CO2 than petroleum diesel.
    Question 3. As the Energy Information Administration forecast 
indicates, we have two choices: we can import ``C.T.L.'' fuels from 
foreign countries or we can produce it ourselves. I believe, and I 
think the witnesses here today have shown, that America can produce 
these fuels cleaner than anywhere else. Given the environmental and 
safety records of other coal countries, wouldn't you agree that the 
production of coal and ``C.T.L.'' in other nations would cause more 
environmental damage than if they are produced in America?
    Answer. Yes, I do. In the U.S. coal is mined under the most 
comprehensive environmental laws found anywhere in the coal producing 
regions of the world. At both the state and federal levels producers 
are obliged to follow specific laws that regulate and control the 
environmental impacts of coal mining. Extensive permit approvals must 
first be obtained before mining operations begin. The impact of coal 
mining on water quality, air quality and wildlife habitat are just some 
of the major considerations that ensure against harm to the surrounding 
ecosystem. Land reclamation following mining is also required by law. 
Since 1978 more than 2 million acres have been reclaimed based on 
detailed plans that must be approved before mining activity begins. All 
coal mines are required to report their toxic releases to the air and 
water. Finally, federal environmental agencies in the U.S. tend to 
operate more independently of political or economic influence than is 
typically the case in many other countries.

       Responses of James Roberts to Questions From Senator Wyden

    Question 1. If price volatility and crude oil prices are the two 
major impediments to bringing coal-to-liquids (CTL) fuels to U.S. 
markets, the ``tipping point'' to make CTL economically viable is at 
$40/barrel and the price of oil is now at $70 per barrel, why does the 
government need to continue subsidizing more CTL research? Why can't 
the private sector start building commercially viable production 
plants?
    Answer. The need for government involvement is not in the research 
arena but in the initial financing stages of developing large-scale CTL 
production. By helping to ``jump start'' investment at the front-end 
engineering and design work required for billion-dollar CTL plants, the 
federal government would help to overcome the reluctance of U.S. 
investors to back what they consider to be unfamiliar technology. U.S. 
financial participation will also reassure private investors by 
discouraging the foreign oil cartel from once again manipulating oil 
prices to kill investment in competing domestic energy production, as 
the cartel did in past decades.
    Question 2. As a Westerner, I am concerned about the water 
resources that are needed to produce fuels from coal. I am also 
concerned about the increased air pollution and greenhouse gases that 
are emitted. Much of the water that would go into CTL production could 
be used-to grow biomass and produce biofuels instead. Has anyone done a 
comparison of which types of energy production cause the least harm to 
the environment while delivering the biggest benefits to consumers? Do 
you know of any analyses that have looked at the ``opportunity costs'' 
involved in producing water-intensive energy like CTL?
    Answer. I know of no formal comparison of the environmental impacts 
of various types of energy production vis-a-vis consumer benefits or 
any analyses which have looked at the water related ``opportunity 
costs'' involved in the production of CTL. However, all forms of energy 
production have associated lifecycle costs, such as water, fertilizer 
and transportation.
    Question 3. If the German and South African experience in producing 
coal fuels is any indicator, wouldn't you say that the only policy 
reason that justifies producing CTL fuels in the U.S. would be a time 
when the U.S. no longer had access to world oil markets?
    Answer. What is instructive about the examples of Germany and South 
Africa is that, like the U.S., they both had substantial coal reserves 
and also faced a dire need to reduce their reliance on costly imported 
energy to service their economies. Their successful experience suggests 
that the U.S. should not wait any longer to see its reliance on 
offshore energy increase before developing--as these countries did--an 
alternative domestic source of fuels that is affordable, abundant and 
not subject to foreign control.
    Across the world, energy has now become the linchpin of economic 
competitiveness, forcing the U.S. and its industrial competitors to 
strategically reassess their energy supplies and sources. The 
perception of energy scarcity has become acute as political instability 
menaces existing supplies, unfriendly governments threaten to 
nationalize energy assets, and nation states revive great power 
alliances to find and secure reliable supplies of oil and gas for their 
growing economies.
    The 2005 hurricane season and the resulting disruption of petroleum 
production and refining capacity in the gulf, coupled with our nation's 
increasing dependence on imported energy and the intensified 
competition for this energy from rapidly expanding economies such as 
China and India, are compelling reasons for the U.S. to secure and 
diversify domestic sources of energy.
    Clearly, a secure America in the 21st century will mean energy 
security. Our security is jeopardized, however, by our increasing 
reliance on foreign energy. The United States currently depends on 
foreign sources for 60 percent of its domestic oil requirements, 
including crude oil and refined products. According to the Energy 
Information Administration (EIA), that dependence will grow to 70 
percent by 2025.
    Already, imported energy--including crude oil and natural gas--
accounts for a third of the record U.S. trade deficit and caused 
Americans to pay 17 percent more for energy in 2005 than the year 
before.
    The Energy Policy Act of 2005 encouraged the development of 
alternative fuels such as coal-to-liquid (CTL) fuels and coal-derived 
natural gas substitutes, but its modest incentives are far too timid a 
response to today's stark realities.
    For a forceful response to the energy challenge, the U.S. must make 
greater use of its unrivalled coal reserves--to provide significant new 
supplies of clean CTL fuels, to enhance oil and coal bed methane 
recovery and to produce ethanol.
    The U.S. has 27 percent of world coal supply--the largest of any 
country--but less than 2 percent of the world's oil and less than 3 
percent of its natural gas. By contrast, Iran and Russia possess almost 
half of the world's supply of natural gas between them.
    Production of coal-derived liquid fuels would expand potential uses 
of America's nearly 250 billion tons of recoverable coal reserves 
beyond electricity generation to help reduce our reliance on foreign 
sources of oil, while promoting national security and providing for 
sustained economic growth.
    With coal reserves and production dispersed widely among more than 
two dozen states, the U.S. boasts a geographic diversity of domestic 
fuel supply that is less susceptible to natural disasters and terrorist 
threat.
    Producing CTL fuel does not depend on unproven technology nor 
require extensive R&D. China is already building a $2 billion CTL plant 
that will begin using its enormous coal reserves in the fall of 2007, 
and plans to build many more.
    Moreover, U.S. coal reserves cannot be nationalized by a foreign 
government, require no costly armed forces to protect, nor costly 
exploration efforts to discover.

    [Responses to the following questions were not received at 
the time this hearing went to press:]

           Questions for Hunt Ramsbottom From Senator Bunning

    Question 1. Would you please explain how your process manages 
carbon emissions as well as sulfur, nitrogen and mercury? How your 
emissions profile compare with other coal-to-liquids processes?
    Question 2. The finished ``C.T.L.'' product is low particulate, low 
mercury and almost zero sulfur. Could you elaborate on the emissions 
characteristics of ``C.T.L.'' transportation fuels compared to current 
fuels?
    Question 3. Your plant in Illinois will convert a natural gas-
powered facility into a coal-powered facility that will produce surplus 
electricity as well as ``C.T.L.'' fuel. Your second plant in 
Mississippi will achieve an impressive rate of 100% Carbon 
sequestration. Do you believe that ``C.T.L.'' can reasonably be 
implemented with these levels of sequestration, electricity generation 
and ``C.T.L.'' fuel production? Wouldn't such a plant be a very 
efficient and clean energy source?
    Question 4. As the Energy Information Administration forecast 
indicates, we have two choices: we can import ``C.T.L.'' fuels from 
foreign countries or we can produce it ourselves. I believe, and I 
think the witnesses here today have shown, that America can produce 
these fuels cleaner than anywhere else. Given the environmental and 
safety records of other coal countries, wouldn't you agree that the 
production of coal and ``C.T.L.'' in other nations would cause more 
environmental damage than if they are produced in America?

          Questions for Hunt Ramsbottom From Senator Bingaman

    Question 1. In testimony before the EPW Committee in November 2005, 
one coal-to-liquids company stated that if the United States converted 
five percent of its recoverable coal reserves to oil, it would be 
equivalent to the existing 29 billion barrels of proven oil reserves in 
the United States.
    I have heard that most processes for converting coal into liquids 
turn a ton of coal into a little more than a barrel's worth of oil or 
refined product such as gasoline or diesel.
    In your experience, is there a process that is that efficient in 
the way it converts coal to oil?
    Question 2. Several companies have indicated support for the loan 
guarantees for coal to liquids plants that are contained in the new 
energy law Congress passed last summer.
    As a company, is this loan guarantee helpful to you as it is 
presently structured? Does it need to be adjusted in any way to assist 
coal to liquids producers?
    Question 3. Several companies have expressed interest in the 
construction of FT plants.
    Is it correct that the development and planning for these plants is 
occurring in compliance with existing environmental law and with the 
acceptance of the local communities in which the plants are proposed to 
be located?
    Question 4. I'm told that the Fischer-Tropsch process has the 
advantage of forming products that are highly paraffinic and these 
products are desirable because they exhibit excellent combustion and 
lubricating properties. Unfortunately, I'm also told a disadvantage of 
the Fischer-Tropsch process is that the process emits relatively large 
amounts of CO2 during the conversion of solid hydrocarbons 
into liquid.
    Would you review the greenhouse gas emissions associated with your 
technology?

            Questions for Hunt Ramsbottom From Senator Wyden

    Question 1. If price volatility and crude oil prices are the two 
major impediments to bringing coal-to-liquids (CTL) fuels to U.S. 
markets, the ``tipping point'' to make CTL economically viable is at 
$40/barrel and the price of oil is now at $70 per barrel, why does the 
government need to continue subsidizing more CTL research? Why can't 
the private sector start building commercially viable production 
plants?
    Question 2. As a Westerner, I am concerned about the water 
resources that are needed to produce fuels from coal. I am also 
concerned about the increased air pollution and greenhouse gases that 
are emitted. Much of the water that would go into CTL production, could 
be used to grow biomass and produce biofuels instead. Has anyone done a 
comparison of which types of energy production cause the least harm to 
the environment while delivering the biggest benefits to consumers? Do 
you know of any analyses that have looked at the ``opportunity costs'' 
involved in producing water-intensive energy like CTL?
    Question 3. If the German and South African experience in producing 
coal fuels is any indicator, wouldn't you say that the only policy 
reason that justifies producing CTL fuels in the U.S. would be at a 
time when the U.S. no longer had access to world oil markets?

                          MONDAY, MAY 1, 2006
                                 ______
                                 
                              Department of Energy,
               Congressional and Intergovernmental Affairs,
                                      Washington, DC, July 5, 2006.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Washington, DC.
    Dear Mr. Chairman: On May 1, 2006, David Garman, Under Secretary, 
testified regarding the economic and environmental issues associated 
with coal gasification technology and on implementation of the 
provisions of the Energy Policy Act of 2005 addressing coal 
gasification.
    Enclosed are the answers to five questions that were submitted by 
Senators Talent, Bunning and Bingaman for the hearing record. The 
remaining seven answers are being prepared and will be forwarded to you 
as soon as possible.
    If we can be of further assistance, please have your staff contact 
our Congressional Hearing Coordinator, Lillian Owen, at (202) 586-2031.
            Sincerely,
                                             Jill L. Sigal,
                                               Assistant Secretary.
[Enclosures.]

                Response to Question From Senator Talent

                    QUALIFYING GASIFICATION PROGRAM

    Question. We have a significant domestic supply of coal in the U.S. 
and I am strongly supportive of technologies that will increase its use 
in the environmentally sensitive manner, specifically coal 
gasification. In last year's energy bill, we included many incentives 
for coal and petroleum residue gasification. I want to see those 
incentives work. Will you, working with the IRS, please clarify the 
definition of ``gasification technology'' and ``eligible property'' as 
it relates to FRS NOTICE 2006-25, Qualifying Gasification Program?
    Answer. Gasification technology and eligible property are defined 
in IRC Sec. 48B(c)(2) and IRC Sec. 48B(c)(3) as added by EPAct 1307(b). 
These definitions are sufficient to prepare applications for the 
Department of Energy (DOE) certification and the Internal Revenue 
Service (IRS) allocation. However, DOE has discussed with the Internal 
Revenue Service (IRS) the possible need to further clarify these 
definitions. The IRS informs us that it is developing supplemental 
guidance on the coal gasification credit and will consult with DOE 
regarding appropriate clarifications to the definitions as part of that 
process.

              Responses to Questions From Senator Bunning

                            COAL TO LIQUIDS

    Question 5. As you know, Section 369 of the Energy Bill provided 
that D.O.E. participate in Department of Defense's Assured Fuels 
Program to evaluate the potential of coal-to-liquids for use by the 
military. What is the status of that program?
    Answer. Section 369 of the Energy Policy Act of 2005 (PL 109-58) 
directs the Secretary of Energy, in coordination with the Secretary of 
the Interior and the Secretary of Defense, to establish a task force to 
develop a program to coordinate and accelerate the commercial 
development of strategic unconventional fuels, including but not 
limited to oil shale and tar sands. This task force has been convened 
and coal-to-liquids technologies are being evaluated.

                          TRANSPORTATION FUELS

    Question 6. Section 417 of the Energy Bill authorizes $85 million 
to test advanced technologies for the production of transportation 
fuels manufactured from Illinois Basin coal. It also provides funding 
for the construction of testing facilities at the University of 
Kentucky's Center for Applied Energy Research among other locations. 
Could you provide an update on this initiative?
    Answer. The Department has not identified funding to do the work 
authorized in Section 417 of the Energy Policy Act of FY 2005. The 
Department's enacted budget for FY 2006 and the Department's budget 
request for FY 2007 did not include funding for this work. The 
Department has not asked for Coal-To-Liquid (CTL) R&D funding for 
several years because the CTL technology is mature, from a research 
perspective.

              Responses to Questions From Senator Bingaman

                          TAX CREDIT PROPOSAL

    Question 3. Section 48B tax credit--Undersecretary Garman, it is my 
understanding that the IRS is using the DOE to help select tax credit 
proposal. How will the DOE assess merit to these proposals, has this 
been communicated effectively or will you simply certify to the IRS a 
proposal has met the criteria outlined by the IRS?
    Answer. The Department of Energy has been asked by IRS to certify 
that tax credit applications are feasible and consistent with energy 
policy goals. DOE will assess applications based on the criteria 
published in the IRS Notice and will internally rank the projects based 
on those criteria. In the event that there are more qualified 
(certifiable) applications than there are available tax credits, DOE 
will certify projects to the IRS in descending order of rank, but only 
until the available tax credits are exhausted. The ranking of qualified 
applications for the Section 48B tax credit will be determined by DOE 
based on Program Policy Factors in accordance with Appendix B of IRS 
Notice 2006-25 ``Guidelines for Program Policy Factors to be used by 
DOE in the evaluation of the applications''. Evaluation of Program 
Policy Factors may include consideration of a variety of project 
characteristics, as appropriate, such as the ratio of plant capacity to 
requested tax credit, plant efficiency, process design compatibility 
with carbon capture (gasifier sizing and pressure, air separation unit 
sizing, quench system, etc.), and location of the facility relative to 
potential carbon sequestration locations and CO2 pipelines 
or pipeline easements.

                            SYNGAS OPERATION

    Question 4. Section 48 tax credit--Undersecretary Garman, it is my 
understanding that there seems to be a concern with section 
48B(d)(3)(D) regarding 90 percent of the facility operating using 
syngas apparently the IRS and the DOE have put forth in a rule for 
comment that it be at ``all times''. Can you please explain why this 
phase was added--it seems virtually impossible to achieve during the 
start up phase of many of these facilities.
    Answer. The Department of Energy has discussed with the Internal 
Revenue Service (IRS) the difficulty of operating with 90 percent 
syngas during startup. The IRS will issue a notice to clarify.
                                 ______
                                 
                                  Agrium U.S. Inc.,
                                  Keani Nitrogen Operatons,
                                           Kenai, AK, May 11, 2006.
Hon. Pete V. Domenici,
Chairman, Senate Committee on Energy and Natural Resources, Washington, 
        DC.
    Dear Senator Domenici: Thank you for the opportunity to testify 
before the Senate Committee on Energy and natural. Resources on May 1, 
2006 regarding the industrial gasification provisions of the Energy 
Policy Act of 2005.
    As requested, enclosed please find responses to the questions 
provided to me on May 4, 2006.
    Should yoy require anything further please do not hesitate to 
contact me.
            Sincerely,
                                        William A. Boycott,
                                                   General Manager.

              Responses to Questions From Senator Bingaman

    Question 1. Section 4 tax credits--Mr. Boycott, how tight are your 
margins and will the tax credits make a difference in deciding to 
produce your plant?
    Answer. The section 48B tax credits could make a difference. If the 
Kenai Blue Sky Project qualified for the maximum $130 million in tax 
credits, we estimate that this amount would improve the overall return 
on investment in the project by approximately 0.5 percent. We are still 
too early in our feasibility analysis to say whether this improvement 
to project economies would make a difference in the ultimate decision 
to proceed.
    Question 2. Section 48 tax credits--Mr. Boycott, approximately how 
big a credit would you apply for and how many projects do you 
realistically think the Energy Policy Act could fund?
    Answer. Under section 48B a total of $650 million in qualifying 
property is eligible for the 20% credit, resulting in a maximum $130 
million credit per project. Since our project will cost significantly 
more than $650 million, we anticipate applying for the maximum amount 
of credit available. We also believe that any industrial scale 
gasification project will cost more than $650 Million, thus every 
project will be applying for the maximum amount of credit. If this is 
the ease, then the total of $350 million available under section 48B 
will fund between 2 and 3 projects.
    Question 3. Loan Guarantees--Mr. Boycott, do you believe it is 
important that the DOE cover 100 percent of the 80 percent project cost 
guarantee?
    Answer. Yes. For the loan guarantee program to be effective, it 
must provide a degree of certainty to the private sector investors 
(project proponent, equity partners and banks and other lenders) that 
the federal government is going to share some of the risk of the 
project. To the extent the federal government implements the loan 
guarantee in a selective approach, agreeing to guarantee less than 100 
percent of covered debt financing becomes significantly more 
complicated and expensive and the certainty provided by the loan 
guarantee will be eroded and its effectiveness will he diminished.
    Question 4. Loan Guarantees--Mr. Boycott, do you believe that it is 
important for the loan guarantee to cover the life of the financing for 
the project or smaller increments of time?
    Answer. The principle is the same as expressed in #3 above. These 
capital-intensive projects are very complex and, as a result, arranging 
financing for them is a difficult undertaking. If the federal 
government embarks on a path of trying to determine that certain phases 
of the project are eligible for a loan guarantee and others are not, 
the value of the loan guarantee as a risk sharing mechanism is 
significantly diminished and the difficulty of acquiring and cost of 
debt is significantly increased.
                                 ______
                                 
              Responses to Questions From Senator Bunning

    Question 1. Across the world, energy has become the lynchpin of 
economic competitiveness. America's coal reserves can provide us with 
an invaluable hedge against our growing addiction to imported energy, 
and provide a significant source of fuel for our growing economy. Could 
you describe the benefits coal gasification could offer to the American 
economy in terms of prices, environmental effects and national 
security?
    Answer. Use of coal gasification technology could provide an 
important alternative source of feedstock for the U.S. fertilizer 
industry. The biggest challenge coal gasification faces today is the 
initial capital investment to construct a commercial-scale facility. 
Once the initial capital hurdle is overcome, it is projected that coal 
derived synthetic gas can provide a very economic feedstock on a dollar 
per BTU basis for the manufacture of fertilizer. In the U.S. fertilizer 
industry, the high price of natural gas has forced the closure of some 
8 million t/y of U.S. ammonia capacity since 1999, leaving 
approximately 11 million t/y of capacity currently operational.\1\ 
Domestic ammonia production in 2006 is expected to account for only 47% 
of total U.S. ammonia requirements compared to 77% in 2000.\2\ Imported 
fertilizer has replaced domestic production, greatly increasing our 
nation's reliance on foreign imports to sustain our agricultural 
industry. The Kenai Blue Sky coal to ammonia project not only provides 
art opportunity to use an alternative energy source to replace scarce 
and expensive natural gas but this project, and others like it, can be 
configured to emit minimal emissions thus allowing an important U.S. 
industry to be sustained in this country. Furthermore, the Kenai Blue 
Sky project is being planned to capture and use the carbon dioxide 
generated for enhanced oil recovery that will in turn enable additional 
production of domestic oil.
---------------------------------------------------------------------------
    \1\ Ammonia Outlook, March 2006, FERTECON Limited, p. 99.
    \2\ Ibid.
---------------------------------------------------------------------------
    Question 2. It seems to me that industry is only asking the 
government for help with the front-end financing of coat gasification 
plant construction. How does the loan guarantee program fit this goal? 
What additional programs may be needed?
    Answer. In order to commercialize coal gasification technology for 
use in the fertilizer industry public support to reduce financing risks 
appears to be required. Theoretically, a properly constructed loan 
guarantee program could assist project costs by reducing the costs of 
borrowing and providing lenders with an additional degree of comfort 
that project debt will be repaid. Because the Title XVII loan guarantee 
program has yet to be implemented (regulations or guidelines for 
administering the program have not been issued) it is not certain how a 
loan guarantee might actually assist our project. A federally backed 
loan guarantee has the potential to greatly enhance the success of a 
gasification project. Until the Department of Energy actually 
implements the loan guarantee program we are not able to comment upon 
the utility of such a program to support the Kenai Blue Sky project. An 
additional program that should be considered is extension and 
enhancement (additional amounts) of the Section 48B tax credits. 
Chairman Chuck Grassley and Ranking Member Max Baucus of the Senate 
Finance Committee have introduced legislation (S. 2401) that, if 
enacted, could be of great benefit to projects, like the Kenai Blue Sky 
project, that may not be ready in time to apply for the limited and 
existing industrial gasification tax credits but would be so in future 
years.
    Question 3. Would you please explain how the coal gasification 
process could be used to manage emissions?
    Answer. Coal gasification technology has improved and been refined 
over the several decades that technology has been in use. In 
traditional combustion processes, emissions can only be controlled at 
the stack (i.e. once combustion has occurred in coal gasification, the 
gas is purified throughout the process. This allows for the capture of 
potential pollutants, such as sulfur before the pollutant reaches the 
stack. The gasification process also allows for the capture of carbon 
dioxide so that it can be utilized in the production of fertilizer 
(urea) or utilized to increase production from existing oil fields 
through Enhanced Oil Recovery (EOR). Using modern gasification 
processes, the overall emissions of pollutants can be less than what is 
achieved with traditional natural gas processes.
    Question 4. As the Energy Information Administration forecast 
indicates, we have two choices: we can import energy from foreign 
countries or we can produce it ourselves. I believe, and think the 
witnesses here today have shown, that America can produce these fuels 
from our coal reserves clearer than anywhere else. Given the 
environmental and safety records of other coal countries, wouldn't you 
agree that the production of coal in other nations would cause more 
environmental damage than if they are produced in America?
    Answer. I believe that we can and will develop projects in North 
America that will mitigate damage to our air, land, and water. The 
Kenai Blue Sky project is a good example of how America's resources can 
be developed responsibly to invigorate our domestic fertilizer industry 
by using coal, our nation's most abundant, domestically controlled 
fossil fuel resource, while also protecting the environment.

                                 ______
                                
     Responses of Brian Ferguson to Questions From Senator Bunning

    Question 1. Across the world, energy has become the lynchpin of 
economic competitiveness. America's coal reserves can provide us with 
an invaluable hedge against our growing addiction to imported energy, 
and provide a significant source of fuel for our growing economy. Could 
you describe the benefits coal gasification could offer to the American 
economy in terms of prices, environmental effects and national 
security?
    Answer. Coal-gasification offers high potential to remove price 
volatility from fuels and feedstocks that are essential as major inputs 
to U.S. manufacturing. Those distressed industries that are natural gas 
dependent, and globally competitive, can economically use gasification 
to produce synthesis gas as substitution for natural gas. Today, faced 
with volatility, they must choose to switch technology and feedstocks, 
or shift production to cheap feedstock regions of the world. 
Gasification technology is a key to preserving hundreds of thousands of 
American jobs that remain at risk, as well as future investments in 
industrial research and innovation that are essential for a growing and 
competitive U.S. economy. Environmental benefits are well known--
greatly reduced emissions as compared to other solid fossil fuels 
technologies, emissions approaching those of natural gas fueled 
facilities, with the lowest cost option for carbon capture and 
sequestration of any coal-based technology. National security benefits 
will include greater diversity of fuels and feedstocks domestically 
based, rather than deepening dependencies upon fossil fuels from 
politically unstable regions of the world. Almost any use of oil and 
natural gas can be replaced with technologies utilizing syngas produced 
from coal gasification if national security is a primary concern.
    Question 2. It seems to me that industry is only asking the 
government for help with the front-end financing of coal gasification 
plant construction. How does the loan guarantee program fit this goal? 
What additional programs may be needed?
    Answer. The federal loan guarantee program will address acute 
``capital market imperfections'' that pose barriers to the capital 
intensive investments in gasification by early adopter industrials. 
These include: higher first-of-a-kind costs including higher financial 
risk premiums; free-rider problems with competitors who adopt later 
when capital costs and risk premiums have been reduced; and Federal 
policies that restrain natural gas supply and increase natural gas 
demand for power generation, while restraining market entry for energy 
and power sales from industrial gasification polygeneration units. In 
short, early adopters of industrial gasification will have perceived 
risks that are greater than later adopters, thus their financing costs 
will be higher and financing may even be difficult to obtain without 
some form of loan guarantee backstop. The federal loan guarantee 
program would allow industrials to overcome capital market 
imperfections in the early development and use of commercial 
gasification technology and would minimize the risk premium for 
financing of early adopter projects. Together with investment tax 
credits, these incentives will work to jump-start industrial 
investments. Beyond commercial deployment, other programs should 
include expanded cost-shared RD&D between industry and the federal 
government. Particularly important research topics include reduction of 
air separation costs and its parasitic power losses, development of 
advanced gasifier designs that improve performance at lower costs, 
development of advanced syngas cleanup technologies, and development of 
advanced technologies for conversion of syngas into desired chemicals, 
fertilizers, and fuels.
    Question 3. Would you please explain how the coal gasification 
process can be used to manage emissions?
    Answer. Typically, oxygen-blown gasification produces a 
concentrated high-pressure syngas stream that enables cost efficient 
and highly effective removal of contaminants such as sulfur and metals 
prior to any downstream combustion or use of the syngas. The process 
can take almost any carbonaceous material, laden with impurities, and 
produce a very clean synthesis gas composed primarily of carbon 
monoxide and hydrogen. Any carbon monoxide in the syngas can be further 
reacted with water and converted to carbon dioxide and hydrogen. Carbon 
dioxide is concentrated in the gas stream and can be relatively easily 
separated from the ultra-clean hydrogen and made ready for 
sequestration or enhanced oil recovery.
    Question 4. As the Energy Information Administration forecast 
indicates, we have two choices: we can import energy from foreign 
countries or we can produce it ourselves. I believe, and I think the 
witnesses here today have shown, that America can produce these fuels 
from our coal reserves cleaner than anywhere else. Given the 
environmental and safety records of other coal countries, wouldn't you 
agree that the production of coal in other nations would cause more 
environmental damage than if they are produced in America?
    Answer. Generally, yes, but only if American markets get moving 
with coal-gasification investments now. This technology is rapidly 
moving to other regions of the world for industrial production beyond 
power, and where capital market imperfections are addressed (e.g., 
China). The attitude of the regulated utility sector in the U.S. is 
that coal gasification at commercial scale is technology for a more 
distant future, and EPACT 2005 provided incentives to accommodate that 
view. Thus environmental benefits are distant. The attitude of 
distressed, globally competitive, natural-gas-dependent industrials is 
different. Industrials can simply shift production to low cost, natural 
gas regions of the world; or with appropriate incentives to overcome 
capital market imperfections, industrials can stay and America can 
realize superior economic and environmental performance from coal, 
sooner, rather than later.

     Responses of Brian Ferguson to Questions From Senator Bingaman

    Question 1. Section 48 tax credit--Mr. Ferguson, I understand there 
is concern with the addition of the phrase ``at all times'' to the 90 
percent syngas rule for a facility to receive a tax credit. Can you 
please explain this problem and whether the DOE or IRS has answered 
your concerns?
    Answer. The problem is that, during periods of start up and 
testing, other fuels may be needed that would make the 90% rule 
impossible to follow. DOE recently indicated that it has asked IRS to 
allow non-conforming fuels during plant startup and shutdown periods. 
Unfortunately, with less than 45 days before the DOE application 
deadline, IRS has provided no response to this or any other question.
    Question 2. Section 48 tax credit--Mr. Ferguson, how important are 
the confidentiality provisions of the applications that are to be 
submitted?
    Answer. Application confidentiality is key to Eastman's global 
business competitiveness. Plant process efficiencies and specific 
designs and operational methodologies revealed in any Eastman 
application would be the result of more than 20 years of unique 
operating experience and innovation. This is competitive advantage. 
Also, the sheer magnitude of these projects could result in any public 
disclosure being considered a material disclosure.
    Question 3. General Competitiveness of the Chemical Industry--Mr. 
Ferguson, your testimony comments on how most if not all chemical 
plants are now being built overseas, is the price of natural gas the 
predominant reason? Can the tax credits and loan guarantees be enough 
to retain the facilities here in the U.S.?
    Answer. The industry belief is that natural gas feedstock 
volatility in the U.S. is the single largest reason for the shift in 
chemical production to other regions of the world. Natural gas 
represents fully one quarter of the U.S. chemical industry's product 
costs. Of course, higher rates of economic growth in Asia for example, 
suggest that there would be more plant investment in that region. But 
the global picture is wholly unbalanced, with a full retreat, or route, 
out of the U.S. to cheaper natural gas regions of the world.
    Domestic chemical manufacturers intent on staying in this country 
have limited choices aside from deploying gasification technology to 
produce competitively priced substitutes for natural gas. While the 
cost of synthesis gas is higher in the U.S. than natural gas prices are 
in Oman, for example, domestic producers will enjoy some transportation 
cost advantage in North American markets. Also, gasification of coal 
and other plentiful fuels will afford resource price stability in 
contrast to volatile natural gas prices.
    The 48B tax credits represent the estimated ``cost premium'' for 
earlier adopter of commercial gasification technology in the U.S. These 
investment tax credits make it rational for the first developers to 
invest money now with reasonable expectation that their investment will 
be competitive with that of subsequent developers who will be able to 
build these same plants for considerably less money in the future. The 
loan guarantees should lower the cost of money for early adopters of 
these highly capital intensive projects, who would otherwise pay a risk 
premium for being early adopters, and are a necessary tool to impede 
the exodus of U.S. chemical companies. I cannot say with certainty that 
these two incentives alone will reverse the exodus, but I can assure 
you that our industry has little hope for staying home without them.

    [Responses to the following questions were not received at 
the time this hearing went to press:]

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                       Washington, DC, May 4, 2006.
Mr. William F. Bruce,
President, BRI Energy, LLC, 114 Canal Street, Suite F, New Smyrna 
        Beach, FL.
    Dear Mr. Bruce: I would like to take this opportunity to thank you 
for appearing before the Senate Committee on Energy and Natural 
Resources on Monday, May 1, 2006, to give testimony regarding the 
economic and environmental issues associated with coal gasification 
technology and on implementation of the provisions of the Energy Policy 
Act of 2005 addressing coal gasification.
    Enclosed herewith please find a list of questions which have been 
submitted for the record. If possible, I would like to have your 
response to these questions by Thursday, May 18, 2006.
    Thank you in advance for your prompt consideration.
            Sincerely,
                                          Pete V. Domenici,
                                                          Chairman.

                     Questions From Senator Bunning

    Question 1. Across the world, energy has become the lynchpin of 
economic competitiveness. America's coal reserves can provide us with 
an invaluable hedge against our growing addiction to imported energy, 
and provide a significant source of fuel for our growing economy. Could 
you describe the benefits coal gasification could offer to the American 
economy in terms of prices, environmental effects and national 
security?
    Question 2. It seems to me that industry is only asking the 
government for help with the front-end financing of coal gasification 
plant construction. How does the loan guarantee program fit this goal? 
What additional programs may be needed?
    Question 3. Would you please explain how the coal gasification 
process can be used to manage emissions?
    Question 4. As the Energy Information Administration forecast 
indicates, we have two choices: we can import energy from foreign 
countries or we can produce it ourselves. I believe, and I think the 
witnesses here today have shown, that America can produce these fuels 
from our coal reserves cleaner than anywhere else. Given the 
environmental and safety records of other coal countries, wouldn't you 
agree that the production of coal in other nations would cause more 
environmental damage than if they are produced in America?

                    Questions From Senator Bingaman

    Question 1. Ethanol production from gasification syngas--Mr. Bruce 
how economically competitive will your facility be to produce ethanol 
as compared to current methods? Can you give what the cost of a gallon 
would be from the method you are employing?
    Question 2. Various gasification feedstocks--Mr. Bruce, how will 
the efficiency of your process vary depending on your feedtocks, be it 
coal, corn stover or other biosolids?
    Question 3. Production capacity--Mr. Bruce, what is the size of the 
production system you hope to achieve and can you build fermenters to 
these scales?
                                 ______
                                 
                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                       Washington, DC, May 4, 2006.
Mr. Bill Douglas,
Vice President, Econo-Power International Corp., 1502 Augusta, Suite 
        100, Houston, TX.
    Dear Mr. Douglas: I would like to take this opportunity to thank 
you for appearing before the Senate Committee on Energy and Natural 
Resources on Monday, May 1, 2006, to give testimony regarding the 
economic and environmental issues associated with coal gasification 
technology and on implementation of the provisions of the Energy Policy 
Act of 2005 addressing coal gasification.
    Enclosed herewith please find a list of questions which have been 
submitted for the record. If possible, I would like to have your 
response to these questions by Thursday, May 18, 2006.
    Thank you in advance for your prompt consideration.
            Sincerely,
                                          Pete V. Domenici,
                                                          Chairman.
                     Questions From Senator Bunning

    Question 1. Across the world, energy has become the lynchpin of 
economic competitiveness. America's coal reserves can provide us with 
an invaluable hedge against our growing addiction to imported energy, 
and provide a significant source of fuel for our growing economy. Could 
you describe the benefits coal gasification could offer to the American 
economy in terms of prices, environmental effects and national 
security?
    Question 2. It seems to me that industry is only asking the 
government for help with the front-end financing of coal gasification 
plant construction. How does the loan guarantee program fit this goal? 
What additional programs may be needed?
    Question 3. Would you please explain how the coal gasification 
process can be used to manage emissions?
    Question 4. As the Energy Information Administration forecast 
indicates, we have two choices: we can import energy from foreign 
countries or we can produce it ourselves. I believe, and I think the 
witnesses here today have shown, that America can produce these fuels 
from our coal reserves cleaner than anywhere else. Given the 
environmental and safety records of other coal countries, wouldn't you 
agree that the production of coal in other nations would cause more 
environmental damage than if they are produced in America?

                    Questions From Senator Bingaman

    Question 1. Filtering of syngas waste gases--Mr. Douglas how 
effective are the current technologies for filtering SOX, 
NOX and mercury?
    Question 2. Types of Coal--Mr. Douglas, are your smaller units 
tuned to specifics types of coal, like Powder River Basin or other 
geographic regions?
    Question 3. Coal Shipment--Mr. Douglas, since these are 
comparatively small units do you have a hard time trying to ship coal 
on rail systems which usually supply large electric power plants?
                                 ______
                                 
                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                       Washington, DC, May 4, 2006.
Dr. Antonia Herzog,
NRDC, Climate Center Staff Scientist, 1200 New York Ave., NW, Suite 
        400, Washington, DC.
    Dear Dr. Herzog: I would like to take this opportunity to thank you 
for appearing before the Senate Committee on Energy and Natural 
Resources on Monday, May 1, 2006, to give testimony regarding the 
economic and environmental issues associated with coal gasification 
technology and on implementation of the provisions of the Energy Policy 
Act of 2005 addressing coal gasification.
    Enclosed herewith please find a list of questions which have been 
submitted for the record. If possible, I would like to have your 
response to these questions by Thursday, May 18, 2006.
    Thank you in advance for your prompt consideration.
            Sincerely,
                                          Pete V. Domenici,
                                                          Chairman.
                     Questions From Senator Bunning

    Question 1. Across the world, energy has become the lynchpin of 
economic competitiveness. America's coal reserves can provide us with 
an invaluable hedge against our growing addiction to imported energy, 
and provide a significant source of fuel for our growing economy. Could 
you describe the benefits coal gasification could offer to the American 
economy in terms of prices, environmental effects and national 
security?
    Question 2. It seems to me that industry is only asking the 
government for help with the front-end financing of coal gasification 
plant construction. How does the loan guarantee program fit this goal? 
What additional programs may be needed?
    Question 3. Would you please explain how the coal gasification 
process can be used to manage emissions?
    Question 4. As the Energy Information Administration forecast 
indicates, we have two choices: we can import energy from foreign 
countries or we can produce it ourselves. I believe, and I think the 
witnesses here today have shown, that America can produce these fuels 
from our coal reserves cleaner than anywhere else. Given the 
environmental and safety records of other coal countries, wouldn't you 
agree that the production of coal in other nations would cause more 
environmental damage than if they are produced in America?

                    Questions From Senator Bingaman

    Question 1. Addition of Carbon Capture Technologies--Ms. Herzog, 
how hard will it be to retrofit a gasification plant with carbon 
capture technologies and what percentage would it increase the facility 
cost after it has been built as compared to adding CO2 
capture during construction?
    Question 2. Cost for Industrial Gasification Plants--Ms. Herzog, 
given that the chemical feedstock gasifiers are about 1/10 the size of 
the larger electric power production gasifiers--how much cost do you 
expect carbon sequestration to add to the process?

                          MONDAY, MAY 8, 2006
                                 ______
                                 
     Responses of the Department of the Interior to Questions From 
                             Senator Craig

    Question 1. What are the agencies' plans to revise and finalize the 
Interim Final Rule?
    Answer. When the rules were published on November 17, 2005, the 
agencies indicated they would consider the public comments that were 
received and their initial experience in implementing the rules and 
consider issuing Final Rules within approximately 18 months. That 
remains our intent. The agencies have received comments through the 
Interim Final Rule and are currently reviewing them.
    Question 2. In your opinion, once the 15 ``transition projects'' 
are addressed, will we settle into a process that works within FERC's 
timelines?
    Answer. We believe that our major workload challenge is occurring 
in this initial period of implementation, which will carry forward 
through most of Calendar Year 2007. This is because we are not only 
implementing a new process, but also: (a) addressing the transition 
projects; (b) managing two high profile, complicated cases, namely 
Hells Canyon and Klamath; and (c) considering (next year) possible 
changes to the rule. After this initial period, workloads may be at 
more manageable levels. Historically, approximately 1/4 to 1/3 of all 
relicensings have included conditions or prescriptions from any of the 
three resource agencies and a far lesser number have conditions from 
more than one agency. It is expected that parties will request EPAct 
processes in the majority of those re-licensing proceedings, but we 
will not be dealing with pending proceedings and considering whether to 
revise the rules. At any given time, the need to address one or more 
difficult cases may create workload issues, but that should not be 
typical after the initial implementation period.
    Question 3. At the hearing, I asked FERC to report back to the 
Committee in about six months regarding the progress that is being made 
in implementing the new hydropower licensing procedures. Will DOI work 
with FERC on this progress report?
    Answer. DOI, DOC, and USDA will be pleased to provide FERC with any 
assistance it requests.

     Responses of the Department of the Interior to Questions From 
                            Senator Bingaman

    Question 1. Mr. Robinson's testimony lists several instances where 
the resource agencies have withdrawn or modified conditions and 
prescriptions, and he attributes this at least in part to the new law. 
Can you explain why conditions and prescriptions have been withdrawn or 
modified in the examples given by Mr. Robinson?
    Answer. Interior has three cases where section 4(e) conditions or 
section 18 prescriptions were modified after the deadline for 
requesting Energy Policy Act processes.
    First, in the Rocky Reach Project (Washington) relicensing, the 
Chelan Public Utility District (PUD) filed alternative section 18 
prescriptions on December 19, 2005. At that time, however, the Chelan 
PUD, Interior, through the FWS, and other parties to the FERC 
proceeding were close to executing a comprehensive settlement to 
resolve outstanding issues in the relicensing. On March 20, 2006, the 
Chelan PUD filed the fully executed settlement agreement with FERC, and 
on March 27, 2006, the Chelan PUD withdrew its alternatives. This 
reflects Interior's continuing policy to seek to resolve resource 
issues in FERC license proceedings through settlement. The Energy 
Policy Act had no bearing on Interior's decision to enter into the 
settlement.
    Second, in the Priest Rapids Project (Washington) relicensing, the 
Grant PUD requested a trial-type hearing regarding section 4(e) 
conditions filed by Interior on behalf of the Bureau of Reclamation 
(BOR), and section 18 prescriptions filed on behalf on the FWS on 
December 19, 2005. After several discussions with Grant PUD, the BOR 
decided to withdraw its section 4(e) conditions and, in their place, 
file section 10(a) conditions. The BOR's section 10(a) recommendations 
are very similar to its section 4(e) conditions, and the BOR believes 
its recommendations are in the public interest and will be supported by 
FERC. For those reasons, the BOR did not see the need to go through a 
trial-type hearing.
    Third, in the Hells Canyon Project (Idaho), the Idaho Power Company 
requested a trial-type hearing regarding preliminary section 4(e) 
conditions filed by Interior on behalf of the BLM on March 29, 2006. 
During the pre-hearing phase of the trial-type hearing, IPC and the BLM 
agreed on terms to resolve IPC's concerns with the BLM's preliminary 
conditions, pursuant to which, on May 15, 2006, the BLM filed with FERC 
revised preliminary section 4(e) conditions. On May 16, 2006, IPC 
withdrew its hearing request.
    The USDA Forest Service has agreed to revise or modify section 4(e) 
conditions in two license proceedings since the deadline for requesting 
EPAct processes. First, in the Boulder Creek Hydroelectric Project 
license proceeding, FERC No. 2219, the USDA received a hearing request 
on December 19, 2005, from Garkane Energy Cooperative (Utah), the 
licensee/applicant. The request pertained to one of the Section 4(e) 
conditions that the Forest Service had submitted to FERC in the Boulder 
Creek Project licensing proceeding. In April 2006, Garkane and the 
Forest Service reached a settlement that provided for a modification by 
the Forest Service of the disputed condition and new protection, 
mitigation, and enhancement measures to be added to Garkane's license 
proposal.
    Second, in the Hells Canyon Project (Idaho), the Idaho Power 
Company (IPC) requested a trial-type hearing regarding preliminary 
section 4(e) conditions filed by the USDA Forest Service. During the 
pre-hearing phase of the trial-type hearing, IPC and the Forest Service 
agreed on terms to resolve issues regarding nine of ten conditions at 
issue in OPC's hearing request. On May 9, 2006, the Forest Service 
filed with FERC revised preliminary section 4(e) conditions covering 
the nine conditions resolved.
    Regarding the National Oceanic and Atmospheric Administration 
(NOAA) prescriptions referred to in Mr. Robinson's testimony (Upper 
North Fork Feather River, project no. 2105, and Poe, project no. 2107, 
both in California), the agency amended previously filed section 18 
prescriptions on December 12, 2005, because it was reasonably certain 
that a watershed-scale settlement agreement would be reached that would 
provide greater protections for Central Valley spring-run Chinook 
salmon and Central Valley steelhead. The settlement was signed earlier 
this year.
    Question 1a. Are you in fact ``rethinking your approach'' to 
conditioning projects, as the NHA testimony suggests? If so, in what 
manner?
    Answer. The new statute underscored the need to carefully formulate 
and justify conditions and prescriptions. Given that conditions and 
prescriptions may generate hearings on contested material facts, 
agencies are taking care to make certain that the factual basis of 
their determinations is especially clear. However, this does not mean 
that agencies are or will be reluctant to propose conditions and 
prescriptions where warranted. The agencies continue to participate in 
FERC license proceedings in accordance with their statutory and trust 
responsibilities. This includes, as applicable, determining conditions 
necessary to adequately protect and utilize reservations, and to 
prescribe fishways at projects where the Secretary deems them to be 
necessary and appropriate. As in the past, agencies must support those 
decisions with substantial evidence, and must provide a clear rationale 
for their conditions and prescriptions. We realize that we must marshal 
the facts and documents supporting conditions and prescriptions in a 
manner that anticipates factual challenges before an Administrative Law 
Judge.
    Question 1b. How can we be assured that the hydroelectric 
relicensing provisions are being implemented in a manner that does not 
undermine resource protection?
    Answer. As noted in the answer to the previous question, the new 
statutory requirements have not made agencies reluctant to propose 
conditions or prescriptions where warranted. As Mr. Finfer noted at the 
hearing, the Departments of Commerce and the Interior formulated 
prescriptions and conditions for the Klamath Project under the new 
requirements, yet their proposed prescriptions and conditions address 
the full range of resource protection issues.
    Question 2. The Administration estimates that the new law will 
result in the request of at least 47 hearings and the proposal of 351 
alternative conditions and prescriptions per year, with a cost to the 
Federal Government of $5 million. Do the resource agencies have 
necessary funding and staff to undertake the hearings and evaluate the 
alternative conditions and prescriptions as required by the new 
provisions?
    Answer. The cited workload estimate was provided when the rule was 
published on November 17, 2005, in order to comply with the 
requirements of the Paperwork Reduction Act. However, it was an initial 
estimate that applied only to the first year of implementation, and a 
new estimate was required. Further, the initial estimate had to be 
provided before the submittal of hearings and alternative requests for 
the ``transition'' projects. We recently completed a draft revision of 
the initial estimate that reflects the submittals for transition 
projects. It projects a reduction in workload of approximately 2/3 from 
the initial estimate provided with the rule. Notice of the proposed 
revision to the workload estimate was published in the Federal Register 
on May 3, 2006.
    We believe that our major workload challenge is occurring in this 
initial period of implementation, which will carry forward through most 
of Calendar Year 2007. This is because we are not only implementing a 
new process, but also: (a) addressing the transition projects; (b) 
managing two high profile, complicated cases, namely Hells Canyon and 
Klamath; and (c) considering (next year) possible changes to the rule.
    After this initial period, however, workloads may be at more 
manageable levels. Historically, approximately 1/4 to 1/3 of all 
relicensings have included conditions or prescriptions from any of the 
three resource agencies and a far lesser number have conditions from 
more than one agency. It is expected that parties will request EPAct 
processes in the majority of those re-licensing proceedings, but we 
will not be dealing with pending proceedings and considering whether to 
revise the rule. At any given time, of course, the need to address one 
or more difficult cases may create workload issues, but that should not 
be a normal occurrence after the initial implementation period. We 
believe that agency budgets, when both base funding and the increases 
requested in the FY 2007 President's Budget (as noted in the answer to 
Question 2a below) are taken into account, will prove adequate to 
address this workload.
    It should be noted that the $5 million figure cited in the question 
was not cited as a measure of Federal costs but instead costs to the 
public participants in the process.
    Question 2a. Can we expect to see this level of funding requested 
in the President's Budget for future fiscal years? Was this amount 
requested for FY 2007? If not, why not?
    Answer. The Department of the Interior has requested an increase of 
$400,000 for Fiscal Year 2007 to address the anticipated hearings 
workload. The Department of Commerce has requested $2.8 million to 
augment technical and legal capabilities and to pay the U.S. Coast 
Guard, which is providing Administrative Law Judges to conduct 
hearings. The Forest Service did not request additional funding.
    We believe that the above agency budgets will prove adequate to 
implement the new requirements. As noted in the answer to the previous 
question, we have provided revised workload estimates that are reduced 
from those that were provided when the rules were published, and 
believe that workloads are likely to prove more manageable after the 
initial implementation period.
    Question 3. What has been the average time that it takes the 
Department of the Interior's Office of Hearings and Appeals to complete 
an on-the-record hearing? How many cases are currently on the docket? 
With respect to these pending cases, what is the average length of time 
between filing of a notice of appeal and the commencement of an 
evidentiary hearing?
    Answer. For on-the-record hearing cases concluded during FY 2005 
and the first 7 months of FY 2006, the average length of time from 
receipt of the case by the Office of Hearings and Appeals (OHA) to case 
completion was 17 months. At the end of April 2006, OHA had 306 on-the-
record hearing cases on its docket, of which 33 had had a hearing. The 
average length of time from receipt of the case to the commencement of 
the evidentiary hearing in those cases was 22 months. This data is not 
for cases filed after enactment of the EPAct.
    Question 3a. Will the hydro hearings impact the hearing dockets at 
the resource agencies in a manner that will delay hearings on other 
matters? For example, will hearings on oil and gas, mining and grazing 
matters at the Department of the Interior be delayed because of the 
hydro provisions? Will the hydro appeals take precedence over other 
matters?
    Answer. Because of the tight statutory time frame for the resource 
agencies to complete hydropower licensing hearings, these cases may 
take precedence over other matters. In FY 2006, Interior may have to 
delay hearings on certain matters (e.g., mining and grazing issues) to 
conduct hydropower licensing hearings. As noted in the answer to 
Question 2a, Interior has requested funding in FY 2007 for an 
additional Administrative Law Judge (AU) and staff attorney to assist 
with these cases, in order to minimize any impact on other cases. 
NOAA's hydropower hearings are not expected to have impacts on the U.S. 
Coast Guard's ability to conduct hearings for other programs within the 
Department of Commerce or other Departments. The U.S. Coast Guard's ALJ 
Office is adequately staffed to handle the workloads and to meet the 
timeframes specified in the regulation. The Department of Agriculture 
(Forest Service) also believes it is adequately staffed to address the 
anticipated workload.
    Question 3b. You mention that USDA has made ALJ's available to 
conduct these hearings. What types of cases have these ALJ's been 
handling? Do these ALJ's have expertise in this subject matter?
    Answer. The USDA Office of Administrative Law Judges has wide 
ranging expertise in areas that include making findings of fact on 
natural resource issues such as those that may be raised in these 
proceedings.
    Question 3c. I understand from your testimony that Coast Guard 
ALJ's will be handling the NOAA fishway appeals. Do these ALJ's have 
expertise in this subject matter?
    Answer. The U.S. Coast Guard ALJ Office has authority under the 
U.S. Code to hear adjudicatory matters on behalf of NOAA when one of 
its marine resource statutes or regulations is implicated. The Coast 
Guard ALJ's have many years of experience dealing with procedural 
regulations such as the regulations the Departments promulgated (e.g., 
the NOAA fisheries enforcement procedural regulations at 15 USC 904). 
NOAA has been working closely with the Coast Guard to alert them to the 
rules, participate in training for their ALJs and inform them about new 
developments.
    Question 3d. What is the legal basis for allowing an ALJ from one 
Department to make determinations for the Secretary of another 
Department (for example, for a Coast Guard or USDA ALJ to make 
determinations that bind the Secretary of the Interior)?
    Answer. Section 241 of the Energy Policy Act of 2005 (EPAct) gives 
parties to a hydropower license proceeding the right to ``a 
determination on the record, after opportunity for an agency trial-type 
hearing. . . .'' The agencies have interpreted this language as making 
applicable to hydropower licensing hearings the adjudication provisions 
of the Administrative Procedure Act (APA), 5 U.S.C. Sec. 554 et seq. 
Under 5 U.S.C. Sec. Sec. 556(b)(3), 557(b), an agency is authorized by 
the APA to use any duly appointed ALJ to take evidence and render an 
initial decision, which can become the decision of the agency without 
further proceedings if the agency so provides by rule. In the interim 
final rules on hydropower licensing hearings, each resource agency 
authorized ALJs employed or used by another resource agency to render 
final decisions on disputed issues of material fact for both agencies 
in consolidated cases. In addition, the Economy Act, 31 U.S.C. 
Sec. 1535, authorizes an agency to procure services from another agency 
pursuant to a reimbursable agreement. Since the APA allows an agency to 
use any duly appointed ALJ to preside at a trial-type hearing, the 
agencies can use Economy Act agreements to procure adjudication 
services from each other's ALJs where doing so will conserve resources 
for both the agencies and the parties and will avoid the risk of 
inconsistent results on common issues of material fact.
    Question 4. Section 241 of the Energy Policy Act requires the 
resource agencies to submit into the record of the FERC proceeding a 
written statement demonstrating that in accepting conditions and 
prescriptions and rejecting others the Secretary gave equal 
consideration to the effects of the condition on energy supply, 
distribution, cost, and use; flood control; navigation; water supply; 
air quality; and preservation of other aspects of environmental 
quality. Does the Department have expertise in these areas? What 
information do you plan to rely on in considering these factors? Please 
describe how you plan to carry out this procedural requirement. Will 
this requirement cause new delays?
    Answer. The agencies will rely on the record of the entire 
licensing proceeding to prepare the statement. In doing so, it is 
expected that they will draw on interdisciplinary expertise including, 
as applicable, attorneys, biologists, economists and other 
professionals. They will also have the option to acquire this expertise 
from other departments or, if appropriate and feasible, to seek 
assistance from consultants. The process has been designed to fit 
within the time frames of FERC's rules, so we do not expect it to 
result in delays although, as noted in the answer to Question 2, the 
initial period of implementation will be especially challenging.
    Question 5. Why were the rules implementing the hydroelectric 
relicensing provisions of EPAct issued as interim final rules without 
opportunity for public comment? Please provide the legal justification. 
Were persons outside of the Administration consulted regarding these 
rules? If so, who?
    Answer. As noted when the rule was published, we believe that the 
fact that the rules are procedural and interpretative, coupled with 
Congress's express direction to put them in place within 90 days of 
enactment, necessitated their publication as interim final rules, a 
determination that is consistent with the Administrative Procedure Act 
(sections 553(b)(A) and (B)). However, the rules were published with a 
request for comments, and we have indicated that we will consider these 
comments and our initial experience in implementing the rules in order 
to make a determination on issuing a final rule next year. During the 
period in which the rules were under preparation, various agency staff 
held a small number of meetings with outside parties, most notably the 
National Hydropower Association and the Hydropower Reform Coalition. 
The purpose of these meetings was to hear the general views of these 
parties, but the agencies did not share drafts of the rules.
    Question 6. Will implementation of the hydroelectric relicensing 
provisions cause new delays?
    Answer. As noted in the answer to Question 2a, we believe that our 
major workload challenge is occurring in this initial period of 
implementation, which will carry forward through most of Calendar Year 
2007. This is because we are not only implementing a new process, but 
also: (a) addressing the transition projects; (b) managing two high 
profile, complicated cases, namely Hells Canyon and Klamath; and (c) 
considering (next year) possible changes to the rule.
    After this initial period, workloads may be at more manageable 
levels. Historically, approximately 1/4 to 1/3 of all relicensings have 
included conditions or prescriptions from any of the three resource 
agencies and a far lesser number have conditions from more than one 
agency. It is expected that parties will request EPAct processes in the 
majority of those re-licensing proceedings, but we will not be dealing 
with pending proceedings and considering whether to revise the rule. At 
any given time, the need to address one or more difficult cases may 
create workload issues, but that should not be typical after the 
initial implementation period.
    Question 7. Who has the burden of proof in the trial-type hearings 
required by section 241 of EPAct? Has this issue been raised in any 
appeals proceedings to date? Do you expect that the ALJ's will be 
consistent in their interpretation of who has the burden of proof?
    Answer. The trial-type hearings required by section 241 of EPAct 
are conducted in accordance with the adjudication provisions of the 
APA. These provisions include 5 U.S.C. Sec. 556(d), which states, 
``Except as otherwise provided by statute, the proponent of a rule or 
order has the burden of proof.'' Since the EPAct itself does not 
provide a burden of proof, the APA default burden of proof applies. The 
issue of which party in a hydropower licensing hearing is the 
``proponent'' of an order has been raised in Idaho Power Co. v. Bureau 
of Land Management, No. DCHD-2006-01 (OHA). On May 3, 2006, the ALJ in 
that case issued an order determining that Idaho Power Company, as the 
party that requested the hearing, was the proponent and therefore had 
the burden of proof. On May 31, the USDA ALJ issued a similar ruling in 
the Hells Canyon proceeding involving Idaho Power and the Forest 
Service. While the agencies cannot predict whether other ALJs will rule 
the same way if the issue is presented to them, the agencies requested 
comments on this issue when they issued interim final rules, and expect 
to address it in their revised final rules, which will thereafter 
ensure consistency among all the ALJs handling these cases.
    Question 8. Please provide for the record for each proceeding in 
which an appeal has been requested: (1) the conditions and 
prescriptions that are the subject of appeal; (2) the material facts 
that are alleged to be in dispute; (3) resolution, if any, of whether 
the fact is material; and (4) resolution, if any, of the appeal. What 
definition of ``material fact'' is to be used by the ALJ's?
    Answer. Since publishing the Interim Final Rules, Interior has 
received hearing requests in seven FERC license proceedings: Hells 
Canyon, Klamath, Box Canyon, Condit, Priest Rapids, Merrimack, and Bar 
Mills. The Forest Service (USDA) has received hearing requests in eight 
proceedings: Hells Canyon, Boulder Creek, Kern Canyon, Pitt River 3-
4&5, Upper North Fork Feather River, Poe, Stanislaus-Spring Gap, and 
Portal. The Department of Commerce (National Marine Fisheries Service) 
has received hearing requests in three proceedings: Bar Mills, Condit, 
and Klamath.
    In response to questions 8(1) and 8(2), we have provided CDs that 
include, for each case above, the agency's filing (or FERC license in 
Box Canyon) that includes the pertinent conditions or prescriptions, as 
well as the hearing requests, which include the alleged issues of 
material fact. In addition, we have (on separate pages for each 
project) provided narratives that identify the hearing requests in 
response to questions 8(2) and narratives that respond to questions 
8(3) and 8(4). In the case of the Hells Canyon Complex, we have also 
provided a supplemental CD with the revised agency filings by Interior 
and USDA (Forest Service) which are referenced in their respective 
narratives.
    The interim final rule defines material fact as ``a fact that, if 
proved, may affect a Department's decision whether to affirm, modify or 
withdraw any preliminary condition or prescription.''
Department of the Interior--Hells Canyon Complex
    (2) On January 26, 2006, Interior filed preliminary section 4(e) 
conditions on behalf of the BLM and preliminary section 18 
prescriptions on behalf of the FWS. On February 27, 2006, the Idaho 
Power Company (IPC) filed a hearing request regarding the BLM's section 
4(e) conditions.
    (3) On May 4, 2006, the ALJ in this proceeding dismissed three 
issues (11.1, 12.2, and 19.2) for lack of jurisdiction without ruling 
specifically on materiality. These were issues that the BLM had 
previously stipulated to in its answer. In that same order, the AU 
replaced IPC's six remaining issues with 60 new issues drafted by the 
ALJ. It appears that IPC's original issues have been dismissed, but the 
ALJ did not make specific rulings as to whether they were in fact 
material, factual, or disputed. The ALJ reserved the right to narrow or 
reduce his list of 60 issues following discovery. The ALJ apparently 
relied on the regulation's definition of ``material fact,'' 43 C.F.R. 
Sec. 45.2, and did not further define that term.
    (4) During the pre-hearing phase of the trial-type hearing, IPC and 
the BLM agreed on terms to resolve IPC's issues regarding the BLM's 
preliminary conditions, pursuant to which, on May 15, 2006, the BLM 
filed revised preliminary conditions with FERC. On May 16, 2006, the 
IPC withdrew its hearing request.
Department of the Interior--Klamath Project
    (2) On March 29, 2006, Interior filed preliminary section 4(e) 
conditions on behalf of the BOR and BLM, as well as preliminary section 
18 prescriptions on behalf of the FWS. On April 28, 2006, Interior 
received a hearing request from PacifiCorp asserting several issues of 
material fact pertaining to the BOR's section 4(e) conditions, the 
BLM's section 4(e) conditions, and the FWS' section 18 prescriptions. 
On April 27, 2006, the Pacific Coast Federation of Fisherman 
Association and the Institute for Fisheries Resources filed a joint 
hearing request alleging issues of material fact regarding the BOR's 
section 4(e) conditions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that the ALJ will use the regulatory definition of ``material 
fact,'' which is set forth at 43 C.F.R. Sec. 45.2 and clarified in the 
preamble of the Interim Final Rules.
    (4) These hearing requests remain pending.
Department of the Interior--Box Canyon Project
    (2) On July 11, 2005, FERC issued a license to the Public Utility 
District No. 1 of Pend Oreille County (PUD). In that license, FERC 
included section 4(e) conditions filed by Interior on behalf of the 
BIA, as well as section 18 prescriptions filed by Interior on behalf of 
the FWS. We have included the BIA's section 4(e) conditions and the 
FWS's section 18 prescriptions as they appear in Appendices A and C of 
the July 11, 2005 license. On December 19, 2005, the PUD and Ponderay 
Newsprint Company (PNC) each filed a request for a trial-type hearing 
regarding the BIA's section 4(e) conditions and FWS's section 18 
prescriptions.
    (3) The hearing requests were rejected on jurisdictional grounds 
(see below), so materiality was not addressed.
    (4) On July 11, 2005, FERC issued a license to the PUD for the Box 
Canyon Project, nearly a month prior to enactment of the EPAct and over 
four months prior to publication of the Interim Final Rules. Hence, 
both the PUD's and PNC's hearing requests fell outside the scope of the 
EPAct and the Interim Final Rules, and, consequently, Interior rejected 
their hearing requests. The PUD and, more recently, the PNC filed 
separate lawsuits in the D.C. District Court. Those matters are still 
pending.
Department of the Interior--Condit Project
    (2) In 1994, Interior filed section 18 fishway prescriptions on 
behalf of the FWS. On December 19, 2005, PacifiCorp filed a request for 
a trial-type hearing regarding the FWS's section 18 fishway 
prescriptions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that, if the case is ever referred to an ALJ, the ALJ will use 
the regulatory definition of ``material fact'' in effect at the time of 
referral.
    (4) In 1999, PacifiCorp, Interior, and several other parties 
executed a settlement agreement to resolve disputes in the relicensing 
of the project through surrender of the project license and 
decommissioning of project works. That settlement remains pending 
before FERC, which has deferred evaluation of PacifiCorp's 1991 license 
application. As a result, on March 15, 2006, Interior notified 
PacifiCorp and all hearing interveners that Interior would not schedule 
any hearing for the Condit Project unless and until FERC issues a 
notice or order reinitiating the proceeding to evaluate PacifiCorp's 
1991 license application. In the event FERC issues such a notice or 
order, Interior will, within 45 days, issue a notice establishing a 
time frame for the FWS' answer and hearing.
Department of the Interior--Priest Rapids Project
    (2) On May 26, 2005, Interior filed preliminary section 4(e) 
conditions on behalf of the BOR and section 18 prescriptions on behalf 
of the FWS. On December 19, 2005, the Public Utility District No. 1 for 
Grant County (Grant) filed a hearing request regarding the FWS's 
section 18 prescriptions and the BOR's section 4(e) conditions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that the ALJ will use the regulatory definition of ``material 
fact'' in effect at the time the case is referred to an ALJ.
    (4) In March 2006, the BOR withdrew the challenged section 4(e) 
conditions, and shortly thereafter Grant amended its hearing request 
and withdrew the issue pertaining to BOR's section 4(e) conditions. At 
this time, Grant's issues pertaining to the FWS's section 18 
prescriptions remain pending.
Department of the Interior--Merrimack Project
    (2) On May 16, 2005, Interior filed preliminary section 18 
prescriptions on behalf of the FWS. On December 19, 2005, the Public 
Service Company of New Hampshire filed a hearing request regarding the 
FWS's section 18 fishway prescriptions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that the ALJ will use the regulatory definition of ``material 
fact'' in effect at the time the case is referred to an ALJ.
    (4) This hearing request remains pending.
Department of the Interior--Bar Mills Project
    (2) On December 12, 2005, Interior filed modified section 18 
fishway prescriptions on behalf of the FWS. On January 11, 2006, FLP 
Energy Maine Hydro filed a hearing request regarding the FWS's section 
18 prescriptions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that the ALJ will use the regulatory definition of ``material 
fact'' in effect at the time the case is referred to an ALJ.
    (4) In March 2006, DOI notified FPL Energy Maine Hydro and all 
hearing interveners that the FWS will file its answer by January 19, 
2007. The hearing will be consolidated with NMFS and the case will be 
referred to the U.S. Coast Guard. The hearing will occur in mid/late 
March 2007. This hearing request remains pending.
Department of Agriculture--Forest Service--Hells Canyon Complex
    (2) On January 26, 2006, the Forest Service filed preliminary 
section 4(e) conditions covering a range of issues. On February 27, 
2006, the Idaho Power Company (IPC) filed a hearing request regarding 
the Forest Service's section 4(e) conditions.
    (3) IPC and the Forest Service are currently in negotiations 
regarding the disputed conditions.
    (4) On May 10, 2006, the Forest Service filed revised preliminary 
conditions with FERC for the Hells Canyon Project. The revisions cover 
9 of the 10 challenged conditions. However, IPC's hearing request 
remains pending before a USDA ALJ with respect to the remaining 
condition.
Department of Agriculture--Forest Service--Boulder Creek Hydroelectric 
        Project
    (2) Garkane Energy Cooperative (Garkane), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding one of the Section 4(e) conditions 
that the Forest Service had submitted to FERC in the Boulder Creek 
Hydroelectric Project (Project, FERC No. P-2219) licensing proceeding.
    (3) Garkane and the Forest Service reached settlement regarding the 
disputed condition; therefore, there was no need to resolve whether the 
disputed facts were material. Per the settlement, Garkane withdrew its 
hearing request and the Forest Service submitted a modified condition 
to FERC. The settlement reflects the Forest Service's consideration and 
balancing of resource protection and project economics. The settlement 
agreement also includes additional protection, mitigation, and 
enhancement measures that were not included in the Forest Service final 
condition nor could they be required under FPA 4(e) authority.
    (4) The request for hearing was withdrawn, and the Forest Service 
filed a modified condition.
Department of Agriculture--Forest Service--Portal Project
    (2) Southern California Edison (SCE), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding two of the FPA Section 4(e) 
conditions that the Forest Service had submitted to FERC in the Portal 
Hydroelectric Project (FERC No. P-2174) licensing proceeding.
    (3) SCE and the Forest Service are currently in negotiations 
regarding the disputed conditions, but no resolution has been reached 
at this time.
    (4) The hearing request remains pending.
Department of Agriculture--Forest Service--Kern Canyon Project
    (2) Pacific Gas and Electric (PG&E), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding two of the FPA Section 4(e) 
conditions that the Forest Service had submitted to FERC in the Kern 
Canyon Hydroelectric Project (FERC No. P-178) licensing proceeding.
    (3) PG&E and the Forest Service are currently in negotiations 
regarding the disputed conditions, but no resolution has been reached 
at this time.
    (4) The hearing request remains pending.
Department of Agriculture--Forest Service--Pit 3/4/5 Project
    (2) Pacific Gas and Electric (PG&E), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding one of the FPA Section 4(e) 
conditions that the Forest Service had submitted to FERC in the Pit 3/
4/5 Hydroelectric Project (FERC No. P-233) licensing proceeding.
    (3) PG&E and the Forest Service are currently in negotiations 
regarding the disputed condition, but no resolution has been reached at 
this time.
    (4) The hearing request remains pending.
Department of Agriculture--Forest Service--Upper North Fork Feather 
        Project
    (2) Pacific Gas and Electric (PG&E), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding one of the FPA Section 4(e) 
conditions that the Forest Service had submitted to FERC in the Upper 
North Fork Feather Hydroelectric Project (FERC No. P-2105) licensing 
proceeding.
    (3) PG&E and the Forest Service are currently in negotiations 
regarding the disputed condition, but no resolution has been reached at 
this time.
    (4) The hearing request remains pending.
Department of Agriculture--Forest Service--Stanislaus-Spring Gap 
        Hydroelectric Project
    (2) Pacific Gas and Electric (PG&E), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding one of the FPA Section 4(e) 
conditions that the Forest Service had submitted to FERC in the 
Stanislaus-Spring Gap Hydroelectric Project (FERC No. P-2130) licensing 
proceeding.
    (3) PG&E and the Forest Service are currently in negotiations 
regarding the disputed condition, but no resolution has been reached at 
this time.
    (4) The hearing request remains pending.
Department of Agriculture--Forest Service--Poe Hydroelectric Project
    (2) Pacific Gas and Electric (PG&E), the licensee/applicant, 
submitted a request with the USDA Forest Service on December 19, 2005, 
for a trial-type hearing regarding two of the FPA Section 4(e) 
conditions that the Forest Service had submitted to FERC in the Poe 
Hydroelectric Project (FERC No. P-2107) licensing proceeding.
    (3) PG&E and the Forest Service are currently in negotiations 
regarding the disputed conditions, but no resolution has been achieved.
    (4) The hearing request remains pending.
Department of Commerce--National Marine Fisheries Service--Condit 
        Project
    (2) On June 1, 1994, the National Marine Fisheries Service (NMFS) 
filed preliminary section 18 prescriptions. On December 19, 2005, 
PacifiCorp filed a hearing request regarding NMFS's preliminary section 
18 prescriptions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that, if the case is referred to an ALJ, the ALJ will use the 
regulatory definition of ``material fact'' in effect at the time of 
referral.
    (4) In 1999, PacifiCorp, NMFS, and several other parties executed a 
settlement agreement to resolve disputes in the relicensing of the 
project through surrender of the project license and decommissioning of 
project works. That settlement is pending before FERC, which has 
deferred evaluation of PacifiCorp's 1991 license application. As a 
result, on March 16, 2006, NMFS notified PacifiCorp and all hearing 
interveners that NMFS would not schedule any hearing for the Condit 
Project unless and until FERC issues a notice or order reinitiating the 
proceeding to evaluate PacifiCorp's 1991 license application. In the 
event FERC issues such a notice or order, NMFS will, within 45 days, 
issue a notice establishing a time frame for its answer and the 
hearing.
Department of Commerce--National Marine Fisheries Service--Bar Mills 
        Project
    (2) On December 12, 2005, the National Marine Fisheries Service 
(NMFS) filed modified section 18 prescriptions. On January 11, 2006, 
FPL Energy Maine Hydro filed a hearing request regarding NMFS's 
modified section 18 prescriptions.
    (3) There have been no rulings on materiality in this case. It is 
presumed that the ALJ will use the regulatory definition of ``material 
fact'' in effect if and when the case is referred to an ALJ.
    (4) On March 16, 2006, NMFS notified FPL Energy Maine Hydro and all 
hearing interveners that NMFS will file its answer by January 19, 2007. 
The hearing will be consolidated with DOI and the case will be referred 
to the U.S. Coast Guard. The hearing will occur in mid/late March 2007. 
This hearing request remains pending.
Department of Commerce--National Marine Fisheries Service--Klamath 
        Project
    (2) On March 29, 2006, the National Marine Fisheries Service (NMFS) 
filed preliminary section 18 prescriptions. On April 28, 2006, 
PacifiCorp and the Hoopa Valley Tribe filed hearing requests regarding 
NMFS' preliminary section 18 prescriptions. Those documents include 
alleged issues of material fact.
    (3) There have been no rulings on materiality in this case. It is 
presumed that the ALJ will use the regulatory definition of ``material 
fact,'' which is set forth at 50 C.F.R. Sec. 221.2 and clarified in the 
preamble of the Interim Final Rules.
    (4) These hearing requests are pending.
    Question 9. Do the rules afford an opportunity for public comment 
on alternative conditions and fishway prescriptions (both those that 
are proposed by the parties and those that are adopted by the resource 
agencies)? If not, should there be an opportunity for comment?
    Answer. The rules do not provide a distinct public comment period 
on alternatives. However, they do require parties to file alternatives 
early in the FERC process, so that FERC can evaluate any alternative 
conditions and prescriptions in its draft NEPA document, which does 
have a public comment period. All parties are allowed to comment on 
FERC's NEPA document, including the agencies' preliminary conditions 
and/or prescriptions and any alternatives. Further, each agency must 
consider FERC's NEPA document and any comments filed on such document 
when deciding whether to modify its preliminary conditions and 
prescriptions or to accept an alternative.
    Question 10. Do you expect to issue revised rules implementing 
section 241? If so, when will they be published? What issues do you 
expect to address?
    Answer. When the rules were published on November 17, 2005, the 
agencies indicated they would consider the public comments that were 
received and their initial experience in implementing the rules and 
consider issuing Final Rules within approximately 18 months. That 
remains our intent. It is important to note that the rules outline in 
detail the requirements associated with requests for hearings and how 
they will be processed. As this is a new requirement, we will examine 
closely any technical or managerial issues that arise as we address the 
initial set of cases.
    Question 11. How do you plan to fulfill the Secretary's tribal 
trust responsibility in implementing section 241 of EPAct? Has the 
Department undertaken Government-to-Government consultation with the 
Tribes on implementation of these provisions? If so, please indicate 
when this occurred and what Tribes participated.
    Answer. In accordance with the President's memorandum of April 29, 
1994, ``Government-to-Government Relations with Native American Tribal 
Governments,'' 59 FR 22951 (May 4, 1994), supplemented by Executive 
Order 13175, Consultation and Coordination with Indian Tribal 
Governments, 65 FR 67249 (Nov. 6, 2000), the Departments assessed the 
impact of the new regulations on Tribal trust resources and determined 
that they do not directly affect Tribal resources. The rules are 
procedural and administrative in nature. However, conditions and 
actions associated with an actual hydropower licensing proposal may 
directly affect Tribal resources. The Departments will continue to 
consult with Tribal governments in specific cases when developing 
section 4(e) conditions and section 18 prescriptions needed to address 
the management of Tribal trust resources. Consultation on individual 
projects typically occurs over a multi-year period and requires 
numerous contacts with the affected tribes.
    A good example of such government-to-government consultation can be 
seen with the Klamath Project, in which Interior and Commerce each 
consulted with several tribes on their joint section 18 prescription, 
which was ultimately filed with FERC on March 29, 2006.
                                 ______
                                 
        Response of Mark Robinson to Question From Senator Craig

    Question 1. Under the new procedures, will FERC wait until a trial-
type hearing is completed before issuing a Draft Environmental 
Statement?
    Answer. No. The trial-type hearing is scheduled for completion 10 
days prior to issuance of the DEIS. The DEIS will contain an analysis 
of any alternative conditions or prescriptions that have been filed. 
The new procedures anticipate trial-type hearing results being 
incorporated into the final EIS after opportunity for comment on both 
the hearing results and the DEIS findings. We believe the parallel 
processing of the DEIS and the trial-type hearing will allow for 
efficient license application processing and allow the Commission to 
appropriately consider conditions and prescriptions and the factual 
basis upon which they're founded.

     Responses of Mark Robinson to Questions From Senator Bingaman

    Question 1. Will implementation of the provisions of EPAct 2005 
result in improved conditions and prescription? If so, in what way? If 
not, why not?
    Answer. Yes, I believe that implementation of the provisions of 
EPAct 2005 will result in mandatory conditions that are fairer and more 
balanced. The legislation provides an increased incentive for agencies 
to provide cost-effective and factually-supported mandatory conditions. 
In addition, it appears to have begun to foster greater interaction 
between resource agencies and the licensees in the development of 
environmental measures, and provide a degree of accountability that 
previously did not exist.
    Question 2. The testimony of the National Hydropower Association 
states that the resource agencies ``appear to be rethinking their 
approach to conditioning projects.'' Do you agree? Please explain.
    Answer. Yes, I agree. Although the new provisions have been in 
effect for only a short period and as explained in my testimony, there 
have been a number of positive outcomes that we surmise may have 
resulted from section 241 of EPAct 2005:
    For the Priest Rapids Project No. 2114 in Washington State, the 
licensee challenged the Bureau of Reclamation's (BOR) section 4(e) 
conditions under EPAct. Subsequently, BOR withdrew its mandatory 
conditions and refiled them as recommendations pursuant to section 
10(a) of the FPA.
    For the Upper North Fork Feather River Project No. 2105 and the Poe 
Project No. 2107, both located in California, the National Oceanic and 
Atmospheric Administration of the Department of Commerce (NOAA 
Fisheries) substituted a reservation of authority to prescribe fishways 
in the future for its previously filed specific section 18 
prescriptions.
    For the Rocky Reach Project No. 2145 in Washington, the licensee 
submitted alternatives to Interior's section 18 fishway prescriptions. 
Subsequently, the licensee and Interior's Fish and Wildlife Service 
(and others) entered into a comprehensive settlement agreement 
addressing, among other things, the licensee's fish passage concerns.
    The FPA requires that the Commission authorize projects that are 
best adapted to a comprehensive plan for improving or developing a 
waterway for beneficial public purposes, including power generation, 
irrigation, flood control, navigation, fish and wildlife, municipal 
water supply, and recreation, giving equal consideration to 
developmental and non-developmental values. Based upon the above 
examples, it appears that section 241 of EPAct 2005, which more closely 
aligns the criteria that the agencies must use in formulating mandatory 
conditions with the Commission's ``equal consideration'' criteria for 
licensing projects under the FPA, may already be resulting in the 
agencies taking a broader look at the impacts of their conditions and 
fishway prescriptions.
    Question 3. Your testimony states concern about whether the 
resource agency appeals process will cause new delay. You note that the 
agencies indicate they can only handle one appeal per month, and you 
are concerned that some licenses may be delayed 6 to 14 months. Do you 
have recommendations on how to prevent these delays?
    Answer. My concern is only for the near term, during which the 
agencies must process hearings and alternatives for 15 transition 
projects (those projects where the Departments of the Interior, 
Commerce, or Agriculture had filed preliminary conditions or 
prescriptions, but no license had been issued, as of November 17, 2005) 
as well as hearings and alternatives for large, complex projects being 
processed under the Interim Final Rule timelines. Because the 
Departments of the Interior and Agriculture have indicated to us that 
they are able to schedule only one hearing per month, we are concerned 
the schedules for addressing hearings and alternatives for transition 
projects will extend some licensing proceedings. We would hope that the 
agencies are able to obtain additional staff resources to expedite 
hearings and the filing of modified terms and conditions for these 
cases.
    Question 4. Do resource agencies have necessary funding and staff 
to undertake the hearings and evaluate the alternative conditions and 
prescriptions as required by the new provisions?
    Answer. I have no information about the agencies' funding and 
staffing.
    Question 5. With respect to pending license applications, if as a 
result of implementation of EPAct 2005 final conditions or 
prescriptions are modified by the resource agencies, what opportunities 
will the public have to provide input? Will additional analysis of the 
modified conditions and prescriptions be required under the National 
Environmental Policy Act, the Endangered Species Act, and other 
environmental statutes? If so, please describe. Will this require extra 
time?
    Answer. The hearing and alternative condition and prescription 
process is well integrated into FERC's hydropower licensing process. 
Modified conditions and prescriptions would be analyzed in the final 
environmental document. Parties who wish to comment on the final 
environment document may do so. Also, after the Commission issues an 
initial licensing order, any party to the proceeding will have the 
opportunity to seek rehearing from the Commission, in the event that 
they disagree with conclusions in the environmental document or the 
order. As to whether additional analysis of modified conditions and 
prescriptions will be necessary, by the time the modified conditions 
are filed, there will already have been three years of prefiling 
discussion about project issues, studies, and environmental measures. 
It is therefore likely that any proposed alternatives or modifications 
will have previously been raised and accordingly considered in the 
Commission's environmental analysis. However, in the unlikely event 
that an agency does develop a condition or prescription that has not 
already been analyzed, the Commission would have to take the time to do 
so.
    Question 6. How do you plan to fulfill the FERC's tribal trust 
responsibility in implementing EPAct 2005? Has the FERC undertaken 
Government-to-Government consultation with the Tribes on implementation 
of these provisions? If so, please indicate when this occurred and what 
Tribes participated.
    Answer. I am not aware of any additional tribal trust 
responsibilities set forth in EPAct 2005. The Commission has already 
fully integrated tribes and their interests into its hydropower 
licensing processes. The Commission staff identifies and contacts 
directly tribes likely to be interested in any hydropower case to 
determine whether and to what degree a tribe may desire to participate.
                                 ______
                                 
                           National Hydropower Association,
                                      Washington, DC, May 18, 2006.
Hon. Pete V. Domenici,
Chairman, Committee on Energy and Natural Resources, U.S. Senate, 
        Dirksen Senate Office Building, Washington, DC.

    Dear Senator Domenici: The National Hydropower Association is most 
appreciative of the opportunity to present industry's views at the May 
8th oversight hearing on the implementation of the hydropower licensing 
provisions of the Energy Policy Act of 2005 (EPAct 2005). These 
provisions are extremely important to the hydropower industry as they 
bring more transparency to the licensing process, while protecting 
important environmental standards.
    Attached are NHA's responses to the questions submitted for the 
record by Senator Craig and Senator Bingaman.
    As we requested in our statement, we hope that the Committee will 
hold additional oversight hearings on this matter in the future as it 
is far too early to gain a full understanding of the impact of these 
provisions and additional experience is warranted.
    NHA commends your leadership and your willingness to hold this 
important oversight hearing.
            Sincerely,
                                       Linda Church Ciocci,
                                                Executive Director.

                Response to Question From Senator Craig

    Question 1. Do hydroelectric licensing reforms make any changes to 
applicable environmental requirements? Is the State's Clean Water Act 
certification process in any way impacted?
    Answer. No, the hydroelectric licensing reforms do not make changes 
to the underlying environmental standards in the Federal Power Act 
(FPA). The FPA standards remain exactly the same as they were prior to 
the adoption of EPAct 2005 and the federal agencies retain their 
authority to impose Section 4(e) and 18 conditions and prescriptions on 
hydropower projects as part of the Federal Energy Regulatory Commission 
(FERC) licensing process. In fact, it is NHA's hope that the provisions 
will reduce process and litigation delays so that environmental 
improvements associated with relicensing are implemented quicker to the 
benefit of the natural resources.
    Additionally, the reforms have no impact or effect on the 
application of the Clean Water Act's state certification process to 
hydropower projects. None of the EPAct 2005 provisions apply to Section 
401 of the Clean Water Act. The reforms also have no impact on the 
application of other federal environmental statutes, such as the 
Endangered Species Act, to hydropower relicensing.

              Responses to Questions From Senator Bingaman

    Question 1. Your testimony states that the resource agencies 
``appear to be rethinking their approach to conditioning projects.'' 
Please explain and provide examples.
    Answer. While it is still very early in the implementation of the 
relicensing provisions, NHA believes that the agencies are devoting 
more thought and attention in the preparation and formulation of 
license conditions and are taking a closer look to ensure that 
conditions are supported by the facts.
    Conditions are only as good as the facts that underlie them. NHA 
supported the relicensing reform provisions to bring transparency and 
accountability to the conditioning process. As the Department of 
Interior's Mr. Finfer stated in his testimony, EPAct 2005 ``. . . 
underscored the need for careful deliberation, justification, and 
documentation with respect to the formulation of conditions and 
prescriptions.'' Now that licensees and other parties can challenge 
disputed facts underlying a condition, it follows that the agencies are 
working to better demonstrate and record them in order to support their 
conditioning decisions.
    Question 2. Will implementation of the provisions of EPAct 2005 
result in improved conditions and prescriptions? Is so, in what way? If 
not, why not?
    Answer. Yes, NHA anticipates that the new provisions will result in 
improved conditions and prescriptions. The trial-type hearing provision 
will help ensure that all conditions are based on a full consideration 
of the relevant facts, as determined by an independent neutral party--
the departmental administrative law judge. NHA believes that better 
facts will produce better conditions.
    In addition, the equal consideration provision will ensure that the 
agencies evaluate the effects of conditions on energy supply, 
distribution, cost, flood control, navigation, water supply, air 
quality and other aspects of environmental quality, resulting in 
licenses that are best suited to the public interest.
    Most important, before a cost or power-saving alternative condition 
is adopted, the agency must determine it meets the statutory FPA 
requirements for environmental and resource protection.
    Better licensing conditions that meet environmental needs and 
improve energy production are possible with these new provisions. This 
is a positive development at a time when the country needs the clean, 
domestic, renewable energy that hydropower provides.
    Question 3. Will implementation of the hydroelectric relicensing 
provisions cause new delays?
    Answer. No, NHA does not anticipate that the relicensing 
provisions, if properly implemented and used, will cause any 
significant delays in the process. In fact, the provisions should 
reduce overall delays by providing licensees and other parties 
additional tools to resolve disputes before a license is issued. By 
resolving disputes early, it should dispense with the need to review 
licenses in the Court of Appeals, which past experience has shown can 
delay license implementation for years. Reducing delays serves all 
parties and allows environmental improvements associated with 
relicensing to be implemented more quickly to the benefit of the 
natural resources.
    Question 4. Please describe the key issues raised in the litigation 
that has been filed by industry with respect to the interim final 
rules?
    Answer. The National Hydropower Association has not filed any 
litigation on behalf of the hydropower industry challenging the interim 
final rules. However, American Rivers and other non-governmental 
organizations have filed suit to enjoin the regulations. NHA also 
understands that one individual hydropower licensee in Washington 
State, Pend Oreille Public Utility District, has also filed a suit 
challenging application of the relicensing reforms to the relicensing 
of the Box Canyon project.
    As NHA is not participating in any legal challenge to the interim 
final rules, we cannot address the specifics of those proceedings. 
Additional details can be obtained directly from those organizations.
                                 ______
                                 
                                           Amercian Rivers,
                                      Washington, DC, May 22, 2006.
Hon. Pete V. Domenici,
Chairman, Senate Committee on Energy and Natural Resources, U.S. 
        Senate, Washington, DC.
    Dear Senator Domenici: Thank you very much for providing me with 
the opportunity to testify before the Senate Committee on Energy and 
Natural Resources on Monday, May 9, 2006, regarding issues associated 
with the implementation of the provisions of the Energy Policy Act of 
2005 addressing licensing of hydroelectric facilities.
    Enclosed are responses to the questions submitted to us by you and 
Senator Jeff Bingaman. If you have any follow-up questions to the 
answers provided, please feel free to contact me.
            Sincerely,
                                            Andrew Fahlund,
                                   Vice President for Conservation.
[Enclosures.]

               Responses to Questions From Senator Craig

    Question 1. In your testimony you claim that license applicants are 
using the hearing process to raise frivolous issues that are not 
disputed material facts and that the agencies--not ALJs--should 
determine whether a hearing is warranted.
    a. Wouldn't that give the same agency staff that have developed a 
preliminary condition the right to prevent a hearing on the facts that 
underlie such a condition? For example, I understand that in the 
ongoing hearing regarding preliminary BLM conditions for the Hells 
Canyon Project, agency counsel filed a Motion to Dismiss virtually 
every issue raised on the grounds that it was not material. The ALJ 
denied this motion and instead found that most of the issues raised 
were material facts.
    b. Isn't an independent judge better equipped to decide whether a 
party has raised material facts and is entitled to a hearing than 
agency staff?
    Answer. Agencies should not be forced to expend resources on trial-
type hearings that are not authorized under the Act. In filings before 
the Administrative Law Judge (ALJ), federal agencies have rightly 
attempted to limit the scope of the hearings, not because they have a 
vested interest in dismissing claims against their conditions but 
because the issues fail to qualify as material. In the case of the 
trial-type hearing in the Department of the Interior concerning 
material facts underlying BLM's conditions on the Hells Canyon Complex, 
the ALJ did not find that the facts raised were material, but rather 
that his interpretation of Congressional intent required him to hold a 
trial-type hearing to make a determination of materiality (even so, he 
ruled that 3 facts did not qualify as material). Agencies can readily 
create systems to ensure impartiality, such as designating hearing 
officer staff (who are not involved in agency conditions) to make 
determinations on whether disputed issues should be dismissed as 
immaterial. We think this approach is preferable to that of deferring 
immaterial issues to ALJs, because of the cost to license parties. 
However, even if all issues are sent to the ALJs, it would still be 
possible to avoid trial-type hearings if ALJs were empowered to make 
summary judgment determinations on materiality before conducting 
hearings.
    Question 2. In American Rivers' comments on the Interim Final Rule 
and in its lawsuit filed in U.S. District Court to vacate that rule, 
your organization argues that the rule's applicability to pending 
licensing proceedings is somehow ``retroactive'' and improper. Can you 
explain how the rule is ``retroactive'' when it applies to proceedings 
where no license has been issued? Since these licenses are valid for 
30-50 years, shouldn't we make sure the facts are right for the 15 
projects that are at issue?
    Answer. Please see our attached motion.*
---------------------------------------------------------------------------
    * The attached motion and comments on the rules have been retained 
in committee files.
---------------------------------------------------------------------------
    Question 3. Why does American Rivers continue to claim that states 
are somehow disadvantaged with this new process when Congress did not 
alter state authority in any way?
    Answer. States are an integral part of the licensing process and 
have interests to protect including their mandatory authority to impose 
water quality certifications and their recommendations under sections 
10(a) and 10(j) for the protection of fisheries, wildlife, and 
recreation. Conditions and prescriptions now subject to EPAct are often 
the result of a collaboration between state and federal interests in 
protecting resources. When those conditions and prescriptions are 
challenged, states have a direct interest in ensuring that their 
interests are protected. For example, the states of Idaho and Oregon 
filed interventions in the request for a trial-type hearing by Idaho 
Power Company to the Forest Service for the Hells Canyon Complex 
hydroelectric proceeding. Thus, scarce taxpayer dollars must be 
expended to file interventions, line up witnesses, and assemble data, 
all within a short-timeline. While profitable license applicants will 
have the financial resources to challenge conditions, we are concerned 
that states, especially those running deficits, may not have the luxury 
to protect their interests due to finite taxpayer dollars. In addition, 
the states' concerns will not necessarily be addressed by the criteria 
given for evaluation of alternative license conditions.

              Responses to Questions From Senator Bingaman

    Question 1. Will implementation of the provisions of EPAct 2005 
result in improved conditions and prescriptions? If so, in what way? If 
not, why not?
    Answer. The sheer burden of the process is likely to harm some 
conditions and cause some agencies to weaken them or narrow their scope 
not based on the merits of doing so, but rather due to the financial 
hardship of imposing them. It is also possible that in some cases, 
agencies will forgo proposing needed resource protection measures 
altogether.
    Question 2. Will implementation of the hydroelectric relicensing 
provisions cause new delays?
    Answer. Already the rules and their provision allowing settled 
cases to be reopened have and will delay the hydroelectric licensing 
process. In their testimony to your committee, FERC staff estimated 
that for 9 of the 14 retroactive cases, there will be 6 to 14 month 
delays in final Commission action despite the requirement in the law 
that the trial-type hearing ``be conducted . . . within the time frame 
established by the Commission for each license proceeding.'' (Section 
241) For example, in the Priest Rapids proceeding, a January 2006 FERC 
schedule states that the application will ``be ready for Commission 
action'' in 2006, but the trial-type hearing is scheduled for January 
2007. The rules openly acknowledge the fact that the decision to allow 
retroactive proceedings to access the EPAct processes will lead to 
disruption in the licensing process. ``In many cases, this sequence and 
timing will need to be adjusted with respect to any license application 
that is currently pending before FERC, if the license applicant or 
another party wants a trial-type hearing or wants to submit an 
alternative condition or prescription.'' (Fed. Reg. at 69807, col.2).
    Question 3. Are the hydroelectric relicensing provisions being 
implemented in a manner that maintains natural resource protection?
    Answer. Absolutely not. We have already seen agencies back down 
from conditions they prescribed, not necessarily because their 
conditions lacked merit, but likely because they cannot afford the 
costs of going through the EPAct processes. For example, in the case of 
Garkane Energy Cooperative proceeding, the Forest Service revised its 
4(e) conditions to reduce the minimum flow releases from 3 to 6 cfs to 
2 cfs. This accommodation allowed the Forest Service to avoid the 
trial-type hearing and the alternative conditions processes. In the 
Hells Canyon Complex licensing, the Forest Service narrowed the scope 
of the trial-type hearing and alternatives process by reducing the 
requirement in its 4(e) conditions that Idaho Power Company acquire 
riparian habitat to offset project impacts from 1,522 acres to 56.3 
acres.
    Question 3a. Can you suggest any modifications to the 
implementation or the regulations that would help achieve natural 
resource protection?
    Answer. Rule changes that could counter the disincentive for 
agencies to propose conditions and prescriptions would include: 
explicitly allowing license parties to propose alternative conditions 
when an agency fails to propose conditions; requiring that all 
communications with agencies concerning alternative conditions and 
trial-type hearings be open to all license parties; and providing for 
an explicit comment period on all alternative condition requests. It 
will be imperative that agencies strictly adhere to the requirement 
that alternatives be no less protective than the original prescription 
or provide for the adequate protection and utilization of the 
reservation. Other recommendations discussed below regarding measures 
to enhance citizen participation will also ensure resource protection, 
since citizens play a vital role in protecting resources. Finally, 
adequate agency funding to ensure effective implementation is critical.
    Question 4. Do you believe that all parties to the FERC relicensing 
proceeding will be able to participate fully in the process under the 
new provisions?
    Answer. Over time there will be a war of attrition, as license 
parties, with the exception of license applicants, find it difficult to 
muster the resources to continue to engage in costly adjudicatory 
proceedings. This will be particularly true if every request for a 
trial-type hearing results in such a hearing, even for immaterial 
issues.
    Question 4a. Can you suggest steps that could be taken by the 
resource agencies and FERC that would help to facilitate participation?
    Answer.

   The agencies should change the rules to ensure that they 
        have the express authority to reject trial-type hearings in 
        which the issues raised are not factual or not material and can 
        be resolved otherwise through the licensing process. Agencies 
        can designate impartial staff, such a hearing officers, to 
        accomplish this task. Granting agencies this authority ensures 
        that citizens are not compelled to expend time and limited 
        resources on trial-type hearings that fail to qualify as 
        material or that can be resolved without a trial-type hearing. 
        Moreover, ALJs should be empowered to make summary judgment 
        determinations prior to commencing trial-type hearings.
   The agencies should establish ex parse rules for decisions 
        regarding alternative conditions and trial-type hearings and 
        also ensure that all parties have equal access to decision-
        making. The intent of the law and rights granted under the 
        Administrative Procedures Act prohibit unilateral discussions 
        with license applicants that leave out citizen groups, but that 
        limitation should be made explicit in the rules.
   The rules should confirm that the burden of proof in a 
        trial-type hearing falls upon the hearing requester. In filings 
        before ALJs, the agencies have noted that a recent decision by 
        the U.S. Supreme Court concerning the application of the 
        Administrative Procedures Act, as well as common law, holds 
        that an entity seeking to overturn an agency decision bears the 
        burden of persuading the ALJ and the ALJs have agreed.
   The rules should be altered to eliminate the provision that 
        the decision of the ALJ is final with respect to the disputed 
        issues of material fact. A decision of the ALJ should not be 
        binding and should be subject to appeal by all parties.
   The rules should establish a public comment period on all 
        proposed alternative conditions. Comments on the NEPA document 
        are insufficient to address alternatives proposed after FERC 
        has completed its NEPA analysis on the agencies' proposed 
        conditions. The omission of public comments in favor of NEPA 
        comments also fails to account for cases in which the agency 
        adopts the alternative as its own prior to the trial-type 
        hearing. Finally, the allowance for NEPA comments in lieu of a 
        discreet comment period on alternatives does not recognize that 
        comments are directed to FERC, an agency with a different 
        mandate and requirements than those of the resource agencies.
   The rules should allow for delaying the trial-type hearing 
        to facilitate settlement talks. The agencies have deliberately 
        postponed the hearings in some of the retroactive cases to see 
        if agreement can be reached on issues that are the subject of 
        challenges, but the rules fail to allow this flexibility in the 
        prospective cases.
   The agencies should encourage and allow e-filing to the 
        Departments and others of all documents. The service 
        requirements and their heavy reliance on multiple paper copies, 
        overnight mail, hand-delivery of documents imposes a heavy 
        administrative and financial burden on citizen groups.

    Question 5. Please describe the key issues raised in the litigation 
that has been filed by American Rivers and other conservation 
organizations with respect to the interim final rules.
    Answer. Please see attached motion.
    Question 6. Please provide for the record a copy of any comments 
filed by American Rivers on the November 17, 2005 interim final rule of 
the resource agencies implementing EPAct 2005.
    Answer. Please see attached comments on the rules.

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