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28–983 PDF 2006

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 

(II)

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

PETE V. DOMENICI, New Mexico, Chairman 

LARRY E. CRAIG, Idaho 

CRAIG THOMAS, Wyoming 

LAMAR ALEXANDER, Tennessee 

LISA MURKOWSKI, Alaska 

RICHARD BURR, North Carolina 

MEL MARTINEZ, Florida 

JAMES M. TALENT, Missouri 

CONRAD BURNS, Montana 

GEORGE ALLEN, Virginia 

GORDON SMITH, Oregon 

JIM BUNNING, Kentucky 

JEFF BINGAMAN, New Mexico 

DANIEL K. AKAKA, Hawaii 

BYRON L. DORGAN, North Dakota 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

DIANNE FEINSTEIN, California 

MARIA CANTWELL, Washington 

JON S. CORZINE, New Jersey 

KEN SALAZAR, Colorado 

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 

(III)

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, EconoPower 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

Page

IV

APPENDIX 

Responses to additional questions: 

April 24, 2006 ................................................................................................... 145

May 1, 2006 ....................................................................................................... 164

May 8, 2006 ....................................................................................................... 172

(1)

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 coalto-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 examVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00005 Fmt 6633 Sfmt 6633 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
2

ine 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 

3

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. Coalto-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. 

4

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 SEQUESTRA- TION, 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 

5

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, 

6

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 

7

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.

8

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. 

9

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 

10

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? 

11

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. 

12

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 broadbased 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 

13

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 

14

* Attachments A and B have been retained in committee files.

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: 

• 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 Gasto-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 

15

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. 

16

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:

17

• 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. 

18

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 

19

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. 

20

1Peabody’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. 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. 

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

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-toliquids 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 coalto-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

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 lowCO2 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 inVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00024 Fmt 6633 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
21

4The 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. 5 Congressional Research Service, U.S. Coal: A Primer on the Major Issues, at 30 (Mar. 25, 

2003). 6 Id. 

7Melissa 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). 8http://www.umwa.org/blacklung/blacklung.shtml 

9 Alabama, Georgia, Eastern Kentucky, Maryland, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia. 10 Energy Information Administration. Annual Coal Report, 2004. 

vestments 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

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

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. 

After mining is complete, these once-forested regions in the Southeast are typically reclaimed as grasslands, although grasslands are not a naturally occurring 

22

11Sencindiver, 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 15 Julian Martin, West Virginia Highlands Conservancy, Personal Communication, February 

2, 2006. 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. 18See, 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. 21 EPA. Mountaintop Mining/Valley Fills in Appalachia: Draft Programmatic Environmental 

Impact Statement. 22 Id. 

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

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. 

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

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

23

23Keating, Martha. ‘‘Cradle to Grave: The Environmental Impacts from Coal.’’ Clean Air Task 

Force, Boston. June, 2001. 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. 29DOE/EIA, 2005. Emissions of Greenhouse Gases in the United States 2004. (December). 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). 

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

Acid mine drainage (AMD) is the most significant form of chemical pollution produced from coal mining operations. In both underground and surface mining, sulfurbearing 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

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

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

24

33Frazier, Ian. ‘‘Coal Country.’’ On Earth. NRDC. Spring, 2003. 34 Reece, Erik. ‘‘Death of a Mountain.’’ Harper’s Magazine. April, 2005. 35Id. 36DOT 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 40Michael Schnayerson, ‘‘The Rape of Appalachia,’’ Vanity Fair, 157 (May 2006). 41 Id. 42 http://nationalatlas.gov/articles/transportation/a—freightrr.html 43 Erik Reece, Lost Mountain: A Year in the Vanishing Wilderness 112 (2006). 

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

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

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. 

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

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 

25

44Personal communication from Hillary Hosta and Julia Bonds, Coal River Mountain Watch 

(Apr. 7, 2006). 45 NRDC. Drawdown: Groundwater Mining on Black Mesa. 

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

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. 

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 fuelefficient 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.

26

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 tax credits 

and standards .......................................................................................... 1.6 4.9

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 residential sectors ... 0.3 0.7

Encourage growth of biofuels industry through demonstration and 

standards ................................................................................................. 0.3 3.9

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 

27

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:]

28

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 

29

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 firstof-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 jumpstart 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 centper-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 

30

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 knowhow, 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 

31

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 

32

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. 

33

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 

34

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 highgrade 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 jumpstarting 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, 

35

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 

36

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 

37

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 

38

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-toliquids, 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. 

39

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. 

40

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 

41

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.] 

(43)

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, 

44

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. 

45

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. 

46

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 

47

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 

48

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 

49

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 gasificationbased 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, gasificationbased 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. 

50

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. 

51

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. 

52

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 

53

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. 

54

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. 

55

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. 

56

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? 

57

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 in- terest 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. 

58

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 DeVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00062 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
59

partment 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 MichiganWisconsin 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 ComVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00063 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
60

pany, 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 

61

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-byproject 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 

62

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. 

63

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 

64

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 selfpay 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. 

65

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 

66

* Attachments 1-3 have been retained in committee files. 

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 shortsighted 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 * 

• Avoids Mid-East Energy Dependency—Maintains U.S. economic strength and 

avoids ‘‘oil style’’ dependence on Middle East—truly a slippery slope. 

67

• 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. 

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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. 

69

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 

70

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. Fivehundred 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. 

71

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-peryear 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 

72

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 byproduct 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 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.

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 

73

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 inVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00077 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
74

centives 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. 

75

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 postcombustion 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. 

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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. 

77

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 

78

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 

§ 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 

79

* Appendixes A-C have been retained in committee files. 

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. 

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. 

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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. 

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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 highpressure 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 

82

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 § 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 § 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 § 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 

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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. 

84

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 comVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00088 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
85

patible 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 21⁄2 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:]

86

1David 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 

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. 

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 

87

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.) 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. 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. 

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. 

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

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 

88

7 UCS, Renewable Energy Can Help Alleviate Natural Gas Crisis, June 2003, at 2. 8 UCS, Clean Energy Blueprint: A Smarter National Energy Policy for Today and the Future, 

October 2001. 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/rptlbriefs/climate-changefinal.pdf. 9a Retained in committee files. 

prices for electricity generators and other consumers offset the slightly higher cost 

of renewable electricity technology.7

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

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

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-asusual 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. 

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 

89

10http://www.eia.doe.gov/cneaf/coal/page/acr/table26.html 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 11a Appendix A has been retained in committee files. 

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

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 coalfired 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. 

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

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 

90

12The 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. 13David Hawkins, Testimony before the Senate Energy and Natural Resources Committee, 

‘‘Coal Liquefaction and Gasification’’, April 24th, 2006. http://docs.nrdc.org/globalwarming/

glol06042401a.pdf 

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. 

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-toliquids program can be compatible with the low-002-emitting transportation system 

we need to design to prevent global warming. 

91

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. 

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. 

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 lowCO2 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 

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15David Hawkins, Testimony before the Senate Energy and Natural Resources Committee, 

‘‘Coal Liquefaction and Gasification’’, April 24th, 2006. http://docs.nrdc.org/globalwarming/

glol06042401a.pdf 

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. 

‘‘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:

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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. 17 Ibid. 

• 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. 

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. 

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’’ 

94

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 

95

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 

96

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. 

97

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——

98

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 

99

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, 

100

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—

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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 

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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 

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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? 

104

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.] 

(105)

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 

106

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 

107

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 liVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00111 Fmt 6601 Sfmt 6601 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
108

censing 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 trialtype 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 

109

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 

110

* The attachment has been retained in committee files. 

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 crossexamine 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 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 

111

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. 

112

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 

113

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, posthearing 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 nonFederal hydropower capacity and cover every region must receive new operating licenses. In issuing new licenses, it is important to ensure that significant natural 

114

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 conVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00118 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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sider 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, prehearing 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. InVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00119 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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deed, 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. 

117

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 NaVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00121 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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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. 

tional 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). 

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. SimiVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00122 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
119

1aThe appendix has been retained in committee files. 

larly, 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 trialtype 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. 

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. 

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2The American Public Power Association, in its comments on the rules, approached the trialtype 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 addition, NHA is concerned that the interim rules do not provide for a trialtype 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. 

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. 

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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. 

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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 apVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00126 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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pearing 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, dediVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00127 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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1Section 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). 

cated 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

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2More 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. 3The 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. 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. 

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 

3. The dam complies with state-developed water quality standards (Clean 

Water Act, Section 401).3

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. 

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 

126

5FERC has a different mandate, balancing interests, schedule, and requirements. (70 

Fed.Reg. 69,807, cols. 1 and 2. Also, see: 7 C.F.R. § 1.673) 

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. § 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. 

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. § 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. 

127

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. 8PG&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. 

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

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. § 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 trialtype 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. § 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 

128

9Letter 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. 

their own rules which precluded any further extensions, also granted an even longer 

extension of EPAct timelines for one project.9

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. 

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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 

130

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 comVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00134 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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pleted, 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 fiVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00135 Fmt 6601 Sfmt 6602 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
132

nally 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? 

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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? 

134

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? 

135

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 triallike 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. 

136

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. 

137

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? 

138

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 

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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 exVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00143 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
140

tending 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 costeffectiveness. 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 DeVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00144 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
141

partments 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 

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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. 

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

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 

143

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. 

(145)

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. 

146

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 

147

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? 

148

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 

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* The report has been retained in committee files. 

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. 

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 fuelefficient 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: 

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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.

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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 lowfriction 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 

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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. 

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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 highblend 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, energyrich components that can be used to provide energy for the conversion process as 

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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 nearzero 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 performVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00158 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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ance 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 FischerTropsch (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. 

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1Mitretek Systems, A Techno-Economic Analysis of a Wyoming Located Coal-to-Liquids (CTL) 

Plant, (April 2005). 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. 3 ibid, p. 1. 

4 ibid. 

5 Clean Air Task Force, Wounded Waters: The Hidden Side of Power Plant Pollution, (February 2004), p. 2. 6 ibid., p. 10. 

7 ibid., p. 10. 

8 EPA. Mid-Atlantic Integrated Assessment: Coal Mining. 

• 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. 

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. 

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

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. 

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

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 

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9 EPA Office of Solid Waste. Acid Mine Drainage Prediction Technical Document, (December 

1994). 10 NRDC, Energy Down the Drain, (August 2004), http://www.nrdc.org/water/conservation/

edrain/edrain.pdf. 11 NRDC, Growing Energy, (December 2004), p. 28, http://www.nrdc.org/air/energy/biofuels/

biofuels.pdf 12 ibid., p. 20. 13 ibid., p. 27. 14 ibid., p. 43. 

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

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

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. 

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

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. 

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? 

158

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 presVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00162 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
159

sures, 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 coauthored 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 

160

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 coalto-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 nearzero 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. 

161

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. 

162

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 

163

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 coalto-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?

164

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 

165

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? 

166

1 Ammonia Outlook, March 2006, FERTECON Limited, p. 99. 

2 Ibid. 

Answer. Under section 48B a total of $650 million in qualifying property is eligi- ble 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. 

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 

167

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 

168

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 ultraclean 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 

169

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 

170

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? 

171

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?

172

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 trialtype hearing, IPC and the BLM agreed on terms to resolve IPC’s concerns with the 

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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. 

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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? 

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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. § 554 et seq. Under 

5 U.S.C. §§ 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. § 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 HydroVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00179 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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power 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. § 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. 

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(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. § 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. § 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 reVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00181 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
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quest 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. 

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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. P2130) 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. 

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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. § 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. 

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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 factuallysupported 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 

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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 standVerDate 0ct 09 2002 10:38 Aug 02, 2006 Jkt 109503 PO 28983 Frm 00186 Fmt 6601 Sfmt 6621 R:\DOCS\28983.TXT SENERGY1 PsN: RSMIT
183

ards 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. 

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* The attached motion and comments on the rules have been retained in committee files. 

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 trialtype 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.* 

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? 

185

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 trialtype 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. 

186

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.

Æ