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ADVANCING COAL RESEARCH AND DEVELOPMENT 

FOR A SECURE ENERGY FUTURE 

HEARING 

BEFORE THE

SUBCOMMITTEE ON ENERGY AND 

ENVIRONMENT 

COMMITTEE ON SCIENCE, SPACE, AND 

TECHNOLOGY 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED TWELFTH CONGRESS 

FIRST SESSION 

THURSDAY, OCTOBER 13, 2011 

Serial No. 112–45 

Printed for the use of the Committee on Science, Space, and Technology 

( 

Available via the World Wide Web: http://science.house.gov 
(II) 

COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY 

HON. RALPH M. HALL, Texas, Chair 

F. JAMES SENSENBRENNER, JR., 

Wisconsin 

LAMAR S. SMITH, Texas 

DANA ROHRABACHER, California 

ROSCOE G. BARTLETT, Maryland 

FRANK D. LUCAS, Oklahoma 

JUDY BIGGERT, Illinois 

W. TODD AKIN, Missouri 

RANDY NEUGEBAUER, Texas 

MICHAEL T. MCCAUL, Texas 

PAUL C. BROUN, Georgia 

SANDY ADAMS, Florida 

BENJAMIN QUAYLE, Arizona 

CHARLES J. ‘‘CHUCK’’ FLEISCHMANN, 

Tennessee 

E. SCOTT RIGELL, Virginia 

STEVEN M. PALAZZO, Mississippi 

MO BROOKS, Alabama 

ANDY HARRIS, Maryland 

RANDY HULTGREN, Illinois 

CHIP CRAVAACK, Minnesota 

LARRY BUCSHON, Indiana 

DAN BENISHEK, Michigan 

VACANCY 

EDDIE BERNICE JOHNSON, Texas 

JERRY F. COSTELLO, Illinois 

LYNN C. WOOLSEY, California 

ZOE LOFGREN, California 

BRAD MILLER, North Carolina 

DANIEL LIPINSKI, Illinois 

GABRIELLE GIFFORDS, Arizona 

DONNA F. EDWARDS, Maryland 

MARCIA L. FUDGE, Ohio 

BEN R. LUJA ́ N, New Mexico 

PAUL D. TONKO, New York 

JERRY MCNERNEY, California 

JOHN P. SARBANES, Maryland 

TERRI A. SEWELL, Alabama 

FREDERICA S. WILSON, Florida 

HANSEN CLARKE, Michigan 

VACANCY 

SUBCOMMITTEE ON ENERGY AND ENVIRONMENT

HON. ANDY HARRIS, Maryland, Chair 

DANA ROHRABACHER, California 

ROSCOE G. BARTLETT, Maryland 

FRANK D. LUCAS, Oklahoma 

JUDY BIGGERT, Illinois 

W. TODD AKIN, Missouri 

RANDY NEUGEBAUER, Texas 

PAUL C. BROUN, Georgia 

CHARLES J. ‘‘CHUCK’’ FLEISCHMANN, 

Tennessee 

RALPH M. HALL, Texas 

BRAD MILLER, North Carolina 

LYNN C. WOOLSEY, California 

BEN R. LUJA ́ N, New Mexico 

PAUL D. TONKO, New York 

ZOE LOFGREN, California 

JERRY MCNERNEY, California 

EDDIE BERNICE JOHNSON, Texas 
(III) 

C O N T E N T S 

October 13, 2011 

Page 

Witness List ............................................................................................................. 2 

Hearing Charter ...................................................................................................... 3 

Opening Statements 

Statement by Representative Andy Harris, Chairman, Subcommittee on Energy and Environment, Committee on Science, Space, and Technology, U.S. 

House of Representatives .................................................................................... 16 

Written Statement ............................................................................................ 17 

Statement by Representative Brad Miller, Ranking Minority Member, Subcommittee on Energy and Environment, Committee on Science, Space, and 

Technology, U.S. House of Representatives ....................................................... 18 

Written Statement ............................................................................................ 20 

Witnesses: 

Mr. Scott Klara, Deputy Director, National Energy Technology Laboratory 

Oral Statement ................................................................................................. 23 

Written Statement ............................................................................................ 25 

Ms. Janet Gellici, Chief Executive Officer, American Coal Council 

Oral Statement ................................................................................................. 37 

Written Statement ............................................................................................ 38 

Mr. Nick Akins, President, American Electric Power 

Oral Statement ................................................................................................. 44 

Written Statement ............................................................................................ 46 

Mr. David Foerter, Executive Director, Institute of Clean Air Companies 

Oral Statement ................................................................................................. 54 

Written Statement ............................................................................................ 57 

Mr. Stu Dalton, Senior Government Representative-Generation, Electric 

Power Research Institute 

Oral Statement ................................................................................................. 62 

Written Statement ............................................................................................ 63 

Appendix I: Answers to Post-Hearing Questions 

Mr. Scott Klara, Deputy Director, National Energy Technology Laboratory ..... 88 

Ms. Janet Gellici, Chief Executive Officer, American Coal Council .................... 107 

Mr. Nick Akins, President, American Electric Power .......................................... 110 

Mr. David Foerter, Executive Director, Institute of Clean Air Companies ........ 112 

Mr. Stu Dalton, Senior Government Representative-Generation, Electric 

Power Research Institute .................................................................................... 117 

(1) 

ADVANCING COAL RESEARCH AND 

DEVELOPMENT 

FOR A SECURE ENERGY FUTURE 

THURSDAY, OCTOBER 13, 2011 

HOUSE OF REPRESENTATIVES, SUBCOMMITTEE ON ENERGY AND ENVIRONMENT, COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY, Washington, DC. 

The Subcommittee met, pursuant to call, at 2:22 p.m., in Room 

2318 of the Rayburn House Office Building, Hon. Andy Harris 

[Chairman of the Subcommittee] presiding. 
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Chairman HARRIS. The Subcommittee on Energy and Environment will come to order. Good afternoon. Welcome to today’s hearing entitled, ‘‘Advancing Coal Research and Development for a Secure Energy Future.’’ In front of you are packets containing the 

written testimony, biographies, and truth in testimony disclosures 

for today’s witness panel. 

I now recognize myself for five minutes for an opening statement. 

I want to welcome everyone to this afternoon’s hearing on, ‘‘Advancing Coal Research and Development for a Secure Energy Future.’’ 

According to the Department of Energy, coal delivered 45 percent 

of America’s electricity supply in 2010, totaling 22 quadrillion 

BTUs of energy. This output is expected to grow an additional 25 

percent by 2035. Dependence on coal is similar outside the U.S., 

representing 40 percent of global electricity generation. 

Coal delivers plentiful, affordable, and reliable electricity to millions of homes and businesses every day. It provides power to the 

industrial and manufacturing sectors that drive our economic engine. Rarely, however, has a beneficial, life-improving resource 

upon which we depend so heavily been so maligned. 

Despite steadily improving efficiency and significantly cleaner 

processes, coal suffers from a reputation that leads many to think 

wrongly that we would be better off without it. 

This animus seems to be at an all-time high. In recent weeks, 

this Committee has spent considerable time examining the pending 

onslaught of regulations aimed at energy producers but particularly at coal energy producers. The review has highlighted the immense challenges facing the coal sector in light of EPA’s dogged 

and scientifically questionable efforts to order major changes to our 

electric generation system. 

The widespread negative impact of EPA’s forthcoming regulations are acknowledged even at senior levels of the Obama Administration. An analysis by the Federal Energy Regulatory Commission found that 40 gigawatts of coal-fired power generation could 

be forced into retirement, and that ‘‘could have drastic consequences for many parts of the country.’’ Similarly, DOE Deputy 

Assistant Secretary for Fossil Energy Jim Wood has estimated that 

EPA rules could force up to 70 gigawatts of coal offline, adding: 

‘‘Number one, electric rates are going to go up. Number two, 

whether or not construction jobs in the green industry are created, 

I think there are virtually no manufacturing jobs that are likely to 

be created from the replacement of coal. Three, transmission grid 

stability is likely to emerge as a major issue, both because of the 

shutdowns and because of the intermittency of renewables.’’ 

The impact of Administration policies on electricity prices and 

coal plant shutdowns should come as no surprise. On the campaign 

trail in 2008, then candidate Obama said openly and clearly that 

his regulatory regime would bankrupt coal companies and necessarily cause electricity prices to skyrocket. 

Fortunately, the President’s wildly expensive vision for cap and 

trade was also wildly unpopular with the American people and, in 

fact, soundly rejected by Congress. 

These concurrent events, the death of cap and trade and EPA’s 

bonanza of new air regulations, beg the fundamental question be-
17 

fore us at today’s hearing. Does it make sense for DOE to continue 

to focus its $400 million R&D effort almost exclusively on carbon 

capture and sequestration, particularly in light of the need for and 

potential of advanced technologies to significantly increase coal utilization efficiency and thus benefit the environment? 

This exclusive focus certainly doesn’t make sense to me. Considering that DOE’s goal is to find carbon capture and sequestration 

technology that ‘‘only’’ increases electricity costs by 30 percent, I 

have to question whether we should be investing taxpayer dollars 

on a technology that likely never will be commercially viable in the 

absence of carbon constraints that Congress has already rejected. 

Perhaps instead of exclusively pursuing what appears to be an expensive and inefficient technology, we could facilitate the development of technologies with greater thermal efficiency that could 

achieve lower pollutant emissions. 

To this end, I look forward to hearing witness recommendations 

on potential coal technology R&D opportunities that are not currently being addressed by DOE and how best to prioritize those opportunities within the current budget environment. I also hope to 

learn more about the status of, outlook for, and lessons learned 

from the $3.4 billion in Stimulus-funded coal sequestration, CO2 sequestration demonstration projects. 

I now yield back the balance of my time and recognize Mr. Miller 

for his opening statement. 

[The prepared statement of Mr. Harris follows:] 

PREPARED STATEMENT OF CHAIRMAN ANDY HARRIS

I want to welcome everyone to this afternoon’s hearing on Advancing Coal Research and Development for a Secure Energy Future. 

According to the Department of Energy, coal delivered 45 percent of America’s 

electricity supply in 2010, totaling 22 quadrillion BTUs (‘‘quads’’) of energy. This 

output is expected to grow an additional 25 percent by 2035. Dependence on coal 

is similar outside the U.S., representing 40 percent of global electricity generation. 

Coal delivers plentiful, affordable, and reliable electricity to millions of homes and 

businesses every day. It provides power to the industrial and manufacturing sectors 

that drive our economic engine. Rarely, however, has a beneficial, life-improving resource upon which we depend so heavily been so maligned. 

Despite steadily improving efficiency and significantly cleaner processes, coal suffers from a reputation that leads many to think—wrongly—that we’d be better off 

without it. 

This animus seems to be at an all-time high. In recent weeks, this Committee has 

spent considerable time examining the pending onslaught of regulations aimed at 

energy producers. The review has highlighted the immense challenges facing the 

coal sector in light of EPA’s dogged—and scientifically questionable—efforts to order 

major changes to the electric generation system. 

The widespread negative impact of EPA’s forthcoming regulations are acknowledged even at senior levels of the Obama Administration. An analysis by the Federal Energy Regulatory Commission (FERC) found that 40 gigawatts of coal-fired 

power generation could be forced into retirement, and that ‘‘could have drastic consequences for many parts of the country.’’ Similarly, DOE Deputy Assistant Secretary for Fossil Energy Jim Wood has estimated that EPA rules could force up to 

70 gigawatts of coal offline, adding: 

‘‘Number one, electric rates are going to go up. Number two, whether or not construction jobs in the green industry are created, I think there are virtually no 

manufacturing jobs that are likely to be created from the replacement of coal. 

Three . . . transmission grid stability is likely to emerge as a major issue, both 

because of the shutdowns and because of the intermittency of renewables.’’ 

The impact of Administration policies on electricity prices and coal plant shutdowns should come as no surprise. On the campaign trail in 2008, President Obama 
18 

said openly and clearly that his regulatory regime would bankrupt coal companies 

and necessarily cause electricity prices to skyrocket. 

Fortunately, the President’s wildly expensive vision for cap-and-trade was also 

wildly unpopular with the American people, and soundly rejected by Congress. 

These concurrent events—the death of cap and trade and EPA’s bonanza of new 

air regulations—beg the fundamental question before us at today’s hearing: does it 

make sense for DOE to continue focusing its $400 million coal R&D effort almost 

exclusively on carbon capture and sequestration (CCS), particularly in light of the 

need for, and potential of, advanced technologies to significantly increase coal utilization efficiency and benefit the environment? 

This exclusive focus certainly doesn’t make sense to me. Considering that DOE’s 

goal is to find CCS technology that ‘‘only’’ increases electricity costs by 30 percent, 

I have to question whether we should be investing taxpayer dollars on a technology 

that likely never will be commercially viable in the absence of carbon constraints 

that Congress has already rejected. Perhaps instead of exclusively pursuing what 

appears to be an expensive and inefficient technology, we could facilitate the development of technologies with greater thermal efficiency that could achieve lower pollutant emissions. 

To this end, I look forward to hearing witness recommendations on potential coal 

technology R&D opportunities that are not currently being addressed by DOE, and 

how best to prioritize those opportunities within the current budget environment. 

I also hope to learn more about the status of, outlook for, and lessons learned from 

the $3.4 billion in Stimulus-funded CCS demonstration projects. 

I yield back the balance of my time and recognize Mr. Miller for his opening statement. 

Mr. MILLER. Thank you, Mr. Chairman. In this Congress, my colleagues on the other side of the aisle pound the drum on a handful 

of themes they believe are consistent with conservative dogma expressed in phrases like ‘‘regulation kills jobs,’’ ‘‘climate change is an 

unproven theory,’’ ‘‘government shouldn’t pick winners and losers.’’ 

But, just repeating something over and over does not really make 

it true. This hearing gives us an opportunity to put a finer point 

on those issues. 

First, to have a stronger economy we do not have to sacrifice 

cleaner air and a healthier and more productive workforce. We will 

hear from Mr. Foerter—is that a correct pronunciation—okay—the 

often-ignored perspective from the side of the power industry that 

designs, manufactures, and installs pollution control equipment. 

Second, when it comes to DOE programs on emerging clean energy technology: solar, geothermal, electric vehicle, batteries, smart 

grid, efficient technologies, bio-based fuels, and all the things that 

may one day make for a cleaner and more sustainable energy economy, my Republican colleagues do not hesitate to cry foul at any 

federal support that they consider to be an inappropriate government intrusion into the energy marketplace. To them these are mature industries in which free market forces alone should push the 

frontiers of innovation, and the Department of Energy investments 

in research just crowd out what the private sector would otherwise 

do. 

They say it is not the job of government to pick winners and losers, and they say that government should never pick winners and 

losers except sometimes. New renewable and efficient technologies 

do not warrant government support, they say, but conventional energy industries do. When it comes to the most established and powerful industries in the world, the same free market principles that 

my colleagues relentlessly espouse apparently have no place. 

More important I have some issues or some questions about the 

manner in which this Committee conducts its hearings. We—the 

reason we do these hearings, we have legislative hearings, is to de-
19 

velop a factual record to support the decisions that Congress has 

to make, and we need reliable, factual information. 

Last week my colleagues on the other side of the aisle accused 

me of behaving inappropriately when I asked a witness about his 

financial interests, the extent to which his income was derived 

from the industry whose interests were at the center of that hearing. 

I ask those questions because that is the kind of information that 

is necessary to evaluate anyone’s testimony. I think legislators 

should take a cue from the courts that have for centuries recognized the importance of that information in evaluating a witness’s 

testimony. The questions I asked were fundamental to our legal 

system, the federal rules of civil procedure required that expert 

witnesses disclose any compensation they get for their testimony 

not just in court but outside of court. Those rules and principles 

are in place because that information about financial interest is relevant and essential to evaluating testimony and reaching a sound 

decision. 

Mr. Chairman, it is not accusing a witness of lying to say they 

had a financial interest, but it may create a bias. It may color how 

they see the world, how they see the facts, and we are entitled to 

know that. We are entitled to know that as Congress, and the 

American people are entitled to know that, and this is an issue 

that I have raised from the first meeting of this Committee. I 

raised questions about the financial disclosure form, the truth in 

testimony form, and whether that adequately discloses financial interest. Chairman Hall assured me then that he would work with 

me. Mr. Rohrabacher, a Member of this Subcommittee, said that I 

could use my five minutes of questioning to raise those issues, and 

I said I would rather use my five minutes to ask about the substance of witnesses’ testimony, not about their financial interest. 

I later wrote a letter along with Ms. Edwards to Chairman Hall 

about working with us on financial disclosures, and he wrote back 

and said that upon reflection he decided that the disclosures were 

perfectly fine, but I could use my five minutes to ask about those 

financial interests. And then last week I did, and leading the attack were Mr. Rohrabacher and Mr. Hall, Chairman Hall, the very 

Members who had said I should use my five minutes to inquire 

about witnesses’ financial interest. 

I do not plan today to ask those questions orally in my five minutes, but I will submit questions for the record, written questions 

afterwards, and in future hearings I may well ask questions about 

financial interests in my five minutes orally, but I intend to make 

it my practice to ask those questions after the hearing in questions 

for the record. 

And with that I yield back my time. It was one second when I 

said that. 

[The prepared statement of Mr. Miller follows:] 
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PREPARED STATEMENT OF RANKING MEMBER BRAD MILLER
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Chairman HARRIS. Thank you very much, Mr. Miller. I will just 

urge you to take a look at the witness list, and it is not hard to 

figure out that if someone is the president of American Electric 

Power, they are probably employed by them, and if someone is 

from the American Coal Council which represents coal producing 

companies, they are probably employed by them. 

So with regards to this particular—— 

Mr. MILLER. And—— 

Chairman HARRIS. Excuse me. With regards to this particular 

panel I think it is pretty clear. 

Mr. MILLER. Perhaps with respect to this panel and that is why 

I don’t plan to ask questions, but we earlier had a witness who listed his occupation as a professor at the University of Houston. Upon 

questioning, his salary at the University of Houston is $1 a year, 

and he makes $1 million a year as a consultant to the very industries whose interests were at issue in that hearing. 

Chairman HARRIS. And again, I don’t know about the past. This 

panel it is pretty clear, and you know, as a physician, you know, 

if somebody wants to know about obstetric anesthesia, they are 

going to have to get someone, you know, they might consult with 

me because you have to go to someone who actually does it to be 

an expert on it as you can imagine. So a lot of times it is pretty 

transparent, and I think it is pretty transparent today. 

But if you have any questions about that, of course, please submit them, and thank you. 

If there are Members who wish to submit additional opening 

statements, your statements will be added to the record at this 

point. 

At this time I would like to introduce our witness panel. Our 

first witness is Mr. Scott Klara, Deputy Director of the National 

Energy Technology Laboratory. Mr. Klara has over 25 years of engineering and management experience that spans a broad spectrum of technology areas including electric power generation, advanced separation processes, coal conversion processes, and simulation systems analysis. 

Our second witness will be Ms. Janet Gellici, Chief Executive Officer of the American Coal Council. Prior to her work with the ACC 

she served as Communications Director of the Colorado School of 

Mines Management Institute and is Public Information Director of 

the Western Governors’ Association. 

Our third witness will be Mr. Nick Akins, President of American 

Electric Power. From 2006 to 2010, he was Executive Vice President for generation responsible for all generation activities of AEP’s 

approximately 40,000 megawatts of Generation resources. Previously he was President and Chief Operating Officer for Southwestern Electric Power Company, serving 439,000 customers in 

Louisiana, Arkansas, and Northeast Texas. 

Next we have Mr. David Foerter, Executive Director, Institute of 

Clean Air Companies. He has several decades of experience advising the public and private sector on environmental legislation, policy, rules, and technology issues with a focus on air pollution control for stationary and mobile sources. He is also currently a member of EPA’s Clean Air Act Advisory Committee and the Deputy of 
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Commerce’s Environmental Technologies Trade Advisory Committee. 

And our final witness today will be Mr. Stu Dalton, Senior Government Representative for Generation of the Electric Power Research Institute. He joined EPRI in 1976, focusing on SO2 control 

and later led this area for 20 years, additionally working on integrated emission controls for NOx, mercury, and particulates. Before 

joining EPRI Mr. Dalton worked at Pacific Gas Electric evaluating 

new generation options, coal gasification and conventional coal, 

refuse biomass firing, and NOx control refits—retrofits. 

Thank you all for appearing before the subcommittee today. As 

our witnesses should know, spoken testimony is limited to five minutes each, after which Members of the Committee will have five 

minutes each to ask questions, but we do have your complete written testimony in front of us. 

With that I now recognize our first witness, Mr. Scott Klara, 

Deputy Director of the National Energy Technology Laboratory. 

STATEMENT OF MR. SCOTT KLARA, DEPUTY DIRECTOR, 

NATIONAL ENERGY TECHNOLOGY LABORATORY 

Mr. KLARA. Thank you, Chairman Harris and Members of the 

Subcommittee. I appreciate the opportunity to discuss the Department of Energy’s coal research and development activities. 

DOE continues to play a leadership role in the development of 

clean coal technologies. The Clean Coal Research Program is designed to enhance our energy security and reduce environmental 

concerns over the future use of coal by developing a portfolio of revolutionary clean coal technologies. 

The Clean Coal Program in partnership with the private sector 

is focusing—focused on maximizing efficiency in environmental performance while minimizing the cost of these new technologies. In 

recent years the program has been restructured to focus on clean 

coal technologies with carbon capture and storage. The program 

pursues the following two strategies. The first strategy is capturing 

and storing greenhouse gases, while the second strategy is improving the efficiency of fossil energy systems. 

The first strategy aims to eliminate the concerns over the emissions of greenhouse gases from fossil-fueled energy systems. The 

second strategy seeks to improve the fuel-to-energy efficiency of 

these systems, thus reducing the pollutant emissions, water usage, 

and carbon emissions on a per-unit energy basis. Collectively, these 

two strategies form the Clean Coal Program within the Department of Energy. 

More specifically, the Clean Coal Program is addressing the key 

technical challenges that confront the development and deployment 

of these technologies through research on such things as cost-effective capture technologies, monitoring verification and accounting 

technologies to ensure permanent storage, permitting issues, and 

the development of advanced energy system. Research is focused on 

technology options, for example, that dramatically lower the cost of 

capturing carbon dioxide from these fossil-fueled energy systems. 

This research can be categorized into three pathways: what we call 

post-combustion, which is pretty much standard PC technology, 
24 

pre-combustion, which is emerging gasification technology, and oxycombustion. 

Another facet of the Clean Coal Program is the regional carbon 

sequestration partnerships that were created in 2003. The partnerships were designed to address a range of issues associated with 

the geologic storage of carbon dioxide. The Clean Coal Program has 

been performing capture and storage field tests focused on things 

like monitoring verification, accounting, and other aspects of geologic storage for many years. And the seven regional carbon sequestration partnerships are critical to this effort. These partnerships 

represent more than 400 unique organizations in 43 states and four 

Canadian provinces. Together the partnerships form a network of 

capability, knowledge, and infrastructure that we believe will help 

enable geologic storage technology to play a role in future energy 

strategies. 

These partnerships represent regions encompassing 97 percent of 

coal-fired CO2 emissions, 97 percent of industrial CO2 emissions, 96 

percent of the total land mass of the United States, and essentially 

all the geologic storage sites which could be potentially available 

for geologic storage. 

The success of the Coal Program also hinges upon whether these 

technologies get deployed, and what we use for that is we—the 

Clean Coal Program relies on commercial scale demonstrations to 

help industry understand and overcome technology issues such as 

start up, component integration, early learning, commercial experience, et cetera, and some of the panelists here have experience 

working with us in these various programs. 

Another aspect, important aspect of the Clean Coal Program is 

what we call CO2 utilization. The program recognizes that technologies such as mineralization, chemical conversion to useful products, algae production, enhanced oil recovery, and enhanced coalbed methane recovery could play an important role in pushing the 

technologies forward. 

Other than enhanced oil recovery, the CO2 reduction potential of 

these technologies is often limited due to such factors as cost and 

market saturation of salable byproducts, but even so these approaches are logical first-entry candidates for validating this 

emerging technology. 

So in conclusion, today nearly three out of every four coal-burning power plant in this country is equipped with technologies that 

can trace its roots back to the DOE Program. For example, NOX

control, SOX control, particulate matter control and mercury control as we go forward. These efforts helped accelerate the production of these cost-effective compliance options to address these legacy environmental issues associated with coal use. 

Additionally, as I mentioned, these utilization technologies are 

logical first market entry candidates to help get the technology 

commercially ready. Enhanced oil recovery particularly of the CO2

utilization options will be the dominant option into the near future 

and has a lot of potential as I have indicated in my testimony. 

I applaud the efforts of this Committee and the Members to take 

on these important industry—these important issues and look forward to responding to questions when we get to the Q and A. 

Thank you. 
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[The prepared statement of Mr. Klara follows:] 

PREPARED STATEMENT OF MR. SCOTT KLARA, DEPUTY DIRECTOR, NATIONAL ENERGY

TECHNOLOGY LABORATORY
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Chairman HARRIS. Thank you very much, Mr. Klara. 

I now recognize our second witness, Ms. Janet Gellici, Chief Executive Officer of American Coal Council, and I just ask you to take 

just 15 seconds to describe the American Coal Council so that Mr. 

Miller understands where you are coming from. 

Ms. GELLICI. Sure. 

Chairman HARRIS. Thank you. 

STATEMENT OF MS. JANET GELLICI, CHIEF EXECUTIVE 

OFFICER, AMERICAN COAL COUNCIL 

Ms. GELLICI. Thank you. My name is Janet Gellici. I am CEO of 

the American Coal Council. The ACC represents coal industry interests from the hole in the ground to the plug in the wall, so we 

represent companies that include coal producers, transporters, and 

consumers of coal. 

I would like to frame my remarks today based on two facts. First, 

we have more coal in the United States than any other country in 

the world, which means we have access to a 200-year supply of affordable, reliable domestic energy. 

Second, we have some of the most admirable and lofty environmental goals of any nation on this planet. There are two facts here. 

They are not at odds. It is not a matter of picking one over the 

other. What we need is to bridge these two facts, and that bridge 

is technology. Other nations are investing heavily in building 

cleaner coal plants and in increasing their use of coal resources. 

Here in the United States 44 percent of our electricity comes from 

coal, but rather than upgrading existing plants or building new 

clean ones, U.S. utilities are planning to shut down their coal 

plants. 

Projected retirements are now on the order of 50 to 100 

gigawatts, representing 15 to 30 percent of our current coal generation. These retirements are due in large part to an inability to meet 

environmental regulatory requirements. They will likely result in 

higher costs to consumers and manufacturers and the potential to 

lead to generation shortfalls. 

So we are imposing more environmental regulations on coal consumers, but we seem unwilling to commit the resources needed to 

actually achieve those objectives. There is an interesting conundrum going on here. Over the past few years our efforts to enact 

environmental regulations have actually been hampered by the 

lack of viable technology. The development and commercialization 

of technologies will actually help us facilitate environmental rulemaking. 

You know, if we were to set down rules for our kids and did not 

provide them with the time, training, and tools to follow those 

rules, we would be called bad parents. Imposing regulatory objectives without providing the time, training, and technologies to meet 

them is just bad governance. 

The good news is that we do have a history of success in meeting 

environmental objectives through RD&D efforts. We have installed 

advanced emission controls on 75 percent of U.S. coal plants and 

achieved an average of 90 percent reduction in criteria pollutant 

emissions. The National Academy of Sciences reports that feder-
38 

ally-funded RD&D provides a public benefit that well exceeds the 

cost of RD&D, including much needed job creation. 

We need to focus our RD&D coal efforts going forward in four 

areas: advanced energy systems, carbon capture and storage, water 

use technologies, and demonstration projects. I have addressed 

these in detail in my written testimony but would like to highlight 

a few points. 

Advanced energy systems can increase the thermal efficiency of 

power plants from today’s average of 33 percent up to 40 percent 

or more, and with each two percent increase in efficiency we can 

reduce the cost—we can reduce fuel use and CO2 emissions by five 

percent. So more R&D will obviously advance technologies that can 

help us achieve these levels of efficiency in environmental gains, 

and this can be done both at existing plants and at new power 

plants. In fact, I believe we can extend the life of our current lowcost power plants in ways that are economic and environmentally 

sound. 

One way to do that is through the use of engineered coal fuels. 

These are technologies that can be applied prior to combustion that 

clean coal. They help remove pollutants, and they improve the heat 

rate of coal so we don’t have to burn as much. 

Now, I understand that given the uncertainty in Congress right 

now that there will be any climate legislation passed in the near 

future, it might be tempting to curtail funding for carbon capture 

and storage. The reality is that while greenhouse gas legislation 

may not be eminent, greenhouse gas regulation is proceeding, and 

we need the technologies to meet those long-term needs. 

To be successful RD&D funding needs to be stable and consistent. Curtailing CCS program technologies could have potentially negative gains, could negate the gains that we have had up 

to this point in time. 

I get at least three to four calls a month from inventors and entrepreneurs who think they have the be-all solution to reducing 

CO2 emissions and coal plant emissions, and I don’t know where 

to send these people. I suggest they go to DOE or NETL, and they 

tell me they have already done that. There is no interest there, 

there is no money, and they are probably not all viable technologies, but I often hang up the phone wondering if I have just 

hung up the phone on the next inventor of penicillin for the global 

warming issues. 

So we have a lot of coal, we have admirable environmental goals, 

and I think we have a lot of innovators out there ready to shine. 

I don’t think the responsibility for effective regulation ends once we 

publish the rule in the Federal Register. 

So I look forward to your questions. 

[The prepared statement of Ms. Gellici follows:] 

PREPARED STATEMENT OF MS. JANET GELLICI, CHIEF EXECUTIVE OFFICER, AMERICAN

COAL COUNCIL

Introduction 

This statement is submitted on behalf of the American Coal Council (ACC), a 

trade association dedicated to advancing the development and utilization of American coal as an economic, abundant, secure and environmentally sound fuel source. 

The ACC (www.americancoalcouncil.org) represents the interests of 170 U.S. coal 

suppliers, coal consumers and coal transportation companies. We represent the coal 
39 

1 U.S. Energy Information Administration, Annual Energy Outlook 2011. 

2 Eugene M. Trisko, Esq. for American Coalition for Clean Coal Electricity, January 2011. 3Shively & Ferrare 2008 Enerdynamics. 

4 Energy Ventures Analysis, ‘‘Employment Impacts Associated with Electric Generation Options’’ for National Mining Association, September 2011. 6 Cloud Peak Energy presentation, ACC Coal Market Strategies Conference, August 23, 2011 

& Fitch Ratings, U.S. Coal Producers Outlook, August 17, 2011. 

industry from the hole in the ground to the plug in the wall. The ACC welcomes 

the opportunity to present a perspective on how to advance coal research and development to ensure our nation’s energy needs are met in an economic and environmentally sound manner. 

Coal is Vital to U.S. Economy 

Our nation’s domestic coal resources are critical to our economic well being, to ensuring our energy reliability and security, and to meeting our environmental goals. 

Today, coal generates nearly 44% of our nation’s electric power; 36 states obtain at 

least 25% of their electricity from coal and 26 states obtain at least 45% of their 

electricity from coal. The Energy Information Administration (EIA) forecasts that 

U.S. coal generation will increase by 25% between 2009 and 2035, with coal’s share 

of the total generation mix remaining steady at 43% in 2035. 1

U.S. coal provides low-cost electric power and price stability compared with other fuel resources. Between 2000 and 2009, natural gas prices ranged from $3.10/million 

Btu (mm Btu) to $12.41/mm Btu. During that same time period, coal never exceeded 

$2.28/mm Btu. Those states that rely on coal for a majority of their electric power 

are the states that have the lowest cost of electricity for their residents and industries. 

High energy costs disproportionately impact low income and fixed income families. In 2001, the 50% of U.S. households making less than $50,000/year spent an average of 12% of their after tax income on energy costs. Today, those families are now 

spending 20% of their household income on energy expenses. 2

Industrial consumers are more likely to be price responsive than any other customer group. There is a strong correlation between the cost of electricity and the 

number of manufacturing jobs in the United States. Between 2000 and 2008, industrial electric prices increased from 4.6 cents/kWh to 7.2 cents/kWh. Over that same 

time period, manufacturing jobs decreased from 17.3 million to 13.4 million. 3 Lowcost electricity directly contributes to the competitiveness of America in international markets. 

Studies show that new coal plants create more construction and permanent employment jobs than any other electric generation options. Coal jobs created per billion dollars invested equal 9,166, versus 7,640 for natural gas and 1,053 for wind 

generation. One recent study details the prospective loss of 1.24 million jobs as a 

result of new coal power plants NOT being built. The National Mining Association 

report details how the Sierra Club’s ‘‘Beyond Coal’’ campaign has targeted for destruction 116,872 permanent jobs and an additional 1.12 million construction jobs 

represented by the proposed power plants that have been prevented from being 

built. 4

The U.S. has 29% of the world’s recoverable coal reserves—more than any other 

nation. Our nation has a 200 year supply of coal at current annual production rates 

of about one billion tons. Globally, coal is the fastest growing fuel source. World coal 

consumption is projected to increase 50% from 139 quadrillion BTUs in 2008 to 209 

quadrillion BTUs in 2035. U.S. coal suppliers expect to take a greater role in international markets, welcoming the opportunity to contribute to improvements in our 

nation’s balance of trade. In 2010, U.S. coal exports were up 36%, from 60 million 

tons in 2009 to 81 million tons in 2010. The forecast for 2011 coal exports is in the 

range of 100-105 million tons. 6

The growing demand for clean energy technologies for the world’s emerging economies will also provide U.S. technology transfer and export opportunities if we are 

willing to invest now in clean coal technology research development and deployment 

(RD&D). While other nations are increasing their use of coal resources and their installation of clean coal power plants, U.S. utilities are shutting down their coal facilities. Currently, 23 GW of coal power generation is slated to be shuttered in the 

next decade. Projected retirements are on the order of 56-101 GW, representing 15- 

30% of current coal power generation capacity. These retirements are due primarily 

to an inability to meet environmental regulatory requirements at reasonable costs 

within acceptable rate structures, as well as to economic demand destruction, aging 

fleet attrition and competition from natural gas fuels. 

Meeting national environmental objectives continues to be coal’s greatest challenge, a challenge that has been in the past and can be in the future addressed with 
40 

7 ‘‘Benefits from Investments in Advanced Coal Technology,’’ Coal Utilization Research Council, National Mining Association, Edison Electric Institute, et. al. fact sheet attached hereto. 8 National Academy of Sciences, ‘‘Energy Research at DOE, Was It Worth It? Energy Efficiency and Fossil Energy Research 1978 to 2000.’’ 2001. 9 ‘‘Benefits of Investments in Clean Coal Technology’’ Management Information Services Inc., 

October 2009. Prepared on behalf of The American Coalition for Clean Coal Electricity. 10 ‘‘Benefits from Investments in Advanced Coal Technology’’– Fact Sheet Coal Utilization Research Council, et. al. 11 ‘‘Direct Federal Financial Interventions and Subsidizes in Energy in FY2010’’ U.S. Energy 

Information Administration, July 2011. 

technology applications. Significant progress has been made over the past 3-4 decades to reduce air emissions. Since 1970, coal use has increased 183% while criteria 

pollutant emissions have decreased 90% on average, including NOx reductions of 

82%, SO2 reductions of 88% and PM10 reductions of 96%. 7

The U.S. cannot achieve its economic, energy security and environmental objectives without coal and the advancement of clean coal technologies. 

Opportunities to Advance the Use of Coal 

The benefits of clean coal technology include cleaner air, reduced pollution, increased energy efficiency, support for U.S. manufacturing, increased U.S. exports, 

enhanced national security and job creation. The role of the Federal government in 

RD&D is to develop technology options that can benefit the public good. The U.S. 

Department of Energy’s Fossil Energy group carries out high-risk, high-value RD&D 

that can: 

• Accelerate the development of new energy technologies beyond the pace that 

would otherwise be dictated by normal market or regulatory forces. 

• Expand the slate of beneficial energy options beyond those likely to be developed by the private sector on its own. 

• Produce revolutionary ‘‘breakthrough’’ technologies that achieve environmental, 

efficiency and/or cost goals well beyond those currently pursued by the private 

sector. 

Federally funded RD&D provides public benefits in excess of the cost of RD&D. 

A National Academy of Sciences report noted that the economic benefits in real dollars provided by Fossil Energy research between 1986 and 2000 equaled $7.4 billion 

versus an investment by DOE of $4.5 billion. 8 The study noted that 600,000 jobs 

were created in the U.S. power equipment industry, resulting from the more than 

700 patents awarded through the Fossil Energy research program. Between 2000 

and 2020, investments in coal RD&D are expected to create nearly 1.2 million jobs, 

with an average of 60,000 jobs created on an annual basis. 9

DOE’s clean coal technology programs have resulted in over 30 successfully completed projects; more than 20 of the technologies have achieved commercial success, 

including the installation of advanced pollution controls on 75% of U.S. coal plants 

at one-half to one-tenth the cost of older systems. A detailed overview of DOE Fossil 

Energy RD&D technology achievements since the 1970s is attached. 10

Given the success of the Fossil Energy RD&D program in terms of economic and 

environmental benefits realized, it is disturbing that investments in clean coal technology are not supported at levels commensurate with other energy resources. A recent study by the U.S. Energy Information Administration (EIA) estimated the 

value of federal support for direct expenditures, tax expenditures, R&D funding, and 

loans and loan guarantees for various energy resources. It noted that in FY2010, 

renewable energy resources, which produce less than 5% of U.S. power generation, 

received 45% of Federal electricity production incentives. Coal, which produced 46% 

of U.S. electricity in 2010, received just 10% of Federal electricity production incentives. 11

During the past several years, the primary focus of DOE’s coal RD&D program 

has been on Carbon Capture and Storage (CCS). The coal industry supports continued RD&D in this area. The U.S., however, faces additional energy and environmental challenges that would benefit from collaborative coal RD&D by the government and private sector. These challenges are more immediate than CCS. 

There needs to be a greater balance between support for CCS initiatives and those 

for other coal RD&D projects that can advance coal generation efficiency and enhance environmental compliance. 

Our environmental rulemaking and legislative efforts of the past few years have 

been hampered, in part, by the lack of economic, commercial and technologically viable solutions. Environmental regulations need to be supported by technologies that 

enable industry to meet target objectives in a timely and economic manner. The de-
41 

velopment of viable technologies will facilitate the establishment of regulations to 

help us achieve our environmental objectives. Regulations and technology development go hand in hand. 

It is counterproductive to decrease Federal investment in coal RD&D at a time 

when our nation needs low-cost electricity to support our citizens and industries, at 

a time when we need all available means to increase the competitiveness of America’s goods in the international marketplace and at a time when the security of domestic energy sources is a high priority. 

Current programs should be maintained and additional resources appropriated to 

ensure utility and industrial compliance with both an increasing number of environmental regulations and increasingly strict targets for environmental objectives. We 

continue to impose more environmental regulations on coal consumers but seem unwilling to commit more resources to actually achieving those objectives. This is akin 

to setting ground rules for our children but not providing them with the tools and 

training to be able to obey the rules we set. 

Why are we so amazed that coal generators are shutting down their power plants 

because they can’t meet environmental objectives? Why are some folks gleeful about 

that? Where is the satisfaction in having our nation’s largest electric power providers shut their doors, stop producing low-cost electricity, fire their employees, and 

still not reach our environmental objectives? 

There can be only one conclusion—that the real objective is not to reduce emissions—that we are really not concerned with meeting environmental objectives. It 

would appear that other agendas are in play here, agendas to eliminate coal generation from our energy portfolio simply because it is based on coal. 

DOE’s recently released Quadrennial Technology Review (QTR) notes that the 

U.S. needs to be a leader in the development of a clean energy economy and that 

‘‘our challenge is to provide electric power in environmentally responsible ways that 

strengthen U.S. competitiveness and protect the climate.’’ These objectives can 

clearly be met through the use of our nation’s vast domestic coal resources in conjunction with the advancement of clean coal technologies. 

DOE has a proven track record of facilitating the development of clean coal technologies that are cost-effectively reducing emissions today and hold much promise 

for continuing to yield similar stellar results in the future. Going forward, we need 

to focus our RD&D efforts on: 

• Carbon Capture and Storage 

• Advanced Energy Systems 

• Engineered Coal Fuels 

• Water Use Technologies 

• Clean Coal Power Initiative Demonstration Projects 

Coal RD&D Priorities 

From an historical perspective, DOE’s early clean coal technology programs focused on advancing technologies that would achieve reductions in criteria pollutants 

regulated under the Clean Air Act (CAA) and Clean Air Act Amendments (CAAA), 

including SO2, NOx and particulate matter. Following many years of RD&D, much 

success was achieved in reducing these emissions. 

We should keep in mind that it was only a few short years ago when the pendulum of DOE funding swung toward advancing carbon management technologies. 

This was in response to the anticipation of legislation and regulations for greenhouse gas (GHG) management and to the increasing international focus on reducing 

CO2. GHG regulations are proceeding and so should these technology development 

efforts—even though U.S. GHG legislation is not imminent. 

It takes substantial time to develop and deploy new technologies—on the order 

of 10–20 years. We should anticipate a continued need for CO2 management technologies and stay the course. It is difficult to turn technology development initiatives off and on and still make cost-effective progress. If we shutter CCS or the 

Clean Coal Power Initiative (CCPI) efforts today and decide in a few years to resurrect them, we will be faced with the prospect of starting all over again at ground 

zero, negating any earlier gains. 

To be successful, RD&D funding needs to be stable and continuous. A funding 

interruption or extreme swings of the funding pendulum are an inefficient use of 

Federal funds. 

We should avoid the knee jerk impulse to pull back CCS technology development 

efforts as we refocus on addressing more near-term regulations for energy efficiency 

improvements and compliance with stricter criteria emissions targets. We should 

also keep in mind that CCS stands for ‘‘carbon capture and storage’’ not ‘‘coal cap-
42 

12 Richard F. Storm, ‘‘What can be done to improve the Thermal Performance of the existing 

coal fleet?’’, EPRI Heat Rate Conference, January 2011. 

ture and storage.’’ Development of CCS technologies is not a coal-only program. Our 

fossil energy colleagues in the natural gas industry will ultimately benefit from CCS 

developments as well. 

Carbon Capture & Storage Priorities – Given the current uncertainty that Congress will pass climate legislation in the near term, it would seem easy to dismiss 

RD&D funding for CCS. In reality, however, the U.S. EPA is regulating GHG emissions and industry is currently being tasked with meeting compliance objectives for 

CO2 reduction. It is, therefore, imperative that RD&D funding support continue. A 

‘‘no regrets’’ approach to advancing technologies for carbon capture, carbon storage 

and carbon utilization today, will ensure that industry can meet current EPA regulations as well as prospective future legislation. 

This longer-term technology need must, however, be balanced with RD&D funds 

to pursue more immediate and near-term environmental objectives with advanced 

energy technologies. While much work has been done in this area and ASTM code 

certification is certainly needed to advance commercialization, there still remains 

opportunities for advances in monitoring and control technologies for advance combustion systems. These technologies can help us produce coal-based electricity more 

cleanly and more cost effectively. They also have the added collateral benefit of reducing CO2 when integrated with CCS applications. Additionally, there may be 

broader applications for high-temperature, high-pressure materials outside of coal 

generation, e.g., in the aircraft industry. 

Advanced Energy Systems Priorities– Advanced technologies are needed to enhance the thermal efficiency of power plants, which today operate at an average efficiency of about 33%. Power engineers can replace our aging coal plants with new 

clean plants exceeding 40% thermal efficiency. This can be achieved in two ways: 

1. Advances in energy systems for new plants including: 

• The development and application of high-pressure, high-temperature materials in boilers and steam turbines for new supercritical and ultra-supercritical power plants. These high performance materials would enhance the efficiency of power plants and reduce emissions of criteria pollutants and GHG 

emissions. 

• Oxy-firing systems that replace combustion air in coal power plants with 

pure oxygen to greatly reduce emissions. 

• Integrated Gasification Combined Cycle (IGCC) systems which advance efforts to capture carbon. 

• Advanced turbine systems that can enhance plant efficiency and help meet 

the demands of IGCC plants with high levels of CO2 capture. 

• Fuel conversion systems that facilitate the production of liquid transportation fuels from coal and biomass. 

2. Efficiency upgrades and heat rate improvements for both existing and new 

plants. New Source Review (NSR) constraints have curtailed efforts to achieve 

efficiency improvements. A leading combustion systems engineer, Richard 

Storm, PE, CEO, Storm Technologies notes that we can achieve a 3–5% efficiency improvement at existing plants by upgrading turbine rotors, installing 

new high capacity boiler feed pumps and higher efficiency air heaters and ductwork, and by upgrading boilers, condensers and feed water heaters. 12

Storm notes that operations and maintenance improvements could potentially increase heat rates up to 750 Btu/kWh and achieve fuel savings of $2 million or more. 

Payback on a $5 million investment would take two years. Capital projects that 

have a potential to trigger NSR are deemed by industry to be very risky. Better 

clarity, and potentially guarantees, are needed on what upgrades will not trigger 

NSR. 

Also of note is that capital investments to improve thermal efficiency often compete with non-optional investments for environmental compliance and other energy 

projects that offer high returns on investment. While not a direct DOE RD&D funding need consideration, these operations and maintenance improvements can provide interim compliance with environmental requirements as we work toward longer 

term solutions. Efficiency gains in the existing coal power generation fleet can offset 

significant amounts of CO2, setting a more achievable bar for us to overcome with 

advanced technologies. 

Engineered Coal Fuels Priorities– DOE’s National Energy Technology Laboratory 

(NETL) has noted that ‘‘ . . . increasing the average efficiency [of power plants] from 
43 

13 ‘‘Improving the Efficiency of Coal-fired Power Plants for Near Term Greenhouse Gas Emissions Reductions.’’ DOE/National Energy Technology Laboratory, April 16, 2010, DOE/NETL2010/1411. 

32.5% to 36% reduces U.S. greenhouse gases by 175 MMmt/year, or 2.5% of total 

U.S. GHG emissions in 2008.’’ 13 At NETL’s February 2010 Technical Workshop 

(‘‘Improving the Thermal Efficiency of Coal-fired Power Plants in the United 

States’’), industry and government representatives identified more than 50 opportunities to improve thermal efficiency. One of these opportunities included the ‘‘use 

of low-grade heat for coal drying’’—an example of numerous Engineered Coal Fuels 

technologies available or under development today to improve heat rate, advance 

power plant efficiency and reduce emissions with prior-to-combustion treatments of 

coal. 

Engineered Coal Fuels (ECF) provide an opportunity to extend the life of existing 

low-cost power plants in an economic, environmentally sound manner. Given the 

current state of our economy and waning competitive position in world markets, 

now is not the time to be shuttering low-cost power plants. As noted earlier, lowcost electricity supports domestic industries and manufacturing jobs, advances the 

competitiveness of the U.S. in international markets and provides for the well being 

of our nation’s citizens. 

ECFs treat and enhance coal prior to combustion, resulting in the following benefits: 

• Reduced Fuel Consumption – increasing energy content by 30% results in 

less coal used. 

• Decreased Emissions of Criteria Pollutants – reductions of SO2 (10–80%), 

NOx (10–50%) and mercury (15–99%). 

• GHG Reductions – increasing combustion efficiency by 2–4% results is a 5– 

10% reduction in CO2 emissions. 

• Increased Capacity – increased power output and improved heat rate enable 

higher capacity utilization and efficiency at the point of combustion. 

ECFs represent low capital cost investments for utility and industrial companies—an operations and maintenance expense versus an intensive capital investment. Stricter pending regulations on SO2, NOx, PM, mercury and HAPs are driving 

the need for some of these more near-term solutions. There is a vital role here for 

government to take assisting with the deployment of these technologies through 

testing and evaluation. This type of a role for government dovetails with the following recommendation from the QTR: 

‘‘The Department [of Energy] needs a professional group that can integrate the 

major functions of technology assessment and cost analysis, program planning 

and evaluation, economic impact assessments, industry studies, and energy 

and technology policy analysis.’’ 

A facility with the capability to test a broad range of temperature, pressures, coals 

and methods would provide an opportunity for companies that have developed advanced combustion systems and engineered coal fuels technologies to verify the benefits and economics of their solutions. It would provide an objective, third party 

evaluation that would benefit all stakeholders, including industry, policy makers 

and the environmental community. 

In the case of Engineered Coal Fuels, we should also undertake RD&D of coal/ 

biomass fuels that can be used in the existing coal generation fleet without significant power plant modification. DOE has committed to fund coal/biomass development of coal gasification applications. Extending the application to the existing coal 

fleet for purposes of advancing coal/biomass applications would provide a near-term 

solution to meeting environmental regulations. 

Water Priorities– Water RD&D is critical for all energy technologies, not just coal 

but nuclear, solar and natural gas as well. We need to devote RD&D funding into 

technologies that can help us reduce water consumption and increase reuse of water 

discharge. 

A sole focus on basic engineering research will not advance commercial technology 

to the marketplace. The CCPI demonstration program needs to be continued and 

adequately funded. Previous lack of funding for demonstration projects resulted in 

what has become well known as ‘‘The Valley of Doom’’—a future in which no new 

coal generation facilities are being planned to be built in the U.S. 

Clean Coal Power Initiative (CCPI) Priorities– The Administration has not requested funding for large-scale demonstration projects for three years now. Demonstration programs are critical for the commercialization of advanced coal, Engi-
44 

neered Coal Fuels and CCS technologies, including the FutureGen project which has 

received funding through the Recovery Act. 

DOE’s proposal to increase the use of computer modeling has benefits in terms 

of reducing the amount of time and money to develop, demonstrate and deploy new 

technologies. But at some point, we need to build something to see how it actually 

works in real life. Modeling cannot replace the value of practical demonstrations. 

Demonstration projects validate the reality of technology applications and confer a 

higher level of understanding, knowledge and acceptance of new technologies. Computational modeling should be supported only to the extent that it does not come 

at the expense of funding other RD&D and demonstration activities. Additionally, the $187 million rescinded from the AEP Mountaineer Project 

should be reallocated for future demonstration projects. 

Going forward, RD&D funding should focus on advancing higher efficiency technologies, reducing capital costs associated with these advanced technologies and increasing the commercial availability of technology solutions. These efforts will help 

us achieve greater reductions in criteria pollutants, as well as CO2 and other greenhouse gases. 

Appended Materials: 

• ‘‘Benefits from Investments in Advanced Coal Technology’’ – Fact Sheet 

Coal Utilization Research Council, et. al. http://www.coal.org/userfiles/file/ 

FINAL%20Benefits%20of%20Investment%20in%20Coal%20RD&D.pdf 

• ‘‘Retrofit Programs Increase Generation Efficiency and Decrease CO2

Emissions’’ – National Coal Council Fact Sheet. http:// 

www.nationalcoalcouncil.org/Documents/Advanced—Coal—Technologies.pdf 

• ‘‘Engineered Coal Fuels Fact Sheet’’ – American Coal Council http:// 

www.americancoalcouncil.org/associations/10586/files/pre-combustion—Apr— 

2011.pdf 

Chairman HARRIS. Thank you very much. 

I now recognize our third witness, Mr. Nick Akins, President of 

American Electric Power. 

STATEMENT OF MR. NICK AKINS, PRESIDENT, 

AMERICAN ELECTRIC POWER 

Mr. AKINS. Good afternoon, Chairman Harris, Ranking Member 

Miller, and distinguished Members of the Subcommittee on Energy 

and Environment. Thank you for inviting me here today and for 

this opportunity to offer the views of AEP on advancing research 

and development for a secure energy future. 

We applaud your efforts to examine DOE coal research and development activities to ensure that coal fuel generation remains an 

important part of this Nation’s energy mix. AEP has a long track 

record of accomplishments with the demonstration of cutting-edge 

technologies. 

In May of this year AEP successfully concluded a demonstration 

of the world’s first integrated CO2 capture and storage project at 

an existing coal-fired power plant using Alstom’s chilled ammonia 

process, a 20 megawatt scale carbon capture and storage project 

captured and permanently sequestered nearly 40,000 tons of CO2

in deep saline reservoirs from our Mountaineer Power Station in 

West Virginia. That was such an important accomplishment that 

AEP has hosted visitors in the thousands from every continent 

around the globe. 

AEP also teamed with DOE to demonstrate the same technologies at commercial scale. While funding challenges caused the 

project to be suspended following the first project phase, we now 

have the engineering design for a carbon capture and storage facility that includes extensive geologic characterization and a solid cost 
45 

estimate. Robust and affordable choices for CCS will not be available in the market if the technology is not demonstrated. We believe DOE should be bolstered in their efforts to develop viable and 

affordable technology solutions. 

AEP’s Turk Power Plant in Southwest Arkansas represents 

America’s first deployment of ultra-supercritical technology, a new 

high-efficiency design that uses less fuel to produce each megawatt 

hour of electricity. This plant will go commercial in mid 2012, and 

will result in a substantial performance improvement over today’s 

conventional sub-critical design. The Turk Plant’s efficiency is more 

than 11 percent greater than the typical sub-critical coal power 

plant. Other advanced technologies deployed at Turk will compound the benefits of higher efficiency resulting in significantly 

lower emissions. 

This is another case of advanced technology making coal usage 

cleaner and more efficient. AEP has also completed front end engineering designs for Integrated Gasification Combined Cycle, IGCC 

technologies, as well. 

The above examples illustrate that my company stands firmly behind technology advancement. The DOE has shown its effectiveness in advancing technology to commercial readiness, and AEP’s 

recent partnership with DOE resulted in meaningful and important 

knowledge. In fact, some of DOE’s project management processes 

have been so effective that AEP has adopted them on other major 

projects. This has truly been a collaborative relationship. 

Of greatest concern to me as I consider leading AEP through unprecedented challenges is the recent regulatory actions of the EPA. 

We strongly support the Clean Air Act and continued reduction 

emissions from our power plants, however, AEP believes that the 

current regulatory track being pursued by the EPA will have damaging impacts on the reliability of our Nation’s electric system as 

well as broad or negative employment and economic implications. 

Together CSAPR, the Utility MACT, Clean Air Visibility Rule, Coal 

Combustion Residuals Rule, and Cooling Water Intake Structures 

Rule will require very large capital investments on a timeline that 

can only be described as unrealistic. 

Among AEP’s most pressing concerns include infeasible compliance deadlines, unprecedented capital expenditures, abrupt and 

significant power plant retirements, electric grid reliability problems, and very high electricity rate increases. We believe that a 

more reasonable approach to energy and environmental policy is 

needed and is discussed in greater detail in my written testimony. 

DOE is in a unique position to be a part of the solution and 

should serve as a trusted advisor to the EPA in the rulemaking 

process. They have the well-informed authority to evaluate the 

electric power generation system and grid stability and security 

risks and can assess the timelines needed to deploy technology at 

the broad scale required under EPA’s Program. 

In summary, continued research, development, and demonstration must be supported and is essential to solving the complex 

problems of energy security, climate change, and environmental 

compliance. We must do more than simply call for it. Private industry must complete their commercial plant demonstrations, and our 

country must devote adequate financial and technological resources 
46 

to this enormous challenge. AEP is committed to being a part of 

this important process and helping achieve the best outcome at the 

most reasonable cost and timelines possible. 

Thank you again for this opportunity to share these views with 

you. 

[The prepared statement of Mr. Akins follows:] 

PREPARED STATEMENT OF MR. NICHOLAS K. AKINS, 

PRESIDENT, AMERICAN ELECTRIC POWER

Chairman Harris, Ranking Member Miller, and distinguished Members of the 

Subcommittee on Energy and Environment of the House Science, Space and Technology Committee, thank you for inviting me here today. I appreciate this opportunity to offer the views of American Electric Power (AEP) on advancing coal research and development for a secure energy future. 

My name is Nick Akins, and I am the President of American Electric Power. 

Headquartered in Columbus, Ohio, we are one of the nation’s largest electricity generators—with more than 38,000 megawatts (MW) of generating capacity—and serve 

more than five million retail consumers in 11 states in the Midwest and South Central regions of our nation. AEP’s generating fleet employs diverse fuel sources—including coal, nuclear, hydroelectric, natural gas, oil, and wind power. But of particular importance for the Committee Members here today, AEP is the largest consumer of coal in the United States and, as a result, our company is an industry 

leader in developing advanced coal-fueled electrical generation and emission reduction technologies, including carbon capture and storage (CCS) and ultra-supercritical pulverized coal (USCPC) technology. 

I am here today to discuss AEP’s experience with our CCS projects and the development of the USCPC technology through the construction of the J.W. Turk Plant. 

In addition, I will highlight the near term challenges to new technology development 

associated with the recently-announced EPA regulations. 

AEP’S LEADERSHIP IN TECHNOLOGY DEVELOPMENT 

AEP has a long and proud history as a leader in our industry for the development 

and deployment of new technologies. The first high- and extra-high voltage transmission lines at 345 kilovolt (kV) and 765 kV were developed by AEP and serve as 

the framework for our interstate transmission system. AEP was among the first to 

develop large central station power plants and to deploy more efficient supercritical 

generating technologies. AEP recently celebrated its centennial by reflecting on its 

century of firsts. 

Most recently, we have built upon this history of innovation by focusing our efforts on new clean coal technologies. These technologies will enable AEP and our 

industry to meet the challenge of reducing greenhouse gas emissions while optimizing the use of our nation’s plentiful indigenous coal resources. As concepts for 

effective CCS from coal-fueled facilities are being talked about and debated around 

the globe, AEP has been on the cutting edge with an aggressive plan to commercialize advanced CCS technology. With the announcement of its successful completion in May of this year, AEP demonstrated the world’s first integrated CO2 capture 

and storage project at an existing coal-fired power plant. Based on Alstom’s chilled 

ammonia process, a 20-MW-scale CCS product validation facility at our 1,300-megawatt Mountaineer Power Plant in New Haven, West Virginia permanently sequestered nearly 40,000 tonnes of CO2 in deep saline reservoirs located 1.5 miles beneath the surface. Just as we were winding down that enormously successful demonstration, AEP and DOE were in the final stages of a commercial-scale engineering 

study of the same technologies. As a result, we now have a robust front-end engineering design for a CCS facility that includes extensive geologic characterization 

and a solid cost estimate. 

In addition to CCS technology, construction currently is underway in southwest 

Arkansas on the 600-megawatt J.W. Turk Plant that will employ new ultra-supercritical coal-fired generating technology. Ultra-supercritical technology uses high 

steam pressure and temperature to increase operational efficiency. The Turk Plant 

represents a new generation of power plant design that uses less fuel to produce 

each megawatt hour of electricity. This means that all emissions, including sulfur 

dioxide (SO2), nitrogen oxides (NOx), mercury, and carbon dioxide (CO2), will be 

lower than conventional coal-combustion processes per unit of electricity produced. 
47 

Once operational, the Turk Plant will be the first commercial scale ultra-supercritical plant to operate in the United States. 

AEP also has pursued the development of Integrated Gasification Combined Cycle 

(IGCC) technology. IGCC represents a major breakthrough in efforts to improve the 

environmental performance of coal-based electric power generation. IGCC technology integrates two proven processes—coal gasification and combined cycle power 

generation—to convert coal into electricity more efficiently and cleanly than any existing uncontrolled power plant. IGCC also has the potential to be equipped with 

carbon capture technology at a lower capital cost and with less of an energy penalty 

than traditional power plant designs, but only after the carbon capture technology 

has been proven at a commercial scale. We still strongly endorse the advancement 

of this technology in the future. 

AEP’S EXPERIENCE WITH CCS AT MOUNTAINEER 

As noted previously, AEP recently completed a CCS validation project at our 

Mountaineer Power Plant using Alstom’s chilled ammonia process. This recently 

completed project treated approximately 20 MW, or 1.5 percent, of the total plant 

flue gas flow. The CCS validation project was privately funded by AEP and partners, started capturing CO2 in September 2009, and initiated CO2 injection in October 2009. The project was designed with the capability of capturing and storing approximately 100,000 metric tons of CO2 annually. Captured CO2 from the project 

was injected through two onsite wells into two geologic formations (Rose Run and 

Copper Ridge) located approximately 1.5 miles below the plant site. The project also 

included three deep wells for direct monitoring of geologic conditions and assessing 

the suitability of the geologic formations for future storage. Consistent with the Underground Injection Control (UIC) Class V Permit, AEP continues to monitor these 

wells. The project supplied data to support the design and engineering of the commercial-scale CCS demonstration at the Mountaineer facility and thereby has laid 

the technical groundwork to enable commercialization of complex technology. Without these demonstrations, there is no chance that CCS will become robust and commercially viable at a reasonable cost for end users of electric power. 

The CO2 capture system proposed for the Mountaineer commercial-scale demonstration project is similar to the Alstom chilled-ammonia system operated at the 

initial validation project, but at approximately 12 times the scale. As with the initial 

validation project, the process uses an ammonia-based reagent to capture CO2 and 

isolate it in a form suitable for geologic storage. The captured CO2 stream is cooled 

and compressed to a supercritical (liquid-like) state for pipeline transport to the injection well sites. The process is designed to remove approximately 90 percent of the 

CO2 from the 235 MW slipstream of flue gas. 

Subsurface geological investigations of the Mountaineer site and surrounding subregion were conducted during 2010–2011 and built on a large amount of work done 

at the site over the last eight years under two separate projects. First, from 2002 

to 2007, the DOE and others provided funding for Battelle to conduct detailed geologic characterization under the Ohio Valley CO2 Storage Project, which included a 

seismic survey and drilling of one well in 2003 followed by reservoir testing, modeling, and conceptual CO2 injection simulations. Second, AEP hired Battelle in 2007 

to construct the geologic sequestration systems for the 20 MW CCS validation 

project. This included completion of the original well and drilling of four new wells 

on the Plant site. Extensive evaluation of voluminous data from the projects along 

with the drilling of an additional characterization well some 2.5 miles south of the 

validation project site, indicate that the Copper Ridge Formation has significant reservoir storage potential. Additional injection potential has been identified in the 

Rose Run Sandstone and other zones. 

While the success of the Mountaineer Plant validation project proved that CCS 

is viable at a coal-fired power plant and also demonstrated that CO2 could be safely 

injected into deep saline reservoirs in that region, the commercial-scale demonstration has been put on hold. An agreement for DOE funding of the commercial-scale 

project was finalized in early 2010, allowing for a combination of DOE CCPI Round 

3 and American Recovery and Reinvestment Act of 2009 funds to provide 50 percent 

of the cost of the project up to $334 million. AEP was responsible for securing the 

other 50 percent of the cost. This seemed very plausible at the time of the grant 

application due to the House’s passage of the Waxman-Markey climate legislation 

and the Senate’s serious consideration of similar legislation at that time. Both bills, 

as well as other legislative proposals, contemplated significant economic incentives 

to develop CCS projects and a regulatory justification for approval by State Commissions. However, during the balance of 2010, as the U.S. economy remained sluggish 

and prospects for climate legislation dimmed, it became clear to AEP that cost re-
48 

covery for the expense of a CCS project would not be approved by state regulatory 

agencies. Therefore, AEP was unable to move forward with the commercial demonstration and has placed the project on hold. The agreement with DOE was terminated following the completion of project Phase 1 and plans to complete the project 

are on hold. 

Even though the Mountaineer commercial-scale project has been postponed, there 

is still enormous value in the efforts and investment by AEP and DOE. Prior to this 

project, much of what has been publically discussed and debated regarding performance and cost was based upon crude estimates and extrapolations from petro-chemical processes that, at best, bore no more than a simplistic resemblance to CCS on 

coal-fired power plants. Because of the work done through Phase 1 of the commercial-scale project, an engineering package has been developed specifically for a retrofit of post-combustion CO2 capture installation on a coal-fired power plant. Detailed process understanding and performance knowledge was collected from the 

validation project and applied at full-scale. Optimization of process elements and individual pieces of equipment has yielded a state-of-the-art design. As a result, we 

now have a robust front-end engineering package that includes extensive geologic 

characterization and a solid cost estimate. While certain aspects of the information 

gained through years of technology development at Mountaineer belong to Alstom 

as intellectual property, a wealth of knowledge has been publically disclosed at conferences and other venues, with even more to come through relationships with DOE, 

the Global CCS Institute, and others. Hundreds of tours and literally thousands of 

visitors have come through Mountaineer Plant over the past several years. Clearly 

this work has been recognized and appreciated on a global scale. 

AEP’s work on CCS is a critically vital step, but only the beginning of a long path 

toward broad deployment of CCS technology. AEP’s work has not yet produced a 

commercial scale demonstration of the technology for capturing and sequestering 

CO2 at an affordable cost. AEP’s work is merely the first of multiple steps in the 

maturation of a widely-deployable technology. Much like the power industry’s experiences with sulfur dioxide scrubbers in the 1970’s, much optimization remains to 

be done. With real demonstrations, brilliant minds working together will identify 

improvements and process optimizations that will eventually simplify designs, drive 

down costs, reduce energy consumption, and make the technology more affordable. 

Now is not the time to ease up on CCS development and demonstration efforts. On 

the contrary, the industry, with government support, must continue to march together down the path of progress. The DOE program of technology development and 

commercial-scale demonstration is critical to making this happen. DOE’s technology 

roadmap and planned demonstration projects are essential for commercial technology advancement. 

AEP’S EXPERIENCE WITH ULTRA-SUPERCRITICAL PULVERIZED COAL 

TECHNOLOGY 

The J.W. Turk Plant is a 600 megawatt (MW) net, ultra-supercritical unit designed to fire subbituminous coal. The Turk Plant cycle is classified as advanced 

coal generation technology primarily because of the use of an ultra-supercritical 

steam cycle. The ultra-supercritical cycle is a technology advancement of the supercritical steam cycle. The term ‘‘supercritical’’ steam cycle means that the water/ 

steam pressure used in this technology is above critical pressure of water (3,208.2 

psi). Water above the critical pressure does not boil, but makes a transition from 

the properties of liquid water directly to the properties of superheated steam. Superheated steam provides a higher efficiency heat transfer mechanism and serves to 

increase the overall efficiency of the steam cycle. While a supercritical plant cycle 

uses high pressure, it uses steam temperatures only as high as 1,050°F–1,080°F. 

The Turk Plant’s main steam temperature will be 1,110°F and its reheat steam temperature will be 1,125°F. These very high temperatures, coupled with operation at 

these high pressures, produce higher cycle efficiency, and thus the term ‘‘ultrasupercritical.’’ In addition, Turk uses advanced equipment design features, such as 

axial flow air and gas fans, pulse jet fabric filters, spray dryer absorber (SDA) technology, and a steam turbine driven boiler feed pump to drive down auxiliary loads 

(power used by plant equipment) which also improve the overall efficiency of the 

generating unit. 

AEP led the industry in the deployment of supercritical pulverized coal technology. The first commercial supercritical unit in the world was AEP’s Philo Unit 

6, built in 1957. Since then, AEP has constructed 20 supercritical units and is currently operating 18 supercritical units. These units range in size from 500 MW to 

1,300 MW, with a total generating capacity of over 17,000 megawatts. 

The advancement to ultra-supercritical has been made possible by recent ASMEapproved, cost-effective high temperature chrome and nickel-based alloys in the 
49 

steam generator, piping, and turbine systems. This development signals a degree of 

maturity which allows for minimal risk in deployment of this advance technology. 

The use of high steam temperatures and pressures at the Turk Plant will result 

in a steam cycle that is one of the most efficient in the industry. In addition, the 

use of high efficiency equipment allows the Turk Plant to have one of the lowest 

heat rates in the world. Turk’s full load higher heating value (HHV) net heat rate 

will be 8,992 Btu/kWh, which converts to an overall net efficiency of 38%, HHV. As 

reported by the DOE Energy Information Administration in January 2009, for 2007 

the industry average full load net heat rate is 10,114 Btu/kWh, HHV, or an average 

efficiency of 33.7%, HHV. The high efficiency of the Turk Plant results in very low 

emissions per megawatt hour, in comparison with those generating units with average efficiency rates. 

To give some perspective, the following is a comparison of Turk Plant’s ultrasupercritical benefits when compared with a same-sized unit using conventional 

subcritical technology, based on an 85% capacity factor, per year basis: 

• 180,000 tons less coal consumed (1,500 fewer coal train cars) 

• 1,600 tons less lime consumed 

• Reduction of 14,000 tons ash and FGD waste 

• 360 million gallons less water consumed 

• 320,000 tons less CO2 emitted 

• 150 tons less SO2 emitted 

• 100 tons less NOx emitted 

Achieving higher efficiency performance is limited by the available materials to 

handle extreme temperatures and pressures, and is also limited by approved methods for welding the materials. Simply put, there are no available materials or approved welding procedures in the U.S. that enable higher temperature steam cycles 

than those installed today at Turk Plant. 

The Turk Plant received regulatory approval in Arkansas, Louisiana, and Texas 

in 2007-2008. Construction of the plant began after AEP Southwestern Electric 

Power Company (SWEPCO) received the Clean Air Act construction permit in 2008. 

Since that time, SWEPCO has encountered some challenges to the various permits 

and regulatory approvals. 

Construction of the Turk Plant continues, with key milestones approaching that 

include the boiler hydro test, followed by the first combustion of coal to take place 

in late spring of next year. The first planned synchronization of the generator to 

the electric grid is planned for mid–2012. 

AEP’S PERSPECTIVE ON THE RECENT EPA REGULATIONS 

AEP strongly supports the Clean Air Act and continued reduction in emissions 

from our power plants. However, AEP believes that the current regulatory track 

being pursued by the Environmental Protection Agency (EPA) will have damaging 

impacts on the reliability of our nation’s electric system, as well as broader negative 

employment and economic implications. Together, the federal Cross-State Air Pollution Rule (CSAPR)—formerly known as the Transport Rule, the Utility Maximum 

Achievable Control Technology Rule (Utility MACT), the Clean Air Visibility Rule, 

the Coal Combustion Residuals Rule (CCR) as well as the Cooling Water Intake 

Structures Rule under section 316(b) of The Clean Water Act (316(b) rule) will require very large utility capital investments on a timeline that can only be described 

as unrealistic. CSAPR and the Utility MACT alone, according to EPA’s own estimates, will impose massive costs within the next 3 to 4 years, the vast majority of 

which will be borne by coal-fired generators and their customers. 

This follows two decades during which generators within these same areas have 

invested billions of dollars to achieve reductions of over 70 percent in emissions of 

both SO2 and NOx. Electricity rates in states where these investments have been 

made have already risen. For most coal-reliant states, the CSAPR will require additional substantial emission reductions starting in January of 2012. In several of 

these states, these represent reductions of more than 30 percent below actual emissions in 2010. Further even more substantial reductions are required in 2014, with 

Ohio, Pennsylvania, Indiana, Kentucky and Virginia required to make 60–76 percent reductions below 2010 actual levels. This is also the same year EPA proposes 

to make the Utility MACT effective for sources nationwide. There is simply not 

enough time to get regulatory approvals, design, permit, and construct scrubbers, 

SCRs or other major pollution control investments to achieve those levels of reductions. As a result, they will force a large number of premature power plant retirements where investments are uneconomical given the remaining useful life of the 
50 

plants. Where such investments are the most cost-effective compliance option, plants 

may have to be idled or significantly curtail production for two or more years in 

order to complete installation of the necessary controls. These power plant operational outcomes raise significant policy, economic, and energy issues that Congress 

should carefully examine. 

AEP has achieved very substantial SO2 and NOx reductions over the past two decades. Our efforts began with a series of cost-effective measures to cut SO2 and NOx

emissions in the 1990’s under the Acid Rain program, including installing SO2

scrubbers and NOx combustion controls, as well as blending lower sulfur coals into 

the fuel mix at plants that could accommodate such coals. The past decade has seen 

a continuation of AEP’s program to transform our fleet of coal-fired generating 

units. This transformation included the installation of state-of-the-art control technologies at many of our generating stations in order to meet the steep NOx reduction requirements of the NOx SIP Call in the early part of the decade. It has continued with a third wave of emissions controls being installed to achieve additional 

NOx and SO2 reductions required under the Clean Air Interstate Rule (CAIR), 

which CSAPR would replace. As a result of these efforts, over the last 20 years, our 

annual SO2 emissions have declined by about 1.1 million tons (a 73 percent reduction) and our annual NOx emissions have been reduced by about 450 thousand tons 

(an 80 percent reduction). 

Over that same period, AEP has invested more than $7 billion in emissions control equipment on our coal units to reduce SO2 and NOx emissions and to comply 

with the NOx SIP Call and CAIR programs. AEP has spent several additional billions of dollars on low sulfur fuel, chemical reagents, and other pollution control operations and maintenance costs. Most of these investments and the emission reductions have occurred in the Eastern portion of the AEP system. About 80 percent of 

AEP coal-fired capacity is located in AEP’s Eastern footprint, which includes coalfired plants in Virginia, West Virginia, Ohio, Kentucky, and Indiana. Annual SO2

and NOx emissions have been reduced at AEP plants in these states by 64 percent 

and 84 percent, respectively, in the last decade alone. About two-thirds of the AEP 

Eastern coal-fired fleet is now equipped with the most advanced SO2 controls—Flue 

Gas Desulfurization (FGD) which reduces SO2 emissions by about 95 percent. Similarly, about three-quarters of the AEP Eastern coal-fired fleet is equipped with the 

most advanced NOx controls—Selective Catalytic Reduction (SCR) which reduces 

NOx emissions by about 90 percent. Two projects were completed in the last 18 

months at our Amos Plant, and we are preparing to submit applications for regulatory approvals to install additional controls in Indiana. All of these efforts have 

also been consistent with an agreement we signed in 2007 with EPA and other 

plaintiffs to settle an enforcement action under the New Source Review Provisions 

of the Clean Air Act. But EPA’s new rules impose more obligations, sooner than required under that Consent Decree. 

We expect this transformation of our coal fleet to continue in the coming decade. 

Two of our newer coal plants in our Western states were originally constructed with 

FGD controls, and we expect to reduce SO2 and NOx emissions further at units that 

are regulated under the Clean Air Visibility Rule in Arkansas and Oklahoma. 

CSAPR will impose additional obligations on our units in Texas, Arkansas, Oklahoma and Louisiana as well. 

The EPA Rules Threaten Electric Grid Reliability, Create Higher Unemployment, and Result in Much Higher Electricity Rates for States Reliant 

on Coal Fired Generation. 

Although AEP is committed to working with EPA in the development of future 

control requirements under its proposed Utility MACT, CCR and 316(b) rules, the 

final Clean Air Visibility Rule, and the final Cross-State Air Pollution Rule, we 

nonetheless have major concerns with these new EPA rules, including the following: 

1. Infeasible Compliance Deadlines. EPA is simply not providing sufficient 

time to design, permit, and install major emissions control technologies on 

large amounts of existing coal-fired capacity that are necessary to comply with 

EPA’s Cross-State Air Pollution Rule (beginning in 2012, with more stringent 

limits in 2014), the proposed Utility MACT Rule (by the end of 2014 or by end 

of 2015) and the proposed Federal Visibility Rule in Oklahoma (end of 2014). 

2. Multiple Major Regulatory Programs Resulting in Unprecedented Capital Expenditures, Mostly Before 2015. There would be two to three times 

as much capital spent in the U.S. to comply with these new EPA rules by 2020, 

compared with the amounts that were spent cumulatively on all utility air pollution controls during the previous 20 years. 
51 

1Specifically, 16 states, out of the 23 states covered under the Cross-State Air Pollution Control Rule program for SO2, would be subject to more stringent SO2 reduction requirements starting in 2014. 

3. Abrupt and Significant Power Plant Retirements due to the Combination of the High Costs of Compliance and the Infeasible Deadlines. Recent studies have suggested that between 50 and 110 gigawatts of coal-fired 

capacity will be forced to prematurely retire due to proposed EPA rules, impacting the reliability of the grid, jobs, taxes, and utility rates. The un-depreciated balances associated with these retirements will place greater pressures 

on utility rates. 

4. Unanticipated Electric Grid Reliability Problems Particularly during 

2014–2016. Because many generating units provide system security and reliability to the grid (e.g., black start, voltage support, etc.), this impact will be 

exacerbated by the large number of premature retirements; substantial idled 

capacity arising from insufficient time to design, permit, and install major 

emissions controls; and the necessarily wide-scale unit outages required to ‘‘tiein’’ these major new emission controls. The greatest capacity reductions will 

occur in the PJM (i.e., Pennsylvania New Jersey Maryland Interconnection) region, a very large power pool which serves the Mid-Atlantic states (NJ, PA, 

DE, MD), plus several states just to the west (including WV, OH, IN, MI and 

parts of IL) as well as in the SERC (i.e., Southeast Reliability Coordinating 

Council) region, which includes most of the Southeastern U.S., with additional 

localized reliability issues in these regions and ERCOT and SPP (the Electric 

Reliability Council of Texas and Southwest Power Pool, respectively). 

5. Very High Electricity Rate Increases Due to High Capital Costs of 

Compliance and New Replacement Capacity. These rate increases will hit 

electricity-intensive manufacturing in the Appalachian Region as well as other 

parts of the Midwest and Southeast particularly hard, leading to industrial 

plant shutdowns and substantial job losses. They will also be disproportionately borne by consumers in some of the poorest rural counties in these same 

states where there are many customers who are unemployed or on fixed incomes. 

There is Not Enough Time to Comply with EPA’s New Rules for Controlling 

SO2, NOx, and HAP Emissions from Power Plants. 

EPA’s Cross-State Air Pollution Rule and Utility MACT Rule will require installation of a large amount of SO2 scrubbers and other capital intensive air emission controls. In particular, under the Cross-State Air Pollution Rule, the SO2 caps become 

significantly more stringent in 2014 for more than two-thirds of the States covered 

under the SO2 portion of the rule. 1 These States are those most reliant on coal and 

they will bear the major portion of the compliance burden for limiting SO2 emissions. The SO2 budget limits in Eastern states, specifically states in the Appalachian Region, are equivalent to an average emission rate of approximately 0.20 

to 0.30 lbs SO2 per million Btu. Such very low emission rates can only be achieved 

at power plants burning Eastern bituminous coals by adding scrubbers. As such, 

these limits would require most all of AEP’s coal-fired power plant units in these 

states to either install FGD, switch to natural gas or significantly curtail operations 

in order to comply. 

In addition to the massive SO2 emission reductions required in 2014, the emission 

reductions slated for 2012 are very significant as well. These new emission requirements will be enforced less than three months from now, with little advanced notice, 

as the final requirements of the Cross-State Air Pollution Rule are significantly 

more stringent than those of the proposed Transport Rule. EPA’s proposed revisions 

just announced last week do not result in appreciable changes in allowance allocations. For example, Ohio, Pennsylvania and Indiana are required respectively to 

make 46 percent, 33 percent and 31 percent reductions in SO2 emissions from 2010 

levels by next year. Other states outside of the Appalachian and Midwest Regions 

are also hit hard with stringent SO2 reduction requirements. For example, Texas, 

even after EPA’s proposed revisions to the budgets, is still required to reduce 2012 

SO2 emissions by 21 percent, as compared to actual 2010 levels. 

These ‘‘new’’ reduction requirements in just three months (first known with the 

issuance of the final rule just two months ago) are particularly problematic because 

utilities are largely unable to make modifications to existing power plants in this 

time frame to substantially reduce emissions. Also, as most utilities procure most 

of their coal on a contractual basis well in advance, a major switch to lower sulfur 

coals is often not a realistic option. As a result, coal-fired power plants will likely 
52 

have to be significantly curtailed. Replacement electricity is likely to come in the 

form of more expensive gas-fired generation. Additionally, the replacement capacity 

might not be located in areas critical to transmission reliability, or able to provide 

voltage support or black start capability, creating further risks to reliability and increasing the costs of maintaining the electric grid. 

In addition to the Cross-State Air Pollution Rule, the proposed Utility MACT Rule 

requires compliance on a plant by plant basis with three separate emission limits 

(1) a very low mercury limit, (2) a PM limit (as a surrogate for non-mercury metals), 

and (3) a hydrogen chloride limit (as a surrogate for acid gases, or an optional stringent SO2 limit as a surrogate at certain units). These limits will have to be met 

by the end of 2014 with a possible one-year extension allowed to the end of 2015. 

Based on a thorough review of these limits (when combined with the requirements 

of CSAPR), we believe AEP will be required to retrofit SO2 scrubbers on most of 

the remaining Eastern fleet, and at a minimum, install a combination of baghouses, 

carbon injection and DSI (dry sorbent injection) at our plants in Texas, Arkansas 

and Oklahoma. For our Western fleet, some of these same units are affected by 

EPA’s Clean Air Visibility Rule (CAVR), and thus could be required to retrofit 

scrubbers on the same or a slightly longer schedule. 

Compliance with the final Cross-State Air Pollution Rule and proposed Utility 

MACT Rule, plus the existing Clean Air Visibility Rule, will effectively require AEP 

to install scrubbers at almost all of its unscrubbed units or retire the plants altogether, and to do so for virtually all of these plants by the end of 2014 (or perhaps 

the end of 2015 if a one year extension is granted). This allows between 2 ° and 

3 ° years for compliance with at most 4 ° years in a few cases. This time frame is 

completely infeasible to get regulatory approvals, design, permit, fabricate, and install a retrofit scrubber as shown in Figure 1 below: 

Figure 1 shows that the average time needed from project commencement to completion for a retrofit scrubber is five years for a regulated electric utility. (The time 

frame is similar if a unit is retired and replaced on site with a new combined cycle 

gas plant). This figure is based on the actual average time period needed during 

2003–10 when AEP added scrubbers at 7,800 MW of capacity or—more installations 

than anyone else in the industry. Given that the EPA rules will require a greater 

number of retrofit projects and/or plant replacements and other related environmental investments across our industry within the same three to five year window, 

compliance with the Utility MACT Rule and Cross-State Air Pollution Rule is simply infeasible within this very short compliance period. 

High Costs and Infeasible Deadlines Will Lead to Substantial Coal Plant 

Retirements and Significantly Compromise Electric Grid Reliability. 

Due to the high costs of compliance and infeasible time deadlines, a large amount 

of coal unit retirements at AEP and across the industry is expected in the 2014– 

15 time period. In addition, a large number of units that are complying by retrofitting will have to be taken out of service, mothballed, or significantly curtailed 

during the 2014–16 time period as well. 
53 

2 NERA (2011). A loss of one job-year is equivalent to a loss of one job for a period of one 

year. Job-years are commonly used by economists, CBO, OMB and others in reporting employment statistics. 

AEP estimates that in its own coal fleet about 6 GW of its coal fired capacity (or 

about 25 percent of the company’s coal-fired generating capacity) would retire by the 

2014–15 time period under the EPA rules. We recognize that certain of our units 

are also subject to the requirements of our New Source Consent Decree, but only 

615 MW is required to comply with those requirements before 2015. Other major 

coal-fired utilities such as Southern Company and DTE Energy Company have estimated that a similar 20 to 30 percent of their coal-fired capacity would retire in the 

period before 2015. AEP also estimates that 1.5–5 GW of coal-fired capacity would 

be temporarily out of service or severely curtailed during 2014–16 as retrofit pollution controls are being completed. 

There is A Better Way 

The combination of EPA’s new rules for power plants will result in a series of relatively inflexible and stringent air pollution and other environmental regulations 

with infeasible timelines and unnecessarily high compliance costs. In addition to 

high costs borne by our electricity customers, these new rules could also result in 

many premature plant retirements and over 1 million net jobs lost in the U.S. 2

We believe that a more reasonable approach to energy and environmental policy 

is needed. AEP has been working on these issues with the International Brotherhood of Electrical Workers (IBEW); the United Mine Workers of America (UMWA); 

and the International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers, and Helpers. 

A comprehensive analysis of the economic impacts of the proposed regulations as 

well as the feasibility and timing of their implementation is needed. While we continue to support sound policy aimed at improving air quality and public health, numerous economic studies and modeling analyses have demonstrated that the implementation of these major EPA requirements occurring in the same narrow time period will have major adverse economic repercussions. More time for phasing in the 

new control requirements is required to smooth the impacts associated with power 

plant closures and electricity rate increases, as well as to allow for the construction 

and installation of major environmental retrofit controls. Longer time frames also 

would enable better planning, ensure electricity grid reliability and avoid many premature plant shutdowns or excessively high costs for pollution controls due to supply constraints. 

Given the multi-dimensional nature of major environmental policy initiatives and 

the immediacy of the compliance deadlines, we believe that Congress must intervene and assure that a sensible multi-pollutant environmental program is developed 

on a rational schedule and that this schedule is coordinated with the other new EPA 

rules. We believe that a legislative approach can continue to promote the air quality 

and public health goals set forth in EPA’s regulatory initiatives while ensuring that 

adequate emphasis is focused on the employment, economic and reliability impacts 

of the program. 

The challenge of EPA’s current regulatory approach is not a technology issue requiring the Department of Energy to venture down the path of R&D or major demonstrations. On the contrary, there is simply no time to develop new technologies, 

demonstrate their viability, and engineer these systems. We believe the technologies 

exist today to enable AEP and the larger US fleet to comply with increasingly stringent environmental requirements while maintaining a robust and reliable electric 

power infrastructure. However, timing is the limiting factor in enabling a viable 

path toward compliance. The role we see for DOE, and it is a vital role indeed, 

would be to become engaged in a thorough analysis of EPA rules impacts and deployment timelines. In short, DOE should serve as a trusted advisor to the EPA in 

the rulemaking process. 

DOE has expertise in all the areas of power generation and electricity transmission and distribution. They have the well-informed authority to evaluate the 

electric power generation system and grid stability/security risks and can make a 

non-biased assessment of the timelines needed to deploy technology at the broad 

scale required under EPA’s program. It is AEP’s preference that DOE be engaged 

in this process. 
54 

CONCLUSION 

In summary, American Electric Power has an established history as an industry 

leader in technology development and deployment. We were the first in high voltage 

transmission of electricity and have blazed trails in the development of smart grid 

technologies. Supercritical steam generation was first put into utility power production by AEP more than a half-century ago, and many of our units operating today 

represent new benchmarks in performance and efficiency at the time they were commissioned. We carry forward that proud tradition even today with deployment of the 

nation’s first ultra-supercritical unit, which will come on line less than one year 

from now. We embrace technology as the means to produce and deliver clean and 

affordable electricity to our customers. We share much of our knowledge with the 

industry because we believe everybody benefits when technology is allowed to flourish. This philosophy of living on the cutting edge of technology advancement has its 

risks and uncertainties, as is most evidenced with our extensive work on CCS. 

While many were hoping and waiting for others to deliver a solution to CO2 emissions, AEP boldly pursued the path of developing and demonstrating CCS technology. Our shareholders have shown the vision to support this approach by shouldering the burden of extraordinarily-expensive demonstration projects when other 

means have not been available. 

We believe DOE should be bolstered in their efforts to develop viable and affordable technology solutions. While legislative activity on CCS has diminished and 

some key government-funded demonstration projects, like AEP’s, have been cancelled or are currently at risk of being cancelled, now is not the time to divert DOE’s 

attention from further advancement of CCS technology. Robust and affordable 

choices for CCS will in fact NOT be available in the market for installation on coalfired power plants if the technology is not demonstrated in the meantime. AEP is 

ready and eager to reenter the demonstration phase of our CCS program at such 

a time when adequate funding of demonstrations enables successful completion of 

projects. 

In this same spirit of ingenuity, AEP urges the new EPA rules be structured in 

a way to allow for cost-effective implementation on a reasonable schedule so as to 

minimize the impacts on our residential customers, local businesses, and the reliability of the electricity grid. It is also critical that the emissions reduction levels 

of the program be set at levels that are technically feasible to achieve over the given 

time frame and are in fact necessary to fulfill the air quality goals and requirements 

of the Clean Air Act. As a nation, we must ensure our future energy security and 

reliability by using domestic resources such as coal, while continuing to advance 

technology. AEP would like to thank the Committee for the opportunity to present 

our views on the issues of advanced coal research and a secure energy future. 

Chairman HARRIS. Thank you very much. 

I now recognize our fourth witness, Mr. David Foerter, Executive 

Director, Institute of Clean Air Companies. 

STATEMENT OF DAVID FOERTER, EXECUTIVE DIRECTOR, 

INSTITUTE OF CLEAN AIR COMPANIES 

Mr. FOERTER. Thank you for inviting the Institute of Clean Air 

Companies or ICAC or Institute to testify and present its perspectives on what motivates the air pollution control and measurement 

industry to innovate and deploy commercial-ready technologies and 

enable power generators and manufacturers to operate responsibly 

and ensure cleaner air to the pollutions they serve. 

To provide some perspective about our industry, we are a growing number of technology manufacturing and service companies 

that have a sustainable industry due to the demand of our technologies and services. And that demand comes from clean air regulations and policies. This industry has great—has matured greatly 

in the more than a half century ICAC has been its public representative, and we are proud of having met and often exceeded 

the regulatory control and measurement challenges of the industries we serve. 
55 

It should come as no surprise that the air pollution control industry is well prepared with suites of affordable technologies and 

eager and experienced workforce to achieve the air quality improvements needed to deliver healthy air. 

The science of air pollution control and measurement are well 

understood by our industry, and technologies are continuously refined through healthy competition if the demand is there. Our industry’s impact on jobs is well documented, and I have included insights into my written testimony. For brevity I won’t go into some 

of those issues. 

Air pollution control and measurement technologies are available 

to meet the upcoming regulations for hazardous and conventional 

air pollutants emitted by firing coal, and we are confident that 

these—that any issues that still exist can be addressed within the 

framework used to develop regulations and do not require any priority for R&D funding. 

Therefore, as an industry largely made up of engineers, we are 

ready to innovate and build equipment that our clients need in the 

marketplace. 

R&D is best used judiciously to develop and test technologies 

where none already exist, and this is clearly not needed to effectively address the air pollutant emissions of conventional pollutants such as criteria and hazardous pollutants in the electric power 

sector. Probably the best example of this is mercury control technology, which about ten years ago didn’t exist to an R&D Program 

that was developed, and it is now probably one of the easiest pollutants to deal with under the Hazardous Air Pollutant Control requirements. 

Because of the diversity of control and measurement technologies 

and the offerings of multiple vendors and mature industry, there 

are many choices available to sources affected by regulations. For 

example, some of the largest SO2 scrubbers may have a large capital cost but also allow sources to take advantage of cost savings 

and using higher sulfur coal that is often much cheaper, less expensive to use. Therefore, it is possible that for some of the facilities cost savings on coal can cover most, if not all, of the technologies that are being put in place. 

But there is also other opportunities because there is less resource and time-intensive technologies are available to be quickly 

deployed and offers the power generation industry the needed flexibility it may need to comply with upcoming regulations. 

For example, direct sorbent injection, another type of scrubbing 

technology, and circulating and dry scrubbers are technology options with costs and install times less than the larger Wet FGD 

types of programs. 

Today I have in my comments nearly two-thirds of the coal-fired 

electric power plants are controlled. I am going to have to review 

that to 75 percent based on two witness testimonies, leaving approximately another 25 percent of the fleet substantially uncontrolled. Decisions to control much of the power fleet generally installed controls on units that were most cost-effective to control. 

Plant retirements are inevitable, even in the absence of regulations. Building new plants is problematic, and so I just add that 

as some of the witnesses already. 
56 

As an industry built on innovations, we seek new challenges and 

opportunities, particularly those that serve the public health and 

industrial progress. There are certainly challenges for all fossil 

fuels, particularly coal, which will benefit from well-spent R&D dollars. Chief among those challenges and right for R&D investments 

is carbon capture as part of a CO2 control strategy. Here the challenge and the opportunity is to enable coal to be a more sustainable 

fuel choice whereby emissions are well controlled. 

In our industry it is clear that regulations designed to improve 

air quality for public health is the primary driver for much of the 

technology development and innovations. For example, as the understanding of particulate control emissions we moved from a very 

coarse type of particulate control emissions to coarse, fine, and 

even condensables. In the amount that we have been doing this 

there has been cost and benefit analysis done, and the benefit-cost 

analysis prepared by EPA shows that for every dollar spent there 

was as much as $4 to $20 that comes back to direct public health 

benefit, and that includes the prevention of pre-mature mortality. 

From our industry’s perspective, this is comforting. 

The biggest challenge that we see is not the hazardous and criteria pollutants. It is in CO2 capture and thermal efficiency. So we 

look forward to seeing work more in that field, not on criterion, 

hazardous pollutants. 

Thank you. 

[The prepared statement of Mr. Foerter follows:] 
57 

PREPARED STATEMENT OF MR. DAVID FOERTER, EXECUTIVE DIRECTOR, INSTITUTE OF

CLEAN AIR COMPANIES
58 
59 
60 
61 
62 

Chairman HARRIS. Thank you very much. 

I now recognize our final witness, Mr. Stu Dalton, Senior Government Representative for Generation of the Electric Power Research Institute. 

STATEMENT OF STU DALTON, SENIOR GOVERNMENT 

REPRESENTATIVE-GENERATION, ELECTRIC POWER 

RESEARCH INSTITUTE 

Mr. DALTON. Thank you, Chairman Harris, Congressman Miller, 

and Members of the Committee. I appreciate the opportunity to 

give this testimony today. 

The U.S. DOE has a significant R&D effort as you have heard, 

developing technology for coal and a long history of doing that work 

with an important program in place. We have worked independently as well as collaboratively with the DOE over several decades 

in many of the areas you have heard talked about today on SO2, NOx, mercury control, as well as on advanced technologies. 

But the changing regulations and demands of the system are requiring or creating new challenges which are, indeed, calling for 

new R&D, and that is what I will talk about today. 

Based on our review there are three major areas that are not sufficiently covered in the current R&D Program. One is high-efficiency combustion plants. We have heard a little talk about that 

today. Another area is water management, we have also heard that 

mentioned. The third area is new implications of the recent work 

on hazardous air pollutants. We have worked on hazardous air pollutants for two decades at least. 

These technologies are needed to meet the global challenges in 

advanced coal-powered technology as well as the domestic regulatory compliance schedules. A fourth area of gasification would 

also benefit from additional R&D. 

The first area involves high-efficiency steam cycles based on 

American advanced alloy steels that have been developed largely 

with funding from the DOE. The need is to accelerate the pace 

from successful component fabrication and testing to in-service boiler and turbine testing that includes operation of a complete integrated demonstration plant. This RD&D would put American technology and suppliers in the lead worldwide for high-efficiency technology and low-emission use of coal. 

The DOE has been a major sponsor of this work, along with the 

Ohio Coal Development Office. They have supported a public, private, federal, and state effort across the U.S. Industry and national 

lab participants have worked for almost a decade on this area to 

create, fabricate, and weld these alloys with work done in six 

states—in Indiana, Ohio, Pennsylvania, Texas, West Virginia, and 

Wisconsin. We have done work with a number of these organizations. 

We have shown that high-temperature materials can work for 

tens of thousands of hours in the lab. You need to take it to the 

full scale. The very high-temperature steam pressures and temperatures that are used to get this high efficiency requires some 

new novel technology. I am holding a report that is actually entitled, ‘‘U.S. Department of Energy and Ohio Coal Development Office Report on Advanced Ultra-Supercritical Materials Project for 
63 

Boilers and Steam Turbines.’’ This report has a lot more details on 

the timing and the content of that work. 

The second area I would like to mention is water management. 

We are seeing new barriers to siting plants as well as barriers for 

continued operation from some of the new regulatory requirements. 

Water management needs to reduce consumption, accommodate 

lower water quality supplies, and address more complex waste 

water treatment. Solid management issues need to be addressed, 

partly because there are requirements that cover all aspects of 

water management, not just water but air and solids as well. Use 

of degraded waters and recovery of water from power are also 

issues. There are many different ideas out there, and EPRI is 

working with industry right now to create a water research center 

in this area. 

A third area is in hazardous air pollutants. Not just in capturing 

Mercury but looking at other compounds like Selenium, Arsenic, 

Hydrochloric acid, Hydrofluoric acid, and things of that sort that 

are—that might be cross-media. You catch it from the air, it goes 

somewhere. 

The variety of coal and power plant types, and emission control 

configurations require different controls because of the new regulations. It is urgent because firms are starting to design and purchase equipment, yet we believe not all these issues are resolved. 

The fourth area, gasification is one where DOE has an ongoing 

program and has been doing a lot of work. We need to accelerate 

work on synthesis gas cleanup, higher temperatures, larger turbines, lower oxygen costs for the supply, and better plant controls. 

Finally, I would like to say that EPRI has been working cooperatively in the area of CO2 control with the Department of Energy. 

The heavy focus on CO2 capture, utilization, and storage we think 

is worthwhile and now utilization might be possible for enhanced 

oil recovery to bootstrap CO2 demonstrations and improve the domestic oil capabilities as well. 

We see that the sustained work on integrated demos is important 

because it is a very broad issue. We thank you for the opportunity 

to address the Committee. 

[The prepared statement of Mr. Dalton follows:] 

PREPARED STATEMENT OF MR. STUART DALTON SENIOR GOVERNMENT

REPRESENTATIVE, GENERATION ELECTRIC POWER RESEARCH

My name is Stuart M. Dalton. I am the Senior Government Representative, Generation, for the Electric Power Research Institute (EPRI, www.epri.com). EPRI conducts research and development relating to the generation, delivery, and use of electricity for the benefit of the public. 

As an independent, nonprofit corporation, EPRI brings together its scientists and 

engineers, as well as experts from industry, academia, and government, to help address challenges in electricity, including reliability, efficiency, health, safety, and the 

environment. EPRI also provides technology, policy, and economic analyses to drive 

long-range research and development planning, and supports research in emerging 

technologies. EPRI’s members represent more than 90 percent of the electricity generated and delivered in the United States, and international participation extends 

to 40 countries. EPRI’s principal offices and laboratories are located in Palo Alto, 

California; Charlotte, North Carolina; Knoxville, Tennessee; and Lenox, Massachusetts. EPRI appreciates the opportunity to provide this testimony today. 

Introduction and summary 

EPRI analysis including our Prism/MERGE reports shows multiple future scenarios in which coal will be an important fuel in the US generation mix. In the 
64 

wake of recently proposed environmental rules and other regulations, U.S. power 

producers have estimated that tens of thousands of megawatts of coal-fired power 

generation capacity could be retired prematurely. At the same time, studies by 

EPRI, the International Energy Agency and others demonstrate that in order to reliably and affordably meet the nation’s energy needs and environmental goals all 

types of power plants—from renewables to advanced coal and natural gas to nuclear—are needed to provide a secure energy future. 

For coal-based generation to fulfill its potential to contribute to the nation’s clean 

energy supply, new technologies and practices must be developed and demonstrated 

to address concerns over air, water, and thermal emissions, as well as secure solids 

disposal and CO2 storage. 

The U.S. Department of Energy (DOE) has excellent research, development, and 

demonstration (RD&D) programs in place on CO2 capture and storage and conducts 

significant work on advanced coal generation technology; these were preceded by a 

long history of successful RD&D on criteria pollutant, particulate, and hazardous 

pollutant controls for coal power plants. 

RD&D on stronger and more durable high-temperature materials as well as improved integration and process configurations for increased plant efficiency have 

paralleled environmental control technology development. EPRI has worked independently, as well as cooperatively, with DOE and other government agencies to 

help attain many of these research objectives. 

The needs of the electric power industry are evolving rapidly because of changing 

emission regulations and power grid system requirements. The continued alignment 

of RD&D efforts to reflect these latest priorities is necessary to help ensure that the 

nation’s coal-based power plants can continue to supply affordable electricity. 

Based on EPRI’s analysis, three major areas not sufficiently covered by current 

DOE coal RD&D need additional support and these areas currently compromise the 

power industry’s ability to meet both global competitive challenges in advanced coal 

power technology and domestic regulatory compliance schedules. A fourth area is 

relatively well addressed, but would benefit from additional RD&D on basic gasification and power block technology improvements. These areas are listed below and 

discussed individually in further detail: 

1. Ultra-high-efficiency steam power cycles based on American advanced alloy 

steels: we need to accelerate the pace from successful component fabrication 

and testing to in-service boiler and steam turbine testing and a complete integrated demonstration plant 

2. Improved water management to reduce consumption, accommodate lower-quality/degraded water supplies, and address more complex wastewater treatment 

and solid by-product management challenges 

3. Workable solutions to proposed hazardous air pollutants (HAPs) emission 

standards accounting for real-world operational issues, flue gas constituent 

interactions and cross-media impacts, and measurement capabilities 

4. Efficiency and cost improvements for gasification power plants independent of 

CO2 capture processes: we need to accelerate scale-up, testing, integration engineering, and demonstration of fundamental improvements in synthesis gas 

cleanup at higher temperatures, higher gas turbine firing temperatures and 

larger turbines (and associated blade temperature control), lower-energy oxygen supply technologies, and better plant controls 

EPRI would like to stress that these areas are identified as necessary to augment, 

not supplant, DOE’s current RD&D programs focusing heavily on CO2 capture, utilization, and storage (CCS). Continued and sustained support for CCS development 

and integrated demonstration is essential to success in this most overarching of 

issues facing coal power plants. 

Advanced ultra-supercritical steam cycle development using nickel-based 

alloys: In-service test facility and fully integrated demonstration 

Higher plant efficiency reduces the amount of fuel consumed and associated emissions and water consumption per megawatt hour of electricity generated. Notably, 

CO2 reduction is significant, up to 20–25% per megawatt hour and the avoided cost 

per ton of CO2 is estimated both by DOE and EPRI as being one of the lowest avoided costs compared to any technology for CO2 capture and storage. This is a winwin approach for utility customers and the environment. Thermodynamics dictates 

that increasing the efficiency of a steam cycle requires hotter and higher pressure 

steam conditions known as ultra-supercritical (USC) at the turbine inlet. Maintaining boiler, piping, and turbine safety and longevity at steam temperatures of up to 
65 

1400°F (760°C) requires a new class of high-nickel-content steel alloys and, in some 

cases, coatings, several of which have been pioneered in the United States under 

a research program sponsored by DOE and the Ohio Coal Development Office 

(OCDO). 

Despite this successful record of fabrication and testing of key boiler and steam 

turbine components by American manufacturers, the program faces federal funding 

uncertainties at a time when European competitors have advanced to an in-service 

boiler test loop and Asian firms are looking to move to higher temperature and pressure cycles. To reach DOE and industry goals for improving coal plant efficiency, 

EPRI recommends a ‘‘managed risk’’ series of demonstration elements embedded in 

commercial power projects, concluding with a fully integrated plant (dubbed 

UltraGen) featuring nickel-alloy high-temperature components, superior environmental controls, and CO2 capture and compression. 

The foundation has been laid with earlier DOE/OCDO materials work managed 

by Energy Industries of Ohio and EPRI (one team focused on boilers, one on steam 

turbines), with a joint vision for future scale-up and demonstration established by 

DOE, EPRI, and the Coal Utilization Research Council. The most developed alloys 

are Inconel 740, a product of Special Metals Corporation in West Virginia, and 

Haynes 282 alloy by Haynes International, headquartered in Indiana. 

Large-diameter pipe extrusions have been made by Wyman-Gordon in Texas, and 

Haynes alloy 282 castings have been made by MetalTek in Wisconsin and Flowserve 

in Ohio. The project also conducted powder metallurgy work at Carpenter Technology Corporation in Pennsylvania. Some of these firms are already receiving inquiries for use of these materials overseas. To reap the benefits of this technology 

research domestically, we need to adequately fund the next stages of development, 

namely in-service test and demonstration to allow for commercial deployment. 

At a cost of about $50M over three years, an in-service component test facility at 

an existing plant would lay the groundwork for the design and installation of a demonstration unit, possibly in later phases of DOE’s Clean Coal Power Initiative or via 

other risk-sharing mechanisms for first applications in the United States. Under 

this scenario, advanced USC plants would become commercially available after 

2020, following successful operation of a demonstration plant. This recommended 

path to commercialization and prior work on advanced materials development are 

described in EPRI brochure 1022770, U.S. Department of Energy and Ohio Coal Development Office Advanced Ultra-Supercritical Materials Project for Boilers and 

Steam Turbines (March 2011). 

Such a commitment would return the United States to the forefront in thermodynamic efficiency, building upon the legacy of the world’s first plants with USC 

steam conditions–AEP’s Philo Unit 6 in 1957 and Exelon’s Eddystone Unit 1, in 

service from 1960 until its retirement this year. Finally, given the prospect of future 

CO2 regulations (and efforts by power producers to demonstrate voluntary CO2 reductions), the impetus for higher efficiency in future coal-based generation units has 

gained traction worldwide. Many new coal plant projects announced over the last 

two years will employ supercritical steam cycles, and several will use high-efficiency 

‘‘moderate USC’’ steam conditions, building a logical progression toward advanced 

USC plants with the help of financiers, state regulators, and other key stakeholders. 

Improved water management to reduce water consumption, accommodate 

degraded water supplies, and address wastewater treatment and solid byproduct disposal challenges 

Water withdrawals and discharges by the power industry are falling under new 

regulatory requirements, and are posing new engineering challenges, as the sources 

and composition of water available to power plants are changing, along with restrictions on its discharge. 

Water is the lifeblood of a power plant, serving both as the working fluid that converts combustion heat to turbine shaft power and as the cooling medium that allows 

high-purity steam cycle water to circulate continuously from boiler to turbine and 

back. Accordingly, water quality and cost are major factors in plant economics. 

Cooling water is a power plant’s largest use. There are proven low-water-use cooling options—developed in the arid western states and other locations where power 

plants have faced water limitations for decades—providing a technical foundation 

for new innovations. However, these alternative cooling options normally require 

more space than traditional ‘‘once through’’ river, lake, or ocean water cooling, 

which can create significant challenges when existing plants are compelled to retrofit recirculating cooling systems in response to Clean Water Act Section 316 rules 

on intake structures and thermal discharges. Thus, there is an RD&D need for retrofit cooling options, as well as designs for new plants. 
66 

Even in areas of the United States with historically adequate water supplies, reducing water use is a growing issue for the power industry, so the need is now national rather than regional. Compounding the challenge is the prospect of future 

regulations limiting CO2 emissions. Virtually every type of CO2 capture technology 

requires steam use for the process and additional cooling. CO2 compression for sale 

or geologic storage also requires additional cooling. DOE research in this area will 

be especially important if CO2 capture, utilization, and storage become widespread 

because power plant cooling demand will increase substantially. 

In many cases, power plants are finding the only (or most economic) new source 

of water is from lower-quality and/or degraded supplies, such as municipal wastewater treatment plant discharge. These less-pure waters require different treatment 

methods and more blowdown (a slipstream sent to the plant’s wastewater treatment 

equipment) than conventional water supplies. 

Wastewater treatment also faces new engineering challenges due to tighter air 

pollution requirements, which result in greater amounts of trace species such as 

mercury, arsenic, selenium, and acid gases being removed from flue gases and 

transferred to wastewater streams. These may need to be treated differently before 

discharge than under prior practices. The particular wastewater treatment needs 

and available technology options depend on the coal and boiler type and the type 

and configuration of air pollution equipment used (e.g., wet vs. dry scrubbing for 

SO2, different types of particulate and NOx controls, and different sorbents or additives for mercury control). EPRI in conjunction with industry is developing an initiative to address plant water management and welcomes further collaboration with 

DOE. 

Additional information is being developed in a draft roadmap by EPRI and the 

Coal Utilization Research Council. Some of the R&D goals being addressed are: 

• Demonstrate reduced water consumption technologies 

• Improve wet, hybrid, and dry cooling testing in conjunction with water balance 

modeling 

• Moisture/water recovery 

• Test membrane, liquid desiccants, cyclic reheat and/or other new approaches, as well as low-temperature heat recovery plus water capture on 

coal gasification/combustion 

• Demonstrate integrated treatment, quality management, and moisture recovery 

• Create an industry water research center to demonstrate methods for reduced 

water consumption and improved water management 

Researching solutions to hazardous air pollutants issues in a real-world deployment setting: flue gas constituent interactions, cross-media impacts, 

and measurement capabilities 

In the same manner that tailpipe emissions from new cars are a minuscule fraction of the emissions from cars of the 1960s, new coal-fired power plants are vastly 

cleaner than plants from a generation ago. In addition, many existing plants have 

been retrofit with technologies to capture SO2, NOx, mercury, and SO3 and fine particulates. 

New regulations have been proposed for hazardous air pollutants and the power 

industry is currently looking at process and operational alternatives for the coal 

fired stations as well as weighing options to retire plants where compliance with 

this plus other pending requirements for criteria emissions, water limitations , and 

solids management is not practical. In the timeframe required it will also be difficult to plan, permit, fabricate, install and place in service the equipment necessary 

to meet the U.S. Environmental Protection Agency’s Maximum Achievable Control 

Technology (MACT) rule proposed in 2011, and the Cross-State Air Pollution Rule 

(CSAPR) rule finalized in July 6, 2011. 

As the government, industry, and EPRI have tested the various types of plants 

and process configurations and their emissions, real-world issues and unintended 

consequences of HAPs reduction methods have been identified. The issues vary, and 

the solutions have required additional R&D to resolve concerns about water and 

solid by-product changes that would make current management practices unsuitable. Conditions can vary widely because coals can contain virtually any of the constituents of the earth’s crust. Because coal and ash compositions vary, plants must 

have different plant configurations, firing equipment, and processes existing on the 

units to operate properly. Testing, modeling, and limited experience has identified 

a wide variety of issues. Some of these issues are cross-media (i.e., between air, 

aqueous, solid release streams) and can cause currently useful materials such as fly 
67 

ash or gypsum used in aggregate, concrete, or wallboard to be questioned or to make 

them unusable. Research is needed in this area to verify and resolve potential impacts to enable reliable, operable units that consistently meet regulations for criteria air emissions, HAPs, as well as water and solids limits, and allows beneficial 

use of coal combustion by-products whenever possible. 

Current emissions controls reduce criteria pollutant emissions to very low levels, 

and often capture a significant fraction of mercury in the process. Nonetheless, new 

regulations call for further reductions in NOx, SO2, SO3, fine particulates, and mercury emissions, with an added focus on other HAPs, including selenium. Chief 

among these regulatory drivers are the utility HAPs MACT and CSAPR rules. EPRI 

has commented on the HAPs MACT in a submission dated August 4, 2011, and 

identified some of the challenges in measurement and compliance that make power 

company compliance difficult within the proposed timeframe and implies urgent 

R&D is needed. Some of the summary comments related to the need for additional 

R&D are quoted below, followed by a comment regarding R&D needs. The entire 

EPRI submission is available to the public at the following site: 

http://mydocs.epri.com/docs/CorporateDocuments/SectorPages/Environment/ 

hapsicr/EPRI—HAP s—Comments—08-04-11.pdf 

EPRI comments on the difficulty of meeting proposed limits and the issues 

with data collection 

• ‘‘No coal-fired EGU (new and existing coal- and oil-fired electric utility steam 

generating units) tested in the ICR (EPA’s Information Collection Request)would likely meet the new unit MACT limits for all three regulated 

HAPs-total particulate matter, mercury, and hydrogen chloride (or the alternative acid gas surrogate, sulfur dioxide). The new unit limits are very challenging to achieve as few EGUs have multiple ICR measurements that are consistently below the proposed new unit limits. The use of the lowest test series 

average introduces biases, and EPA should use the average of all ICR data for 

setting the HAPs standards for both new and existing EGUs.’’ 

The proposed regulations for new and existing coal- and oil-fired electric utility 

steam generating units (EGUs) have very low limits which have been set based on, 

in many cases, erroneous data and a limited number of data points. Despite the values that are eventually established, additional R&D will be needed to ensure that 

the new limits can be met on an ongoing basis and for the variety of coals and plant 

designs in operation. 

EPRI comments on dry sorbent injection and the ability to use the technology without power plant impacts in other areas 

• ‘‘Additional data are required to evaluate the use of dry sorbent injection as a 

control for removing hydrochloric acid (HCl) and hydrofluoric acid (HF). Based 

on the limited available data, there are concerns about whether EGUs firing 

medium- to high-chloride coals can achieve the HCl standard using dry sorbent 

injection, and whether there would be impacts to balance-of-plant operations.’’ 

A number of firms are considering dry sorbent injection to manage hydrochloric 

acid (HCl) and hydrofluoric acid (HF). Because data are limited it is unclear the 

range of coals and conditions which may be able to use this control technique and 

the type of sorbent that will be effective and able to avoid cross media issues after 

use (not making an air issue into a solid waste or water issue). R&D is needed to 

test alternate sorbents and their fitness for the purpose of acid gas control and the 

cost effectiveness of their use. 

EPRI comments on the data not representing the range of operating conditions and the ability to comply under all normal and transient conditions. 

• ‘‘The ICR did not require EGUs to test over the full range of operating conditions, and therefore the ICR data do not represent the entire range of emissions 

variability from power plants. Additional measurements are needed to adequately characterize the variability of HAPs and surrogate emissions during 

normal plant operations. Sources of emissions variability include fuels burned, 

startup and shutdown conditions, partial load operation, and other reasonably 

foreseeable changes to operating conditions. Limited measurements at one facility indicated that trace metal variability was comparable to the variability of 

filterable PM measurements.’’ 

The EPA’s Information Collection Request (ICR) collected data for a number of 

static conditions but data is not available to assure power plants can comply with 

a range of operating conditions typical of coal plant operation. In order to retain reliable grid operation and maintain the obligation to serve customers with economic, 
68 

secure power, it is normally necessary to vary load from different types of generation sources. Now that more ‘‘non-dispatchable’’ power such as wind is generated in 

certain areas of the country such as the upper Midwest and Texas, power companies 

are seeing added requirements to turn down or reduce coal generation periodically 

and bring it back if those non-dispatchable sources cannot generate. This variation 

in demand will mean chemical and physical processes may be called on to operate 

out of their most efficient or effective ranges and it may be difficult to meet the 

emission standards during transients or at partial loads. R&D is needed to evaluate 

and test, understand, model and provide guidelines for design and operation in 

these instances. 

As regulations become more sweeping, with less flexibility in terms of time averaging and emissions banking and trading, fuel-specific nuances become magnified 

in their impact on compliance assurance, as do the relative effects of emissions from 

transients (startups, shutdowns, and load changes), seasonal variations, effects of 

one emission control device (or new additive) on another device, and measurement 

reliability. Compliance timetables are short and coal plant ‘‘back ends’’ are packed 

with emissions control devices so many strategies for capturing trace toxics involve 

modifications to existing systems or operations. A major industry concern is unintended consequences that could risk noncompliance or lead to premature corrosion 

or other failure of emissions control equipment. 

In the near term, EPRI notes particular technology development and demonstration needs as follows: 

• Controls consistent with 90%-plus mercury reduction for all applications and 

fuels 

• Managing acid gas removal including HCl and SO2 as surrogates for acid gases 

• Model, test, and develop operation and maintenance practices for wet and dry 

scrubbers which are also used to remove HAPs, and how to best manage crossmedia impacts and implications for operations, such as corrosion due to high 

levels of chlorides or halogens in plant process water 

• Selective catalytic reduction (SCR) NOx control catalyst regeneration strategies, 

as well as SCR catalyst management systems consistent with year-round system operation at >90% NOx removal, minimum SO3 generation, and maximum 

oxidation of elemental Hg in the flue gas 

• Robust, reliable FGD systems for all coals 

• More wear-tolerant, low-pressure-drop, ultra-high-efficiency baghouses for control of particulates from a wide range of fuels; improved performance of electrostatic precipitators (ESPs) for applications not suited to baghouses or amenable 

to upgrading in existing power plants; and demonstrated wet ESPs for acid mist 

and fine trace metal particulate capture 

• Resolution of balance-of-plant issues and long-term operability issues for recently installed environmental controls. 

Recent Testimony by J. Edward Cichanowicz an independent consultant based in 

Saratoga, California before this Subcommittee October 4, 2011 is available on line 

at the following url (http://science.house.gov/sites/republicans.science.house.gov/files/ 

documents/hearings/100411— Cichanowicz.pdf) his testimony identifies issues with 

the short time for compliance being proposed under MACT and CSAPR. We agree 

with the concerns addressed by Mr. Cichanowicz and suggest that this creates an 

urgent need to get DOE support for understanding the HAPs issues and solutions. 

We need to understand unintended consequences, the ability to comply under all 

conditions, and the ability of the planned equipment to address varying coals and 

water compositions. Given the tight schedule the power industry faces for compliance, DOE could best support industry RD&D efforts by building upon previous 

work for mercury controls, including management of HAPs control processes to minimize water and/or solids contamination. In other words, power plant operators need 

help identifying and testing approaches to managing HAPs issues holistically for the 

variety of plant types and conditions. To summarize, specific areas the industry 

needs support in are: 

1. Understanding HAPs control (mercury, HCl, trace metals) balance of plant 

issues such as corrosion, increased PM emissions, solid by-product disposal/ 

use, leaching, and wastewater treatment 

2. Development of lower cost HAPs control options to maintain the viability of 

coal-fired power plants 

3. Understanding the variability of long term HAPs control effectiveness (startup, shutdown, cycling) 
69 

4. Understanding the underlying mechanisms for HAPs formation and control, 

as well as independent assessments of emerging emission controls 

Efficiency and cost improvements for gasification power plants: synthesis 

gas cleanup at higher temperatures, higher gas turbine firing temperatures 

and larger turbines, lower-energy oxygen supply technologies, and better 

plant controls 

Gasification technology uses heat and pressure to partially oxidize a carbonaceous 

fuel to create a combustible ‘‘synthesis gas,’’ which can be fired in a highly efficient 

combined cycle (gas turbine and steam turbine) power block. In the power industry, 

gasification plants are used with inexpensive solid fuels, such as coal or petroleum 

coke, or sustainable fuels such as biomass, and in some cases, the plants sell steam 

or hydrogen as well as electricity. Gasification technology is also offers a relatively 

lower incremental cost for incorporation of CO2 capture and compression, relative 

to other fossil power technologies. However, a ‘‘base’’ gasification combined cycle 

power plant (i.e., one without CO2 capture and compression) usually costs more than 

other types of fossil power plants. Hence there is an RD&D focus on improving gasifier, power block, and auxiliaries performance and cost by equipment improvements 

and improved integration. DOE has long and active history in coal gasification 

RD&D, providing a knowledge and experience base to manage an accelerated program of competitiveness-driven gasification combined cycle technology development 

and demonstration, which would parallel ongoing efforts on integrating CO2 capture 

and compression. 

The synthesis gas, or syngas, produced in a gasifier consists chiefly of CO, with 

varying degrees of methane and heavier hydrocarbons, hydrogen, water vapor, CO2, nitrogen, and H2S, COS, and other sulfur compounds. To prevent erosion and corrosion in the gas turbine and associated heat exchangers and ducting, and to limit 

stack emission of sulfur species, the ‘‘raw’’ syngas is cleaned of particulate matter 

and sulfur compounds. Traditionally, this is accomplished by cooling the syngas 

with a water quench and/or a series of heat exchangers, and treating it with sulfur 

removal processes commonly used in the petrochemical industry. Because cooling reduces the thermodynamic properties of syngas, plant designers would prefer a reliable and effective ‘‘warm gas’’ cleanup process (which is actually quite hot). This has 

been the subject of numerous DOE RD&D efforts, and new technical options are 

ready for pilot- and demonstration-scale testing so this needs to be emphasized in 

the DOE portfolio. 

To capture CO2 from a gasification combined cycle power plant, an additional step 

(known as water-gas shift) is added to the syngas cleanup train, in which water 

vapor and syngas react in the presence of a catalyst to form hydrogen and CO2. Established chemical industry processes can remove the CO2, leaving a high-hydrogen 

content that can be combusted in the gas turbine with little CO2 formation. Emerging technologies, such as membranes, may be able to separate the hydrogen from 

CO2 with less energy and in more compact vessels. One promising approach couples 

the membrane with the water-gas shift reaction, saving additional equipment, 

space, and cost and could benefit from additional support. 

Gas turbines designed specifically to combust high-hydrogen-content syngas are 

being built, tested, and commercially introduced. These will be essential to reliable 

and efficient gasification power systems with CO2 capture and compression. DOE 

development and demonstration funding has contributed to success in this area. 

Equally important in EPRI’s view is RD&D to move gas turbine technology to higher firing temperatures to improve efficiency and output—for both conventional and 

high-hydrogen syngas. EPRI economic analyses show larger and more efficient gas 

turbines to be perhaps the single most important step to improving integrated gasification combined cycle power plant economics. Although the commitment of gas 

turbine manufacturers is essential to ultimate success in realizing new commercial 

offerings, advances in the underpinning materials, design concepts and integration 

engineering can advance with DOE and industry cooperative efforts. 

Many gasifier designs use a nearly pure oxygen input to the gasification reaction. 

That oxygen has traditionally been produced by cryogenic air separation units, 

which tend to be large, expensive, and large energy consumers. DOE has been funding lower-energy alternative oxygen production technologies, and EPRI has assembled an industry team to participate in one such effort, the scale-up and testing of 

Air Products’ ion transport membrane (ITM) technology. EPRI is assisting in assuring that the product design and test program meet power company ‘‘real world’’ operation and maintenance criteria and also in gasification plant integration engineering. 

EPRI believes that this model of cooperative DOE, industry team, and technology 

developer RD&D speeds the path to successful deployment and attainment of elec-
70 

tricity cost reductions for the American economy. EPRI is also investigating whether 

a variation in the process can be used for supplying oxygen to future oxygen-fired 

systems (an early example of an oxygen-fired system is the FutureGen 2.0 project). 

Additional development and demonstrations in this area can support cost, efficiency 

and energy security from a variety of coal utilization processes. 

Gasification power plants will also benefit substantially from improvements in 

process measurement and control. For example, durable fast sensors that provide 

real-time readings of temperatures and gas composition within the gasifier would 

provide operators with more accurate and timely measurement of syngas heating 

value, which in turn could be fed forward to power block controls. For the last several years, an EPRI program has been investigating the use of laser-based sensors 

for this purpose, and scale-up and demonstration funding is still needed. • For additional information on gasification power plant RD&D opportunities, 

refer to EPRI publication 1023468, Advanced Coal Power Systems with CO2

Capture: EPRI’s CoalFleet for Tomorrow Visionr – 2011 Update. 

Sustaining vital DOE RD&D on CO2 capture, utilization, and storage 

EPRI’s analysis of options needed for the future validates DOE’s high 

prioritization of RD&D to establish effective, economical, and publicly acceptable 

technologies to reduce atmospheric greenhouse gas buildup. This supports DOE’s 

work on coal-based technology including CO2 capture at power plants, cost-effective 

cleanup and compression for on-site geologic injection or transportation off-site, CO2

utilization where economical, and secure long-term storage away from the atmosphere. In particular, EPRI identifies the following current work as warranting continued RD&D to achieve the cost and efficiency improvements necessary to allow 

viable commercial deployment: 

1. R&D, scale-up, and integrated operation of coal power systems based on gasification and oxy-combustion technologies (presently through Clean Coal 

Power Initiative and American Reinvestment and Recovery Act funding, loan 

guarantees, and other mechanisms plus base program DOE funding) 

2. CO2 capture, compression, and storage RD&D to seek breakthrough innovations for low-cost capture, lower-energy compression, and for larger scale integrated projects, to understand operational flexibility, cost reduction options, and techniques to verify long-term storage 

3. CO2 utilization: because CO2 used for enhanced oil recovery (or other means 

of generating revenue) will be essential to jump-starting CCS deployment, 

and may also help in reducing dependence on foreign oil, additional geologic 

characterization of areas near concentrations of power plants may be a logical follow-on under the DOE regional carbon sequestration partnerships 

programs 

Chairman HARRIS. Thank you, and I thank the panel for the testimony. Reminding Members Committee rules limit questioning to 

five minutes. 

The chair at this point will open the round of questions, and I 

recognize myself for the first five minutes. 

Mr. Klara, let me just ask a question. The CCS projects that 

were funded from the first Stimulus Bill, was the total allotted 

around a little over $3 billion? Is that correct? 

Mr. KLARA. The Stimulus Bill provided $3.4 billion but not all 

that went to demonstrations. 

Chairman HARRIS. How much of that—— 

Mr. KLARA. Probably about a little more than $2 billion went to 

demonstrations. 

Chairman HARRIS. And of that $2 billion how much has been 

spent in the last year and a half? 

Mr. KLARA. The spending on the Stimulus so far is probably in 

the neighborhood of $500 million. 

Chairman HARRIS. So the Stimulus Bill passed a year and a half 

ago, which was supposed to provide immediate jobs obviously at 

least $1–1/2 billion of that is sitting around, something that you 

are waiting to spend. 
71 

Mr. KLARA. Well, the—— 

Chairman HARRIS. Or can be spent but has not been spent, 

hasn’t created a job. 

Mr. KLARA. No. There have been some jobs created with—— 

Chairman HARRIS. Out of that $1–1/5 billion that hasn’t been allotted. Is that an accurate representation of the timeline of things? 

Mr. KLARA. Yes. 

Chairman HARRIS. Okay. Those projects, of the ones that are 

going to be, that were funded, what is your belief, how many of 

those will be successfully implemented to the point where all that 

money will be spent? 

Mr. KLARA. Well, we have had one project drop out which was 

indicated by Mr. Akins. 

Chairman HARRIS. Okay. 

Mr. KLARA. Our AEP project. We have seven projects currently 

being funded with Stimulus dollars, and right now all of those 

projects continue to go forward in a positive direction. 

Chairman HARRIS. Now, was there any project further along 

than the AEP project? 

Mr. KLARA. Yes. We actually have three projects that are—have 

already started construction. One is with Southern Company, another is with Archer Daniels Midland, and another with Air Products. So, yes, three of the projects are actually starting construction, and I would add, too, that the Stimulus requirements were 

pretty specific on putting a lot of the money on what we call these 

demonstration projects, and I think what you will hear from members of the panel is when you deal with building demonstration 

projects, retrofitting a plant or building an entirely new plant—— 

Chairman HARRIS. Right. 

Mr. KLARA. —that the spending profile was such that it takes a 

couple—— 

Chairman HARRIS. Yes. They are not shovel ready, are they? 

Mr. KLARA. No. Correct. 

Chairman HARRIS. Right, and so that is what I thought. 

Let me ask a question, Mr. Dalton, I guess if I summarize your 

testimony, you kind of believe that we really ought to have a diversified approach to research on these coal-related areas. 

Mr. DALTON. Yes, Mr. Chairman. 

Chairman HARRIS. Okay. 

Mr. DALTON. Absolutely. We need all the options, coal, nuclear, 

renewables, several options. 

Chairman HARRIS. So that the movement in certainly with regards to the Stimulus Bill and in the President’s budget toward 

really a concentration on just CCS with really decreased funding 

to the other areas is probably in your opinion might not be the 

right direction to go. 

Mr. DALTON. Well, we see that the addition of work on very high 

efficiency, getting that to the—— 

Chairman HARRIS. Right. 

Mr. DALTON. —demonstration stage is critical, and there are new 

areas that are opening up partly due to regulation, on water and 

HAPs—that are requiring some additional—— 

Chairman HARRIS. Right. There might be very useful places for 

that funding. Yes. I can understand that. 
72 

What is the—and a question to Mr. Akins and Ms. Gellici, I 

mean, what is the future for, the outlook for building new power 

plants? Mr. Akins, you have said you have one, the ultra-supercritical plant under construction. If I could just ask about how much 

more does that cost to build than a regular plant in a conventional, 

I guess we call them sub-critical plants. 

Mr. AKINS. Typically a sub-critical plant would probably be on the order of $1.5 billion, maybe $1.6 billion. This one is around $2.1 

billion to $2.3. 

Chairman HARRIS. And it consumes how much less fuel is your 

consumption per—— 

Mr. AKINS. Eleven percent. 

Chairman HARRIS. Eleven percent less, and of course, with that 

it is also less pollution because you are burning less fuel I take 

it—— 

Mr. AKINS. Yes. Absolutely. 

Chairman HARRIS. —with that. Okay, and so to the rate payer, 

I mean, what is your estimate of how much that increases the cost 

of the electricity? 

Mr. AKINS. Generated? 

Chairman HARRIS. Yes. 

Mr. AKINS. For the power plants? 

Chairman HARRIS. You go to the ultra-supercritical versus the 

conventional. 

Mr. AKINS. Over the lifetime of the plant—— 

Chairman HARRIS. Yes. 

Mr. AKINS. —it will be relatively negligible compared to the subcritical. 

Chairman HARRIS. Negligible. 

Mr. AKINS. And from an environmental standpoint you—— 

Chairman HARRIS. Beneficial. So the testimony we have heard, 

and well, I guess we didn’t hear it but I was going to ask Mr. Klara 

actually to substantiate that, is it true that, in fact, a goal is only 

a 30 percent increase in costs? 

Mr. KLARA. Well, we have two pathways. 

Chairman HARRIS. Right. 

Mr. KLARA. The one pathway is for new plants gasification which 

would be 10 percent—— 

Chairman HARRIS. Right. 

Mr. KLARA. —and the other is for pulverized coal-based systems, 

which is what you are talking about with Mr. Akins, and yes, there 

is a 35 percent increase with the cost of adding—— 

Chairman HARRIS. For the CCS technology. 

Mr. KLARA. Correct. 

Chairman HARRIS. Right, but when you are talking about ultrasupercritical, that is not—that has nothing to do with CCS. Right? 

That is just thermal. 

Mr. KLARA. That is correct. 

Chairman HARRIS. Right. So, in fact, if what you are looking to 

do is decrease pollution and keep the costs over the—of the lifecycle 

of the plant relatively stable, you wouldn’t pick a CCS technology, 

I mean, because, I mean, if our, I mean, I can guarantee that if 

our research goal is to only increase the cost by 30 percent, it is 

going to increase at least 30 percent. Is there any reason to believe, 
73 

Mr. Klara, that we are going to hit below that target in the next 

few years for increased costs? Well, we won’t know until the demonstration projects are done, I guess. 

Mr. KLARA. Well, yeah. You are correct that when you add CCS 

to a plant that it adds cost. Within our program we are trying to 

look at a no-regrets path forward, and part of that no-regrets, for 

example, is that if you could use the carbon dioxide that is captured for valued-added stream back such as enhanced oil recovery, 

now you can potentially have a scenario where it is—— 

Chairman HARRIS. Sure. A win-win. 

Mr. KLARA. —neutral. Yeah. Win-win. 

Chairman HARRIS. Right. 

Mr. KLARA. Right. 

Chairman HARRIS. Thank you. 

Mr. Miller. 

Mr. MILLER. Thank you, Mr. Chairman. I was Chair of the Subcommittee on Investigations and Oversight of the Science Committee in the two previous Congresses to this one, and questioned 

and criticized the Bush Administration for pulling, without explanation, the funding for Future Gen, which was the principal, very 

ambitious carbon sequestration effort for coal. So I do support R&D 

for the coal industry. 

Mr. Dalton urged DOE to help the coal power industry meet competitive challenges. Ms. Gellici, Ms. Gellici, by the way, I appreciate your using, speaking slowly and using—avoiding big words in 

your testimony so I could understand it. You said that the sole 

focus on basic engineering and research will not advance commercial technologies to the marketplace, and the Department of Energy 

funding of late-stage, large-scale demonstration activities advances 

the efficiency, reduces capital costs, and increases the commercial 

availability of the advanced coal technologies. 

Do all of you agree with those statements? Do any of you disagree with those statements? I am not seeing any movement at all. 

Either heads up or down. I assume no one disagreed at least. 

Why does, again, I supported research, R&D funding for Future 

Gen but why is the coal industry not capable of doing that research 

themselves? The basic research, to applied research, to demonstration on their own. What are the reasons that justify government 

funding for research that helps that industry? 

Mr. Akins. 

Mr. AKINS. Sure. I will be happy to answer that. You know, when 

you start with these technologies, it is basically bench-top scale, 

and then it moves to more proving the technology. Moving to commercial scale is an entirely different approach where the magnitude of the dollars associated with it are important to be able to 

deal with from a cost-recovery perspective. In our business we have 

to be able to recover our costs from someone, and we invested over 

$100 million dollars on the integrated carbon capture and storage 

project I talked about, and our shareholders wound up footing that 

bill. 

For—to upscale this project to another CCS project would be on the order of $700 to a billion dollars, and when you talk about that 

kind of dollar commitment, there has to be some sense of certainty 

around not only legislation or regulation but also for us to be able 
74 

to recover from our costs from the customers. We have to be able 

to have some requirement to do so. 

Mr. MILLER. So the funding for that research and development 

does not crowd out private investment in innovation? 

Mr. AKINS. The funding for the research if the government were 

to fund it? 

Mr. MILLER. Right. 

Mr. AKINS. If the government were to fund that type of research, 

we could advance the technology. 

Mr. MILLER. And it wouldn’t discourage private investment. It 

wouldn’t crowd out private investment. 

Mr. AKINS. I think at the demonstration scale you could have private investors involved with that as well. 

Mr. MILLER. Okay. 

Mr. AKINS. I think it is a public-private partnership. 

Mr. MILLER. All right. Well, do you think that the same arguments apply to the less mature technologies? One of you suggested 

we should be doing all coal and nuclear and the newer technologies 

as well. Do the same arguments not apply to them, and if not, why 

not? 

Mr. AKINS. Are you asking me? 

Mr. MILLER. Yes, sir. You were—you volunteered earlier so—— 

Mr. AKINS. Okay. Yeah. I think the advancement of the technology is needed regardless. If we are going to have a secure energy future in this country, it includes all resources, and the government has to be very selective about—and make sure we maximize the value of taxpayer funds to support these kind of investments, but it is clearly important to advance the technologies on 

all fronts. 

Mr. MILLER. Mr. Foerter, the industry often has estimates on 

what compliance with EPA regulations will cost, and it usually assumes the worst possible case, the most expensive, the most time 

consuming, retrofits, wet scrubbers, cooling towers. All that will be 

required. But it appears in most cases there are other technological—there are other technology options that are less costly and 

can be implemented more quickly. 

Could you describe the options the power companies might have 

and what the biggest factors are in how they choose between technologies, how to proceed, what the technological readiness is of 

those various options? 

Mr. FOERTER. Yes. In fact, that is an astute difference between 

the difference of trying to predict what is going to go into the marketplace and what the marketplace actually creates. When EPA 

makes predictions, they use big monolithic type of technologies, 

and that is where the big costs come out. 

But when you get into the marketplace and there is—it is quite 

different, and quite frankly, our industry moves with that market, 

what the demands are and what the changes are. Things like ash 

handling and water cooling issues. All those things start to come 

in. We start looking towards dryer systems, so a wet scrubber becomes not the favorite, and you start moving down that same chain 

and looking at dry systems or direct sorbent injection kind of systems. Direct sorbent injection installed in a couple of months. A 

wet scrubber takes 30 plus months to install it. 
75 

So it is very different in that kind of thing. Wet scrubbers, very 

expensive, direct sorbent injection, relatively inexpensive. Your 

cost—the biggest cost there is going to be the reagent that you are 

continually feeding into the system. You turn it on, and you turn 

it off, and that is where your costs begin and end. 

So we have really diversified within our system, and I, when I 

talk about our pollution control technologies, if I started to move 

towards saying just wet FGD for scrubbing, you know, there would 

be a lot of my members who would be very unhappy because they 

are all out there competing in the marketplace to sell all the different suites of technologies, and the same thing happens with 

NOx and every other pollutant that is out there. 

Mr. MILLER. My time has expired. 

Chairman HARRIS. Okay. Thank you. The gentleman from Maryland. 

Mr. BARTLETT. The other gentleman from Maryland. Thank you 

very much. 

We use energy in basically two different forms. We use electrical 

energy for a great variety of things, and we use liquid fuels, and 

it is hard for us to compare the relative costs of those because they 

are used in very different domains. 

But when we can use them for the same thing like in an electric 

car, we find that you have about half the cost per mile in the electric car that you do in a car using liquid fuels. So we know that 

the electric power is much cheaper per unit of power than liquid 

fuels. The average American should be a big fan of coal because the 

electricity is so cheap largely because coal is the source of the base 

load production for most of our electricity. 

Ms. Gellici, you said that we have 200 years of coal. Is that a 

current use rate? 

Ms. GELLICI. That is correct. Yeah. 

Mr. BARTLETT. Okay. Be careful when you hear somebody say we 

have so many years of something at current use rates. Do you suspect that we will increase the rate at which we use coal? 

Ms. GELLICI. Yeah. The latest projections are that we will probably increase our use of coal by about 25 percent. 

Mr. BARTLETT. Twenty-five percent. Wow. Do you know what 

that does? If you increase the use of coal only two percent—— 

Ms. GELLICI. Uh-huh. 

Mr. BARTLETT. —two percent growth of something, it doubles in 

35 years. It is four times bigger in 70 years, it is eight times bigger 

in 105 years, it is 16 times bigger in 140 years. That means that 

your 200 years of coal, if we increase its use only two percent, you 

suggested 25 percent, that dramatically reduces the time. But if 

the increase is only two percent, that 200 years now shrinks to 70 

years. So be very careful when you hear somebody say we have so 

many years of something at current use rates, because our economy 

is growing, our use of energy is growing. That is very likely to increase. 

You know, that is not a very long time, is it? Seventy years. And 

then it is all gone if we increase its use only two percent. You said 

we might increase its use 25 percent, which would dramatically reduce the time that it is available to us. 
76 

I would ask to have a couple of slides loaded into our little magic 

system. I don’t know if it did or not but—oh, there they are up 

there. Okay. Well, I can’t read the end of that. Does that say 35 

years or 30 years? That one says 35 years. Okay. We are talking 

about secure energy future, and this is a chart produced by the 

IEA. This is a creature of the OECD, one of the two best entities 

in the world tracking the use and predicting the continued production of liquid fuels. 

If you look at that, you will see if—I am sure that is—yes, that 

is the one that ends in ’35. They are predicting that by ’35, we will 

have, will be producing only 96 million barrels a day. Now we are 

producing 84 million barrels a day. Just two years before this their 

prediction had us in—by 2030, producing 106 million barrels a day. 

Notice the dramatic reduction in the production of conventional 

oil. That is the dark blue on the bottom. It is now plateaued for 

four years at 84 million barrels of oil a day. That plateau was 

reached in our country in 1970. 

With everything we have done since then since like finding a lot 

of oil in Alaska and the Gulf of Mexico and drilling more oil wells 

than all the rest of the world put together, today we produce half 

the oil that we did in 1970. The United States certainly has to be 

a microcosm of the world, and you see those two big wedges in 

there? The medium blue wedge and the light blue wedge, the light 

blue wedge is oil that we are going to get from fields that we discovered that are too tough to develop like under 7,000 feet of water 

and 30,000 feet of rock out in the Gulf of Mexico. The medium blue 

field there is fields yet to be discovered. Those two wedges, if the 

United States is any indication what will happen, will not occur. 

So we are talking about a secure energy future. The production 

of liquid fuels for the future is going to do in the world what it has 

done in the United States, and it is inexorable. We could not turn 

it around with all of our creativity and innovation, and so this is 

where the world is going, and we are talking about a secure energy 

future since that was a part of the title of our hearing, I just wanted to use this opportunity to present those graphs to show that we 

have got some big challenges facing us. 

Thank you all for what you are doing to help us have more energy. 

[The slides follows:] 
77 

SLIDES PRESENTED BY MR. ROSCOE BARTLETT, COMMITTEE ON SCIENCE SPACE AND

TECHNOLOGY
78 
79 

Chairman HARRIS. Thank you very much. 

I recognize the chairman, the gentleman from Texas. 

Mr. HALL. I thank you, Mr. Chairman. I want to talk a little 

about the EPA’s war on energy, which is really the President’s war 

on energy, which this Committee and this Chairman has devoted 

a lot of time and effort to examine over the last few months. 

Specifically, with regard to coal, we have looked at the science 

behind the whole package of Clean Air Act rules EPA’s pursuing, 

and we held a hearing in September on the Cross-State Rule. I 

don’t know if you all know about that or you remember about it 

or you read the reports within it, which would force the closure of 

significant coal-fired electricity capacity, even in my State of Texas, 

as close to me as I know about, and I don’t know how much other 

all over the country. But we would lose 500 jobs in one plant, in 

one little district there. 

EPA announced revisions to this rule last week after some weaknesses in the technical assumptions were exposed and after Dr. 

Broun and this chairman, Dr. Harris, and other subcommittee 

chairmen and Congressman Rohrabacher had raised that Billy 

Graham preaches against all the time on it, and I don’t think that 

is enough. And I have called for EPA to simply scrap the rule and 

start all over. 

My question is this, primarily Mr. Akins, but I welcome thoughts 

from anybody else that wants to chime in on it. How do the compliance deadlines under mercury MACT and the Cross-State rules 

compare with the time it takes to install the emissions control 

equipment necessary to achieve compliance with these rules? 

That is a question, and what happens when you can’t install 

equipment in time under these rules? 

Mr. AKINS. Chairman Hall, it is something we have done quite 

a bit of analysis on. It typically takes us about five years to put 

a scrubber in, and I think EPA had assumed three years. I don’t 

know where their numbers come from. I will let them cover their 

numbers, but with our numbers they are based upon substantial 

amount of work done. We spent $7.2 billion in the last—over the 

last decade putting in scrubbers and SCRs, Selective Catalytic Reduction devices. It typically takes about five years because we have 

to go through regulatory approvals with the In-State Commissions 

before we are able to move forward with the projects. And then by 

the time you get through with engineering, project design, construction, those types of things, a procurement of supplies, you are 

talking about five years. 

So—and as what we have looked at is the staging of all those 

projects, it is just impossible to get the number of projects done in 

that amount of time. If we—for AEP it would force the retirement 

of about 6,000 megawatts of generation. If you impute that, we are 

about ten percent of the coal-fired capacity in the country. That 

would be about 60,000, which is right in line of many of the studies 

that have been done. 

So if we can’t get the projects done, we either retire the units or 

we put them on idle. I mean, we just don’t run them for a period 

of time, but then that capacity is not available to customers during 

peak periods like in Texas over the summer. 
80 

Mr. HALL. Well, listening to your figures I think in the CrossState rule I think they gave from now to the first of the year—— 

Mr. AKINS. That is right. 

Mr. HALL. —to correct that. Just impossible. Absolutely impossible to do that. Impossible even to plan it probably. 

Mr. AKINS. That is right. 

Mr. HALL. And yes, ma’am. 

Ms. GELLICI. Yes. I think this is one of other major differences 

between the current regulations as proposed and the ones that we 

had seen in the past. We have much success in meeting the SO2

and NOX reduction regulations that have been imposed in the past 

because we had a five to ten year compliance schedule. The Acid 

Rain Program was passed in 1980, and we had five years, five to 

ten years for compliance. 

What we are looking at now is extremely truncated compliance 

deadlines, sometimes three years if we are lucky but oftentimes 

much shorter. So—— 

Mr. HALL. Well, thank you for that, and Mr. Akins, another 

thing. Can you explain how the new EPA rules could threaten the 

electric grid reliability? Just address that. I think I have—— 

Mr. AKINS. We have done—— 

Mr. HALL. —about 30 seconds left. 

Mr. AKINS. —an extensive amount of analysis. When you look at 

the security of the electric grid, these plants are located in particular areas for reasons, and primarily they supply black start 

which restarts the system in a blackout or voltage support, which 

supports the voltage so that, basically so power could be delivered 

where it needs to be delivered. 

So you look at these plants in these localized areas, if you truncate all these units at one time, then we are essentially shutting 

them down, and they are not available to the grid. And in that context you are dealing with serious reliability implications, and we 

have looked at it on our system in a lot of detail and have confirmed that is the case, and in fact, the regional transmition organizations like ERCOT, Southwest Power Pool, and PJM have 

verified that. 

Mr. HALL. I thank you, and my time is up. I thank you for your 

service, each of you, and for coming here today, and I thank the 

chairman for holding this hearing. 

I yield back. 

Chairman HARRIS. Thank you very much, and we still have time 

before we have to go to see the President of Korea, so we will have 

another round of questioning. 

I will recognize myself for the first five minutes. 

Mr. Klara, let me ask you, is—if those additional projects fail to 

be—to reach completion, the CCS projects with the Stimulus 

money, what happens to that money that is not spent? And I guess 

we can just ask upfront, you know, the AEP project that is not— 

it looks like it is not going to continue. I mean, is that money going 

to come back to pay down the deficit, does it—what does it do? 

What happens to that money? 

Mr. KLARA. Well, what we know or what I know is that any of 

the Stimulus funds will go back to the Treasury. Where it goes 
81 

from there is beyond my ability to know, but, yes, any of the Stimulus funding that is not used will go back to the Treasury. 

Chairman HARRIS. Okay. So that is your belief. Okay. Very good. 

I am glad to hear that because we got a little deficit running. 

I am going to ask you also, you know, I think everyone kind of 

acknowledges cap and trade isn’t going anywhere, and in the absence of cap and trade, you know, they probably—I would imagine 

there is really no economic way that you could have carbon restrictions that wouldn’t make electricity rates skyrocket. 

So given that what is the Administration’s position on the future 

of coal in America? I mean, is it—is CCS really going to be financially viable at all unless you had a cap and trade system? I 

mean—— 

Mr. KLARA. Well, we have tried to design the program as a noregret strategy as I somewhat inferred earlier, and what I mean by 

that is we have tried to design it such that the key developments 

that come out of the program are going to be valuable whether 

there is a carbon—— 

Chairman HARRIS. Well, let us assume that that is not scalable. 

Let us just make the assumption that we are not going to grow 

enough algae to use the CO2, and we are not going to, you know, 

that, yes, there will be some secondary oil recovery, but let us assume that that is a minimal benefit. Or is that what the Administration is banking on, that we are actually going to have some incredible breakthrough, and we are going to be able to use every 

molecule of CO2 from a burnt piece of coal to do something else? 

Mr. KLARA. Well, we believe, looking at the R&D portfolio and 

if it is successful. So if you make the assumption that it can be successful—— 

Chairman HARRIS. I know, but Solyndra made the assumption, 

too, and it is a lot of money and a lot of effort that it goes to the 

negation of other efforts. It is really the bottom line of the hearing. 

So—but I think you have answered the question, so thank you for 

that. 

Mr. Foerter, you made the statement that building new plants is 

problematic, but Mr. Akins sitting next to you said, wait a minute. 

They just built an ultra-supercritical plant, and it is going to have 

negligible effect over its lifetime on the cost of energy, and it is 

going to burn cleaner, it is going to burn more efficiently. Why do 

you say it is problematic? 

Mr. FOERTER. Well, and we agree on the thermal efficiency and 

it is a better, you know, it has an upfront CO2 benefit from it as 

Janet Gellici kind of talked about in the different levels, and if you 

ask Mr. Akins about how long it took to go through that permit 

and how problematic that process may have been, it was very, very 

difficult. 

Chairman HARRIS. So it is the regulations you mean? 

Mr. FOERTER. It was a process of trying to get—there is no infrastructure right now that allows for power plants to be built without 

sort of a CO2 kind of issue. So the real issue comes back to CO2. Chairman HARRIS. Right. So if we negated the CO2 issue, let us 

say we put it on hold for awhile, we could build plants that actually are more efficient and cleaner and could supply energy from 

coal. 
82 

Mr. FOERTER. Well, the idea was that we were going to build new 

plants that could be retrofitted with a technology which would be 

proven, and that that is what AEP and others were trying to do. 

But building new plants, there is an upfront—— 

Chairman HARRIS. Let me just clarify something because the 

plant Mr. Akins is building actually produces less CO2 per unit of 

energy. 

Mr. FOERTER. But they go through permit processes which are 

strenuous—— 

Chairman HARRIS. Right, but it—just so, I mean, there are ways 

to do it without sequestration I guess is what I am getting to with 

that. 

Mr. FOERTER. Well, up front you do get the reduction. Eventually 

you are—if you are trying to look to a 70 or 90 percent reduction 

on the CO2, you are going to start using like a technology they 

were trying to demonstrate fully, scale, and that is the chilled ammonia chilled ammonia process which was working well at a smaller scale. 

Chairman HARRIS. Right. 

Mr. FOERTER. They are getting ready to go to the next level. 

Chairman HARRIS. I don’t know. It sounds like an ultra-supercritical might be the next level. I mean, your testimony did mention the availability of dry sorbent injection as a technology option, 

pollution control, but as you know, EPA’s proposed utility rule relies heavily on this technological fix. 

Which coal-fired units in the United States utilize that dry sorbent injection to capture more than 90 percent of acid gases? 

Mr. FOERTER. Well, the dry sorbent injection and EPA’s—we 

even commented on this. We think they have overused the DSI 

part of it. We think they will go drier systems, which are dry scrubbers and circulating dry scrubbers. We don’t think we are necessarily going to see the wet type scrubbers that Mr. Akins was 

talking about that take five years to put in place. We will see something that takes a lot less install time, permits still have to be 

found, but we think that EPA, and we have told them we—— 

Chairman HARRIS. Those permits again. Thank you very much. 

I am out of time. 

Mr. FOERTER. Those permits are always there. Yeah. 

Chairman HARRIS. I recognize Mr. Miller. 

Mr. MILLER. Thank you, Mr. Chairman. 

I have questions that kind of pursue the line of questioning I had 

earlier for Mr. Foerter. Critics of the EPA regulations say that the 

regulations will cause, will force a number of coal plants to close 

and even compromise the reliability of our electric system, but the 

projections of the number of retirements do vary greatly, and the 

estimates as Mr. Foerter said of costs also vary greatly. And it appears that some that are supposedly going to close because of EPA 

requirements were scheduled to retire anyway. That happens. 

Plants wear out and also technology becomes obsolete. It is replaced by other technologies. 

Do any of you see the likely coal plant retirement rates—or, how 

do you see the likely coal plant retirement rates under current expectations, business as usual, versus that under EPA regulations? 
83 

Mr. FOERTER. If I could, if you have been watching, you sort of 

have a trend of what the announcements are for retirements and 

what the predictions are. I just saw one yesterday. ICF had said 

68 megawatts or gigawatts in retirement, have now revised that 

down to around 40. There has been—so you start putting more and 

new information in, including final rules, not proposed rules, information. You start seeing those numbers of retirements come down 

quite a bit. 

But on these plants we have 50 and 60-year-old air pollution control technologies on some of these plants. So, the technologies wear 

out, the boilers can wear out, the technologies are put on them, 

wear out. They lack any useful life in them. 

So some of these are not even supplied with coal anymore, and 

so they are just sitting there waiting for a decision to be made, and 

decisions are starting to be made. 

Mr. MILLER. Okay. Can the rest of you kind of roughly describe 

what plants you think might be retired and how they compare in 

age and efficiency and the environmental profile compared to the 

rest of the coal fleet? 

Mr. AKINS. Well, typically, I can speak for our system. We have 

several of the 50, 60-year-old units, and the units continue to operate fine. You have made a lot of capital commitments associated 

with the continuing operation of those plants. 

One thing I wanted to clarify was when we talk about—they 

were slated to retire anyway, that is true. We plan on retiring several of these units through the 2020 timeframe and beyond. The 

issue is the compliance time that forces those retirements on an 

earlier basis. 

So if we are talking about 2014, or 2015, you are effectively truncating all of these units at the same time, and that is the part that 

we have an issue with. These units are going to gradually retire. 

They are intended to do that. We will make decisions on the scrubber technology, on whatever, dry sorbent injection or whatever, but 

many of these units will probably not survive, but we know that, 

and we are making that transformation to a new energy future, I 

think. My biggest issue is that people need to have the patience to 

get there. I mean, this is a heavy capitalized industry, and when 

we talk about retiring units, they are done over time, they are done 

in the manner to preserve the reliability of the system, and to mitigate cost increases to customers. 

So those are the kinds of things we look at. 

Mr. MILLER. Do the regulators, in fact, have the authority to disallow closing a plant if it would threaten reliability, electrical reliability? 

Mr. AKINS. Yes. They do. The in-state regulator would have to 

give approval for retirement of the units. 

Mr. MILLER. Right. 

Mr. AKINS. And reliability of—the priority in that, they have the 

resource requirements within the state, the regional transmission 

organizations, they also have the authority which is an extension 

of FERC, and then obviously if the EPA requires something, then 

we are stuck between three agencies trying to determine what the 

heck to do. 
84 

Mr. MILLER. Okay. Mr. Foerter, you said that some of the estimates of cost were high because they assume that the most expensive technology would have to be used, but do you think the estimates about forcing plants to close would change when the industry really did look at the technological, regulatory, and financial options available to them? 

Mr. FOERTER. Yeah. I think it would change because they were 

looking at it like the example I would use with Mr. Akins was five 

years for building this scrubber. Well, we are not building any big 

scrubbers like that anymore, and for that first 75 percent, we were 

building lots of big wet scrubbers. I mean, that is what we spent 

our last five to seven years doing. 

As we move into the future, we are moving towards things that 

have less capital cost, so if you got an old car, and you want to— 

you try to fix it up a little bit, you are not going to go in there and 

put a new engine, a new transmission and everything else. You are 

going to try to do what you can with less capital costs. It might 

mean you use some fuel additives, some things to keep it going, 

and that is exactly what is happening, could happen in this industry. We can keep these things running as long as we can. 

There was a good testimony in another hearing where they said 

they tried to close down a power plant, and then they went through 

this due diligence process, took 29 months for everybody to agree 

this is how they were going to do a closure on that plant for reliability issues. So it does work really well. We have a lot of confidence. In fact, we have heard that reliability card used many, 

many times before and it just doesn’t happen, and we have done 

some very, very big capital projects like SCR where the boiler goes 

out for quite a bit and FGD, where these are much bigger tax construction projects. 

So it hasn’t happened in the past. I am not exactly sure why I 

think it is going to happen in the future. 

Mr. AKINS. If I could respond to that, is it okay? 

Mr. MILLER. Sure. It is up to the chairman. My time has expired. 

Chairman HARRIS. Sure. 

Mr. AKINS. Okay. The first thing is we have spent $7.2 billion on 

investments in scrubbers and SCRs. We continue to build large 

scrubbers and SCRs throughout out system. For 500 megawatt 

units, for 1,300 megawatt units, and we have achieved over 80 percent reduction in SOx and NOx emissions from our power plants. 

To get the other 20 percent or 15 to 20 percent is another $6 to 

$8 billion, and that is what we are slated to spend in the future 

on these plants. So, there are smaller, more elegant solutions that 

are cheaper, that are less efficient, but scrubbers and SCRs continue to be built. 

Mr. FOERTER. If it is helpful, as they start building—that means 

that these units they expect to keep around for a long time, and 

they are willing to make the large capital investments, and the 

way that the Clean Air Act is set up and particularly the max 

standards is there is more time than is provided there. In fact, we 

have used that more time in many other industries. Someone was 

telling me about metal smelters. You can’t just shut a unit down 

and not have, you know, you still have to have the capacity. 
85 

Same thing happens here. There is lots of flexibility, and EPA 

has reached as hard as they can finding that flexibility, and I think 

they have done a pretty good job. No one is going to shut down 

units that are critical to reliability in the Nation’s power. 

Chairman HARRIS. Thank you. Let me just take 30 seconds for 

a follow-up with Mr. Akins. 

The—with regards to the dry sorbent technology, is that an answer for a lot of your plants? That is something that you are—— 

Mr. AKINS. Yeah. We are utilizing dry sorbent technology, but in 

a lot of cases you get the maximum benefit for scrubber, for removal efficiencies you are going to the larger scrubbers, and for the 

larger units that is what you put in place. 

Chairman HARRIS. The dry sorbent? Not—you can’t do it. 

Mr. AKINS. We have dry scrubbers, we have wet scrubbers but— 

and the dry sorbent injection is a smaller, less—— 

Chairman HARRIS. Smaller scale. 

Mr. AKINS. —efficient solution. 

Chairman HARRIS. Thank you, and before we—and in the last— 

if you would in the last minute, I am just going to ask each of you 

if—we are going to, obviously going to spend money on CCS. We 

are going to spend research money that is in the pipeline. What 

should our number two priority be with regards to governmentfunded coal research? 

Just go down the line. Mr. Klara. What do you think? You had 

a chance, all of you had a chance to look over what you think we— 

where you think we should be spending the money. 

Mr. KLARA. Well, I think many of the things that were mentioned here, for example, water management is a key. 

Chairman HARRIS. You think water management. 

Mr. KLARA. And you have heard that time and time again. 

Chairman HARRIS. Okay. Ms. Gellici. 

Ms. GELLICI. Efficiency improvements. I think even just through 

simple operations and maintenance techniques we can pick up 

three to five percent efficiencies at our existing power plants. We 

have got some new source review issues that are preventing us 

from doing that, but there is still quite a bit of low-hanging fruit 

out there that we can reduce not just criteria, pollutants, but SO2

as well. 

Chairman HARRIS. Okay. Mr. Akins. 

Mr. AKINS. Yeah. I would agree efficiency improvements. 

Chairman HARRIS. And including thermal energy—— 

Mr. AKINS. Yes. 

Chairman HARRIS. —improvements? 

Mr. AKINS. Yes. 

Chairman HARRIS. And Mr. Foerter? 

Mr. FOERTER. Yeah. The thermal efficiency of new power plants 

as I previously had talked about. There is—you need to test these 

things out. I mean, the TURK Plant is an ultra-supercritical or 

supercritical, so we want to keep pushing that envelope. You can 

get up to 50, maybe 51 percent. Those are huge benefits as you get 

out there. They do need to be tested and maybe not through the 

public permitting process. 

Chairman HARRIS. Mr. Dalton. 
86 

Mr. DALTON. All of the above. Actually, efficiency and water 

both—— 

Chairman HARRIS. Okay. 

Mr. DALTON. —are—— 

Chairman HARRIS. Listen, thank you very much to the panel for 

your testimony. It has been very eye opening. If any Members have 

additional questions for the witnesses, we ask you to submit them, 

and we are going to ask you to respond to them in writing. The 

record will remain open for two weeks for additional comments 

from Members. The witnesses are excused, and the hearing is adjourned. 

[Whereupon, at 3:43 p.m., the Subcommittee was adjourned.] 
(87) 

Appendix I: 

ANSWERS TO POST-HEARING QUESTIONS
88 

ANSWERS TO POST-HEARING QUESTIONS

Responses by Mr. Scott Klara, Deputy Director, 

National Energy Technology Laboratory 
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Responses by Ms. Janet Gellici, CAE, 

Chief Executive Officer, American Coal Council 

Question Submitted by Chairman Andy Harris 

Q1. As we examine the future of coal in America, it is important to consider what 

the President said in November 2008 about the outlook for coal under his Administration. He said that ‘‘if somebody wants to build a coal-powered plant, 

they can. It’s just that it will bankrupt them.’’ The American Coal Council’s 

member companies are in the business of building and operating coal plants. 

What is the status of and outlook for building new plants? And if new power 

plants do not move forward, what does that mean for electricity supply and reliability? 

A1. In response, I would reference a recent Burns & McDonnell which evaluated 

the existing coal fleet in compliance with various EPA regulations, including a) the 

proposed Clean Air Transport Rule (CATR)—now known as the Cross State Air Pollution Rule (CSAPR), b) National Emission Standards for Hazardous Air Pollution 

(NESHAP)—utilizing the proposed Industrial Boiler MACT rule as a proxy since the 

proposed Utility MACT had not been introduced yet at the time, c) Coal Combustion 

Residue Regulations and d) Clean Water Act Cooling Water Requirements under 

sections 316(a) and 316 (b). 

B&Ms analysis indicated that these regulations would require approximately $135 billion in retrofit capital costs and $8 billion/year in additional O&M expenses. The 

additional costs associated with retrofit equipment are expected to increase the U.S. 

average electricity price by approximately 8%. These costs would force high-cost, 

smaller units to retire and would force some mid-cost, mid-sized units to retire with 

most to be retrofitted with compliance pollution control equipment. Most low-cost, 

large units would be retrofitted. 

Announced coal-fired plant retirements as of the summer 2011, total 161 units = 

26.5 GW; this represents 7% of the fleet on a capacity basis and 14% of the fleet 

on a unit basis. B&M believes that 40–50 GW of coal generation will be retired due 

to low utilization, current coal and gas costs, and upgrade investments. Other industry analysts have projected retirements on the order of 60-80 GW this decade. 

Another study prepared by NERA Economic Consulting examined the same EPA 

regulations and concluded that these policies would lead to 39 GW of prematurely 

retired capacity by 2015, about 12% of 2010 U.S. coal-fired electricity generating capacity. Compliance costs were projected to be approximately $21 billion (in 2010$) 

per year over the period from 2012 to 2020. Capital costs for environmental controls 

and replacement capacity are about $104 billion. 

According the NERA study, ‘‘Coal-fired generation is projected to decrease by an 

average of 11.1 percent over the period from 2012 to 2020. The reduction in coal 

demand is projected to decrease coal prices by 5.7 percent on average. In contrast, 

the regulations are predicted to increase natural gas-fired generation by 19.7 percent on average over the period and increase Henry Hub natural gas prices by 10.7 

percent on average. The increase in natural gas prices would lead to an estimated 

average increase in costs of about $8 billion per year for residential, commercial and 

industrial natural gas consumers, which translates into an increase of $52 billion 

over the 2012–2020 period (present value in 2010 as of 2011 discounted at 7 percent). Average U.S. retail electricity prices are projected to increase by an average 

of 6.5 percent over the period.’’ 

The study further notes that ‘‘Over the period from 2012 to 2020, about 183,000 

jobs per year are predicted to be lost on net due to the effects of the four regulations. The cumulative effects mean that over the period from 2012 to 202, about 1.65 

million job-years of employment would be lost.’’ 

With regard to potential job losses, another report released in September 2011 indicates that efforts to curtail development of new coal plants are contributing to potential job losses of 1.24 million jobs in 36 states. 

The intent of the Clean Air Act was to ensure that new units met technology limits (New Source Performance Standards – NSPS), while existing units were regulated by air quality standards. Overtime, the fleet would get cleaner. EPA has 

changed the rules by forcing existing units to meet limits on a schedule which cannot be met without closing those units. Previous CAA programs made it possible to 

invest in emission controls at the economic units to obtain the greatest reductions. 

The newest, large units got NSPS technology while allowing the older units to continue to run, enhancing reliability of the electric supply grid. EPA used trading to 

allow for the most efficient investments to reduce emissions. New EPA programs require technology at all plants with limited trading. 
108 

Previous EPA programs provided a 5–10 year compliance schedule, e.g., acid rain 

regulations were passed in 1990 and required compliance at points in 1995 and 

2000; CAIR was promulgated in December 2003, requiring compliance at points in 

2010 and 2015. New EPA programs allow less than three years to comply, e.g., 

HAPS final rule is expected in December 2011 with compliance required by 2014; 

CSAPR final rule anticipated in August 2011 requires compliance in 2012 and 2014. 

It is reasonable, therefore, to assume that EPA is interested in closure of coal units, 

not control of coal-fired emissions. 

A combined reduction in coal-fired electricity and a greater reliance on natural 

gas is likely to result in an increase in the cost of electricity and a loss of jobs. Additionally, prospective coal power plant closures may result in significant challenges 

for the transmission and power system reliability. As noted by ICF International 

Inc. ‘‘Because system reliability must be ensured during these retirements, many 

plants slated for closure likely will be put into reliability must run (RMR) status, 

delaying their decommissioning timelines. Furthermore, significant challenges loom 

for plants in RMR status. RMR rules are not designed to support multi-year, highcapital retrofit investments but rather temporary status quo operations to address 

reliability concerns. Plants that fail to retrofit or retire by the deadlines specified 

in the EPA rules could incur heavy civil and criminal penalties. They could also affect market prices as uneconomic supply is kept on line.’’ 

ICF’s analysis indicated that the location of the prospective power plant retirements could significantly impact system reliability, not just from a resource adequacy perspective, but with transmission security in mind as well. Among the key 

study results: 

1. Event retiring moderate amounts of capacity can incur the risk of transmission 

security problems. 

2. Demand-side management can help mitigate a low-voltage situation, but cannot solve the problem when load reduction requirements are up to the 30 percent level. 

3. Sufficient replacement capacity is only part of the solution. The location of this 

capacity is also important.’’ 

‘‘Removing up to nearly one-sixth of the nation’s coal-fueled generation in a geographically concentrated manner, i.e., concentrated in MISO, PJM, and SERC from 

the power system has billion-dollar implications, and decisions are very difficult to 

reverse once the train has left the station.’’ 

Q2. In the current budget environment, it is imperative that DOE improves 

prioritization and pursue only the most important and impactful R&D. With 

that in mind, what would you change about the current DOE R&D portfolio? 

Specifically, what at the 1–2 areas that you believe deserve highest priority within DOE coal R&D? What are the 1–2 areas or activities currently supported that 

may warrant cuts in order to pay for the highest priority? 

A2. I will stand by my testimony in addressing this question. We need to focus our 

coal R&D efforts going forward in four areas: 

• Advanced Energy Systems 

• Carbon Capture and Storage 

• Water Use Technologies and 

• Demonstration Projects 

Given the current uncertainty that Congress will pass climate legislation in the 

near term, it might be tempting to curtail funding for Carbon Capture and Storage 

RD&D. The reality is that while GHG legislation may not be imminent, GHG regulation is proceeding and we need technologies to meet our long-term CO2 reduction 

goals. To be successful, RD&D funding needs to be stable and consistent. Curtailing 

the CCS technology program today could potentially negate gains we’ve made to 

date and impair our ability to meet future requirements. 

Q3. The National Coal Council is a Federal Advisory Committee tasked with advising the Secretary of Energy—at his request—on general policy matters relating 

to coal. The last three NCC reports focused exclusively on CCS and the Committee has not weighed in on non-CCS coal issues in over five years. As a member of the NCC, and in light of the increasing need to prioritize R&D efforts, 

do you believe there would be value in an NCC report detailing a long-term 

roadmap to advance entire system-wide advancements of a coal-fired unit to put 

DOE on a path towards facilitating a new fleet of coal plants? Would it be similarly beneficial if the NCC reviewed how best to meet stringent air toxics rules 

or handle toxic waste byproducts? 
109 

A3. I believe an NCC report detailing a long-term roadmap to advance clean coal 

technology developments would be duplicative of the efforts historically and presently being advanced by the Coal Utilization Research Council (CURC 

www.coal.org), in cooperation with EPRI and other industry associates. 

Does ‘‘toxic waste byproducts’’ refer to coal ash? Perhaps not since coal ash is not 

‘‘toxic.’’ If the question does relate to coal ash, I feel again that others, such as the 

American Coal Ash Association (www.acaa-usa.org) and the Utility Solid Waste 

Group (www.uswag.org) are already presently addressing these issues and that effort in this area by NCC would be duplicative. 

In keeping with its charter, I believe there may be a role for the National Coal 

Council to advise the Secretary on plans, priorities and strategies to more effectively 

address technological, regulatory and social impacts of current issues relating to 

coal production and use. This would include addressing how to facilitate advancement of tomorrow’s clean coal fleet. 
110 

Responses by Mr. Nick Akins, President and 

Chief Executive Officer of American Electric Power 

Questions Submitted by Chairman Andy Harris 

Q1. As we examine the future of coal in America, it is important to consider what 

the President said in November 2008 about the outlook for coal under his administration. He said that ‘‘if somebody wants to build a coal-powered plant, 

they can. It’s just that it will bankrupt them.’’ 

American Electric Power is in the business of building and operating coal plants. 

What is the status of and outlook for building new plants? And if new power plants 

do not move forward, what does the mean for electricity supply and reliability? 

A1. AEP has a long history in building and operating coal plants and is completing 

our Turk plant, a brand new ultra-supercritical coal plant in Arkansas, which will 

be among the most efficient and cleanest coal plants in the U.S. 

In the near term, there are many uncertainties associated with building new coal 

fired power plants, including stagnant growth prospects in an already depressed 

economy, the currently low natural gas prices, and future environmental regulations 

to name just a few. As a result, AEP will mostly be building new natural gas plants 

over the next few years to replace retiring existing coal fired units as well as to 

meet additional demands for power. Furthermore, the addition of new gas-fired capacity will provide for a more diverse portfolio in the AEP generating fleet, which 

historically has been powered predominantly by coal. 

However, over the longer term, we believe that a portfolio of different generating 

options will be essential in meeting future demands for electricity. This includes 

coal, natural gas, nuclear and renewable energy. To ensure affordable and reliable 

electricity, we cannot entrust our future electricity supply to only one fuel or source 

of power. While generating plants fueled by natural gas look particularly attractive 

today due to the currently low natural gas prices and the apparent plentiful supply 

of shale gas in the U.S. due to the advent of natural gas fracking, in the long run, 

being overly reliant on natural gas for electric power is not a wise strategy. Such 

a dependence on natural gas has many inherent risks due to real possibility of supply problems, price volatility, and higher prices—all of which have occurred in the 

recent past. America’s coal resources remain plentiful and low cost and need to play 

an important role in U.S. electricity supply in the future. 

Regarding reliability, our greatest concern in the near term is that the new EPA 

regulations that I discussed in my testimony will force a significant number of coal 

fired plants to retire prematurely in just the next 2–3 years. This could pose significant local and regional reliability problems because new replacement capacity, 

transmissions improvements and other measures to address reliability problems 

cannot be completed in that short a period of time. As I have noted, these reliability 

problems (along with adverse impacts on jobs and the economy) can be largely resolved simply by extending the compliance time frames through federal legislation. 

Q2. In the current budget environment, it is imperative that DOE improves 

prioritization and pursue only the most important and impactful R&D. With 

that in mind, what would you change about the current DOE R&D portfolio? 

Specifically, what are the 1–2 areas that you believe deserve highest priority 

with DOE coal R&D? What are the 1–2 areas or activities currently supported 

that may warrant cuts in order to pay for the highest priority? 

A2. AEP believes that the Department of Energy (DOE) should focus its coal R&D 

efforts on developing advances in ‘‘next generation’’ technologies to address the high 

cost and energy penalty concerns associated with the reduction of CO2 emissions 

from coal fueled power plants. Such technologies could include the following: 

• Advanced oxygen production systems; 

• oxy-combustion systems; 

• coal gasification systems with CO2 capture and sequestration, including polygen 

systems that produce high value products in addition to electricity; and 

• post-combustion CO2 capture systems that employ catalysts, advanced enzymes 

or emerging membrane separation technologies as a means to reduce dramatically energy penalties associated with the operation of CO2 capture technology. 

These next generation technologies hold out the promise of generating electricity 

with very low emissions of both CO2 and other conventional air pollutants at much 

lower energy consumption and operating costs than currently available technologies. 

AEP believes that the development and deployment of these technologies is critical 
111 

to ensure that coal, with its relatively low cost and abundant domestic supply, remains a viable and important component of a portfolio of domestic generation 

sources. 

AEP generally does not favor in the near term federal expenditures for additional 

large scale demonstration projects beyond those that are already underway for deploying existing CO2 capture technologies. However, federal investments that encourage early commercial deployment of these CO2 capture technologies could be 

warranted for those projects that use the captured CO2 for enhanced oil recovery 

(EOR) due to their very large economic, energy independence, and energy security 

benefits. DOE studies have identified 45–67 billion barrels of domestic oil resources, 

most of which can only be produced if additional volumes of CO2 from fossil fueled 

power plants and industrial sources become available. At current prices for oil, these 

resources have an estimated direct economic value of $5–7 trillion, and would provide important energy independence, energy security, and employment benefits to 

the nation. In the near-term, development of this domestic energy resource may best 

be fostered by favorable federal policies to encourage the deployment of these CO2 

capture technologies for EOR purposes. In the longer term, the federal coal R&D 

efforts recommended above for developing next generation technologies would support development of this domestic energy resource by lowering energy consumption 

and overall operating costs of generating electricity while capturing CO2. 

Questions Submitted by Ranking Member Brad Miller 

Q1. Please provide your name and employing organization(s). 

A1. Nick Akins, President and Chief Executive Officer of American Electric Power. 

Q2(a). Are you an officer or employee of, or otherwise compensated by, any other organization(s) that may have an interest in the topic of this hearing? 

A2(a). No 

Q2(b). If the answer to question 2a is ‘‘yes,’’ please specify the organization(s) and 

the nature of your relationship with the organization(s). 

Q3(a). In the last three calendar years, including this one, have you been a registered 

lobbyist? 

A3. No 

Q3(b). If the answer to question 3a is ‘‘yes,’’ please list all of your client(s) that may 

have an interest in the subject matter of this hearing, and the dates between 

which you represented that client or those clients. 

Q4. If you have worked as an attorney, contractor, consultant, paid analyst, or in 

any other professional services capacity, please provide a list of all of your firm’s 

clients who you know to have an interest in the subject matter of this hearing. 

These should be clients that you have personally worked with in the last three 

calendar years (including the present year). Provide the name of the client, the 

matter on which you worked and the date range of that work. If there was a 

deliverable, please describe that product. 

A4. I have only been an employee of American Electric Power during the specified 

3-year period. I have not worked as an attorney, contractor, consultant, paid analyst, or in any other professional services capacity for any other company or firm 

during the last 3 years. 

Q5. Please provide a list of all publications on which you have received an author 

or coauthor credit relevant to the subject of this hearing. If the list is extensive, 

the 10 most recent publications would be sufficient. 

A5. Not applicable. I am not an author of publications relevant to the subject of the 

hearing. This does not include any other publications of American Electric Power 

related to our business, such as annual reports, etc. Those are publications of the 

corporation, and not written by me personally. 
112 

After several attempts by the Committee staff to obtain responses to posthearing questions, Mr. Foerter refused to furnish answers for the record. 

Questions submitted to Mr. David Foerter, 

Executive Director, 

Institute of Clean Air Companies 
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Responses by Mr. Stu Dalton, 

Senior Government Representative-Generation, 

Electric Power Research Institute 

Questions Submitted by Chairman Andy Harris 
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Æ