[House Hearing, 112 Congress]
[From the U.S. Government Publishing Office]







                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





[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]





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







                                _____

                  U.S. GOVERNMENT PRINTING OFFICE

70-591 PDF                WASHINGTON : 2011
-----------------------------------------------------------------------
For sale by the Superintendent of Documents, U.S. Government Printing 
Office Internet: bookstore.gpo.gov Phone: toll free (866) 512-1800; DC 
area (202) 512-1800 Fax: (202) 512-2104  Mail: Stop IDCC, Washington, DC 
20402-0001













              COMMITTEE ON SCIENCE, SPACE, AND TECHNOLOGY

                    HON. RALPH M. HALL, Texas, Chair
F. JAMES SENSENBRENNER, JR.,         EDDIE BERNICE JOHNSON, Texas
    Wisconsin                        JERRY F. COSTELLO, Illinois
LAMAR S. SMITH, Texas                LYNN C. WOOLSEY, California
DANA ROHRABACHER, California         ZOE LOFGREN, California
ROSCOE G. BARTLETT, Maryland         BRAD MILLER, North Carolina
FRANK D. LUCAS, Oklahoma             DANIEL LIPINSKI, Illinois
JUDY BIGGERT, Illinois               GABRIELLE GIFFORDS, Arizona
W. TODD AKIN, Missouri               DONNA F. EDWARDS, Maryland
RANDY NEUGEBAUER, Texas              MARCIA L. FUDGE, Ohio
MICHAEL T. McCAUL, Texas             BEN R. LUJAN, New Mexico
PAUL C. BROUN, Georgia               PAUL D. TONKO, New York
SANDY ADAMS, Florida                 JERRY McNERNEY, California
BENJAMIN QUAYLE, Arizona             JOHN P. SARBANES, Maryland
CHARLES J. ``CHUCK'' FLEISCHMANN,    TERRI A. SEWELL, Alabama
    Tennessee                        FREDERICA S. WILSON, Florida
E. SCOTT RIGELL, Virginia            HANSEN CLARKE, Michigan
STEVEN M. PALAZZO, Mississippi       VACANCY
MO BROOKS, Alabama
ANDY HARRIS, Maryland
RANDY HULTGREN, Illinois
CHIP CRAVAACK, Minnesota
LARRY BUCSHON, Indiana
DAN BENISHEK, Michigan
VACANCY
                                 ------                                

                 Subcommittee on Energy and Environment

                   HON. ANDY HARRIS, Maryland, Chair
DANA ROHRABACHER, California         BRAD MILLER, North Carolina
ROSCOE G. BARTLETT, Maryland         LYNN C. WOOLSEY, California
FRANK D. LUCAS, Oklahoma             BEN R. LUJAN, New Mexico
JUDY BIGGERT, Illinois               PAUL D. TONKO, New York
W. TODD AKIN, Missouri               ZOE LOFGREN, California
RANDY NEUGEBAUER, Texas              JERRY McNERNEY, California
PAUL C. BROUN, Georgia                   
CHARLES J. ``CHUCK'' FLEISCHMANN,        
    Tennessee                            
RALPH M. HALL, Texas                 EDDIE BERNICE JOHNSON, Texas













                            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

 
                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.



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]



    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 before 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 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 develop 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:]
            Prepared Statement of Ranking Member Brad Miller



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]



    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 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, pre-
combustion, which is emerging gasification technology, and oxy-
combustion.
    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.
    [The prepared statement of Mr. Klara follows:]
Prepared Statement of Mr. Scott Klara, Deputy Director, National Energy 
                         Technology Laboratory



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


    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 federally-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 low-cost 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 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\
---------------------------------------------------------------------------
    \1\ U.S. Energy Information Administration, Annual Energy Outlook 
2011.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \2\  Eugene M. Trisko, Esq. for American Coalition for Clean Coal 
Electricity, January 2011.
---------------------------------------------------------------------------
    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\ 
Low-cost electricity directly contributes to the competitiveness of 
America in international markets.
---------------------------------------------------------------------------
    \3\ Shively & Ferrare 2008 Enerdynamics.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \4\  Energy Ventures Analysis, ``Employment Impacts Associated with 
Electric Generation Options'' for National Mining Association, 
September 2011.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \6\ Cloud Peak Energy presentation, ACC Coal Market Strategies 
Conference, August 23, 2011 & Fitch Ratings, U.S. Coal Producers 
Outlook, August 17, 2011.
---------------------------------------------------------------------------
    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 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\
---------------------------------------------------------------------------
    \7\ ``Benefits from Investments in Advanced Coal Technology,'' Coal 
Utilization Research Council, National Mining Association, Edison 
Electric Institute, et. al. fact sheet attached hereto.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \10\ ``Benefits from Investments in Advanced Coal Technology''- 
Fact Sheet Coal Utilization Research Council, et. al.
---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------
    \11\ ``Direct Federal Financial Interventions and Subsidizes in 
Energy in FY2010'' U.S. Energy Information Administration, July 2011.
---------------------------------------------------------------------------
    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 
development 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 capture 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\
---------------------------------------------------------------------------
    \12\ Richard F. Storm, ``What can be done to improve the Thermal 
Performance of the existing coal fleet?'', EPRI Heat Rate Conference, 
January 2011.
---------------------------------------------------------------------------
    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 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.
---------------------------------------------------------------------------
    \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/NETL-2010/1411.
---------------------------------------------------------------------------
    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, low-cost 
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, Engineered 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 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 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. 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 sub-region 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 recovery 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 ``ultra-supercritical.'' 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 ASME-approved, cost-effective high temperature chrome and 
nickel-based alloys in the 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 ultra-supercritical 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 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 coal-fired 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.

    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 ``tie-in'' 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.
---------------------------------------------------------------------------
    \1\ Specifically, 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.
---------------------------------------------------------------------------
    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 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:



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]




    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.
    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\
---------------------------------------------------------------------------
    \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.
---------------------------------------------------------------------------
    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.

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 
coal-fired 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.
    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.
    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:]
Prepared Statement of Mr. David Foerter, Executive Director, Institute 
                         of Clean Air Companies



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]



    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 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 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 win-win 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 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 by-
product 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.
    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 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, 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 cross-media 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)

      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 electricity 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.
    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.
    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 sub-critical.
    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 
ultra-supercritical, 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, 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 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.
    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.
    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:]

Slides Presented by Mr. Roscoe Bartlett, Committee on Science Space and 
                               Technology



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]



    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.
    Mr. Hall. Well, listening to your figures I think in the 
Cross-State 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 
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 
no-regret 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.
    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?
    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.
    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.
    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 government-funded 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.
    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.]
                              Appendix I:

                              ----------                              


                   Answers to Post-Hearing Questions




                   Answers to Post-Hearing Questions
Responses by Mr. Scott Klara, Deputy Director,
National Energy Technology Laboratory



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


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.
    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, high-capital 
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?

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.
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 
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.
After several attempts by the Committee staff to obtain responses to 
post-hearing questions, Mr. Foerter refused to furnish answers for the 
record.

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



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


Responses by Mr. Stu Dalton,
Senior Government Representative-Generation,
Electric Power Research Institute

Questions Submitted by Chairman Andy Harris



[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


                                


