Reliable & Resilient

The Value of Our Existing Coal Fleet

An Assessment of Measures to Improve 

Reliability & Efficiency While Reducing Emissions

May 2014
Reliable & Resilient

The Value of Our Existing Coal Fleet

An Assessment of Measures to Improve 

Reliability & Efficiency While Reducing Emissions

May 2014

NCC CHAIR

John Eaves

Arch Coal, Inc.

COAL POLICY COMMITTEE CHAIR

Fredrick D. Palmer

Peabody Energy

STUDY CHAIR

Jeff Wallace

Southern Company Services

TECHNICAL WORK GROUP CHAIR

Steve Wilson

Southern Company

LEAD AUTHORS

Doug Carter

J. Edward Cichanowicz

Stu Dalton & EPRI Team

NCC EXECUTIVE VICE PRESIDENT & CHIEF OPERATING OFFICER 

Janet Gellici

The National Coal Council is a Federal Advisory Committee to the U.S. Secretary of Energy.

The NCC advises, informs and makes recommendations to the Secretary on matters requested by 

the Secretary relating to coal or the coal industry.

Library of Congress Catalog # TBD
The National Coal Council 

The National Coal Council (NCC) was chartered in 1984 based on the conviction that an industry 

advisory council on coal could make a vital contribution to America’s energy security. NCC’s 

founders believed that providing expert information could help shape policies relevant to the use 

of coal in an environmentally sound manner. It was expected that this could, in turn, lead to 

decreased dependence on other less abundant, more costly and less secure sources of energy.

These principles continue to guide and inform the activities of the Council. Coal has a vital role to 

play in the future of our nation’s electric power and energy needs. Our nation’s primary energy 

challenge is to find a way to balance our social, economic and environmental needs. 

Throughout its 30-year history, the NCC has maintained its focus on providing guidance to the 

Secretary of Energy on various aspects of the coal industry. NCC has retained its original charge 

to represent a diversity of perspectives through its varied membership and continues to welcome 

members with extensive experience and expertise related to coal. 

The NCC serves as an advisory group to the Secretary of Energy, chartered under the Federal 

Advisory Committee Act (FACA), providing advice and recommendations to the Secretary of 

Energy on general policy matters relating to coal and the coal industry. As a FACA organization, 

the NCC does not engage in lobbying activities.

The principal activity of the NCC is to prepare reports for the Secretary of Energy at his/her 

request. During its 30-year history, the NCC has prepared more than 30 studies for the Secretary, 

at no cost to the Department of Energy. All NCC studies are publicly available on the NCC 

website. 

Members of the NCC are appointed by the Secretary of Energy and represent all segments of coal 

interests and geographic distribution. The NCC is headed by a Chair and Vice Chair who are 

elected by the its members. The Council is supported entirely by voluntary contributions from 

NCC members and receives no funds from the federal government. Studies are conducted solely 

at the expensive of the NCC and at no cost to the government.

The National Coal Council values the opportunity to represent the power, the pride and the 

promise of our nation’s coal industry.

February 14, 2014

The Honorable Dr. Ernest Moniz

U.S. Secretary of Energy

U.S. Department of Energy

1000 Independence Ave., SW

Washington, DC 20585

Dear Mr. Secretary:

On behalf of the members of the National Coal Council (NCC), I am pleased to accept your 

request that the NCC conduct the study you requested in your letter dated January 31st, 

2014. Activity has begun on preparing this study which will provide an assessment of the 

existing U.S. coal fleet and the job implications of modifications and technology solutions 

in pursuit of enhancing the capacity, efficiency and emissions profile of the fleet. 

NCC Vice Chair, Jeff Wallace, Vice President of Fuel Services for Southern Company, will 

serve as the Council Chair for this study. Steve Wilson, General Manager of Research and 

Development, Southern Company, will Chair the Study Work Group.

The Study Work Group has targeted a completion date for this study of early May 2014. 

The spring meeting of the NCC has been approved by Principal Deputy Assistant 

Secretary Chris Smith for Wednesday, May 14th, 2014. The study will be presented for the 

NCC membership’s approval at the May 14th meeting. 

NCC’s leadership looks forward to meeting with you to discuss the existing coal fleet 

study. Please let us know when you would like to meet.

Thank you for your support of the National Coal Council. We look forward to completing 

the requested study in a timely manner for use in the continuing dialogue on issues 

related to our nation’s energy future.

Sincerely,

John W. Eaves
May 14, 2014

The Honorable Dr. Ernest Moniz

U.S. Secretary of Energy

U.S. Department of Energy

1000 Independence Ave., SW

Washington, DC 20585

Dear Mr. Secretary:

On behalf of the members of the National Coal Council (NCC), we are pleased to submit to you 

pursuant to your letter dated January 31st, 2014, the report “Reliable and Resilient: The Value of 

Our Existing Coal Fleet.” The study’s primary focus was to assess what industry and the 

Department of Energy, separately and jointly, can do to enhance the capacity, efficiency and 

emissions profile of the existing coal generation fleet in the United States through the application 

of new and advanced technology. The study also examines the job implications of modification 

and addition of equipment at existing coal power plants. Other issues addressed in the report 

include benefits afforded by the existing fleet and changes that could impact those benefits in the 

future.

The NCC study was conducted during the winter of 2013-2014. The severe cold weather events 

experienced while the study was underway reinforced the importance of retaining and 

maintaining coal generation assets in order to reliably and affordably meet the electricity needs 

of U.S. residents and businesses. The major lesson learned from the Polar Vortex experience is 

that the availability and operation of coal units now scheduled for retirement over the next two 

years enabled the power sector to meet demand during periods of harsh weather.

NCC’s assessment of the existing U.S. coal fleet supports the findings that:

• The current 310 GW fleet of coal-fired power plants underpins economic prosperity in the 

U.S., providing direct economic and macroeconomic benefits; energy supply and price 

stability; environmental benefits through continuous technology advancements; and jobcreating opportunities.

• Coal plant closures and increasing reliance on natural gas for power generation will adversely 

impact price stability and resource supply.

• New Source Review (NSR) regulations adversely impact generators’ decisions and ability to 

enhance plant efficiency, reduce emissions and improve overall operations and capacity. 

• Collaborative RD&D efforts (DOE and industry) can enhance the ability of the coal fleet to 

improve its flexibility and reliability, to increase its efficiency and to reduce its emissions 

profile. 
The need for RD&D is vital to support marketplace shifts and public policy objectives:

• Increasing deployment of intermittent renewable energy technologies, competition from 

other fossil fuels, use of non-design coals and continued use of older coal generation 

technologies will lead to increased operation of base load units in a cycling mode for which 

they were not designed.

• Modest improvements in efficiency are possible with existing technologies to improve heat 

transfer, reduce heat losses and make better use of low quality heat. More advanced 

improvements, if technically and commercially viable, could significantly enhance efficiency.

• Challenges arise in complying with emerging regulations for control of traditional pollutants 

when new control regimes create secondary, follow-on emissions issues.

• Existing coal plants were not designed or located with CCS in mind; the ability to retrofit these 

plants for CCS is problematic. More research is needed to commercialize CCS retrofit 

potential; improved efficiencies provide an interim path in the meantime.

The U.S. benefits from having a diverse portfolio of electricity sources. The Energy Information 

Administration (EIA) projects very little new coal capacity will be built in the U.S. through 2040. 

Therefore, maintaining coal’s role in this diversified portfolio will likely rest on industry’s ability to 

continue safe and economical operation of the existing fleet, while making the changes necessary 

to ensure continued environmental compliance.

Past challenges to coal generation, such as the need to reduce emissions of sulfur dioxide, 

nitrogen oxides and mercury, were met through collaborative efforts between the public sector 

and the private sector to develop new technologies. The question posed by this report is – Can 

this be done again? The National Coal Council believes that “Yes, it can be done and yes, it must 

be done.” 

Thank you for the opportunity to conduct this study and produce this report. The Council stands 

ready to address any questions you may have on the recommendations it contains. 

Sincerely,

John W. Eaves

NCC Chair

(May 2012-May 2014)
Reliable & Resilient

The Value of Our Existing Coal Fleet

Study Work Group & Review Team

EXECUTIVE MANAGEMENT TEAM

Jeff Wallace, Southern Company Services – Study Chair

Fred Palmer, Peabody Energy – Coal Policy Committee Chair

Bill Brownell, Hunton & Williams – Coal Policy Committee Vice Chair

TECHNICAL WORK GROUP CHAIR

Steve Wilson, Southern Company

STUDY LEADERSHIP TEAM

Steve Wilson, Southern Company – Study Technical Chair

Doug Carter, Independent Energy Consultant – Lead Author

J. Edward Cichanowicz, Independent Engineering Consultant – Principal Author

Stu Dalton, EPRI – Principal Author

Janet Gellici, National Coal Council

STUDY REVIEW TEAM

Don Gaston, PSEG Fossil

Matt Usher, American Electric Power

Mark Wilson, Tri-State Generation & Transmission 

Todd Adkins, Patriot Coal

Sy Ali, Clean Energy Consulting

Janos Beer, MIT

Roger Bezdek

 Management Information 

 Services Inc. (MISI)

Lisa Bradley, AECOM

Frank Clemente, Penn State

Chase Crawford, Southern Company

Mike Durham, ADA-ES

Fred Eames, Hunton & Williams

Clark Harrison, CH2M Hill

Bob Hilton, ALSTOM Inc.

Makram Jaber, Hunton & Williams

Holly Krutka, Shenhua Group

Rich Lopriore, PSEG Fossil

Rafic Minkara, Headwaters

Ram Narula, Consultant

Bob Purgert, Energy Industries of Ohio

Mark Schoenfield, Jupiter Oxygen

Rick Smith, Ameren Energy

Ben Yamagata

 Coal Utilization Research Council

Cover Photo Source:

Boon (http://www.booninc.com/index.php), reprinted with permission.

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

COAL POLICY COMMITTEE

Robert O. Agbede, Chester Engineers

Sy Ali, Clean Energy Consulting 

Richard Bajura, West Virginia University

Theodore K. Barna, Barna Solutions, LLC

Janos M. Beer, Massachusetts Institute of Technology

Jacqueline F. Bird

F. William Brownell, Esq., Hunton & Williams

Dr. Frank Burke, Consultant

Stu Dalton, EPRI

Jack Daly, Sargent & Lundy

Ted Doheny, Joy Global, Inc.

Michael D. Durham, ADA-ES

John Dwyer

John W. Eaves, Arch Coal, Inc.

George Ellis, Pennsylvania Coal Association

Alex G. Fassbender, Ecovia Corporation

Paul J. Feldman, Midwest ISO

John S. Fischer, Breakthrough Energy, LLC

Mark Fraley, FirstEnergy Solutions Corp

Robert D. Gabbard, PPL EnergyPlus, LLC

Guy Gorney

Manoj K Guha, Energy & Environmental Services

Clark D. Harrison, CH2M Hill

William Hoback, IL Office of Coal Development 

Gerald (Jerry) A. Hollinden

Clarence Joseph Hopf, PPL EnergyPlus

Marty Irwin, IN Center for Coal Tech. Research

Michael Karmis, Virginia Tech

Norman Kettenbauer, GenPower Services

Klaus Lambeck, Public Utilities Commission of Ohio

John T. Long, Connemara Ltd.

Richard P. Lopriore, PSEG Fossil LLC

Jason Makansi, Pearl Street, Inc.

John S. Mead

Nancy Mohn, ALSTOM 

Ram G. Narula

Kenneth J. Nemeth, Southern States Energy Board

Jerry J. Oliver, Global Tech Management Services

Fredrick D. Palmer, Peabody Energy

Robert M. Purgert, Energy Industries of Ohio

Mark Schoenfield, Jupiter Oxygen Corporation

Gregory A. Workman, Dominion Resources

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Reliable & Resilient

The Value of Our Existing Coal Fleet

Table of Contents

A. Executive Summary ....................................................................................................1

1. Introduction..............................................................................................................................1

a. Flexibility and Reliable Operation ....................................................................................3

b. Improving Unit Efficiency .................................................................................................4

c. Reducing Emissions..........................................................................................................5

i. Traditional Emission Controls..........................................................................................5

ii. Retrofitting CCS ................................................................................................................6

2. Key Findings and Recommendations .......................................................................................7

a. The Value of the Existing Coal Generation Fleet..............................................................7

b. Changes that Could Impact the Existing Coal Generation Fleet.......................................8

c. Improving Fleet Flexibility and Reliability.........................................................................9

d. Increasing the Efficiency of the Existing Fleet..................................................................9

e. Reducing Emissions from the Existing Fleet...................................................................10

The 2014 Polar Vortex ..................................................................................................... 12

B. The Role (Benefits) of the Existing Coal-Fired Power Plant Fleet, Including 

 Portfolio Value ......................................................................................................... 17

1. Background.............................................................................................................................17

2. Profile of the Existing Coal Fleet.............................................................................................18

3. Benefits Provided by the Coal Fleet.......................................................................................21

a. Direct and Macroeconomic Benefits..............................................................................21

b. Supply and Price Stability Benefits.................................................................................27

c. Environmental Benefits..................................................................................................31

d. Carbon Capture, Utilization and Storage (CCUS)............................................................33

4. Findings and Recommendations............................................................................................35

a. Findings...........................................................................................................................35

b. Recommendations..........................................................................................................36

C. Changes that Could Impact Future Benefits from the Existing Coal Fleet.................... 37

1. Reduced Rate of Demand for Electricity ................................................................................37

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

2. More Advantageous Natural Gas Prices.................................................................................39

3. Environmental Regulation......................................................................................................41

a. Non-CO2 Regulations......................................................................................................41

b. CO2 Limitations...............................................................................................................41

c. Other Related Regulations .............................................................................................42

d. Cumulative Impacts........................................................................................................42

4. New Source Review – Major Modifications...........................................................................42

5. Aging of Fleet..........................................................................................................................45

6. Reduced Funds for R&D (Industry & Government)................................................................47

7. Findings and Recommendations............................................................................................48

a. Findings...........................................................................................................................48

b. Recommendations..........................................................................................................48

D. Technology Responses to Maximize Future Benefits to Society.................................. 49

1. General Introduction..............................................................................................................49

2. The Path to Improving the Flexibility & Maintaining the Reliability of the Existing Fleet .....49

a. Background and Introduction.........................................................................................49

b. Analysis and Discussion..................................................................................................50

c. Findings...........................................................................................................................54

d. Recommendations..........................................................................................................55

3. Improving the Efficiency of Power Generation From the Existing Coal Fleet........................56

a. Background and Introduction.........................................................................................56

b. Analysis and Discussion..................................................................................................57

i. Fuel Type and Fuel Processing .......................................................................................58

ii. Boiler and Steam Conditions..........................................................................................60

iii. Steam Turbine and Condenser ......................................................................................61

iv. Process Instrumentation and Controls..........................................................................64

v. Low Temperature Heat Recovery..................................................................................64

vi. Auxiliary Power Consumption........................................................................................65

vii. Cooling System...............................................................................................................66

viii.Changing Plant Thermodynamics..................................................................................66

ix. Cumulative Benefits of Multiple Actions.......................................................................69

x. Important Caveats..........................................................................................................70

c. Findings...........................................................................................................................71

d. Recommendations..........................................................................................................72

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

4. Emission Reductions from the Existing Fleet .........................................................................72

a. Addressing Conventional Pollutants ..............................................................................72

i. Background and Introduction........................................................................................72

ii. Analysis and Discussion..................................................................................................73

iii. Findings ......................................................................................................................75

iv. Recommendations.........................................................................................................75

b. Retrofitting CCS on the Existing Coal Fleet.....................................................................75

i. Background and Introduction........................................................................................75

ii. Analysis and Discussion..................................................................................................75

iii. Findings ......................................................................................................................85

iv. Recommendations.........................................................................................................86

APPENDIX A Turbine Upgrade or Efficiency Improvement Projects Cited in NSR 

Enforcement Initiative.................................................................................. 1

1. Turbine Upgrade or Efficiency Improvement Projects Cited in NSR Enforcement Initiative... 1

2. Standard Turbine Overhauls or other Turbine Projects Cited in NSR Enforcement Initiative . 2

APPENDIX B Present Technical Status of CCS..................................................................... 1

1. Introduction.............................................................................................................................. 1

2. Post-combustion Control ......................................................................................................... 1

3. Oxycombustion ........................................................................................................................ 5

APPENDIX C 2012 Generation, Million MWH by State ....................................................... 1

APPENDIX D Reports of the National Coal Council – June 1986-May 2014.......................... 1

APPENDIX E Member Roster – 2014.................................................................................. 1

APPENDIX F Dissenting Opinion ........................................................................................ 1

APPENDIX G References.................................................................................................... 1

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Reliable & Resilient

The Value of Our Existing Coal Fleet

List of Tables

Table B.1. Electricity Price in 2013, Cents/kWh. ..........................................................................24

Table D.3.1. Summary of Cost, Heat Rate Payoff, and Capacity Payoff for Steam Turbine 

Improvement Options – For Circumstances Where a Technology is Practical. ...........62

Table Appendix B-1. Summary of Post-combustion CO2 Pilot Plant and Demonstration 

Projects: North America and Europe. .............................................................................3

Table Appendix B-2. Post-combustion CO2 Controls: Experience and Lessons Learned. ...........4

Table Appendix B-3. Status of Oxycombustion Demonstration Tests. ..........................................7

List of Figures

Figure PV1. U.S. Electricity Generation for January & February, 2012-2014..............................13

Figure PV2. Portion of Increase in U.S. Electricity Generation, by Fuel ......................................13

Figure PV3. Projected 2020 Energy Capacity, by Fuel..................................................................15

Figure B.1. Estimated U.S. Primary Energy Consumption Before 1945. .....................................17

Figure B.2. U.S. Electricity Generation by Energy Source. ...........................................................18

Figure B.3. Generation by Fuel, 2012. ..........................................................................................19

Figure B.4. Generation Fuel Mix for all Entities............................................................................20

Figure B.5. Generation Fuel Mix for Cooperatives.......................................................................20

Figure B.6. Generation Fuel Mix for Public Power Utilities. (Source: APPA)...............................21

Figure B.7. Levelized Cost of Electricity. .......................................................................................22

Figure B.8. Value of Existing Coal Fleet: Electricity Cost Savings................................................23

Figure B.9. Source of U.S. Electric Power (Data from DOE/EIA)..................................................25

Figure B.10. Average Retail 2012 Electricity Prices, by State (Data from DOE/EIA). ..................25

Figure B.11. Fuel Price Volatility. ..................................................................................................26

Figure B.12. Future Fuel Prices (Data from AEO-2014, DOE/EIA). ..............................................26

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Figure B.13. U.S. Population Change. ...........................................................................................27

Figure B.14. Impact of Energy on Discretionary Income. ............................................................28

Figure B.15. 30% of Global Coal is in the U.S................................................................................29

Figure B.16. The U.S. Coal-Fueled Electricity Supply Chain. ........................................................30

Figure B.17. Coal Use and Declining Emissions. ...........................................................................32

Figure B.18. Power Plant Emission Trends. ..................................................................................33

Figure C.1. U.S. GDP: 1947-2013..................................................................................................38

Figure C.2. Annual U.S. Electricity Generation. ............................................................................38

Figure C.3. Monthly Generation from Natural Gas and Coal.......................................................39

Figure C.4. Henry Hub Spot Prices. ...............................................................................................40

Figure C.5. Natural Gas Price Predictions Versus Actual Price. ...................................................40

Figure C.6. U.S. Coal-fueled Generating Capacity Additions. ......................................................45

Figure C.7. Coal Generating Capacity, by State (based on EIA-Fm860 data). .............................46

Figure C.8. Projected Coal Capacity in 2025 (based on EIA-Fm860 data)...................................46

Figure C.9. DOE RD&D Budget for Coal Use Technologies. .........................................................47

Figure D.3.1. Power Plant Efficiency.............................................................................................58

Figure D.3.2. Coal Moisture Impact on Efficiency. ......................................................................60

Figure D.3.3. Condenser Fouling and Turbine Heat Rate............................................................63

Figure D.3.4. Schematic of Topping Cycle for Conventional Rankine Power Station. ................68

Figure D.4.1. Timeline for CCS.......................................................................................................79

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Reliable & Resilient

The Value of Our Existing Coal Fleet

Abbreviations

ACI – activated carbon injection

AEO2013 – Annual Energy Outlook 2013 

APPA – American Public Power Association

ARI – Advanced Resources International

ARRA – American Recovery and Reinvestment Act

AUSC – Advanced Ultra-Supercritical

BACT – Best Available Control Technology

bcf – Billion Cubic Feet

Btu – British Thermal Units

CCR – Coal Combustion Residuals

CCS – Carbon Capture & Storage

CCUS – Carbon Capture Utilization & Storage

CFD – Computational Fluid Dynamics

CO2 – Carbon Dioxide

CSAPR – Cross State Air Pollution Rule

CUCR – Coal Utilization Research Council

DOE – Department of Energy

DSI – Dry Sorbent Injection

EERE – Energy Efficiency and Renewable Energy

EERS – Energy Efficiency Resource Standards

EIA – Energy Information Administration

EOR – Enhanced Oil Recovery

EPA – Environmental Protection Agency

EPRI – Electric Power Research Institute

EU – European Union

FERC – Federal Energy Regulatory Commission

FGD – Flue Gas Desulfurization

FOAK – First-Of-A-Kind

GADS – Generating Availability Data System

GDP – Gross Domestic Product

GHG – Greenhouse Gas

GW – Gigawatt

HAPs – Hazardous Air Pollutants

HHV – Higher Heating Value

H-P – High Pressure

I&C – Instruments and Controls

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

IEA – International Energy Agency

I-P – Intermediate Pressure

IPCC – Intergovernmental Panel on Climate Change

ISO-NE – Independent System Operator – New England

kWh – Kilowatt Hour

LCOE – Levelized Cost of Electricity

LHV – Lower Heating Value

LIHEAP – Low Income Home Energy Assistance Program

LNG – Liquified Natural Gas

L-P – Low Pressure

MATS – Mercury and Air Toxics Standards

mcf – Thousand Cubic Feet

MISI – Management Information Services, Inc.

MMBtu – Million Btu

MM&V – Monitoring, Mitigation and Verification

MW – Megawatt

MWe – Megawatt Equivalent 

MWh – Megawatt Hour

NAAQS – National Ambient Air Quality Standards

NCC – National Coal Council

NCCC – National Carbon Capture Center

NERC – North American Electric Reliability Corporation

NETL – National Energy Technology Laboratory

NGCC – Natural Gas Combined Cycle

NH3 – Ammonia

NOx – Nitrogen Oxides

NRECA – National Rural Electric Cooperatives Association

NREL – National Renewable Energy Laboratory

NSPS – New Source Performance Standards

NSR – New Source Review

O&M – Operations and Maintenance

OMB – Office of Management and Budget

PM – Particulate Matter

PRB – Powder River Basin

RCRA – Resource Conservation and Recovery Act

R&D – Research and Development

RD&D – Research, Development and Demonstration

RGGI – Regional Greenhouse Gas Initiative

ROZ – Residual Oil Zone

RPS – Renewable Portfolio Standards

SC – Super Critical

SCR – Selective Catalytic Reduction

SNCR – Selective Non-Catalytic Reduction

SO2 – Sulfur Dioxide

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

SO3 – Sulfur Trioxide

tcf – Trillion Cubic Feet

TWH – Terawatt Hours

UIC – Underground Injection Control

USGS – United States Geological Survey

VSD – Variable Speed Drives

WFGD-WWT – Wet Flue Gas Desulfurization-Wastewater Treatment 

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Reliable & Resilient – The Value of Our Existing Coal Fleet

An Assessment of Measures to Improve Reliability and Efficiency While Reducing Emissions

A. Executive Summary

1. Introduction

The existing fleet of coal-fired power plants underpins economic prosperity in the U.S. Coalbased generation has dominated U.S. electricity supply for nearly a century. In 2013, coal again 

led U.S. generation, at 39%. Low cost coal keeps U.S. electricity prices below those of other free 

market nations. For example, in 2013 the average price of residential and industrial electricity in 

the U.S. was one-half to one-third the price of electricity in Germany, Denmark, Italy, Spain, the 

UK and France (see Table B.1). These price differentials translate into more disposable income for 

U.S. consumers, and a competitive edge for U.S. industry in global markets. If the existing coal 

fleet were replaced with the next cheapest alternative generating source, natural gas combined 

cycle power plants, a conservative estimate of the impact on the U.S. economy would be a 1.5% 

drop in Gross Domestic Product (GDP) and a loss of 2 million jobs per year. Characteristics of the 

existing U.S. coal fleet, and its benefits to society (including employment benefits, economic 

benefits, and benefits to energy security and grid reliability), are discussed in Section B of this 

report.

The “Polar Vortex” weather events of January and February 2014 demonstrated the contribution 

of the existing coal fleet, including those units currently scheduled for retirement over the next 2 

to 3 years, to the reliability of the U.S. electricity grid. AEP reported that it deployed 89% of its

coal units scheduled for closure, and Southern Company reported use of 75% of its coal units 

scheduled for closure. Use of these units enabled utilities to meet customer demand during a 

period when already limited natural gas resources were diverted from electricity production to 

meeting residential heating needs. Nationwide, over 90% of the increase in power generation in 

January and February 2014 (versus January and February 2013) came from the existing coal fleet.

The U.S. benefits from having a diverse portfolio of electricity sources. However, the Energy

Information Administration (EIA) projects very little new coal capacity will be built in the U.S. 

thorough 2040.1

 EIA projects that coal’s share of total generation will decline from 39% in 2013 

to an average of 37% for 2014-2040,2 assuming current environmental regulations.i Therefore, 

maintaining coal’s role in this diversified portfolio will likely rest on industry’s ability to continue 

safe and economical operation of the existing fleet, while making the changes necessary to 

ensure continued environmental compliance.

i

Current regulations do not include, for example, rules now under development for CO2 limits, restrictions on cooling water intake 

structures, and coal combustion residuals (ash) management.

Section A 1 | Page

 
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

The existing coal fleet will face a number of serious challenges over the next few years. Some 

derive from the demographics of the fleet: it is getting older. The average U.S. coal-fired power 

plant has operated for 39 years.ii

 Older generating units are often financially and in some cases 

technically, less capable of accommodating large capital investments to meet new regulatory 

requirements and as units age their maintenance costs increase. The age of a generating unit is 

not a dispositive criterion in decisions related to the continued operation of that unit, but age is 

one of several important considerations influencing decisions regarding capital investments to 

meet future reliability and environmental compliance requirements.

Other challenges relate to meeting new environmental requirements as existing coal-fired power 

plants must cope with a range of new air pollution regulations, as well as federal requirements 

related to water use, wastewater treatment and solid waste management. Additional rules are 

being developed to limit CO2 emissions. Thirty states now have renewable portfolio standards or 

other measures like energy efficiency resource standards that tend to reduce the use of and/or 

place additional pressures on existing coal-fired generators in the midst of more intermittent 

renewable generation and additional states have established “goals” rather than standards.

Still other challenges are market oriented, such as the recent lack of growth in electricity demand

and strong competition from other generation sources, including natural gas based generation. 

These factors are felt most strongly in competition for new generating assets, but existing units 

are also affected. The combination of market factors and regulatory requirements will likely 

result in many existing coal-fired units being retired earlier than their economic lifespan, and 

others operating in a “cycling”iii or “flexible” mode in future years, rather than in a traditional 

“base load” mode. All of these challenges will pressure existing coal-based units to operate more 

cost-effectively and with greater flexibility if they are to remain in service. 

Past challenges to coal generation, such as the need to reduce emissions of sulfur dioxide, 

nitrogen oxides and mercury, were met through collaborative efforts between the public sector 

and the private sector to develop new technologies. The terms “Flue Gas Desulfurization”, 

“Selective Catalytic Reduction” and “Activated Carbon Injection” were not part of the nation’s 

lexicon in 1970. Today these systems, developed through industry/government collaboration, 

are standard equipment on new coal-fired power plants and have been widely deployed on 

existing units as well. Additionally, for every dollar of federal funds invested in coal RD&D, 

thirteen dollars of benefits accrued to the nation. Moreover, RD&D in advanced coal 

technologies can produce products for sale abroad, enhancing U.S. manufacturing and improving 

the nation’s balance of trade. The question posed by this report is: Can this be done again? More 

specifically, what technological solutions can be developed by the private and/or the public 

sector to enhance the existing coal generation fleet’s capacity, efficiency and emissions, as well 

as the jobs outlook for those that operate and supply those assets?

ii Capacity-weighted age, as of 2014, excluding retirements in 2013-14.

iii For purposes of this report, the term “cycling” includes both startup transitions and operational changes from minimum to 

maximum capability.

Section A 2 | Page

 
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

This report considers three main categories of technologies that, if developed, would assist the 

existing coal fleet in meeting many of its challenges:

• Technologies enabling more flexible operation for units that will be cycling and 

undergoing more frequent startups and shutdowns while maintaining reliability.

• Technologies to improve the efficiency of the existing fleet. More efficient power plants 

tend to emit less of all pollutants, but the focus of this report is more efficient 

technologies that reduce emission of CO2.

• Technologies, other than improved efficiency, that reduce emissions from coal-fueled 

power plants. These technologies would address traditional gaseous, liquid and solid 

waste streams, as well as CO2 emissions from existing coal-fired units.

a. Flexibility and Reliable Operation

Most large existing coal-fired power plants were originally designed to run in “base load” mode. 

With very low costs of operation, these units ranked high in the “economic dispatch” of units 

available to satisfy electricity demand by residential, commercial and industrial power consumers. 

As noted above, changing market conditions have led to the expectation that many of these base 

load designed units will, in the future, be used in a cycling mode resulting in significant 

operational and maintenance issues. Some may operate at base load during peak demand 

seasons (winter and summer), and be cycled or brought off the grid during other seasons. 

Exacerbating the need for more flexibility in the remaining fleet is the expected retirement of 

many of the older, smaller coal fired units that have provided cycling operation in the past. About 

20% of the generating capacity of the existing coal fleet is expected to retire by 2020 due to 

market conditions and currently applicable regulations (most of this capacity will retire by 2016, 

when compliance with the recent Mercury and Air Toxics Standards (MATS) is required). Twothirds of this retiring capacity is composed of units with subcritical steam cycles, less than 300 

megawatt (MW) in size. Recently these smaller older units have contributed to fleet resiliency 

during times of high systems demand: units now scheduled for retirement were operated near 

full capacity. Additional regulations now under development may increase retirements of these 

more flexible units. 

Many of today’s sophisticated emission control systems are designed to operate under relatively 

constant conditions and at high load factors. For example, selective catalytic reduction systems 

for nitrogen oxides (NOx) control require that flue gases have a minimum temperature for the 

catalyst to be effective. Operating at low load may not meet this criterion with currently available 

catalysts, monitoring and control systems. Systems for capturing sulfur dioxide (SO2) may 

operate at lower thermal efficiency at partial load, and may create new, less manageable 

wastewater issues and coal combustion products. 

Technologies to address these problems can take several forms. One is the development of 

improved materials, such as better alloys and metal coatings that are stronger and less sensitive 

to corrosion. Stronger materials allow thinner-walled components and thinner walls result in less 

damage from the stress of changing temperatures that accompany cycling operation. 

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Another type of technology involves improved sensors and controls. These can both automate 

the optimization of multiple plant operating parameters under rapidly changing load conditions, 

as well as help in predicting problems before a critical component fails. Improved sensors and 

monitors can allow operation closer to design margins and with greater reliability by detecting 

performance or life degradation. Improved non-destructive diagnostic systems would also aid 

reliability. Existing “asset management” programs need to be modified to reflect the effects of 

cycling on plant economics and reliability. 

An additional class of potentially useful technologies would treat coal to reduce moisture or trace 

element content – factors that can impact unit availability and performance, particularly when a 

unit is designed to use coals from a variety of sources. Enabling flexible operation at a unit that 

uses coals from different sources will be more difficult and costly. 

In general, training programs and studies using lessons learned and best practices can assist plant 

operators and maintenance personnel with the improved technologies and procedures that are 

critical to success.

b. Improving Unit Efficiency

Decisions to commit resources to energy efficiency measures generally consider a range of 

factors. These include the obvious positive impacts on fuel use and reduced emissions; 

potentially negative impacts related to new source review policy (discussed in Section C.4.); and 

less obvious potential effects on operational flexibility such as achieving minimum loads, higher 

ramp rates, increased outage durations. Increasing attention to emissions of carbon dioxide 

(CO2) will provide greater impetus to improve efficiency. 

A number of technical reports have considered specific measures that could potentially be 

applied within a coal-fired power plant. For example, coal could potentially be dried using waste 

heat, making the boiler more efficient. Steam turbines could potentially be refit with modern and 

more efficient multistage rotors. In addition, corrosion and deposition on major heat transfer 

components (boiler tubes and condensers) could potentially be reduced, making heat transfer in 

those components more efficient. 

On some units, alkali materials can be injected into flue gases to reduce acidity that would 

otherwise present corrosion problems at low temperatures, thereby potentially allowing greater 

heat recovery from flue gases. Improved sensors and controls could potentially allow a plant to 

operate closer to conditions optimal for higher efficiency. Variable speed drives could potentially 

be used to make motors more efficient, particularly at lower load.

While many of the needed technologies already exist and are operating on some units, these are 

not a one-size-fits-all package of solutions that can be readily applied to or accommodated by the 

existing coal fleet. The opportunity to apply these efficiency improvements across the existing 

fleet will vary significantly. 

In some cases, the opportunity will be negligible because the unit either is already operating in a 

highly efficient mode with some or all of the improvements in place or because the 

implementation of potential improvements is not cost-effective and/or technically feasible. As 

such, the degree of efficiency improvement possible at a given unit is highly site-specific, and may 

depend on the design of the unit, current maintenance procedures, whether the unit operates as 

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base load or cycling, the type of coal used by the unit, system economics and the economics of 

the specific measure and the configuration of the unit. Even the location of a unit is relevant to 

efficiency because plant efficiency is sensitive to ambient temperature and atmospheric pressure 

(elevation). 

This report does not provide a quantitative assessment of the degree to which these existing 

technologies could improve the heat rate (or efficiency) of the existing coal fleet. The U.S. 

Environmental Protection Agency (EPA), in a technical support document developed for the 

greenhouse gas emission rulemaking, concluded that heat rate reductions of 2-5% are possible 

for individual generating units, but that conclusion was not rigorously reviewed or corroborated 

by this report.

3

 

Most waste heat recovery applications hinge on reliable heat exchangers which have not been 

adequately demonstrated in the U.S., thus there is much skepticism surrounding their viability. 

However, many designs have been employed abroad with reasonable success. Therefore, the 

public and private sectors should engage in research opportunities to adequately demonstrate 

and improve current designs. 

It may be possible to add “topping” or “bottoming” cycles to existing units to increase their 

efficiency. This would involve adding one or several new components, and integrating these with 

the existing plant’s operation. The retrofit of a topping or bottoming step to a conventional 

Rankine cycle is a potential efficiency improvement that requires an extensive research, 

development and demonstration (RD&D) effort.

The New Source Review (NSR) permitting program unintentionally limits investments in 

efficiency. Some actions to improve efficiency at an existing power plant could lead to a 

designation of the change as a “major modification” subjecting the unit to NSR permitting 

requirements. These requirements usually entail additional environmental expenditures (that 

can reduce efficiency), as well as delays associated with processing the permit. In general, if a 

plant owner expects that an efficiency improvement would lead to such a designation, the 

efficiency project will not be pursued as the resulting permitting process would be extensive and 

the compliance requirements would be onerous and likely too stringent to be practicable. 

Unfortunately, this prospect has all but eliminated RD&D that would more than marginally 

innovate the fleet.

c. Reducing Emissions

In addition to the discussion on efficiency, which tends to reduce all emissions, this report 

considers two other categories of emission reductions at existing coal-fueled power plants: 

traditional emission controls and reduction of CO2 emissions through use of carbon capture and 

storage (CCS).

i. Traditional Emission Controls

The existing coal fleet is generally well equipped with systems designed to control emissions of 

particulate matter, nitrogen oxides and sulfur dioxide. These systems and recent additions aimed 

at hazardous air pollutants (HAPs) are effective at removing other pollutants such as mercury. 

Existing units also comply with regulations related to thermal emissions to bodies of water that 

supply cooling water at the power plant, wastewater emissions and solid waste management. 

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However, recently proposed or adopted regulations will lead to more stringent emission 

reduction requirements, and often reduction of emissions in one media (e.g., air) will result in 

new pollution control issues in another media (e.g., wastewater). With these new rules in mind, 

this report recommends several areas in which collaborative RD&D could develop improved 

technologies to mitigate emissions. Such collaborative efforts have been highly successful in 

developing and commercializing technologies in the past, including flue gas desulfurization, lowNOx burner systems, selective catalytic reduction of NOx and mercury control technologies. 

Moreover, for every dollar of federal funding in coal technology development, approximately 

thirteen dollars of benefits accrued to the nation.4

ii. Retrofitting CCS

The Obama administration’s stated long term climate goal is to reduce U.S. greenhouse gas (GHG)

emissions by 83% (relative to 2005 emissions) by 2050.5 Although U.S. coal-fueled power plants 

contributed only 3% of global GHG emissions in 2012, fossil energy-based electricity generation 

contributed 31% of total U.S. GHG emissions in 2012 (23% from coal-fired units; 8% from natural 

gas-fired units).6

 These numbers suggest any future reduction requirements will target a large 

reduction in CO2 emissions from fossil energy-based power. One possible pathway for such a 

reduction is the development and deployment of CCS technologies. Much progress on 

developing CCS systems for coal-fired power plants has been achieved by the collaborative RD&D 

program managed by the U.S. Department of Energy (DOE). However, as indicated in DOE’s 

program plans for CCS, much remains to be done. 

Previous NCC reports have addressed CCS control technology and identified the primary 

shortcomings of CCS technologies currently under development to be:

• They have not been demonstrated at commercial scale on a power plant

• The knowledge base on saline storage and enhanced oil recovery (EOR) remains limited, 

and there are unresolved non-technical barriers to both

• The current technologies are too costly, impose significant energy penalties and can 

significantly increase cooling water requirements for the generating unit

• There are numerous challenges related to the integration of CCS on existing units

• Significant uncertainty exists regarding the characteristics, feasibility and availability of 

geologic storage opportunities

• Significant legal and regulatory challenges remain to be resolved, including those related 

to the long-term stewardship and liability of geologically stored CO2

Some of these problems are being addressed to some extent by ongoing RD&D. With adequate 

funding, DOE plans to have 2nd Generation CCS technologies (at lower cost than current 

technologies) available to begin demonstration in 2020-2025, and available for commercial use a 

few years later. However, retrofitting existing units (or repowering them with CCS systems) poses 

the additional problem that there is a limited time window for development of needed 

technologies. Less than 10% of the existing coal fleet will be under 40 years of age in 2030. 

As discussed in Section B, the age profile of existing coal-fired power plants varies by region, and 

by type of utility. For example, coal units owned by rural cooperatives tend to be newer than 

those operated by investor-owned utilities. Decisions on whether to retrofit capital intensive 

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hardware, such as CCS systems, are based on multiple economic factors, some of which relate to 

the remaining useful life of potential retrofit candidates, and some of which are highly uncertain 

when projected 15 years into the future. These uncertainties include the capital cost of 

competing electricity generation technologies, new environmental requirements and the future 

price of natural gas. Nevertheless, from both an economic perspective and from the perspective 

of meeting climate change mitigation goals, much less costly CCS technologies are needed much 

sooner than the current program provides.

In addition, although DOE has a robust research and development (R&D) program, there does not 

appear to be a plan to obtain the resources needed to move research products to the more costly 

demonstration stage of technology development.

2. Key Findings and Recommendations

The following key findings and recommendations are taken from the more detailed listings of 

findings and recommendations in Sections B, C and D. 

a. The Value of the Existing Coal Generation Fleet

Findings

• The U.S. existing coal fleet continues to play a vital role in meeting our nation’s electric 

power needs. The extreme cold weather events of the winter of 2013-2014 highlight the 

need to maintain a diverse portfolio of generation options in order to ensure the 

availability of affordable, reliable power for residential and industrial uses.

• The historical deployment of advanced coal technologies demonstrates that coal 

generation can be increased while simultaneously reducing emissions. 

• Retrofitting advanced environmental technologies and enhancing efficiency at existing 

coal plants could result in the creation of 44,000 to 110,000 jobs, depending on the 

degree of efficiency improvement achieved.

Recommendations

• DOE should lead collaborative efforts with industry to assess the impacts of the 2014 

polar vortex experience on power prices, availability and reliability.

• DOE should ensure that basic federal energy policy assessments, such as the Quadrennial 

Energy Review7 and the President’s Advanced Manufacturing Initiatives8 consider the 

impact of lower priced electricity facilitated by coal-fired power plants, and include an 

assessment of the value of diversity of generation sources and how pending coal plant 

retirements are likely to impact power prices, availability and reliability.

• DOE should lead collaborative efforts with industry to evaluate the implications of 

generation diversity on the President’s advanced manufacturing initiatives and efforts to 

enhance the global competitiveness of U.S. manufacturers.

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b. Changes that Could Impact the Existing Coal Generation Fleet

Findings

• Natural gas prices continue to be volatile, reinforcing an historical trend. Past efforts by 

both industry and government have not produced accurate predictions of future natural 

gas prices. Increased reliance on natural gas for power generation will impact price 

stability and resource supply.

• The price of coal per unit of energy delivered to electric power plants is less than the price 

of delivered natural gas. EIA projects that coal’s price advantage will increase through at 

least 2040.

• New Source Review regulations impact generators’ decisions and ability to enhance plant 

efficiency, reduce emissions and improve overall operations/capacity. The delay and cost 

associated with obtaining an NSR permit tend to eliminate efficiency enhancement 

projects as viable options. 

• Many of the challenges facing the existing coal fleet are technology based, and would 

benefit from DOE-led collaborative RD&D with industry. Funding requirements, 

particularly for demonstration projects are significant.

• EIA projects that 60 gigawatts (GW) of coal capacity will be retired by 2020, relative to 

2010, based on projected market conditions, but not considering a series of recently 

proposed and not yet promulgated environmental regulations applicable to coal-fired 

power plants.

• Notwithstanding retirement of approximately 20% of the coal fleet capacity, EIA projects 

that under current regulations, coal-fired generation will remain approximately the same 

from 2010 through 2040.

Recommendations

• DOE should work with the EPA to eliminate New Source Review-related barriers that 

disincentivize generators to pursue efficiency improvements that would otherwise reduce 

emissions, increase capacity and enhance plant operations.

• DOE should seek input from industry research associations such as the Electric Power 

Research Institute (EPRI) and Coal Utilization Research Council (CURC), regarding priority 

research needs and the appropriate balance between research, development and 

demonstration of technologies relevant to the existing coal fleet.

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c. Improving Fleet Flexibility and Reliability

Findings

• In the future, factors such as increased deployment of intermittent renewable energy 

technologies, competition from other fossil fueled generation, use of non-design coals

and the increasing age of the coal generation fleet will lead to increased operation of base 

load-designed coal generation units in a cycling mode.

• Greater understanding of failure mechanisms leading to tube leaks, component failures

and other malfunctions leading to forced outages and reduced equipment life are 

necessary to maintain system reliability.

• Similarly, major emission control subsystems were generally designed for steady state 

operation and may not operate as reliably or effectively under changing load conditions.

Recommendations

• DOE should lead collaborative RD&D efforts with industry to develop assessment tools, 

improved sensors and controls, non-destructive evaluation, remaining life evaluation and

an understanding of damage mechanisms.

• DOE should lead collaborative RD&D efforts with industry to enhance practical knowledge 

about operating flue gas desulfurization (FGD) and selective catalytic reduction (SCR)

systems in a cycling environment, with a range of off-specification coals.

• DOE should lead collaborative RD&D efforts with industry to develop advanced materials 

that are more corrosion resistant and have increased strength. Stronger heat exchanger 

materials can be designed with thinner walls that are more tolerant of temperature 

cycling.

d. Increasing the Efficiency of the Existing Fleet

Findings

• Modest improvements in efficiency are possible at some units with existing technologies 

to improve heat transfer, reduce heat losses and make better use of low quality heat.

• New Source Review policy is a major barrier to implementing known efficiency measures 

at existing coal-fueled power plants.

• The addition of a topping or bottoming cycle to an existing generating unit’s Rankine 

cycle, if proven feasible and developed commercially, could deliver significant efficiency 

improvements. Practical systems could require up to 10 years to commercialize.

Recommendations

• DOE should lead collaborative RD&D efforts with industry to develop topping and 

bottoming cycles that can be retrofit to existing power plants.

• DOE should work with regulatory agencies to remove NSR barriers to efficiency upgrades.

• DOE should lead collaborative RD&D efforts with industry to develop best practices 

manuals for potential application of currently known techniques to improve power plant 

efficiency.

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e. Reducing Emissions from the Existing Fleet

Findings

• Past federal RD&D to improve the performance and reduce emissions from coal-fired 

power plants has yielded $13 of benefits for every dollar of federal investment.

• Proposed standards for wastewater effluents from existing coal-fueled power plants are 

not achievable under all operating conditions (e.g., for wastewaters with high oxidation 

reduction potential) using existing technologies.

• Some of the challenges posed by emerging regulations for traditional pollutants are the 

result of other emission control systems. For example, bromine or other chemicals 

introduced to enhance mercury removal from flue gases can alter wastewater streams 

from air pollution control devices. 

• The recently proposed CO2 New Source Performance Standards (NSPS) rules specified 

more stringent monitoring and reporting requirements for power plant CO2 used for EOR 

versus “natural” CO2 used for EOR. According to a major EOR operator, “the proposed 

NSPS rule will foreclose – not encourage – the use of CO2 captured by emissions sources in 

EOR operations.”9 It is unclear whether these rules, when finalized, will allow the 

flexibility needed by EOR operators in practical EOR projects.

• Substantial progress has been made on CCS systems for CO2 capture from power plants, 

but much more work is needed before these systems can be a practical commercial 

option for existing power plants. Cost, system integration and legal framework issues are 

all major barriers to deployment of currently available technologies.

• While many of the more technical aspects and costs of the CCS process are fairly well 

categorized, the costs and risks associated with monitoring, mitigation and verification 

(MM&V), permitting, site negotiation, property rights, liability, legal/contracting costs, 

costs of meeting legal or regulatory requirements, etc., are less well understood and 

quantified.

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Recommendations

• DOE should lead collaborative RD&D efforts with industry to develop:

o technologies and mechanisms to meet additional requirements for wastewater effluents from 

existing coal-fueled power plants,

o technologies to address control of secondary emissions from primary emission control 

systems, such as bromine and trace metals removed from flue gases that are discharged via 

wastewater streams, and

o systems to conserve water and reduce cooling water environmental impacts from existing 

power plants.

• The need for accelerated solutions points to greater emphasis on hands-on test facilities 

that emulate the National Carbon Capture Center design concept.

• DOE should place much more emphasis on commercial scale demonstration of CCS 

systems, both capture and storage options. 

• DOE should work with states and regulatory agencies to create a pragmatic legal 

framework for CO2 storage, particularly in saline formations, and to avoid monitoring 

requirements that deter use of captured CO2 in EOR applications.

• DOE should lead collaborative RD&D efforts with industry to analyze CO2 storage related 

issues associated with meeting financial responsibility compliance per Class VI 

Underground Injection Control (UIC) regulations [40 CFR §146.85].

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The 2014 Polar Vortex

The National Coal Council’s Existing Coal Fleet Study was conducted during the winter of 2013-

2014. The severe cold weather events experienced throughout the U.S. highlighted the value of 

our existing coal fleet and reinforced the need to 

maintain our coal generation option.

In January and February of 2014, the nation was swept 

with a series of cold weather events that tested the 

integrity of electricity supply. In general, electricity 

supply met demand, even under these severe 

conditions. However, electricity and gas prices surged 

for many consumers as energy supplies were stretched 

to their limits. More importantly, with increasing levels 

of coal retirements scheduled over the next three years 

(five times the level of retirements in 2012), it is clear 

that if those retirements had already occurred, the 

outcome this winter would have been much worse. 

During increased power demand for much of the U.S. in January, for example, alternative fuels 

were significantly supply constrained and in the words of The New York Times, “Coal [came] to 

the Rescue.”

10 Wind produced only 4.7% of the nation’s power while solar produced less than 

0.2%. Nuclear provided only 5% of incremental “year-over-year” generation and hydroelectric 

output declined 13%. As natural gas supplies faltered, gas turbines were taken offline but gas 

prices still spiked from the Northeast through the South to the Midwest to the Northwest. In 

some areas gas to produce electricity was more expensive than liquid fuel, even though the price 

of oil for generation rose to over $400 per barrel. Public Service of New Hampshire resorted to 

burning jet fuel and for the U.S. as whole, oil accounted for more incremental year-over-year

generation than did nuclear power. 

To some degree, the events of the 2013-2014 winter and their causes were predicted. The 

Federal Energy Regulatory Commission’s (FERC) Winter Reliability Assessment, published in 

December 2013 stated: “The 2012–2013 winter period demonstrated that New England’s natural 

gas dependency risk continues to escalate and existing fuel arrangements of many generators will 

lead to continued challenging and complex operating conditions when the power system and fuel 

supply deliveries are stressed.”11

As shown in Figure PV1, for the months of January and February 2014, compared to the same 

months in 2013 and 2012, coal was the leading source of electric power in the U.S. Figure PV2 

shows that, for the winter of 2014, compared to 2013, coal-fueled generation provided 92% of 

that increase.

12 Although demand for power was greater in 2014, generation by natural gas 

decreased, because natural gas was diverted to fuel residential heating needs and gas prices 

soared to over three times that of coal.

13 As the year progresses, the nation is depending upon 

“gas to coal switching” to refill gas storage, which declined to 822 billion cubic feet (bcf) at the 

end of March 2014, the lowest level in over a decade and almost one trillion cubic feet lower than 

April 2013.14 A record average of at least 90 bcf/week of injections would be required over the 

“This country did not 

just dodge a bullet – we 

dodged a cannonball.” 

– Nick Akins, CEO

American Electric Power

Testimony before 

Senate ENR Committee

Polar Vortex 12 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

next seven months to refill storage to 3.5 trillion cubic feet (Tcf). The average injection in 2013 

was ~ 64 bcf/week. 

Figure PV1. U.S. Electricity Generation for January & February, 2012-2014

Figure PV2. Portion of Increase in U.S. Electricity Generation, by Fuel

The U.S. may or may not reach adequate storage by the beginning of this year’s winter heating 

season, but one fact is certain: without the ability to shift generation from gas to coal, the goal 

would be impossible, and with another round of severe weather the U.S. would see another and 

far more severe shortfall in gas supply accompanied by rising prices. More than an additional 500 

Polar Vortex 13 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

bcf in gas to coal switching is required in 2014 to reach average storage. In short, without gas to 

coal switching over 2013-2014, storage would now be virtually exhausted or, far more likely, 

prices would be at record levels. 

The U.S. coal fleet’s value has never been more apparent. Yet, a significant portion of the 

electricity required to make up for the limitations of gas and other fuels is provided by coal plants 

slated for closure, many of which are prematurely being taken off the grid because of increasingly 

stringent regulatory policies. Plants such as Brayton Point (1,530 MW) in Massachusetts enabled 

many states to avoid a full blown energy crisis.

• “89% of our coal capacity slated for retirement in 

mid-2015 is called upon and running. Natural gas 

delivery is challenged." Nick Akins, CEO, American 

Electric Power

• At one point about 75% of New England's gas 

generating capacity was not operating due to lack 

of supply or high prices. 

• At least 75% of Southern Company’s coal power 

plants scheduled to soon close was needed to 

meet consumer demand. 

• The Tennessee Valley Authority set new records 

for electricity demand at the same time that many 

of its coal-fired generating facilities are scheduled 

for closure, including two of its three highly 

productive Paradise Units. 

• “We really counted on [a] combination of coal and 

gas and nuclear and pump storage and hydro, we 

needed every bit of it.” Lynn Good, CEO, Duke Energy

• The North American Electric Reliability Corporation (NERC) found that the New England 

generation fleet is overly reliant on natural gas as a primary fuel source, and generators 

are heavily dependent on pipeline capacity released by the firm capacity rights holders.15

• Public utility commissions in Ohio and Pennsylvania urged consumers to conserve, 

especially electricity. "I have been on the commission since 2008. This is the first time we 

have had to issue a winter conservation request." Pennsylvania PUC Chairman Robert 

Powelson

Without the coal plants slated to go offline, these regions as well as others would not have met 

the demand for power. The capacity factor of America's coal plants averages almost 70% while 

many gas plants could not get fuel this winter and will continue to be replaced by coal throughout 

the year. What will happen when these reliable base load coal plants are closed in the next 24 

months? Importantly, once a coal unit is closed, its license terminates.

Based on the most recent data from EIA, if premature closures proceed, by 2018 natural gas 

generating capacity will exceed that of coal, nuclear and hydro combined. (See Figure PV3.) With 

the closure of at least 60 GW of coal generation capacity in the next few years, America will be 

excessively dependent on gas for electricity. Gas prices are more volatile than any other fuel; 

The value of the existing 

coal fleet is not an 

abstract concept. At a 

time of great stress on 

power demand in 

Jan/Feb 2014, coal 

produced 92% of the 

increase in U.S. 

electricity generation, 

relative to Jan/Feb 

2013.

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sustained supply has yet to be demonstrated and is questionable due to the rapid decline rate of 

shale gas production from newly completed wells. 

Figure PV3. Projected 2020 Energy Capacity, by Fuel.

Energy price spikes and supply problems in New England and 

throughout the nation this winter demonstrated that current coal 

policies are imprudently placing the reliability, affordability and

security of America's electric supply system at risk. The problems in 

New England are precursors to other parts of the nation where 

overdependence on gas prevails and is even further on the rise. 

New England and New York City spot natural gas prices have 

averaged $19.81/million Btu (MMBtu) through March compared 

with $18.25/MMBtu for fuel oil that can be used in power 

generation. 

Reliability and affordability are both at risk. Gordon van Welie, CEO 

of the New England Independent System Operator (ISO-NE) has 

warned: “The region abruptly went from a capacity surplus and low 

prices to a capacity shortfall and relatively high prices." The 

capacity shortfall will cost New England utilities over $3 billion by 

2018. The recent average price for a megawatt hour of electricity in 

New England was $163 – that is 200% higher than in January 2013 

and 400% higher than in January 2012, and the outlook for 2015 

and beyond is bleak. 

Warnings over the impacts from loss of coal capacity have been sounded by industry over the 

past few years. The planned near term closings of two major coal plants (Brayton Point, 1530 

"Even in the last 

year, you’ve seen 

nearly a 50 percent 

increase in the price 

of natural gas from 

where it was in 2012. 

There’s a storm 

that’s brewing." 

Randall Data, CEO, 

Babcock and Wilcox, 

2014

"As demonstrated by 

cold snaps just this 

winter, natural gas 

prices are volatile and 

spike...This has an 

immediate adverse 

effect on consumer 

electric bills. Coal, and 

its stable price is a longterm proven hedge 

against natural gas 

volatility and is critical if 

we are to continue to 

provide affordable 

electricity for our 

members." John Novak, 

Director of Environmental 

Issues, National Rural Electric 

Cooperative Association

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National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

MW and Salem Harbor, 750 MW) and one nuclear station (Vermont Yankee, 600 MW), essentially 

ignores warnings from agencies focused on reliability, including NERC and FERC. And, closure will 

apparently proceed despite the NE-ISO declaring Brayton as a “must-run” facility.16 Worse is to 

come, as New England digs its hole deeper: It is planning to rely on natural gas and (non-hydro) 

renewable energy for about 80% of its electricity.

17,18

Other states face similar risks, such as Florida, Delaware, Massachusetts, Nevada and Rhode 

Island, all of which used natural gas to generate over 60% of the electrical generation in 2013.19

In fact, most of the southern tier is at increasing risk as overdependence on natural gas 

proliferates. Over 130 million people now rely on natural gas to provide more than 50% of their 

electricity in summer and the number is steadily increasing. EPA rules may force Arizona to close 

Navaho Generating Station, a facility associated with a large Native American workforce and the 

source of more than one-seventh of the state's electricity. 

Based on EPA policies Ohio would lose at least 40 coal generating units, Pennsylvania 26, 

Alabama 21 and Wisconsin 14.20 With over 300 units closing, few states will be untouched by the 

consequences of the loss of reliable and affordable coal-based electricity. Gas price spikes have 

nationwide consequences, cost jobs and overwhelm family budgets, pushing more and more 

households to seek government aid to pay electric bills and heat their homes.

Summary Implications of Projected Retirements 

EIA indicates at least 54 GW of coal generation will be forced to close by 2016, more than 

one-sixth of the entire coal fleet in just two years. At over 1,600 terawatt hours (TWH) of output, 

coal produces about 40% of the nation's electricityiv and the cuts into reliable coal capacity may 

go much deeper, particularly as environmental regulations now under development are 

promulgated. Units that retired in 2010-2012 were relatively small, with an average size of 97 

MW and heat rate of 10,695 British Thermal Units/kilowatt hour (Btu/ kWh). In contrast, units 

currently scheduled for retirement are larger and more efficient; at 145 MW, the average size is 

50% larger than earlier retirements, with an average heat rate of 10,398 Btu/kWh. 

The major “lesson learned” from the Polar Vortex experiences in January and February of 2014 

was that the U.S. power grid is less resilient than previously believed. Only the availability and 

operation of coal units now scheduled for retirement over the next two years enabled the power 

sector to meet demand during periods of harsh weather events.

iv The EIA Annual Energy Outlook – 2014 projects that, based on current regulations, coal’s contribution to total generation will 

average 37% for the period 2014-2040.

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B. The Role (Benefits) of the Existing Coal-Fired Power Plant Fleet, 

Including Portfolio Value 

1. Background

The U.S. relied on wood as its primary source of energy during its first century. However, coal 

offered the opportunity to exploit entirely new ranges of industrial activity, including steel 

production, Portland cement and glass production, and chemicals derived from gasified coal.21

After the Civil War, and until the end of the Second World War, coal provided the bulk of energy 

in the U.S. The 1882 opening of Thomas Edison’s Pearl Street Station in Manhattan launched a 

new energy age. Coal-generated steam drove six dynamos that supplied electricity through 20 

miles of underground cable to light one square mile of New York City. And Edison’s incandescent 

light bulb replaced the intense electric arc systems in earlier electric lighting applications.22 In a 

rush of technological advances, alternating current systems replaced direct current systems 

(making longer range transmission practical), steam turbines replaced reciprocating designs and

electric motors and electric appliances expanded markets beyond lighting applications. By 1929, 

two-thirds of American homes had electricity.23 Figure B.1 shows U.S. energy consumption by 

fuel for the period up to 1945.24 Today, electricity is integral to almost all aspects of everyday life 

in the U.S. – including work, play, health care, safety and communications. Electricity continues 

to increase in importance in the U.S. economy, increasing from 38% of total U.S. energy 

consumption in 2000 to 42% forecast in 2040.25, 26

Figure B.1. Estimated U.S. Primary Energy Consumption Before 1945.

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The U.S. National Academy of Engineering ranked electrification as the “most significant 

engineering achievement of the 20th Century.”27 Similarly, in November 2013 the Atlantic

magazine assembled a panel of scientists, engineers, entrepreneurs and technologists to assess 

the 50 innovations “that have done the most to shape the nature of modern life since the 

widespread use of the wheel.”28 Electricity was ranked the second most significant, after the 

printing press.

2. Profile of the Existing Coal Fleet

Figure B.2 shows the growth of U.S. electricity generation from 1950–2013, by energy source.29 

Throughout this period, coal has dominated electricity generation, typically providing about half 

of total U.S. generation.30 This dominance has resulted from coal’s domestic abundance, 

accessibility, reliability and low cost compared to other generation alternatives.

Figure B.2. U.S. Electricity Generation by Energy Source.

States vary considerably in their reliance on a particular fuel for electricity generation. Figure B.3 

presents generation data by fuel for the year 2012.31

The Clean Air Act Amendments of 1970, and additional amendments in 1977 and 1990, have led 

to regulations limiting emissions of multiple air pollutants from coal-fired power plants. By the 

end of 2011, 60% of the U.S. coal fleet had FGD scrubbers installed (for SO2 control), and 67% had 

either a SCR or a selective non-catalytic reduction (SNCR) installed (for NOx control).32 

Remaining units generally reduced SO2 emissions through the use of low sulfur coal, and NOx 

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emissions through the use of low-NOx combustion modifications. EPA projected that the MATS 

would result in additional deployment of air pollution control equipment, including another 22 

GW of dry FGD, 43 GW of dry sorbent injection (DSI), 141 GW of activated carbon injection (ACI), 

101 GW of fabric filters, 34 GW of electrostatic precipitator upgrades and 63 GW of FGD 

upgrades.33

Figure B.3. Generation by Fuel, 2012.

v

Just as there is substantial variability the mix of power generation sources geographically, the mix 

also varies by business structure. Investor owned utilities and non-utility generators dominate 

generation, with each providing 39% of total U.S. generation in 2011. However, publicly owned 

utilities (state and municipally owned power entities) contributed 10% of total generation, federal 

power agencies contributed 7%, and cooperatives contributed 5%.34 

Figure B.4 shows the contribution by fuel type for all power generation in 2012, and Figure B.5

shows the contrast for rural cooperatives.35 Note the much larger reliance by cooperatives on 

coal, and correspondingly less reliance on natural gas. The fuel mix for public power utilities (for 

2011) is similar to that for cooperatives, with 45% of generation from coal, and 16% from natural 

gas.36 The business structure is relevant to technology choices because different types of entities 

have different sensitivities to capital investment due to financial structures and taxation. For 

v

Based on EIA data. A state tabulation of generation and electricity price data is included as Appendix 3.

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example, investor owned utilities typically finance power plants with approximately 50% debt and 

50% equity, whereas publicly owned utilities finance almost entirely via debt instruments, and 

interest on municipal bonds is not subject to federal income tax. 

Figure B.4. Generation Fuel Mix for all Entities.

Generation Fuel Mix

37%

30%

19%

12%

1%

0%

5%

10%

15%

20%

25%

30%

35%

40%

Coal Gas Nuclear Renewables* Oil

• Including 7% Hydro

Source: 2012 EIA data (all sectors)

Total Generation: 4,054 billion kWh

Total Industry (all electric utilities)

Figure B.5. Generation Fuel Mix for Cooperatives.

58%

17%

12% 13%

0%

10%

20%

30%

40%

50%

60%

Coal Gas Nuclear Renewables*

Source: EIA and RUS data

*including hydro (10%)

Fuel Mix

Rural Electric Distribution Co-ops

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Figure B.6. Generation Fuel Mix for Public Power Utilities. (Source: APPA)

3. Benefits Provided by the Coal Fleet

The current coal fleet (approximately 310 GW of generating capacity) is the result of decades of 

bipartisan support of coal, ranging from Presidents John Kennedy to Jimmy Carter to Ronald 

Reagan to George Bush. In 1980, Carter asked Congress to mandate that “utility companies cut 

their massive use of oil by 50% within the next decade and switch to other fuels, especially coal, 

our most abundant energy source.” From the Democratic 1980 Platform: “The Democratic Party 

regards coal as our nation's greatest energy resource. It must play a decisive role in America's 

energy future. We must increase our use of coal.” Since 1980, coal generation has increased 37% 

or 425 TWH – more than the current total power production of the United Kingdom. The existing 

fleet of coal-fired power plants underpins economic prosperity in the U.S. Coal-based generation 

has dominated the U.S. electricity supply for nearly a century. (See Figure B.2.)

The benefits derived from the existing coal fleet have several components. These include the 

direct and macroeconomic benefit of low-cost electricity, the portfolio value of having a diverse 

mix of fuels and technologies for power generation, and the energy security value of a power 

generation option that is not dependent upon real-time fuel delivery/transport and is relatively 

immune to purposeful attack (terrorism).

a. Direct and Macroeconomic Benefits

Macroeconomic benefits can be estimated by calculating the cost of replacing generation from 

coal with the most economical source of new generation. 

Figure B.7 shows the levelized cost of electricity (LCOE) in megawatt hours (MWh) for a range of 

types of new power plants, based on cost parameters used by DOE/EIA in its Annual Energy 

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Outlook, including fuel costs projected for 2018-2048. Note that for these assumptions, the least 

costly form of new electric power is a natural gas combined cycle (NGCC) unit, without a system 

to capture and store CO2 ($67/MWh, in 2011 $s). Note also that the non-capital (operating) costs 

for a well-controlled coal unit total about $35/MWh. 

One way of estimating the value of the existing coal fleet is to calculate the cost of replacing it 

with another form of generation. If it were even possible to replace the existing coal fleet with 

the least cost source of new electric power, then the operating costs of the coal fleet ($35/MWh) 

would be replaced by full levelized costs for new NGCC generation. Under EIA’s “Reference 

Case”, that price would be $67/MWh. However, with the substantial increase in gas consumption 

caused by replacing so much coal generation, gas prices would increase above the amount 

assumed in the EIA reference case. For this analysis, the future price of gas was postulated to 

equal EIA’s “Low Oil & Gas Resource Case,” resulting in a higher gas price, and a resulting LCOE of 

$72/kWh. Even this price is considered conservative since the additional NGCC units would 

require over 11 quadrillion Btu of gas per year, 48% of the total domestic dry gas production in 

2011.

Figure B.7. Levelized Cost of Electricity.

Figure B.8 shows the implications of such a replacement program, assuming EIA projected fuel 

costs for each year, the average generation from coal for 2008-2012 and that the fleet could be 

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replaced in 2020.vi The increased cost of electricity in the first year of analysis (2020) is $54

billion, and rises to $90 billion per year in 2040, due to the increasing differential between the 

projected costs of coal versus gas. The first year cost, $54 billion, is about 15% of the revenues 

from all retail electricity sales in 2011 ($371 billion). A nominal 15% increase in the price of 

electricity would reduce U.S. GDP and employment by about 1.5%.37 Current U.S. GDP is $16 

trillion per year (chained 2009 $s), and non-farm employment is 137 million jobs.38 Hence a 1.5% 

change could result in a $240 billion decline in GDP and loss of 2 million jobs.

Figure B.8. Value of Existing Coal Fleet: Electricity Cost Savings.

Another way of considering the value of the existing coal fleet is to compare the price of 

electricity in the U.S. to that of other free market nations. Table B.1 presents such a 

comparison.39 European power costs are two to three times those in the U.S.vii 

vi It would be impossible to martial the resources necessary to replace the existing coal fleet by 2020. Nevertheless, the year 2020 

was chosen to enable a simple, transparent first order cost assessment that, even with very conservative assumptions, 

demonstrates that the existing coal fleet provides substantial economic benefits to the nation. vii A significant part of the European Union (EU) price differential is believed to be based on taxes and fees levied in the EU to foster 

greater use of emerging renewable energy systems. These surcharges were estimated to total 20 billion euros in 2013. Die Welt, 

November 6, 2013. Additionally, the delivered price of coal and natural gas are generally 2-4 times as much as in the U.S. (Electric 

Power Monthly – March 2014, USDOE/EIA, March 21, 2014, http://www.eia.gov/electricity/monthly/; Statistical Review of World 

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Table B.1. Electricity Price in 2013, Cents/kWh.

Lower cost electricity acts as a stimulus to the economy, providing more disposable income to 

consumers and creating a competitive edge for U.S. manufacturers supplying global markets. 

Further evidence of the value of the existing fleet can be seen in a visual comparison of states 

that have a large share of electricity generation from coal40 (see Figure B.9), with states that have 

low retail electricity prices41 (see Figure B.10).

Given the importance of electricity to the economy, basic energy policy assessments, such as the 

Quadrennial Energy Review42 and the President’s Advanced Manufacturing Initiatives43 should 

consider the impact of lower priced electricity facilitated by coal-fired power plants. 

Just as importantly, coal provides economic stability and has been a crucial buffer to spiking gas 

prices. Over the past decade, natural gas prices have proven volatile indeed. In 2004, gas to 

produce electricity had doubled in just two years to reach $5.50/thousand cubic feet (mcf).

viii 

Then it more than doubled again by 2008 to peak at $12.41/mcf. By 2012, the price dropped to 

$2.81/mcf and averaged $4.44/mcf in 2013. The average price of gas delivered to electric power 

plants in January 2014 was $7.21/mcf, 60% higher than the price in January 2013.44 Average 

annual fuel prices since 2001 and projected future prices are presented in Figures B.11 and B.12. 

This past winter has demonstrated that large price spikes remain a characteristic of natural gas: 

• In New England, natural gas prices reached $77/mcf or $435 per barrel in oil equivalent 

terms, causing the switch from gas to oil power generation.45

• In New York, natural gas prices reached $90/mcf.46

• In the Northwest, spot natural gas at Malin Hub in Oregon quadrupled from $7.70 to 

almost $30/mcf.47 

• Deliveries to the Algonquin Citygates rose to $24.35, gas at Iroquois Waddington was 

quoted at $21.70, gas on Tennessee Zone 6 200 L increased to $29.72.48

• The Northern Natural Ventura price reached $43.82.

49

Energy 2013, BP, http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy2013.html.)

viii This report usually states natural gas prices in dollars per million Btu’s ($/MMBtu), so that they are directly comparable to other 

fuel prices. Prices will be reported in dollars per thousand cubic feet ($/mcf) if those units were used in a referenced document. 

The relationship between the two metrics varies slightly with the heating value of natural gas, but is generally: $1.00/MMBtu = 

$1.02/mcf.

Consumer class Electricity Price in 2013, Cents/kWh

U.S. Denmark France Germany Italy Spain UK

Residential 12 42 20 41 32 31 24

Industrial 7 15 13 20 23 17 16

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Figure B.9. Source of U.S. Electric Power (Data from DOE/EIA).

Figure B.10. Average Retail 2012 Electricity Prices, by State (Data from DOE/EIA).

 

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Figure B.11. Fuel Price Volatility.

Figure B.12. Future Fuel Prices (Data from AEO-2014, DOE/EIA).

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b. Supply and Price Stability Benefits

Energy supply and price stability are crucial elements in socioeconomic progress. The U.S. is still 

expanding, both in terms of population and GDP, and will continue to rely on its coal plants to 

meet electricity demand over the coming decades as the nation’s population increases by almost 

120 million by 2050. (See Figure B.13.) About 90% of the population will be urbanized. 

Figure B.13. U.S. Population Change.

The U.S. will not be able to reliably and affordably meet growing demand without a balanced 

energy portfolio that includes coal. Coal has traditionally provided a buffer against higher 

electricity prices, and it could be argued that an expanded coal fleet will be needed to meet the 

needs of the American people. By 2030 alone, the EIA projects that population will grow by over 

40 million, GDP will increase by almost 50% and at least 27 million new homes will be built. If 

electricity demand returns to the pre-recession growth rate, the U.S. would need an additional 

1,300 TWH by 2030 -- as much as the power consumption of France, Germany and the United 

Kingdom combined. 

The energy burdens of low-income households are much higher than those of higher-income 

families. Energy burden is a function of income and energy expenditures. As shown in Figure 

B.14, households with the lowest incomes have the highest relative energy costs. 

The last time the U.S. added 

120 million urbanites (1960-

2005) we used:

• 4.1 billion metric tons of 

cement – the equivalent of 

85 interstate highway 

systems.

• 4.8 billion metric tons of 

steel – enough Golden Gate 

Bridges to circle the Earth 4 

times. 

• 131,500 terawatt hours of 

electricity – enough to 

power France for well over 

two and a half centuries. 

• 40 billion tons of coal – but 

still have enough left for 

250 years. 

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Figure B.14. Impact of Energy on Discretionary Income.

Source: American Association of Blacks in Energy.

Thus, for 42% of households – mostly senior citizens, single parents and minorities – increased 

energy costs force hard decisions about what bills to pay: housing, food, education, health care 

and other necessities. Cost increases for any basic necessity are regressive in nature, since 

expenditures for essentials such as energy consume larger shares of the budgets of low-income 

families than they do for those of higher-income families. Whereas higher-income families may 

be able to trade off luxury goods in order to afford the higher cost of consuming a necessity such 

as energy, low-income families will always be forced to trade off basic necessities to afford the 

higher-cost good. Over 90 million Americans are currently eligible for energy subsidies under the 

Low Income Home Energy Assistance Program (LIHEAP), a program administered by state 

agencies but primarily funded by U.S. Department of Health and Human Services grants.

America’s coal endowment, coupled with an established supply chain, provides the opportunity 

for socioeconomic progress to occur with energy security, power reliability, price stability and 

affordability. The U.S. has 27% of the world's proven coal reserves. Figure B.15 shows 

distribution of coal resources throughout the U.S. The National Academy of Sciences has stated: 

"U.S. recoverable reserves of coal are well over 200 times the current annual production of 1 

billion tons and additional identified resources are much larger. Thus, the coal resource base is 

unlikely to constrain coal use for many decades to come." In 2013, the U.S. produced an 

estimated 1,022 million short tons of coal, exported 116 million tons and imported 9 million tons. 

A total of 942 million short tons were domestically consumed of which 93% (874 million) was 

used to generate electricity. 

• Families earning more 

than $50,000 per year 

spent only 4% of their 

income to pay energyrelated expenses.

• Families earning 

between $10,000 and 

$25,000 per year (29% 

of the U.S. population) 

spent 13% of income 

on energy.

• Those earning less 

than $10,000 per year 

(13% of population) 

spent 29% of income 

on energy costs.

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Figure B.15. 30% of Global Coal is in the U.S.

Over the past 150 years, the U.S. has built a vast infrastructure for extracting, transporting and 

utilizing coal for electric power, as the map in Figure B.16 indicates. The U.S. coal-fueled 

electricity generation supply chain is unmatched in the world. Research at Penn State 

University estimated the U.S. coal power supply chain provides over $1 trillion in gross 

economic output, 7% of U.S. GDP, 6.8 million jobs (5% of the U.S. workforce) and $362 billion in 

annual household income.50

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Figure B.16. The U.S. Coal-Fueled Electricity Supply Chain.

Figure courtesy of Peabody Energy. • 1,200+ active coal mines

• 95,000 miles of Class 1 railroads

• 12,000 miles of commercially navigable 

waterways

• 90,000 miners

"There are many areas of the country that either 1) have insufficient access to natural gas, 2) 

do not have suitable sites for CO2 storage or enhanced oil recovery sites, or 3) cannot be 

supplied wholesale power reliably through the existing transmission grid. How will the EPA 

reconcile elimination of new coal-fired capacity in these situations?" 

National Rural Electric Cooperatives Association (NRECA)

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In Implications of Greater Reliance on Natural Gas for Electricity Generation (2010), the American 

Public Power Association (APPA) demonstrated the prohibitive infrastructure cost of replacing 

coal with gas.

• Supply concerns: Just to replace coal power, the U.S. would need an additional 14 trillion 

cubic feet of gas – equivalent to the combined production of Texas, Louisiana, Oklahoma 

and the Gulf of Mexico.

• Infrastructure concerns: Merely to build the power plants, pipeline system and storage 

infrastructure necessary to provide reliable gas would require an outlay of over $800 

billion (2014 dollars).

• It would be physically challenging within any reasonable time frame, given the geology for 

storage. 

• Gas price escalation concerns: EIA projects that natural gas will cost $4.77 per million Btu 

in 2020. The APPA estimates that over the long term it would cost $11/MMBtu (2014 

dollars) simply to replace depleting reserves.

Continuing to close affordable base load coal generation will not only mean higher electric rates, 

but also higher manufacturing costs and increased heating costs for over 55 million families who 

heat with gas. 

c. Environmental Benefits

Continuous technology improvements have greatly reduced key emissions in the context of 

substantial increases in coal generation. Clean coal technologies work. The White House report, 

The Blueprint for a Secure Energy Future in March 2012 concluded: “implementation of clean, 

state-of-the-art coal-based technologies will help insure America’s energy security.” The 

CURC/EPRI coal technology roadmap found that, “Over the last 40 years, technology advances 

have led to impressive improvements in coal’s environmental “footprint.” For example, 93% of 

coal-fired power plants in the U.S. have installed, or are now in the process of installing, low NOx 

burners and other technologies which dramatically reduce power plant emission of nitrogen 

oxides. Reductions in emissions of SO2 are even more dramatic.”51

The U.S. has shown that additional coal can be used to produce more electricity, more efficiently, 

while reducing emissions. Today’s clean coal technologies drive enormous environmental 

improvement. Since 1970, coal used for electricity increased substantially alongside a doubling of 

GDP as key emissions have decreased almost 90%. State-of-the-art technologies have reduced 

emissions of SO2 by 88%, NOx by 82% and particulates by 96%. (See Figure B.17.) A combination 

of all of these technologies, in addition to use of sorbent injection systems, also enables highly 

efficient mercury removal. Utilities have invested more than $100 billion in these technologies in 

recent decades.

“There's nothing like a cold winter to remind utilities of the 

value of their coal fleet.” 

Paul Forward, Managing Director, Stifel Financial

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Figure B.17. Coal Use and Declining Emissions.

Supercritical power plants such as Prairie State (Illinois) and ultra-supercritical plants like AEP’s 

John W. Turk, Jr. plant (Arkansas) are the technological pathway to even lower emissions and the 

necessary precursor to carbon capture and storage. Figure B.18 shows the emission rate of 

recently permitted or constructed coal-fueled power plants compared to average emission rates. 

Although not shown in the figure, CO2 emissions from new supercritical or ultra-supercritical 

steam units can be as much as 25% lower than from the oldest operating U.S. coal plants.

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“We’re looking at something on 

the order of $70-90 a ton. In that 

context, that looks something like 

a 70-80% increase on the 

wholesale price of electricity." –

Julio Friedmann

Deputy Assistant Secretary for Clean 

Coal, DOE 

Figure B.18. Power Plant Emission Trends.

Currently available CCS technologies, resulting in 70-80% 

increases in the levelized wholesale cost of electricity 

compared to the same unit without CCS, are 

economically impractical in the absence of government 

subsidies. If such costly CCS technologies were broadly 

deployed, the increase in wholesale electricity costs 

would cause a profound increase in retail electricity 

prices. These extreme costs constitute a “call to action” 

to develop much less expensive CCS technologies.

d. Carbon Capture, Utilization and Storage (CCUS)

The use of CO2 for EOR is the CCUS approach providing the greatest potential for economic and 

environmental pay off over the next several decades. Enhanced oil recovery depends upon 

adequate supplies of CO2. The only way to obtain CO2 at scale is through carbon capture and 

utilization from coal power plants. 

DOE-sponsored research found that “next generation” CCUS and EOR technologies would enable 

the economic recovery of 67 billion barrels of “stranded oil” which could be produced assuming 

an $85/barrel oil price. In addition, there is emerging recognition that the Residual Oil Zone (ROZ) 

resources are enormous and could yield yet another 33 billion barrels for a total of at least 100 

billion barrels of oil that would otherwise remain unavailable. 

But the sine qua non of such recovery is the availability of adequate amounts of CO2. New EOR 

projects are being delayed due to a lack of CO2. Advanced Resources International (ARI) 

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estimates that as much as 20 billion metric tons of CO2 will be needed to produce this recoverable 

resource, and if potential ROZ production is included, the required CO2 exceeds 33 billion metric 

tons. However, only about 2 billion metric tons of CO2 will be available from natural sources and 

natural gas processing. Coal-based CCUS technologies can help meet this 31 billion metric ton 

shortfallix to enable the U.S. to produce domestic petroleum resources and avoid reliance on the 

imported oil that severely impacts our trade balance of payments and national security. Many of 

the 310 GW of existing coal-based generation units can serve as the foundation for the vast 

amounts of CO2 required, pending development of adequate pipelines and infrastructure. And, 

since coal generation will continue to be a leading source of electric power, it will provide a 

steady, affordable and reliable source of CO2 if the technology is further developed and 

commercialized.

Clean Coal Technology Job Benefits: Part of the Secretary of Energy’s request of the National Coal 

Council was to “address the jobs implications of modification and addition of equipment at 

existing coal fired power plants.” A major factor defining the impact of such employment impacts 

is the extent of efficiency improving measures to be deployed on the existing coal-fired power 

plant fleet. This report does not attempt to project a likely average efficiency improvement for 

the fleet due to several major uncertainties, including:

• The extent to which recognized efficiency improving measures have already been 

deployed,

• Site-specific technical and economic barriers to potential efficiency improving measures,

• The degree to which efficiency improving measures would be deterred by current policies 

regarding NSR “major modifications,” and the possibility that such policies might be 

changed in order to realize the benefits of efficiency improvements,

• The cost, performance and applicability of some potential efficiency measures, such as 

adding a topping cycle to an existing unit, and

• The potential loss in efficiency due to future operation of existing coal-fired power plants 

at reduced load, or with additional emission reduction hardware.

Nevertheless, others have projected potential changes in coal fleet efficiency. For example, 

although it is unclear whether, and if so to what extent, the above uncertainties have been taken 

into account, EPA has offered the following estimate of potential efficiency improvements: “A 

reasonable expectation for individual plants would be a 2 to 5 percent reduction [in heat rate], 

considering site-specific constraints. More analysis is needed to consider costs and estimate a 

reasonable expectation for the average fleet-wide heat rate reduction, but it will likely be less than 

5 percent.”52 

Management Information Services, Inc. (MISI)53 estimated the cost of creating additional 

generating capacity via efficiency improvements and concluded that this was less than the cost of 

ix 31 Billion tonnes of CO2 is roughly equivalent to 90% capture of all CO2 generated by 110 GW of CCS-equipped coal-fueled power 

generation over a 40 year period. This equivalent capacity would vary depending on the number of years of operation, capacity 

factors and the energy requirements of the CCS system.

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building new power plants. The resulting reduction in the projected cost of additional electricity 

was significant and showed that implementing efficiency measures on existing coal-fired power 

plants would have a stimulus effect on the overall U.S. economy. The employment increases 

from this “macro-economic” job impact of lower priced electricity was estimated to greatly 

exceed the jobs created by constructing and operating the efficiency projects. Overall, MISI 

projected that approximately 22,000 new jobs would be created for each percent reduction in 

overall fleet heat rate.

The EPA report and the MISI report can be considered together to offer a range of possible

annual job impacts of potential efficiency measures applied to the existing fleet. By combining 

the jobs per percent reduction in heat rate, derived from the MISI report, with the range of heat 

rate reductions projected by EPA “for individual plants,” a range of up to 44,000 to 110,000 jobs 

can be projected.

4. Findings and Recommendations

a. Findings

• Electricity is essential to U.S. citizens’ economic well-being, health, safety and quality of 

life. Access to low-cost, reliable coal-fueled power generation enhances lives. The 

deployment of advanced coal technologies will be key to achieving our nation’s energy, 

economic and environmental goals.

• Coal’s domestic abundance, accessibility and low cost will ensure its continued leading

role among U.S. power generation sources if coal’s environmental challenges can be met.

• The impending retirement of nearly 20% of the U.S. coal fleet by 2020 could put as many 

as 1 million jobs (or more) at risk.54

• Coal fleet retirements will cause electric rates to increase significantly, and will be 

especially harmful to those states heavily dependent on coal – in these states, electric 

rates could increase 30-50% (or more).55

• The U.S. existing coal fleet continues to play a vital role in meeting our nation’s electric 

power needs. The extreme cold weather events of the winter of 2013-2014 highlight the 

need to maintain a diverse portfolio of generation options in order to ensure the 

availability of affordable, reliable power for residential and industrial uses.

• Low-cost generation, such as that produced by the existing coal-fired generating fleet, is 

especially vital to ease the burdens of low-income and fixed-income households.

• The historical deployment of advanced coal technologies demonstrates that coal 

generation can be increased while simultaneously reducing emissions. 

• Retrofitting advanced environmental technologies and enhancing efficiency at existing 

coal plants could result in the annual creation of 44,000 – 110,000 jobs, depending on the 

degree of efficiency improvement achieved.

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b. Recommendations

• DOE should lead collaborative efforts with FERC and industry to assess the impacts of the 

2014 polar vortex experience on power prices, availability and reliability.

• DOE should ensure that basic federal energy policy assessments, such as the Quadrennial 

Energy Review56 and the President’s Advanced Manufacturing Initiatives57 consider the 

impact of lower priced electricity facilitated by coal-fired power plants, and include an 

assessment of the value of diversity of generation sources and how pending coal plant 

retirements are likely to impact power prices, availability and reliability.

• DOE should lead collaborative efforts with industry to evaluate the implications of 

generation diversity on the President’s advanced manufacturing initiatives and efforts to 

enhance the global competitiveness of U.S. manufacturers.

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C. Changes that Could Impact Future Benefits from the Existing Coal 

Fleet

1. Reduced Rate of Demand for Electricity

Growth in electricity demand reflects to some degree growth in the U.S. economy. Figure C.1 

shows U.S. GDP in the post-World War II period.58 Economic growth in the 1950s and 1960s 

averaged 4.3%/year, whereas it averaged 2.6%/year over the past 20 years and 1.2% over the 

past 5 years. Figure C.2 shows annual electricity generation since 1950, and the growth rate of 

generation (in a 5-year moving average).59 

Electricity demand grew at 6-11%/year during the 1950s and 1960s, at 2.5% or less since 1995, 

and was actually negative in 2009, 2011 and 2012. In addition to the overall lower growth rate of 

the economy, recent demand for electricity has also been affected by demand-side energy 

efficiency measures, a continuing shift from manufacturing to services and, within the 

manufacturing sector, to less energy intensive manufacturing. Looking to the future, EIA’s most 

recent projections assume GDP growth of 2.4%/year for 2012-2040, and Electric Power Sector 

generation growth of 0.8%/year.

60 This relatively low rate of growth in electric power demand 

emphasizes the importance of providing policies and technologies that preserve the existing 

fleet’s benefits and portfolio value.

Many analysts agree that to solve its current economic and financial problems, the U.S. will have 

to start producing more and exporting more and will have to reverse the decades-long atrophy of 

its manufacturing sector.61 The U.S. will no longer be able to shift its energy-intensive production 

activities abroad and will thus require significantly more reliable, reasonably priced electricity in 

the coming years – electricity that is not subject to cut-offs and wild price spikes. Much of this 

low cost reliable electricity will have to be provided by coal.

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Figure C.1. U.S. GDP: 1947-2013.

Figure C.2. Annual U.S. Electricity Generation.

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2. More Advantageous Natural Gas Prices

Recent use of the existing coal fleet has been influenced by a dramatic decrease in the price of 

natural gas, and a resulting decrease in the cost of electricity from NGCC generation. Figure C.3 

shows EIA data for power generation from coal and gas between July 2011 and July 2013.62 Note 

that during 2012, coal-fired generation dropped sharply from coal’s rolling 4 year average, while 

the opposite occurred for natural gas generation. Coal’s share of generation recovered

somewhat in 2013. Figure C.4 shows the corresponding spot prices for natural gas during these 

periods: lower in 2012, and higher in 2013.63 

Future natural gas prices are uncertain. They could be influenced by environmental regulations 

on gas production and its use in power plants, by larger exports of liquified natural gas (LNG) and

by the need for expanded pipeline and gas storage infrastructure. Additionally, much of the 

existing natural gas infrastructure is aging and in need of maintenance. Over half the nation’s 

pipelines are over 50 years old; the leak rate in gas mains is one every 8 miles per year, and one 

leak every 2 miles for services lines.64 EIA’s most recent projections for the price of delivered 

gas to electric utilities indicate an expected real (constant dollar) increase of 3.1%/year, for 

2012-2040, versus 1.0%/year for coal. It should be noted that past natural gas price projections 

have been inaccurate. Figure C.5 shows a retrospective accounting of past EIA projections versus 

the actual price of natural gas (the heavy black line in Figure C.5).65 An ability to make accurate 

projections of future natural gas prices is relevant to the existing coal fleet, because retirement 

decisions for existing coal capacity will rely in part on projected costs for coal and natural gas.

Figure C.3. Monthly Generation from Natural Gas and Coal.

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Figure C.4. Henry Hub Spot Prices.

Figure C.5. Natural Gas Price Predictions Versus Actual Price.

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3. Environmental Regulation 

A number of new and emerging environmental 

regulations for the existing coal fleet will reduce 

operating flexibility and will require the implementation 

of very expensive compliance strategies. Taken together, 

these regulations are a major driver of decisions to retire 

approximately 20% of the existing coal fleet by 2020.66 

Future behavior is speculative; but since only a portion of 

the expected regulations have been promulgated, it is 

reasonable to conclude that the amount of retiring 

capacity will increase, absent the development of much 

more cost-effective compliance technologies.

a. Non-CO2 Regulations

Since 2011, EPA has promulgated a series of new 

regulations impacting the electric power sector. Perhaps 

most significant are the Cross State Air Pollution Rule 

(CSAPR) and MATS. Additionally, states have 

implemented new limitations based on improving 

visibility in Class I areas (National Parks, Wilderness 

Areas). Rules also have been proposed, but have not yet 

been promulgated, to revise effluent guidelines for 

certain wastewater streams from power plants, to revise 

regulations for cooling water intake structures (pursuant 

to Section 316(b) of the Clean Water Act) and to revise 

coal combustion residuals (CCR) regulation under the 

Resource Conservation and Recovery Act (RCRA). EPA is 

also developing new rules, including a new ozone 

transport rule, and revisions to National Ambient Air 

Quality Standards (NAAQS) that could ultimately require revisions to State Implementation Plans 

to reduce emissions of SO2 and NOx from power plants. Strategies to comply with these new 

requirements will be expensive and will increase the operating costs and potentially impact the 

performance of the existing coal generation fleet.

b. CO2 Limitations

In January 2014, EPA proposed NSPS for CO2 emissions from new fossil fuel-based power plants. 

The limitation that would apply to coal-fueled power plants was 1,100 lb-CO2/MWh (gross), a rate 

that would effectively require use of “partial” CCS. EPA has committed to proposing guidelines 

under the authority of Clean Air Act Section 111(d) for state regulation of CO2 emissions from 

existing coal-fueled power plants. This regulatory package was sent to the Office of Management 

and Budget (OMB) for the pre-proposal interagency review on March 31, 2014.

67 These 

regulatory guidelines are scheduled to be proposed in June 2014 and promulgated in June 

2015.68

“The electric industry is becoming more 

complex due to political and societal 

drivers propelling new policies, such as a 

carbon-reduced resource portfolio.”

“The uncertainty increases with the 

potential for carbon emission 

limitations.... It is evident that continued 

policies aimed at limiting carbon 

emissions will impact the coal generation 

fleet in MISO, increasing the potential for 

resource deficiencies and corresponding 

reliability impacts.”

“Reliability factors other than capacity 

and energy requirements can be more 

difficult to address; for example, the 

ability of the bulk power system to 

withstand disturbances and remain in 

compliance with NERC Reliability 

Standards. These and other less obvious 

reliability concerns are further 

exacerbated by the continued retirement 

of steam-driven generators.”

“Early retirement of multiple units in the 

short run can stress the bulk power 

system....”

2013 Long-Term Reliability Assessment, 

NERC, Dec 2013

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In addition to federal regulations, some states have regulatory programs that require reductions 

in CO2 emissions from power plants. California has adopted a “Cap and Trade” system that 

includes power plants, as well as other source categories. Nine northeastern states have a 

collaborative program that applies only to power plants (the Regional Greenhouse Gas Initiative, 

or RGGI). 

Separate from the near-term NSPS goals, the Administration has stated a long-term goal of 

reducing U.S. GHG emissions by 83% below 2005 emission rates by 2050.69 Meeting such a goal 

will be difficult in the absence of CCS technology. The Intergovernmental Panel on Climate 

Change (IPCC) recently issued its Fifth Assessment Report, comprised of a series of working group 

reports addressing knowledge related to climate change. Contributors to the report modeled 

mitigation efforts necessary to meet various atmospheric CO2 concentration targets, using a 

range of models. They found that, “many models cannot reach 450 ppm CO2eq concentration by 

2100 in the absence of CCS.” For those models that could reach the mitigation goal without the 

availability of CCS technology, the cost of doing so was 138% greater (more than double) without 

CCS technology than with CCS technology.70

c. Other Related Regulations

The District of Columbia and 29 states have adopted Renewable Portfolio Standards (RPS), rules 

that require a certain percentage of a state’s power generation to derive from renewable energy 

(wind, solar, biomass, etc.). An additional eight states have set renewable portfolio goals, rather 

than enforceable standards.71 Similarly, 20 states have adopted Energy Efficiency Resource 

Standards (EERS) that take different forms, but generally require electric utilities to encourage 

end use efficiency systems (more efficient appliances and electrical devices, building insulation, 

etc.). These regulations introduce additional pressures to operate the existing coal generating 

fleet less or in a less efficient manner (due to cycling, minimum load, etc.).

d. Cumulative Impacts

All of the regulations now under consideration by EPA have not yet been promulgated, so their 

cumulative impact is unknown at this time. The EIA reports that 10 GW of coal capacity retired in 

2012, and projects another 50 GW to retire by 2020, based on a combination of market forces 

and regulations which have been adopted through 2013.72 The potential significance of future 

CO2 regulations on the existing fleet can be gleaned from the EIA’s assessment of GHG scenarios 

in the Annual Energy Outlook 2013 (AEO2013). For carbon fees (or taxes) ranging from $10 per 

tonne CO2 to $25 per tonne CO2 in 2014 (increasing at 5% per year above inflation), U.S. coalfueled power generation would decrease between 35% and 98% in 2040, compared to 

generation in 2010.73

4. New Source Review – Major Modifications

Under EPA’s NSR program, major new sources, and major modifications of existing sources, must 

obtain preconstruction permits that contain a requirement to apply state-of-the-art air pollution 

control technology (among other requirements). As observed by the National Research Council in 

a report prepared for EPA, “NSR’s treatment of modifications has been particularly 

controversial.”74 In general a physical change (that is not considered to be “routine maintenance, 

repair or replacement” under the Agency’s rules), or a change in the method of operation, at a 

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major source that causes a significant net increase in emissions will trigger NSR. Much of the 

controversy regarding NSR lies in determining whether the change is non-routine maintenance, 

repair and replacement (or subject to certain other exclusions), and whether the change causes 

an increase in emissions. EPA has promulgated rules and definitions75 that guide the source 

owner and the permitting authority in making determinations regarding major modifications. 

Unfortunately, these rules have been so controversial, at least since the late 1990s, that the very 

uncertainty created by them works as a powerful disincentive for utilities to undertake projects 

that might trigger NSR, or to conduct the research necessary to develop additional efficiency 

innovations. Moreover, the requirement for a modified facility to obtain a permit before any 

construction activity may commence and to apply the “best available control technology” (BACT),

among other requirements, serve as a strong economic disincentive to making such changes at an 

existing power plant. 

Beginning in 1999, EPA launched a major enforcement initiative against electric utilities for 

projects at existing coal-fired power plants, which EPA believed to have violated the Agency’s NSR 

regulations. EPA estimated that by 2005, as a result of the ensuing litigation, the utility industry 

had committed to spend over $5 billion on capital equipment to reduce emissions.76 That 

enforcement initiative continues to the present.

The intricacies of NSR regulation are beyond the scope of this report, but the larger concepts are 

important to understand because they impact the development and potential use of some of the 

technologies being considered in this report. Specifically, under NSR as interpreted by EPA’s 

enforcement arm since the start of the enforcement initiative in the late 1990s, many of the 

technologies considered in this report would not be considered routine maintenance, repair, and 

replacement. 

Intuitively, one might think that projects that improve efficiency, such as those considered in this 

report, would never trigger NSR even if they are considered “physical changes,” because they 

decrease emissions per unit of power produced. Unfortunately, that is not necessarily the case 

under NSR, because of the way the NSR rules define “emissions increase.” 

As the rules currently stand and are enforced by EPA, such projects would trigger NSR if they 

result in an increase in emissions of any NSR-regulated pollutant (which includes “conventional” 

pollutants, such as SO2, NOx and particulate matter (PM), as well as greenhouse gases) on an 

annual basis. Thus, if the unit at issue is utilized more after the project than before (and that 

increased utilization is caused by the project, for example because the increased efficiency is so 

substantial that it makes the unit more attractive to run), the project could be said to result in an 

NSR emissions increase. The delay and cost associated with obtaining an NSR permit before the 

project may commence and with installing “BACT” would eliminate the project from 

consideration in the vast majority of cases.

EPA has confirmed the problem described above. The Agency has stated, for example, that “As 

applied to existing power plants and refineries, EPA concludes that the NSR program has impeded 

or resulted in the cancellation of projects which would maintain and improve reliability, efficiency 

and safety of existing energy capacity. Such discouragement results in lost capacity, as well as 

lost opportunities to improve energy efficiency and reduce air pollution.”77 EPA explained that a 

major reason for these impacts was that “energy efficiency improvements are often associated 

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with increases in utilization, because the more efficient generating units are dispatched more 

often. Efficiency improvements can also result in an increase in capacity or availability. In such 

cases, there can be local emissions increases that trigger NSR if the projects are not routine 

maintenance.”78 

Assuming that overall electricity demand is unchanged, increased use of an efficient unit will lead 

to less use of another less efficient unit. In general, it is likely that the displaced generation will 

be from a less efficient coal unit so regional emissions could decline in the exchange. Hence, 

current rules could result in higher national emissions and continued degradation of efficiency 

within the existing fleet. Of course, a power plant owner could accept the additional 

requirements that come with NSR and make the efficiency improvement, but as stated by EPA: 

“the costs associated with NSR, particularly the costs to retrofit pollution controls, can render 

these projects uneconomical. Thus, the EPA finds that NSR discourages some types of energy 

efficiency improvements when the benefit to the company of performing such improvements is 

outweighed by the costs to retrofit pollution controls or to take measures necessary to avoid a 

significant net emissions increase.”79

This is not a theoretical problem. At the start of the NSR enforcement initiative, EPA considered a 

“dense pack” project (a turbine upgrade technology marketed by GE) at Detroit Edison’s Monroe 

Plant.80 In that case, Detroit Edison argued that the efficiency improvement was not substantial 

enough to change the unit’s loading order and thus potentially result in increased utilization of 

the unit. In particular, Detroit Edison noted that the units at issue were “already at the top of the 

loading order and had a capacity factor of approximately 85% for 1998.”81 Thus, the company 

concluded, any “increase in use would be the result of demand and unforeseen outages, which 

could and would have occurred regardless of whether or not Detroit Edison proceeds with the 

Dense Pack project.”82 

While it did not reject Detroit Edison’s claim outright (stating instead that the initial 

determination on the issue is the State agency’s), EPA indicated that it “disagree[d] that the 

dispatch position of the Monroe plant necessarily means that the Dense Pack project would not 

result in increased use, and hence, increased emissions.”83 

Given the information provided by the company showing that there is some 

fluctuation in annual use and that Units 1 and 4 are not operated at their 

maximum physical capacity, the fact that Monroe is at the top of the 

loading order is insufficient to demonstrate that the significant increase in 

efficiency associated with the Dense Pack project, and the corresponding 

decrease in the cost of producing electricity, would not result in increased 

use and emissions.

84

During the enforcement initiative that ensued in the following 13 years, EPA and environmental 

groups have sued several companies for efficiency improvement projects similar to Detroit 

Edison’s, as well as for less extensive turbine repair or replacement projects—e.g., turbine 

overhauls. A list of these cases and the specific claims at issue are included in Appendix A. This 

list is limited to turbine upgrades or replacements – the list would be much longer if improved 

materials of construction and improved designs of heat transfer surfaces were included.

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In short, the fundamental barriers to improving power plant efficiency and reliability cited by EPA 

in its 2002 report remain in today’s NSR rules. The uncertainties created by the NSR rules, their 

enforcement by EPA and certain environmental groups against some of the very types of 

efficiency improvement projects considered in this report, and the very substantial—even 

prohibitive—cost of NSR create strong disincentives to the widespread deployment of such 

measures. 

5. Aging of Fleet

Figure C.6 shows the rapid growth of coal-fired power generation in the U.S. between 1950 and 

1980, and the limited additional growth thereafter. Although there is no fixed general endpoint 

for the useful life of a coal-fired power plant, as a unit ages, large capital investments tend to 

become less attractive due to the unit’s remaining life. For investments with relatively rapid 

payback, typical of some efficiency and flexibility improvements, age is not a major issue. But for 

CCS retrofits and other large capital investments that do little to improve or prolong the existing 

power block, the remaining useful life of a unit can be an important factor influencing utilities’ 

decisions, and in regulated markets, utility commission approvals.x

 Figure C.7 maps current coalfired capacity by state, and Figure C.8 shows the capacity of units that will be less than 40 years 

old in 2025.85 The earliest date by which 2nd Generation CCS technologies are projected to be 

available and economically competitive under the current RD&D schedule, is 2030.

Figure C.6. U.S. Coal-fueled Generating Capacity Additions.

x

An examination of the expected technological and economic life of generating units in the existing coal fleet and the influence of 

those factors on decisions regarding capital investments in an existing generating unit would be a useful subject for future analysis.

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Figure C.7. Coal Generating Capacity, by State (based on EIA-Fm860 data).

 

Figure C.8. Projected Coal Capacity in 2025 (based on EIA-Fm860 data).

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6. Reduced Funds for R&D (Industry & Government) 

The technology scope of DOE’s coal RD&D program has remained relatively constant since 2004, 

focusing primarily on advanced, more efficient, power systems and CCS. Funding has varied from 

year to year, with external R&Dxi ranging from about $300 million to $400 million per year for 

2004-2014. Federal funds for cost-shared commercial-scale demonstration projects ranged from 

$50 million to $290 million per year for 2004-2009, and an additional $3.4 billion was provided for 

demonstration projects under the American Recovery and Reinvestment Act (ARRA) of 2009. No 

additional demonstration project funding has been appropriated since 2009. It should be noted 

that $370 million of these appropriated funds were lost through budget rescissions, and $145 

million of ARRA funding was returned to the Treasury Department because of cancellation of a 

demonstration project. Figure C.9 shows the combination of R&D, demonstration, and fund 

rescission, by year, for FY04-FY14, and the Administration’s budget request for FY15. If all of 

these sources and losses are combined, including the ARRA funds, the average federal 

appropriation for coal RD&D for 2004-2014 was $675 million per year.

In contrast, the Administration’s coal RD&D budget request for FY 2015 is $277 million, of which 

$243 million is for external (cost shared) RD&D (the remainder is for National Energy Technology 

Laboratory (NETL) salaries and other aspects of NETL in-house R&D). This represents a decrease 

of approximately 64% compared to the average appropriations for the previous 11 years. $243 

million represents 0.9% of the Administration’s total budget request for DOE in FY2015.

Figure C.9. DOE RD&D Budget for Coal Use Technologies.

xi External R&D is defined as cost-shared collaborative activities with industry, and is in contrast to in-house R&D funding for 

research performed at NETL, typically about $35 million per year. The distinction is made because DOE’s accounting protocol for 

these funds changed in FY2009.

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Overall, the Administration’s FY2015 budget request for discretionary activities by DOE increased 

by 2.7% above FY2014 appropriations, to $27.9 billion. The request for Energy Efficiency and 

Renewable Energy (EERE) increased by 22% to $2.3 billion.86 In 2013, coal generated 1,586 

million MWH of electricity; non-hydro renewable energy generated 253 million MWH of 

electricity.87

7. Findings and Recommendations 

a. Findings 

• While U.S. demand for electric power will continue to grow in the long term, the nearterm more modest projected rates of growth reinforce the importance of advancing 

policies and technologies that preserve existing coal fleet investments.

• Natural gas prices continue to be volatile, reinforcing an historical trend. Increased 

reliance on natural gas for power generation will impact resource supply and price 

stability.

• Increasingly stringent environmental regulations will reduce operating flexibility, increase 

capital investment expenses and potentially impact plant performance for U.S. power 

generators.

• New Source Review regulations impact generators’ decisions and ability to enhance plant 

efficiency, reduce emissions and improve overall operations/capacity. The delay and cost 

associated with obtaining an NSR permit tend to eliminate efficiency enhancement 

projects as viable options. 

• Many of the challenges facing the existing coal fleet are technology based, and would 

benefit from DOE-led collaborative RD&D with industry. Funding requirements, 

particularly for demonstration projects are significant.

• The IPCC concluded that reaching climate change goals without CCS will more than double 

the cost of mitigation.

b. Recommendations

• DOE should work with the EPA to eliminate New Source Review-related barriers that 

disincentivize generators to pursue efficiency improvements that would otherwise reduce 

emissions, increase capacity and enhance plant operations.

• DOE should seek input from industry research associations, such as the Electric Power 

Research Institute and the Coal Utilization Research Council regarding priority research 

needs and the appropriate balance between research, development and demonstration 

of technologies relevant to the existing coal fleet. 

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D. Technology Responses to Maximize Future Benefits to Society 

1. General Introduction

Changing circumstances are challenging the ability of the existing coal fleet to provide benefits to 

society. In the past, similar challenges have been met with improved technologies. Past 

challenges to coal generation, such as the need to reduce emissions of sulfur dioxide, nitrogen 

oxides, and mercury, were met through collaborative efforts between the public sector and the 

private sector to develop new technologies. 

The terms “Flue Gas Desulfurization”, “Selective Catalytic Reduction”, and “Activated Carbon 

Injection” were not part of the nation’s lexicon in 1970. Today, these systems, developed 

through industry/government collaboration, are standard equipment on new coal-fired power 

plants and have been widely deployed on existing units as well. Additionally, for every dollar of 

federal funds invested in coal RD&D, thirteen dollars of benefits accrued to the nation.88 

Moreover, RD&D in advanced coal technologies can produce products for sale abroad, enhancing 

U.S. manufacturing and improving the nation’s balance of trade. 

Three families of technologies will be discussed in the remainder of this section:

• Measures to improve the flexibility and reliability of the existing coal fleet, particularly 

with respect to operating in non-base load modes.

• Measures to improve the efficiency of existing coal-fired power plants.

• Emission reduction technologies, both for traditional pollutants and CCS technologies for 

reducing CO2 emissions from existing coal-fired power plants.

2. The Path to Improving the Flexibility & Maintaining the Reliability of the Existing Fleet 

a. Background and Introduction

Most of the larger generating units in the existing coal-fired power plant fleet were designed to 

run as base load units. However, as these units continue to age, as relatively low-priced NGCC 

power enters the network and as renewable portfolio standards and renewable energy 

certificates lead to greater market penetration of renewable energy-based generation, these coal 

units are likely to be increasingly dispatched in a cycling mode, and incur more frequent startups 

and shutdowns. Even more efficient units such as supercritical units which were designed and 

operated historically as base load are now experiencing varying load and even reserve shutdown 

due to economic dispatch. Some of these very large units (up to 1300 megawatt equivalent 

(MWe) single units) had not experienced such dispatch changes until the past few years. As 

discussed below, this need for more flexible operation will require a range of actions by the 

power sector if these units are to continue to function with the reliability required by a modern 

electricity network. 

In addition to the changing duty cycles, the fleet will need to adjust to comply with new 

environmental regulations. Moreover, for those units already configured with a full complement 

of environmental controls, changes may be necessary to maintain or enhance their level of 

performance in the non-steady state conditions associated with partial load operation. 

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b. Analysis and Discussion

Characteristics of the new mission for the existing coal units89 include:

• Increased load-following operation

• Greater unit turndown during low demand

• Frequent unit starts (hot, warm and cold)

• Increased load and thermal ramp rates

• Frequent reserve shutdown 

• Meeting more stringent emissions requirements 

All of the above changes in duty cycle tend to reduce efficiency.

Regionally, many units vary from base load at some times of the year to intermittent or rapidly 

changing load patterns. Intermittent generation requirements on the system can contribute to 

the changing role of coal. Seasonal variation in wind and solar production can lead to higher 

turndown and/or reserve shutdown of balancing assets, including coal.90 Variations in the output 

of these intermittent sources within a typical day can be rapid, and lead to load-following of coal 

units, frequent unit starts and, most importantly, increased frequency and rates of load ramping. 

The tendency for peak hourly wind generation to be out of phase with hourly trends in demand 

forces more coal units to run at minimum loads or shut down during the night, and ramp up and 

down to balance load.91 

In addition to the inverse correlation between wind output and system demand often seen on an 

hourly basis for each day, there is a similar trend observed on a monthly basis throughout a 

typical year. These two factors can combine to result in a wide range of coal balancing load 

required between the extremes of renewable generation levels. 

Analysis of NERC Generating Availability Data System (NERC-GADS) data reported by coal units in 

the 2005-2009 timeframe indicates an increase in reserve shutdown hoursxii in 2009. This is 

observed across a range of unit sizes, in both supercritical and subcritical designs. This had 

produced a reduction in reported net capacity factor, particularly for older subcritical units which 

are experiencing increased turn-down, low load operation. These impacts may be primarily 

driven by an overall demand reduction (4% from 2008 to 2009 according to EIA) and a shift in 

dispatch to gas-fired assets (gas-fired combined-cycle production net capacity factor increased by 

5% from 2008 to 2009). However, displacement of coal by intermittent generation is already a 

factor in certain regions, with a growth in overall renewable generation of 18% from 2005 to 2009 

reported by EIA. 

A study conducted by the National Renewable Energy Laboratory (NREL) on wind and solar 

integration in the western states predicted a wide range in the level of coal-fired balancing load 

required during the time period of 2017 assuming a 35% renewable asset portfolio.

92 These 

xii Reserve shutdown hours are the total number of hours a unit was available for service but not electrically connected to the 

transmission system for economic reasons.

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balancing units would experience frequent starts, high turndown, ramping and reserve shutdown 

hours. 

Exacerbating the challenge of increased need for flexibly operating coal units over time is the fact 

that many of the more flexible existing coal units will be retired or reduce their level of output. 

For example, a number of smaller units (often < 300 MWe) with higher design margins allowing 

flexibility are being retired. These units often have fewer existing emission controls, less 

sophisticated instruments and controls (I&C) and, in the past, have often dispatched in load 

balancing mode. These are often older, less efficient units, and are not cost-effective to upgrade 

to meet current emission standards. Approximately 40GW of the 60GW of coal units that have 

announced their retirement, or are considered probable retirements, are less than 300 MWe 

capacity.93 

Increased cyclical and low-load activity also will impact the operation of air emissions control 

systems (e. g., SCR, FGD and mercury controls), as well as wastewater treatments. The clearest 

example of a constraint on unit flexibility may be the addition of SCRs. These systems are 

analogous to the catalytic converter used on an automobile. The catalyst typically requires a 

minimum temperature for proper operation. When the grid requirements or dispatch require 

only minimum load, that level of operation may be restricted by the SCR. Effective minimum load 

to ensure a temperature adequate to maintain SCR performance may be higher than the load at 

which the plant would otherwise be able to operate safely and sustainably without the SCR. 

Industry and suppliers are dealing with some of these issues, with catalyst formulation and best 

methods of operation, but additional public/private sector collaboration to address this challenge 

would be useful, and DOE has an excellent track record for collaborative RD&D to develop 

emission control technology. 

Additionally, the performance of FGDs added for SO2 control, and potentially for oxidized 

mercury capture, may have been designed and tested at full load, but not optimized for transient 

(cycling) operation. Even if the FGD can meet emission requirements during these transients it 

may do so with higher parasitic power loads (e.g., pumping, pressure drop). In addition the 

quality and character of wastewater and solid byproduct streams from FGD such as gypsum may 

change during flexible operation. The solids and ions captured change depending on the specific 

process configurations and additives such as bromine used for mercury capture as well as coal 

constituents such as chlorine, boron, thallium, etc., which must be treated in the wastewater 

treatment process or managed in solid coal combustion products. 

In addition to air pollution control requirements, water use also varies and plant water 

management may be disrupted by cycling operation. For example, a wet flue gas desulfurization -

wastewater treatment (WFGD-WWT) system has a large volume of water/slurry stored within it. 

With any change in load, the water/slurry requirements change. Thus when a unit load is 

dropped there is less demand for water and the system has too much. The system operation 

adjusts to this but then the load demand is increased and now the system is short of water. 

These swings in water demand result in operational and process upsets that the WFGD-WWT 

systems were not designed to handle. An industry-funded Water Research Center is being used 

to test novel technologies that assure compliance with regulations, promote efficiency and assure 

reliability under variable duty cycles.

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Finally, generating units that are turned down (operated at reduced power output) below their 

original design basis may also see a reduction of mass transfer across the absorber, resulting in 

high emission levels. Cycles of concentration in the wastewater may be disrupted. This requires 

understanding of water balances in a variety of combinations of different coal types, plant 

designs, plant operating modes and control equipment configurations. DOE process modeling 

and simulation as well as industry R&D in this area in the past has been helpful. 

In order to manage emissions controls, new operating practices need to be monitored, and 

instruments and controls must be matched to the variable load conditions during startup, 

shutdown and transient operation. Very low quantities of some trace elements are present in 

flue gases and waste waters. Yet to manage these they must be monitored, often in large 

streams, with corrosive constituents or erosive particles making proper monitors and instruments 

critical to operation. Crosscutting efforts on monitoring of these constituents help not only 

existing coal units but new fossil and biomass units as well.

Economic operation of existing coal units experiencing increased cycling in the future may require 

adjustments to traditional asset management approaches. The proper planning for use of system 

assets (asset management) is not simple and simple cost models do not always factor in issues 

like damage mechanisms from the difference between a hot unit restart and a warm or cold 

restart. Thermal and mechanical stresses on materials are not well known for operating 

conditions that have not been previously experienced. These stresses can lead to lower reliability 

and higher costs. For example, a series of fast startups from cold start conditions can cause 

header cracking, and very fast ramp can cause short term overheating and burst boiler tubes. 

These conditions could result in a lengthy outage and lost generation, yet the cost of this cycling 

impact may not be fully factored into dispatch cost algorithms.

On a system-wide basis the most flexible assets have an advantage in load balancing and 

providing system resiliency. New equipment changes, modifications, retirements and load 

requirements may make older operational correlations inaccurate and result in not 

understanding the longer term impacts of flexible operation. Gaining this information from case 

studies and unit analysis from a variety of coal and unit types can help the generating units and 

grid operate reliably, keep customer costs low and lead to efficient asset management and lower 

emissions. Revised operational insights and best practice analysis will help the existing plants 

manage operations to meet grid support demands.

It is well recognized that coal quality and character can impact reliability, emissions and 

efficiency, and aid in assuring flexibility. New concepts supported by DOE RD&D, such as coal 

drying, have already been adopted in limited commercial applications, but have potential for 

expanded use for efficiency gains, emission reduction and improved cold weather operability 

(e.g., frozen coal/coal feed management). Other processes for coal cleaning, trace element 

removal, etc., can be useful in combination with different emission controls to provide efficient 

operation and better control of emissions with flexible operation.

All of the above measures address issues relevant to a generating unit when it is operating. There 

are also issues that relate to units which are not operating. When a unit is brought down in load 

and then taken off line it is not always clear if that shutdown will be brief or extended. The 

management of gas and liquid side environments to prevent damage changes if an outage is 

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short or longer term, and gaining insights into best practices here will help the reliability of the 

fleet. With more units coming off line seasonally for extended layup it is now more common to 

consider measures to prevent materials degradation. A simple example is the addition of filming 

amines on the steam side in short term layup (e.g., over a weekend); yet if the layup is for a 

month the amines would be ineffective and more elaborate shutdown, inert blanketing and 

storage may be required. Additional measures may also be needed for worker safety, for purge 

and startup and it may be appropriate to modify system controls, logic and hardware to allow 

automated and routine longer term layup if this type of operation is anticipated in the future. 

The methods and costs of various layup options is another area of active R&D by industry and an 

ongoing need.

However, improved or upgraded instrumentation, sensors and software are ineffective if plant 

operators and maintenance staff do not understand their use. Ideas to improve flexibility and 

reduce impacts on the plant can be relatively simple, including things like control system 

modifications as new equipment is added or operation is adjusted. Training for these changing 

operating conditions is needed and resources to do training at multiple plant sites are not always 

available. Advanced simulation, remote O&M fleet wide monitoring and case study illustrations 

can be useful in training operating staff. Maintenance and repair training in proper welding 

techniques for aged or novel materials compared to original specification needs to be available. 

Training and operational aids are a research need.

Benefits from enabling existing coal-fired power plants to function reliably in the emerging 

marketplace should provide significant benefits to society. Coal units provide increased reliability 

and system resiliency during peak load periods as illustrated in the winters of 2012-13 and 

2013-14. Regional constraints on natural gas transmission, coupled with high demand for heating 

and bottlenecks on gas supply particularly in the Northeastern U.S., have limited existing natural 

gas generation and caused short term price volatility and strained power generation capacity. 

Some reported short term prices were well over $100/MMBtu for regional natural gas supply.94 

Coal has the unique advantage among central generation sources of an on-site coal pile 

providing weeks or even months of fuel supply at the point of generation, contributing to grid 

support reliability, resiliency and reduced regional fuel supply issues.

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c. Findings

Load following and cycling of existing coal units is required now and will be required more and 

more in the future to provide resiliency for the grid. Increased unit cycling, with more frequent 

startups and shutdowns, and more operation at partial load present a number of challenges to 

the reliability, efficiency, environmental emissions and economical operation of the existing coal 

fleet. 

• Fundamental understanding of advanced alloys, systems of materials and repairs can 

improve the reliability and resiliency of the fleet. More advanced and adaptable materials

and improved welding, joining and repair methods (for thinner, stronger, more corrosion 

resistant, more flexible alloys and composites) can be used both for repair and for 

upgrades to existing plant. This can provide improved flexibility, reliability and more 

efficient operation.

• Improved instrumentation and control allows more flexibility, especially of recently

installed more complex pollution control systems that have had unexpected operational 

issues (e.g., limits on operation, cross-pollutant impacts).

• Nondestructive evaluation methods and computational capabilities are inadequate for the 

more complex conditions and additional equipment found in today’s operating plants.

Improvements can help predict and help prevent failures and help operate and maintain 

equipment and retain flexibility.

• DOE has ongoing work on process control for next generation plants including first 

principles dynamic modeling, system and plant level simulation, algorithm development 

for sensor placement and addressing the complexity of advanced systems. This work 

could well be adapted to the more complex control requirements and new equipment 

needs from cycling and transient operation for the existing fleet.

• Better understanding of pollution control systems operating under cycling conditions is 

needed. During low load and at minimum load several systems can experience air, liquid 

and solid impacts such as the following: SCR can have issues with minimum load 

operation due to low temperatures making catalyst less effective for NOx reduction; FGD 

systems can have oxidation issues due to high excess oxygen in the flue gas that impact 

the form of captured selenium which makes water treatment for selenium difficult; and 

particulate emissions during startup and stabilization can change resistivity and chemical 

character of the particulate making particulate control difficult. The impact of newer 

additives used to enhance environmental systems, such as bromine added for mercury 

oxidation, can exacerbate corrosion issues and introduce new contaminants to 

wastewater streams. Additional research is also needed regarding cooling water 

consumption, and treatment of cooling water blowdown. The full extent of emission 

control needs is unknown because several significant regulations are still pending or in 

litigation. 

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d. Recommendations

• DOE should lead a collaborative effort with industry to develop improved assessment 

tools in several areas, including: damage mechanisms, costs and reliability changes 

associated with cycling and fuel changes; remaining life assessment for cycled units; and 

asset management tools. 

• DOE should lead collaborative efforts in the areas of materials development (higher 

strength alloys allowing thinner components), fabrication (powdered metallurgy), welding 

techniques and evaluation of remaining life. 

• DOE should lead collaborative efforts to develop improved sensors and control systems to 

automate flexible operation, detect maintenance issues associated with flexible 

operation, evaluate extreme environments and measure trace concentrations of toxic 

pollutants. Improved non-destructive evaluation techniques to test components should 

also be developed. 

• DOE should lead collaborative efforts to develop improved “best practices” approaches to 

operating coal-fired power plants under cycling conditions and ramping conditions, 

including steam pressure management and maintaining proper water chemistry. 

Workforce training is needed in these new techniques. 

• DOE should lead collaborative R&D regarding the impact of cycling and use of offspecification coals on environmental control systems, including cooling systems, SCRs 

operating at low load (improved catalysts), treatment of FGD effluent, wastewater 

treatment, landfill operation and leachate collection/treatment and HAPs controls. 

• DOE should lead a collaborative effort with industry to investigate the potential for coal 

pre-treatment to improve operating flexibility and efficiency, as well as to reduce

emissions. 

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3. Improving the Efficiency of Power Generation From the Existing Coal Fleet 

a. Background and Introduction

Improving the efficiency of existing power plants is critical to maintaining the value of the existing 

coal fleet.

The operating paradigm of coal-fired plants has changed in the last few decades. Units designed 

for base load operation now routinely “cycle” between very low and high load. Boiler and 

environmental control system design was likely optimized for fuel properties that are constant 

but now are highly variable. Finally, the past practice of removing units from service for 

maintenance at 1-2 year intervals has been extended to 3 year or longer periods for many 

generating units. Each of these trends compromises plant generating efficiency. 

Improving thermal efficiency can provide two important benefits: the reduction of fuel 

consumption, which lowers operating costs; and the reduction of emissions, including CO2

emissions.xiii Thermal efficiency improvements generally require an investment in process 

equipment, or in operation and maintenance (O&M), or more likely both. The economic incentive 

to improve efficiency at a power plant thus has practical limits. Most notably, the efficacy and 

payoff of any given efficiency improving measure at a power plant is site-specific. The 

improvements and payback described in this section are exemplary only, are not additive and 

depend on many factors. The initial design and condition of a plant, age, coal rank, 

environmental requirements and maintenance practices determine the payoff that can be 

derived. Benefits may be temporary as equipment wear asserts its toll. 

Potential efficiency improvements at existing coal-fired power plants should be considered in the 

context of other future adjustments at these units. For example, operating at lower load will 

usually result in a higher heat rate, and lower load operation tends to occur with older units and 

units in systems heavily populated with intermittent renewable energy power plants. 

Finally, regulatory considerations can complicate decisions to pursue energy efficiency projects. 

As discussed in Section C, efficiency improvements that reduce the variable cost of electricity 

generation can lead to increased use of a unit, and under certain conditions result in the changes 

being deemed a “major modification” for purposes of applying NSR regulations. In general, such 

a designation would entail significant new emission reduction requirements that would not only 

be costly, but that could offset and in some cases completely negate efficiency gains by increasing 

parasitic power demand to operate air pollution control equipment. For these reasons, such 

efficiency improving projects historically have not been implemented.

Appreciating efficiency improving opportunities addressed in different reports requires an 

understanding of terminology and conventions, including the following:

xiii For a given unit and fuel, CO2 emissions are directly proportional to heat rate, with a small adjustment for CO2 release from 

systems using limestone FGD.

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• Efficiency is the ratio of useful output energy divided by input energy. Efficiency is usually 

stated in terms of a percentage. The average efficiency of the U.S. coal fleet in 2012 was 

33%.

• Heat Rate is the inverse of efficiency, i.e., input energy divided by useful output energy. In 

the U.S., heat rate is usually stated in British thermal units of input energy divided by 

kilowatt-hours of output energy (Btu/kWh). The average heat rate of the U.S. coal fleet in 

2012 was 10,300 Btu/kWh (net). An increase in plant efficiency of one percentage point –

from 33% to 34% – will reduce plant heat rate by approximately 300 Btu/kWh.

• Conventions Vary. The metrics by which both efficiency and heat rate are determined 

vary both between and within North America, Europe and China and Pacific Rim 

countries. Consistency and accuracy are critical. For example, heat rate can be stated in 

terms of “gross” power output (including the electricity consumed within the power plant 

for motors driving pumps, fans, pulverizers, etc.), or in terms of “net” power output (the 

electricity supplied to the grid). A pulverized coal power plant may consume 8% of its 

generation on-site, so a unit with a net heat rate of 10,300 Btu/kWh would operate at a 

gross heat rate of 9540 Btu/kWh (assuming 8% internal power consumption). 

Measurement conventions for input energy also vary. In North America, energy input is 

usually expressed based on a fuel’s higher heating value (HHV), which ignores certain 

energy losses associated with water in the products of combustion. In contrast, Europe 

uses the fuel’s lower heating value (LHV), which accounts for this unrecovered energy. 

The impact of this difference in conventions varies with the moisture content of the fuel. 

For a typical bituminous coal, the difference in reported efficiency is about 2% (i.e., 33% 

efficiency in the U.S. is equivalent to 35% in the U.K.). For higher moisture coals 

(subbituminous, lignite) the difference can be 3-5%.95

The use of different efficiency metrics can be confusing. Some reports cite an efficiency 

improvement in terms of a specific component (e.g., 3% improvement in steam turbine 

efficiency) whereas others relate to the entire power plant (e.g., a 3% improvement in plant 

efficiency). It is critical – for DOE, the utility industry and EPA – to use the same basis for any 

comparisons. This report generally expresses performance improvements both in terms of a %-

efficiency value and a heat rate value.

The remainder of Section D.3 describes potential efficiency improvements relevant to the existing 

coal fleet, summarizes key findings and recommends future actions by industry and the DOE to 

improve the efficiency of the existing coal fleet.

b. Analysis and Discussion

It is convenient to organize the discussion of efficiency improving opportunities around 

functionally similar categories within the power plant. Figure D.3.1 graphically depicts the major 

subsystems in a coal-fired power plant. Seven categories of plant activities or operational 

attributes are used in this report: (a) fuel type and fuel processing, (b) boiler and steam 

conditions, (c) steam path for energy extraction (e.g., steam turbine and ancillary components), 

(d) process controls, (e) options for low temperature heat recovery, (f) auxiliary power 

consumption and thermal losses, and (g) the cooling system. Each of these categories of design 

or operation will be examined as a means to improve thermal efficiency of generation. In 

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addition to this traditional view of efficiency improving options, this section will close with a brief 

discussion of possible approaches to changing the fundamental thermodynamics of an existing 

power plant via addition of “topping” or “bottoming” cycles.

Figure D.3.1. Power Plant Efficiency.

i. Fuel Type and Fuel Processing

Altering the source of coal or fuel mix can improve thermal efficiency. Fuels with lower moisture 

content have lower latent heat losses. Additionally, lower coal sulfur content reduces sulfur 

trioxide (SO3) in flue gases. Flue gases must be maintained above the condensation temperature 

of SO3 to avoid corrosion and plugging problems. Hence, lower sulfur coal may enable improved 

recovery of low quality heat. 

There are three basic alternatives to changing coal characteristics: switch coals, dry the coal or 

process the coal. 

Coal Switching. Coal properties determine both gross and net efficiency due to impacts on boiler 

performance and compatibility with environmental systems. Most coal switching in the last 

decade has substituted subbituminous for bituminous coal, seeking least cost SO2 and NOx 

compliance. Reversing these changes – if enabled by environmental control system design –

could elevate efficiency due to the lower moisture content of higher rank coal. For example, a 

large (500 MW) generating unit that fires a bituminous coal, such as North Appalachian, and 

switched to Powder River Basin (PRB) subbituminous coal would incur a boiler thermal efficiency 

penalty of 4.2 percentage points (e.g., a boiler thermal efficiency of 89.2% would decrease to 

85.0%, due to higher fuel moisture content). The auxiliary power consumption of pulverizers, gas 

fans and sootblowers could increase, in this example case, by 5.9%. As a result of the decrease in 

boiler efficiency and the increase in auxiliary power requirement, the net plant heat rate would 

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decrease by 5%, or about 500 Btu/kWh.

96 The thermal efficiency of generation would increase by 

about 1.6%. It is important to emphasize fuel choice is dictated by numerous variables (e.g.,

price, availability, boiler design and environmental controls) so changing coal rank may not be

practical at many units.

Coal Drying. Lowering moisture from coal increases boiler thermal efficiency and thus plant 

generating thermal efficiency, if the moisture can be reduced using waste heat. Figure D.3.2 

depicts the role of fuel moisture on total plant generating thermal efficiency, the latter calculated 

on both a HHV and LHV basis. Coal drying with waste heat is a commercially available option, but 

one that not every plant can effectively deploy. Drying coal with waste heat has been 

commercially deployed on North Dakota lignite to increase boiler thermal efficiency. Great River 

Energy utilized coal drying to reduce the moisture content of North Dakota lignite from 39% to 

29%, increasing plant net generating thermal efficiency by 4% (lowering heat rate by about 1,200 

Btu/kWh).

97 Less improvement would be expected for drying higher coal ranks (bituminous and 

subbituminous coals) because they tend to be much lower in moisture content than lignite.

Coal Processing. Altering the composition of coal – going beyond removing moisture – is defined 

as fuel processing or beneficiation. Payoff can be significant. Whereas conventional (physical) 

coal cleaning uses density as a basis for removing inorganic material, coal processing or 

beneficiation uses chemical treatment to reduce inorganic content. These processes focus on 

trace elements that can compromise material longevity and contribute to controlling regulated 

hazardous pollutants. For example, work conducted in the 1990s used binary and ternary 

supercritical fluids, and compounds such as perchloroethylene to remove sulfur and inorganic 

materials but was abandoned as flue gas desulfurization technology evolved.98 Revisiting 

chemical coal treatment may provide significant payoff in improved efficiency, generation 

reliability and multi-pollutant control. 

Additionally, coal beneficiation – adding compounds to coal during coal processing – shows 

promise. For example, PSEG is experimenting with an ammonium hydroxide-based beneficiation 

process that displaces both water and inorganic material. In a pilot test processing a “batch” of 

coal samples, coal moisture decreased from almost 31% to less than 7%. As a consequence, 

heating value increased from 7,859 Btu/lb to 11,363 Btu/lb.99 

Benefits of physically cleaned coal extend beyond efficiency improvement due to reduced 

moisture content. For example, removing inorganic material can reduce boiler slagging and 

fouling, improving heat transfer in the boiler and elevating efficiency. Lower sulfur fuel can 

reduce the auxiliary power demand for conventional FGD, increasing net unit power output. 

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Figure D.3.2. Coal Moisture Impact on Efficiency.

Figure courtesy of E.ON.

ii. Boiler and Steam Conditions

Several means are available to either restore boiler performance to original design levels, or 

improve on the original design based on unit-specific experience and improved materials. 

Maximize Utilization of Existing Surface, or Add Surface. The utilization of existing boiler heat 

transfer surface area can sometimes be improved, depending on the existing state. Repairing or 

replacing failed or excessively fouled surfaces may improve boiler thermal efficiency and plant 

generating efficiency – although in many cases such improvements simply restore efficiency to 

original design values. Improving or restoring unit generating efficiency by up to 0.16-0.33 

percentage points (lowering unit heat rate by up to about 50-100 Btu/kWh) is possible in 

exchange for capital costs of $4-5M for a 500 MW plant.100 For some units, heat transfer surface 

- such as the economizer section - can be increased, capturing more heat to preheat boiler 

feedwater. Some of these changes could enable greater flexibility in low load operation, such as 

extending the low load range for a unit’s selective catalytic reduction system. For example, 

upgraded economizers could reduce gas exit temperature by up to 20-400 F, increasing boiler

thermal efficiency sufficiently to lower plant heat rate by up to 0.5-1% (i.e., increase generating 

efficiency by up to 0.16-0.33 percentage points).

101

Advances in materials-of-construction – based on metallurgy and coating presently experimental 

and not yet commercially proven – could increase payoff. New materials can improve heat 

transfer, reduce accumulation of inorganic material and fouling, and lower pressure drop. One 

topic of interest is an evolving class of material coatings referred to as “nano-coatings” that 

minimize accumulation of deposits and thus resistance to heat removal from the tubes. In 

concept, the entire steam raising sections of a boiler can be replaced with advanced materials 

improving boiler efficiency and thus the thermal efficiency of generation.

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Intelligent Sootblowing. Maintaining clean gas-side tube surfaces maximizes heat transfer for an 

operating cost mostly comprised of steam power to drive sootblowers. Activating sootblowers 

only when needed based on monitoring boiler performance is designated “intelligent” 

sootblowing and maintains clean tube surfaces with minimal power. On older boilers, gross heat 

rate reductions of up to 30-90 Btu/kWh (improvements in thermal efficiency of up to 0.1-0.3

percentage points) have been observed; improvements in thermal efficiency of up to 0.5 

percentage points (heat rate reduction of up to 150 Btu/kWh) have been recorded for units firing 

PRB and lignite where slagging and fouling had reduced thermal efficiency. Typical efficiency 

improvements of up to 0.2 percentage points (heat rate reduction of up to 60 Btu/kWh) are 

anticipated. The capital cost for intelligent sootblowing is typically $0.5M for a 500 MW plant.102 

For example, the 780 MW Jeffrey Energy Center, firing subbituminous coal, installed intelligent 

sootblowing in conjunction with monitoring key areas of the furnace, such as measuring the 

accumulation of ash with strain gauges, and the thermal effectiveness of each heat exchanger in 

the boiler. Gross heat rate was lowered by about 90 Btu/kWh, increasing the thermal efficiency 

of generation by 0.3 percentage points.

103

In summary, extracting more heat from combustion gases could elevate by 0.5% the boiler 

efficiency (e.g., 88.0 to 88.5%) for each 100 F reduction in gas temperature. Increasing boiler 

temperature by this magnitude, where practical, will lower heat rate by 50 Btu/kWh, increasing 

thermal efficiency of generation by 0.17 percentage points. Almost all impacts on downstream 

equipment are beneficial, except for SCR NOx control operation and increased potential for SO3-

derived deposits. 

iii. Steam Turbine and Condenser

Changes to the steam turbine offer potential for significant improvement in power plant 

efficiency. These changes, which have been already implemented on many units, can include a 

complete replacement of rotors and inner casings, or upgrade of high-payoff components. For 

example, selected elements of the high- , intermediate- and low-pressure stages of a steam 

turbine can be replaced or refitted. Table D.3.1 summarizes the range in cost incurred and payoff 

derived for a menu of improvement options that are commercially available. As reported in Table 

D.3.1, for some units steam turbine efficiency gains can be achieved by installing improved or 

new control valves or seals, and the use of innovations such as partial arc admission for steam 

control valves, the latter enabling unit turndown with reduced loss of efficiency.

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Table D.3.1. Summary of Cost, Heat Rate Payoff, and Capacity Payoff for Steam Turbine 

Improvement Options – For Circumstances Where a Technology is Practical.

Action

Capital 

Cost ($M)

Heat Rate Payoff 

(Btu/kWh)

Capacity 

Payoff (%)

Steam Turbine General

H2 Purity 0.25 10 0.10

Partial Arc Admission 1 50 0

Control Valves 4

High Pressure Turbine

Steam Seal Upgrade 1 50 0.75

Steam Path Upgrade 6 95-135 1.5

Intermediate Pressure Turbine

Steam Seal Upgrade 1 20 0.20

Steam Path Upgrade 5 50-100 0.70

Low Pressure Turbine

LP Steam Seal Upgrade 0.75 120 0.30

LP Steam Path Upgrade 5 65-225 0.65

Table D.3.1 shows replacing any of the high-, intermediate- or low-pressure components of the 

steam turbine will require a capital cost from $1M for seals, $5-6M for steam path changes, and 

from $5 to $8.5M for a rotor replacement. Gains in gross unit heat rate, for situations where 

these measures are practical, range from 30-40 Btu/kWh to several hundred Btu/kWh –

representing an increase in generating efficiency of up to 0.10-0.67 percentage points. The large 

gains are possible only for units that are severely degraded. Retaining the turbine components 

but replacing ancillary components such as the steam valves, seals, and deploying partial arc 

admission provides a 5-50 Btu/kWh heat rate decrease – representing an increase in generating 

efficiency of up to 0.17 percentage points - for typically about $1M capital cost. 

The benefits listed in Table D.3.1 are believed typical, but the magnitude of any improvement and 

the cost to deploy vary significantly between different units. The specific payoff and cost vary 

from site to site. Advanced modeling with computational fluid dynamics (CFD) techniques is 

anticipated to identify improved designs and will increase these benefits.

The steam turbine condenser – cooled by either “once-through” means, or mechanical or natural 

draft towers – can be viewed as a complement to the steam turbine. (The specific role of cooling 

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towers is addressed in a subsequent section.) The condenser when properly cooled creates a 

partial vacuum that presents a “negative backpressure” to enhance turbine output. Hence, 

reduced condenser performance due to corroded surfaces or leakage reduces the condenser 

vacuum and turbine output (and plant efficiency). For example, allowing back pressure to 

increase from 40 to 60 mbar can increases the required heat consumption to provide the same 

power output by about 2.5%.104 

Figure D.3.3 depicts the role of condenser fouling on relative heat rate: poor cleaning of surfaces, 

resulting in a cleanliness factor of 75%, increases gross unit heat rate by 0.6 percentage points, or 

about 60 Btu/kWh, equivalent to a decrease in generating efficiency of 0.20 percentage points. 

Improved condenser maintenance can increase O&M costs by $30-70K annually for a 500 MW 

unit, but elevate thermal efficiency by up to 0.10-0.25 percentage points, thus lowering gross unit 

heat rate by up to 30-70 Btu/kWh.

105 

Figure D.3.3. Condenser Fouling and Turbine Heat Rate.

Source: © Australian Government Department of the Environment, reprinted with 

permission under a Creative Commons Attribution 3.0 Australia license 

(http://creativecommons.org/licenses/by/3.0/au/deed.en)

Periodically, condensers are “retubed” as tubes that are badly corroded and beyond repair are 

replaced with new material. This action is economic only for units high in capacity factor and with 

significant remaining lifetime, enabling recovery of investment.

Similar to the case with boiler heat exchangers, presently experimental advanced metallurgy and 

coatings could, with successful R&D, lead to improved condenser performance. These nextgeneration condensers could reduce corrosion and fouling, and enable expeditious and effective 

cleaning, thereby improving plant efficiency. 

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iv. Process Instrumentation and Controls

Both enhanced monitoring of plant condition – using advanced sensors and instrumentation as 

well as diagnostic software – offers significant payoff in plant efficiency. 

The list of components and processes that can be monitored by advanced sensors and software is 

wide-ranging, and cuts across many aspects of plant operation. For example, the operation of 

fans, pulverizers, boiler feed pumps, steam turbine components, and the condition of the steam 

path, gas flow in ductwork and gas composition provide data that can be processed in real-time. 

Deploying neural network and other intelligent software to diagnose and control operation of 

these components – activating changes at the best time with respect to fuel utilization, boiler 

excess air and auxiliary power demand – favorably affects boiler thermal efficiency and plant 

auxiliary power consumption. Software products of this type are commercially available, but 

additional refinements could elevate benefits and payback. 

The benefits vary widely, depending on the state of existing equipment, most importantly the 

digital signal processing capabilities. Heat rate improvements up to 150 Btu/kWh are possible.106 

The existing control system must be equipped with digital capabilities to maximize results, and in 

some cases the legacy control system must be upgraded. The capital charge for advanced 

process instrumentation and control systems – presuming an upgrade to digital controls is not 

required – typically ranges from $0.50M to $0.75M for a wide range of generating unit sizes. 

Next-generation instrumentation and controls are being developed to both improve monitoring 

capability and address diagnostics. Specifically, developing Advanced Pattern Recognition 

software employs statistical methods to assist in the early identification and assessment of 

performance shortfalls. An array of sensors located throughout all major components of the 

power station – fuel preparation, the boiler, environmental controls, heat rejection equipment 

and the steam turbine – will report the status of key components in real time. Using this data and 

pattern recognition ability will further elevate insight to achieve high thermal efficiency. 

The benefits of improved instrumentation and controls can be significant, with estimates showing 

a 5-to-1 payback in development costs in specific cases.

107

v. Low Temperature Heat Recovery

Several means to capture low quality heat can be explored to exploit further benefits, including: 

Air Heater Performance. Air heaters are typically designed to lower average gas exit 

temperatures to within 5-10 °F of the SO3 acid dewpoint. For most coals this temperature is 

between 280-320 °F. In practice a higher margin between the gas discharge temperature and the 

SO3 dewpoint is typically observed to prevent localized corrosive damage to metal surfaces such 

as ductwork. In recent years, alkali-based sorbents have been used to remove SO3, reducing acid 

gas emissions while minimizing the damaging role of SO3. Injection of these alkaline compounds 

is not without risk; in some cases the solid sulfates produced will accumulate in the air heater, 

plugging gas passages (which harms efficiency). In some air heaters, it may be possible to 

increase heat exchanger surface area, assuming that there is sufficient fan power to overcome 

the additional pressure drop across the heat exchanger, and that SO3 condensation is not a 

problem. Correction of leakage at air heater seals presents an additional opportunity to reduce 

heat losses.

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Providing additional heat input to the boiler may introduce safety issues by creating an unstable 

condition in the pulverizers, perhaps resulting in spontaneous combustion of some low rank 

coals, but this issue is believed to be manageable. 

Feedwater Preheating. Boiler feedwater is typically preheated with partially expanded steam 

from the steam turbine. Increasing the number of feedwater heating steps – typically 5-7 for 

state-of-art units – is feasible and uses readily available components and technology. The 

barriers to widespread implementation are cost for additional heat exchangers and increasing the 

capability of boiler feedwater pumps to overcome the additional resistance to flow. The 

effectiveness of feedwater heaters is impacted by both internal and external (water side and 

steam side) corrosion and deposits, and internal passages can become plugged and nonoperative. Another means to increase feedwater heating is expanding the economizer section 

(which also preheats feedwater), as described in the previous section.

Supplemental Low Temperature Gas-Side Heat Recovery. Gas exiting the particulate collector 

prior to the FGD process contains low quality heat that with the right materials can be recovered. 

Heat exchanger design must account for corrosion and fouling. Near-term options are limited by 

heat exchanger cost and materials of construction. The history with low temperature heat 

recovery in the late 1970s and 1980s is not encouraging – gas/gas heat exchangers were 

deployed on units equipped with flue gas desulfurization to eliminate the heat rate penalty for 

flue gas reheat. These so-called gas reheaters were plagued with corrosion and high gas pressure 

drop. Most were removed in the mid-1990s as wet stacks were designed and installed to manage 

plume dispersion of wet flue gas. However if these problems could be overcome, the use of low 

temperature heat recovery for boiler feedwater preheat could increase plant generating thermal 

efficiency by up to 1%, thus lowering gross unit heat rate by up to about 300 Btu/kWh.

108

Technologies that cool flue gas and facilitate SO3 condensation on fly ash, rather than on tube 

surfaces, can enable recovery of waste heat before the particulate control device.

109 These 

systems have been demonstrated in Japan with success over the last ten years. Some are 

constructed of simple carbon steel and could be retrofitted in an existing unit, particularly if a unit 

is undergoing a hot to cold side particulate control device conversion. 

vi. Auxiliary Power Consumption

The net plant thermal efficiency is directly affected by the consumption of auxiliary power for 

ancillary components. Several means are available by which to minimize auxiliary power loses. 

Variable speed drives (VSD) can minimize power consumption at lower load, and can be applied 

to large power consuming motors for inducted draft and forced draft gas fans, circulating water 

pumps, coal pulverizers, flue gas desulfurization alkali slurry pumps, cooling tower fans and other 

major power consuming motors. These motors and drives can consume almost all of the typically 

8% of gross plant load devoted to auxiliary power.110 

Variable frequency drives are commercially available. For existing units that are shifted from base 

load to cycling duty these systems may have increased value in reducing the associated heat rate 

degradation. The capital cost for such equipment is $9-11M for a 500 MW plant, with the range 

of net thermal efficiency increasing by up to 0.05-0.50 percentage points (e.g., lowering heat rate 

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as much as 15-150 Btu/kWh). The wide range in improvement is due to the variable baseline, 

defined by the drive motors the plant was equipped with.111 

Other methods can reduce auxiliary power losses but the applicability can be limited and payoff 

uncertain. Specifically, advanced CFD techniques can be applied to streamline the entire 

combustion air and combustion product gas flow path, reducing power consumption by fans by

as much as 15% - 25% (depending on the unit).

112 Reducing air infiltration into the boiler 

ductwork where applicable can increase gas temperature aiding heat recovery and improve boiler 

efficiency by up to 0.15 percentage points (lowering gross plant heat rate by as much as 15

Btu/kWh), and reduce fan power consumption. These measures to reduce auxiliary power are 

commercial but the modest payoff – typically increasing the thermal generation efficiency by no 

more than 0.05 percentage points – has limited application.

vii. Cooling System

Recirculating cooling systems (cooling towers) are most efficient when there is optimal 

distribution of cooling water flow across the tower “pack” – the sections that promote 

evaporative cooling. Improving the distribution of water improves performance. Replacing or 

augmenting the “pack” with improved materials to promote evaporative cooling increases 

cooling tower performance, increasing thermal efficiency of generation by up to 0.26 percentage 

points (reduction in gross heat rate of up to 70 Btu/kWh). These benefits are mostly applicable in 

summer months. The cost can range from $1.5 to 5 M for a 500 MW plant. In theory, 

augmenting cooling with a supplementary ”helper” tower can also improve performance, if space 

on-site is available. 

The potential increase in thermal efficiency from a “helper” tower is site-specific and requires a 

detailed site study. The other approach to heat rejection at a power plant is “once-through” 

cooling, which withdraws water from a water body, uses it for cooling in the condenser and 

returns it to the water body at an elevated temperature. Actions to increase heat transfer by 

maintaining clean condenser surfaces are of greatest interest for this type of cooling system. 

Options to improve cooling are uncertain due to pending regulations impacting once-through 

cooling at existing power plants (i.e., Clean Water Act section 316(b) rules). In most cases, the 

use of once-through cooling removes more heat from the condenser compared to cooling towers, 

particularly if a relatively low temperature source of cooling water is obtained, such as from a 

large river or lake. If Section 316(b) rules prohibit using once-through cooling and require 

converting to cooling towers, the reduced condenser heat removal will lower generating 

efficiency. 

viii. Changing Plant Thermodynamics

The efficiency-increasing measures addressed in this report so far target conventional plant 

design - the industry “workhorse” deployed to date. These concepts have been applied at one or 

more plants, with variable payoff. These measures serve to refine and optimize plant operation, 

but the performance does not significantly change because the thermodynamics of plant design 

remain essentially the same. 

More radical steps can be explored to extend the thermodynamic limits to gain efficiency. These 

actions enable the single Rankine cycle that typifies a conventional plant to either exploit higher 

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temperature heat addition, or to reject heat at lower temperatures. To accomplish this the 

thermodynamic cycle would be changed by adding a separate “topping” step or a “bottoming” 

step to the conventional Rankine cycle.

Other more radical changes to the thermodynamic cycle have been used in the past. Specifically, 

an existing Rankine cycle can be coupled with a “bottoming” step using the Brayton cycle. This 

well-known “combined cycle” approach is broadly deployed for natural gas-firing and is a stateof-art concept for advanced coal-based generation. However, retrofitting such a combined cycle 

to an existing unit can be of limited value. The retrofit of combined cycle has been successfully 

implemented on a generating unit at the Wabash River station, but provided limited payback. 

Consequently, this discussion focuses on elevating the temperature of Rankine cycle heat 

addition and improving heat rejection. 

It should be noted that retrofit constraints could prohibit changes to the thermodynamic cycle. 

These constraints include limited space for the additional heat exchangers, modifications to the 

gas and steam path, and the need for refined process instrumentation and controls. It is likely 

that retrofitting high temperature heat exchangers on an existing boiler will require “dissimilar” 

metal junctions. Technical challenges related to dissimilar metal welds and other factors must be 

addressed.

Topping Cycle Addition. A topping cycle can be added, either increasing the temperature of heat 

added to the Rankine cycle, or alternatively as a separate closed loop Brayton cycle. Exploiting 

the Rankine cycle is likely the closer to near-term availability of the two options.

A Rankine topping cycle would first provide a means to capture high temperature boiler heat, and 

then extract useful work with a second, separate steam turbine. (See Figure D.3.4.) This action –

effectively empowering a subcritical steam boiler to provide supercritical or ultra-supercritical 

steam conditions – elevate the generation efficiency by up to 2-4 percentage points, thereby 

lowering gross heat rate by as much as 600-1,200 Btu/kWh.

113 The hardware to deploy such a 

system using steam as the working media could be developed within 10 years. Other working 

media with potentially more favorable thermodynamic properties, such as ammonia or 

supercritical CO2, could be applied to further improve efficiency, but this effort would likely 

require more than 10 years of development, to assure material and media compatibility. 

Figure D.3.4 depicts one means to deploy a Rankine-based topping cycle. In the conventional 

layout, the boiler generates steam for expansion in the high pressure (H-P) turbine, which 

exhausts the expanded steam to the boiler for reheat, that is in turn expanded in the 

intermediate pressure (I-P) turbine. The expanded steam from the intermediate-stage turbine 

enters the low pressure (L-P) turbine which operates in the conventional manner. A topping cycle 

would entail retrofitting heat exchangers constructed of material that can deliver supercritical or 

ultra-supercritical steam pressure and temperature, to be expanded in a supercritical (SC) steam 

turbine designed for these conditions. 

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Figure D.3.4. Schematic of Topping Cycle for Conventional Rankine Power Station.

A Rankine topping cycle that could employ advanced ultra-supercritical (AUSC) steam conditions 

– up to 1,1200 F steam temperature – could be developed in a ten-year effort. A longer term 

pathway – perhaps 15 years – could deliver steam temperatures up to 14000 F, further increasing 

efficiency. 

A second topping cycle option is the closed Brayton cycle using CO2 as a working fluid. The closed 

Brayton cycle – used in nuclear power generation – will require a longer development period 

compared to a Rankine topping cycle. This topping cycle theoretically could be retrofit into a 

conventional plant in a manner similar to the topping Rankine cycle in Figure D.3.4, except that a 

second cooling system would be required. Similar to the topping Rankine cycle, an additional 

heat exchanger is retrofit into the boiler to generate a high pressure and temperature working 

media – perhaps supercritical CO2 (due to attractive thermodynamic properties). The high 

pressure, high temperature CO2 expands in a closed cycle turbine, enabled by cooling from a 

second cooling system (wet or dry tower or heat exchanger). Depending on the working media 

and the details of the cycle, the increase in efficiency could exceed that of a Rankine–based 

topping cycle. This option is believed to be competitive with elevating the Rankine cycle 

temperature addition in cost and performance. The benefits could be significant and as such this 

options merits development. 

As noted in the beginning of this section, retrofit barriers to extension of the thermodynamic 

cycle could be significant. These barriers would have to be explored in design studies to identify 

solutions. 

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Bottoming Cycles. Rankine bottoming cycles can improve heat rejection and thus increase 

thermal efficiency. The concept of using a bottoming cycle is not new, and has been successfully 

applied in small industrial processes as a means to utilize waste heat.114 A Rankine bottoming 

cycle would replace the conventional steam condenser with an alternative heat exchanger that 

operated in a closed cycle cooling system. An alternative working media such as an organic fluid, 

ammonia (NH3), or CO2 could be used that can be more effective than steam. A bottoming cycle 

option that would employ an organic solvent is possible in the longer term, and could improve 

thermal efficiency by 1 percentage point or less, lowering gross plant heat rate by as much as 300 

Btu/kWh, but perhaps more importantly eliminate the use of water for cooling. 

ix. Cumulative Benefits of Multiple Actions

Many of the preceding actions can be applied contemporaneously to derive multiple benefits, 

assuming that the conditions at the target unit are favorable to the changes. In some cases the 

benefits are cumulative – such as those derived from minimizing auxiliary power, fuel drying, and 

improving heat rejection. Other actions that increase heat removal from the boiler – economizer 

modifications, improved air heater performance and low temperature heat recovery – do not 

provide cumulative benefits. All efficiency improving measures are unit and site-specific and will 

not always be technically and/or economically feasible.

Regardless, near-term efficiency gains can accrue from several actions at a unit. As an example, 

consider a nominal 500 MW unit that is fully equipped with state-of-art environmental controls, 

and located in a Midwestern state where the penetration of wind power is significant, thus 

forcing the unit to lower capacity factors and “deeper” levels of cycling. As a result, the operating 

time spent at low load where economizer temperatures are below the minimum required for 

effective SCR operation is significant, leading to higher NOx emissions.

Several near-term actions could improve low load performance and increase heat recovery at this 

hypothetical unit. First, a split economizer could be deployed, capturing additional heat following 

the SCR process. This additional heat is used for boiler feedwater preheat. Next, a revised air 

heater is utilized enabling extremely low air heater temperatures – to perhaps 2400 F. Key to 

achieving this level of heat recovery is the near elimination of SO3 by alkali injection, and 

designing heat absorbing materials to avoid accumulating deposits. It should be noted that it has 

not yet been demonstrated that an air heater exit gas temperature as low as 2400 F can be 

practically achieved, but future efforts may show this outcome is feasible. An additional 

efficiency-improving step in this example is deploying fuel drying to lower moisture from coal – in 

this case a low sulfur eastern fuel – to further increase boiler efficiency. Finally, installing a new 

condenser constructed from state-of-art materials that resist fouling will improve heat rejection 

and efficiency.

A detailed analysis would be required to assess the benefits of this set of measures, as well as its 

compatibility with new source review regulations. It is possible that a thermal efficiency 

improvement of up to 3-4 percentage points could be derived, if these actions can be proven to 

work together and do not compromise plant reliability.

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x. Important Caveats

Projects to improve the efficiency of existing coal-fired power plants are considered in the 

context of site-specific technical and economic considerations. Although the individual 

technologies can be described in general terms, their likely degree of deployment in the coal fleet

cannot be. Conditions excluding a potentially applicable technology might include:

• The hardware present at a unit. For example, an option designed for a Ljungstrom air 

preheater may not apply to a unit using a tubular air preheater.

• The measure may have already been employed.

• The measure may present operational or reliability issues that outweigh its value in 

efficiency gains.

• The cost of the change may exceed its value in efficiency improvement.

• The change may raise NSR “major modification” issues.

• Efficiency improvements from some types of measures will degrade over time.

There are also factors at play which could lead to decreased efficiency at existing coal-fired power 

plants. These include:

• Operation at reduced load, which generally increases a unit’s heat rate. Reduced load 

might result from expanded renewable energy or natural gas-based generation, or higher 

variable costs at an aging unit. For example, changing a subcritical unit from full load to 

50% load can increase heat rate by 900 Btu/kWh, imposing a penalty in thermal 

generation efficiency of 3% for the period of operation at 50% load.

115

• Variable load operation. Startups and periods of transitional operation increase heat rate, 

so more variable unit operation tends to lead to higher overall heat rate. 

• Adding environmental controls. Parasitic power requirements for a wet scrubber can 

reduce net output and increase net heat rate by 2-3%, lowering net thermal efficiency of 

generation by 0.65-1.0 percentage point. Converting the cooling system from oncethrough to recirculating cooling (cooling towers) can reduce thermal efficiency of 

generation by 0.5 percentage points (increase heat rates by 1.5%).

116

• Switching from bituminous coal to a high moisture subbituminous coal could increase 

heat rates significantly, both due to the moisture and due to higher power requirements 

for pulverizers.

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c. Findings

• A number of efficiency improving measures are commercially available for use with the 

existing fleet. The benefits and cost are highly variable and depend on the specifics of any 

one site. Many of these measures have been already applied on units in the existing 

inventory. Additional work is necessary to determine how to increase the penetration of 

these measures across the generating fleet, and the magnitude of the benefits. 

• Of the options commercially available, two significant opportunities to increase efficiency 

include steam turbine upgrades (such as rotor replacements), and measures to reduce the 

moisture of lower rank coals using waste heat, although, again, it must be emphasized 

that the magnitude and availability of these opportunities are highly site-specific. 

Continued work to refine turbine blade design, and the use of advanced materials could 

lead to further opportunities. Additional benefits, as yet unquantified, are believed to be 

achievable in the next ten years.

• Significant opportunities to increase efficiency are also available by improving heat 

rejection through the condenser, as aided by design changes to cooling towers and oncethough cooling systems. Improved materials may reduce fouling of condenser surfaces 

and improve performance, while improved cooling tower designs and materials may 

increase heat rejection. 

• There are areas where additional incremental RD&D is appropriate, such as revisiting the 

benefits of chemical coal cleaning, developing improved materials, coatings for boiler 

tubes and next-generation sensors and controls that incorporate diagnostic capabilities. 

Better monitoring and control can potentially benefit both part load and full load heat 

rates. 

• Low temperature heat recovery shows promise, but needs work. Corrosion issues in 

concept can be reduced by alkali injection, but heat exchangers that resist 

corrosion/fouling and present low gas pressure drop must be developed. Such heat 

exchangers may be enabled by new coatings (nano-coatings; super hydrophobic coatings) 

to improve heat transfer properties. Alternatively, it may be possible to utilize simple 

carbon steel in heat exchangers that resist corrosion through the interaction of ash and 

SO3. These low temperature heat recovery concepts provide an added benefit of reducing 

trace metals and SO3 in air emissions by improving the performance of particulate 

controls via lower flue gas temperatures.

• Enhancing the conventional Rankine Thermodynamic cycle by adding topping or 

bottoming cycles, or using different working fluids than water, show promise for 

significant efficiency improvements. These options require significant cost and major 

changes to the generating unit and control systems. Rankine bottoming cycles using 

organic fluids have been deployed with success on small industrial processes as a means 

to utilize waste heat. The retrofitting of bottoming or topping cycles (with one exception)

has not been deployed to date, and would require RD&D to become commercially viable. 

• Achieving the most significant improvements in efficiency may be deterred by concern

that the required equipment modifications and improvements will be characterized a 

“major modification” under New Source Review regulations, and result in additional 

environmental requirements that would be costly and reduce the efficiency gains.

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d. Recommendations

• The private sector should work to develop improved fuel drying heat exchangers for use 

with high moisture fuels, such as PRB subbituminous coal and lignite.

• The private sector should continue work to develop tube coatings to enhance heat 

transfer, use alkali injection to reduce SO3 in flue gas and enable greater heat recovery 

from air heaters, develop non-metallic heat exchangers for recovering low temperature 

heat, and extend neural network technologies into next-generation sensors and software. 

An R&D campaign needs to be undertaken to demonstrate the effectiveness and 

reliability of deploying these actions into commercial plants.

• DOE should lead a collaborative effort with industry to design next-generation steam 

condensers, using state-of-art materials that resist fouling and corrosion; develop 

advanced, enhanced heat transfer materials and material coatings; develop improved 

cooling tower pack materials; and revisit chemical coal cleaning processes developed in 

the 1980s (in light of multiple benefits to efficiency, reliability, and emission control).

• DOE should lead a long-term (10 year) collaborative effort with industry to integrate 

topping and bottoming cycles with existing power plant designs in order to substantially 

increase the efficiency of existing power plants.

• DOE should work with EPA to find a way to deploy changes at existing coal-fired power 

plants that would result in higher fleet efficiency, including adding heat exchanger surface 

in the boiler, improving steam paths, providing better heat rejection, and in the long-term 

the use of topping and bottoming cycles, without imposing new emission reduction 

requirements due to the change.

4. Emission Reductions from the Existing Fleet

a. Addressing Conventional Pollutants

i. Background and Introduction

For purposes of this report, the term “Conventional Pollutants” refers to all regulated air, water 

and solid waste products from an existing coal-fueled power plant, other than CO2. 

With respect to conventional pollutants, this report will focus on the impact of recent regulations, 

or pending regulations that require emission controls that differ from previous regulations. For 

example, new systems to mitigate mercury emissions into the atmosphere may result in trace 

materials being introduced into the flue gas of an existing coal-fueled power plant, and into other 

emission control systems, where the trace materials could become a wastewater issue. 

Some of the new regulations require compliance in a very short time frame. For example, the 

compliance deadline for MATS is generally 2016. For these rules, there is insufficient time to 

launch an R&D program to address compliance issues. Other rules are still pending and may 

provide the needed time for useful RD&D. In short, the following discussion is not a general 

analysis of all pollution control measures applicable to the existing fleet. Rather, it focuses on 

relatively recent regulatory developments, for which RD&D may result in more effective or more 

cost-effective mitigation technologies.

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The National Carbon Capture Center

The National Carbon Capture Center (NCCC) is a key component of the DOE’s strategy in 

promoting U.S. economic, environmental 

and energy security through reliable, clean

and affordable power produced from coal. 

The NCCC is a cost-effective, flexible test 

center for evaluating the critical 

components of advanced CO2 capture and 

power generation technologies which are 

crucial for maintaining coal as a viable fuel 

source. The center was established in 

2009. Offering a world-class neutral test 

facility, providing access to real flue gas and 

syngas streams, with utilities, steam and 

instrumentation provided, and employing a 

highly specialized staff, the NCCC 

accelerates the commercialization of 

advanced technologies to enable coalbased power plants to achieve near-zero 

emissions. In undertaking its mission, the 

NCCC is involved in a range of activities to develop the most promising technologies for future 

commercial deployment, thereby maximizing the value derived from project funds. 

The existing coal fleet will require new and improved technologies to meet ever changing 

environmental requirements for non-carbon emissions. The NCCC concept – providing an 

accessible (and reusable) test bed for technologies that are ready for evaluation in a genuine 

power plant operating environment – is an excellent and cost effective approach to ensure that 

emerging technologies are evaluated, refined and commercialized as rapidly as possible. 

ii. Analysis and Discussion

Air Emissions

Many of the emission control technologies being installed today on the existing coal fleet were 

accelerated in their development process by DOE supported RD&D programs. This is certainly 

true for SOx, NOx, particulate control and more recently mercury and HAPs control. Both R&D, 

pilot plant tests and first of a kind demonstration programs were supported by DOE and enabled 

by prior clean coal programs , including the Power Plant Improvement Initiative and Clean Coal 

Power Initiative. Since the DOE Innovation for Existing Plants program concluded and work on 

mercury large scale field tests was completed, new RD&D issues have surfaced as technology is 

being applied. 

The key culprit is the continual addition of disparate emission requirements on existing plants, 

and the subsequent interactions of new emission controls. Operating problems have become

more acute – the need for flexible operation and “deep” turndown. Control technologies 

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developed some years ago have experienced unanticipated problems, such as cross media 

impacts on wastewater streams or solids. Process reactors for the selective catalytic reduction of 

NOx incur buildups of compounds like ammonium bisulfate when operated near the minimum 

operating temperature, as required for NOx control at low load. The resulting limits on operation 

were discussed earlier. Understanding the materials of construction issues is an example of new 

R&D that is a consequence of proposed emissions control additives. This requires sophisticated 

measurement, monitoring and control as well as specific water treatment and enhanced 

materials use. DOE R&D that is ongoing on materials, instrumentation and controls, and sensors 

as well as work now re-starting on water management can benefit the management of 

conventional air emissions.

Water Emissions

With new requirements for individual wastewater treatment proposed by regulators, existing 

plants may require separate water treatment of many disparate streams rather than treatment of 

single combined streams like ash pond effluent. Regulation of new constituents (e.g., wash 

waters from new environmental equipment, cooling tower blowdown experiencing higher 

concentrations from increased cycles of concentration, etc.) may require multiple wastewater 

treatment options at a single plant with different methods. DOE support, building on prior work 

in water and HAPs control, could be helpful. 

Solid Waste Emissions

Solid waste streams (also termed coal combustion products and coal combustion residuals) are 

also changing as new devices and process integration are added to meet new regulatory 

requirements. Where fly ash may have been sold for cement or concrete additive, addition of 

solids can put the ash out of specification for such use. In addition, new water balances and 

WFGD use with new air emission controls may cause new issues for products like gypsum. The 

ultimate product from a zero discharge water unit, if that is used, is a salt that requires 

management as a solid.

EPA has proposed but not yet promulgated final rules for management of coal combustion 

residuals (CCRs). One challenge facing owners of coal generating facilities is ensuring 

containment of wastes in existing impoundments. It may be useful to explore the economic 

feasibility of reevaluating the potential to extract stored ash for beneficial use and converting 

these impoundments to dry storage. 

In short, it all goes somewhere and the new integrated management aspects of air, water and 

solids all interact. Improved knowledge of these interactions is needed and would benefit from 

expanded DOE support.

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iii. Findings

• New emission streams are being generated by the systems employed to capture 

traditional hazardous air pollutants. The contaminants can present challenges both to 

emission control and corrosion control of downstream equipment. 

• Trace contaminants in solid waste streams can interfere with the ability to recycle 

collected materials for beneficial use.

• Given relatively short compliance periods, little time is available to develop new 

approaches to address these issues. 

iv. Recommendations

• DOE should reestablish a program for Innovations for Existing Plants. Identification of 

specific technologies to be developed can be established via NETL-sponsored workshops 

to take input on the most pressing technology needs. 

• DOE should consider the limited time period available before commercial systems are 

needed for compliance in determining the best funding approach for this effort.

b. Retrofitting CCS on the Existing Coal Fleet

i. Background and Introduction

On November 25, 2009, the White House announced that the President’s climate goal for 2050 

was an 83% reduction in U.S. GHG emissions, relative to 2005 levels.117 Fossil energy-based 

electricity generation contributed 31% of total U.S. GHG emissions in 2012 (23% from coal-fired 

units; 8% from natural gas-fired units).118 These numbers suggest a need for a large reduction in 

CO2 emissions from fossil energy-based power generation over the coming decades. One 

possible pathway for such a reduction is the development and deployment of CCS technologies. 

The DOE has been pursuing a program of RD&D on CCS technologies for over a decade. Congress 

has appropriated $5.7 billion for this program since FY2008.119 For comparison, consider federal 

funds directed toward other low-carbon programs. In FY2013 (only), Congress appropriated $3.9 

billion for energy efficiency and renewable energy incentive programs.120 This total excludes 

Internal Revenue Service tax credits, such as the additional $3.9 billion paid as a production tax 

credit to qualifying wind generators for 2013.121

This Section will address the status of CCS technology and identify areas where additional effort is 

needed. As the details of the CCS options have been discussed in previous NCC reports,122 that 

material will not be repeated here; highlights of key CCS options and a summary of 

demonstration projects are presented in the text. Appendix B provides additional information on 

the demonstration projects planned and in progress.

ii. Analysis and Discussion

The Scope of the Challenge

The challenge for CCS is broad. The variety of applications presented by three ranks of coal 

(bituminous, subbituminous and lignite) and four firing systems (pulverized coal, crushed coal 

with cyclones, fluid bed and integrated gasification/combined cycle) are numerous. The evolving 

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coal-firing technique of oxycombustion is also a candidate to use for retrofit or repower if plant 

owners need to apply CCS.xiv 

CO2 separation techniques can employ chemical sorbents, membranes, physical sorbents and 

other techniques. CO2 storage is envisioned in both deep saline reservoirs, as well as in oil 

bearing formations for EOR. Suitability of storage reservoirs within each of these categories can 

vary significantly in terms of location, porosity, permeability and other characteristics critical to 

the ability of the targeted storage space to permanently contain injected CO2. 

A program to commercialize CCS will not have to address every permutation of fuel, combustion 

technique, capture technique and storage approach. It is clear however that a successful CCS 

development program will require multiple commercial scale demonstrations. The requirements 

for a demonstration program to address the risks of evolving CCS are discussed below. 

Mitigating Elements of Technology Risk

The evolution of CCS – by far the most complex environmental control process conceived and 

proposed to date – will present risk to host generating units. 

Owners of evolving environmental control technology distinguish between a process being 

commercially offered as opposed to commercially proven. Typically, a technology is considered 

commercially offered if a supplier can design, construct and startup a control process. This 

product can be state-of-the-art, employ best design practices, but due to limited experience 

performance cannot be guaranteed.123 

In contrast, a control technology is considered commercially proven if a supplier has meaningful 

commercial experience, and the supplier can offer performance guarantees so that risk is 

commensurate with other aspects of power generation equipment. The evolution of a process 

from the state of commercially offered to commercially proven requires gaining meaningful 

experience at large scale, with a variety of coals, and meeting reliability targets. The evolutionary 

steps are addressed as follows:

Scale. A typical existing coal-fired power plant likely to consider retrofit of CCS will generate 400-

800 MW – requiring treatment of combustion products at large scale. Evolving technologies are 

necessarily tested at small-scale, and – if passing threshold tests – evolve to slip-stream tests, 

small commercial unit tests, and eventually 300-400 MW commercial demonstrations. A step-bystep scale-up is required so lessons learned at pilot-plant and 50-100 MW scale can be extended 

to commercially competitive units.

Coal Variety. Experience should be available with three categories (or ranks) of coal in the U.S. –

bituminous, subbituminous, and lignite – for a process to be commercially proven and suitable for 

national application. The influence of coal type ranges from the gas volume generated to the 

content of trace species. The trace species content has implications for material corrosion, 

xiv For example, FutureGen2 will repower an existing pulverized coal unit with oxycombustion and CCS.

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performance of catalysts and reagent injected for pollutant removal, and composition of liquid 

and solid byproducts. 

Reliability. The most damaging aspect of poor reliability is not failure to meet a specified 

environmental control target – but forcing the host unit to operate either at restricted load, or to 

shut down for maintenance and repairs. The cost penalty incurred is dominated by lost revenue 

from the plant, rather than labor or parts for repair or enhanced maintenance. Additionally, units 

failing to meet commitments to regional transmission organizations can face steep fines.

Meaningful Process Guarantees. The owner should be protected from most reasonable risks due 

to failure of a process to attain guaranteed environmental control targets, or compromised 

reliability. Power station owners can never be fully protected from process failure – the cost to a 

supplier to compensate an owner for lost revenue is too great to insure. However, suppliers can 

guarantee the numerous subsystems of process performance – gas pressure drop across an 

absorber, lifetime of a catalyst or the degree of utilization of reagent, and material longevity, as 

examples. Suppliers will not be able to guarantee these aspects of a process without extensive 

experience at the scale and variety of fuel types the market requires. 

Lessons from Flue Gas Desulfurization

The experience in commercializing flue gas desulfurization is instructive in the evolution of CCS. 

Technologies to remove SO2 from the flue gas of conventional pulverized coal emerged in the 

early 1970s, and required three decades of testing at scale to evolve the technology so as to offer 

meaningful process guarantees.

Present-day flue gas desulfurization processes deliver up to 98% SO2 removal, do not compromise 

plant reliability and minimally penalize plant thermal efficiency. This was not always the case. 

Early FGD equipment compromised plant reliability and frequently did not meet SO2 removal 

requirements. The problem was so acute that the EPA for many years routinely tracked the SO2

removal and reliability penalty imposed by FGD equipment.124 For example, FGD-equipped plants 

in 1978 that fired high sulfur and medium sulfur content coal averaged reliability levels of 53 and 

69%, respectively, well below acceptable levels.125

Decades of evolving processes, refining process chemistry and using experience to improve 

equipment design essentially eliminated the reliability penalty.

The Need for Process Integration

Operating CCS will be disruptive to a coal-fired power plant. The present state of CCS capture 

processes require substantial power and compromise a unit’s electrical output. The magnitude of 

power loss and heat rate compromise is demonstrated by the decision of owners of the W.A. 

Parish station, to add an 80 MW natural gas turbine to power the CO2 compressors and solvent 

generators for a CCS demonstration unit, rather than absorb the generation loss. Moreover, the 

CO2 capture and processing rate must be integrated with the pipeline delivery of CO2 to its 

storage site and the storage injection process. All of these components must work together; 

otherwise one component limits the operation and reliability of whole system. 

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Many of the components that comprise a CO2 capture process have been demonstrated in other 

duty, but to date as separate elements. As demonstrated with FGD evolution, a control 

technology can be affordable and reliable only with multiple applications that show how to 

integrate the components.126

Controls, Load Following. A large number of individual components must operate in a 

synchronous manner through load swings, and not present limits to ramp-up or ramp-down rate, 

or induce performance shortfalls for environmental controls.

Effective Use of Low Quality Heat (Thermal Efficiency). The significant heat rate penalty that 

accompanies CCS could be mitigated by integrating the use of low quality heat in the plant.

Retrofit Specific Issues

There are several aspects of retrofit CCS applications that differ substantially from greenfield 

(new facility) applications. These include: 

• The age and remaining life of the existing unit being retrofit

• Limitations on physical space at the existing facility, and the proximity of major 

components

• Limited sources of auxiliary power to operate the CCS system

• Proximity to CO2 storage sites or pipelines 

Ultimately, a decision to retrofit CCS will be complex and involve impacts on the overall 

generating system, dispatching economics, return on investment, the timing of the retrofit, future 

fuel price volatility and other factors. CCS retrofit projects that include replacing key components 

– described more broadly as repowering – could provide benefits that partially offset the cost of 

the CCS system, as currently expected for the Boundary Dam and FutureGen2 demonstration 

projects. 

Cost of CCS

The capital cost of CSS retrofits is a barrier to their deployment. First-of-a-kind (FOAK) 

demonstration projects suggest that CCS retrofits of current technology would cost several 

thousand dollars per kilowatt of capacity. CCS cost reduction is a central goal of NETL’s RD&D 

program. The goal for second generation technologies is to have a system capable of reducing 

capture costs from today’s $100-140/tonne CO2 to $40/tonne CO2 captured that is “ready for 

demonstration in the 2020-2025 timeframe (with commercial deployment beginning 2025).”

127

Demonstrations and large pilot plants are progressing in various states for each of the three 

major CCS categories. The significant demonstrations that are operating or planned, are 

discussed below, including shortcomings and additional information required for commercial 

duty. Figure D.4.1 presents a timeline of the key demonstrations and experience anticipated to 

influence the commercial feasibility of CCS in the U.S. and North America.

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Figure D.4.1. Timeline for CCS.

 

The time projected by NETL to develop affordable retrofit CCS technologies and the age of the 

existing fleet are in conflict. Assuming optimistic outcomes to RD&D, units being designed in 

2025 will not begin operation before 2030, and multiple replications of 2nd Generation technology 

may be needed before costs achieve the stated goals. As shown in Figure C.8, only 43 GW of the 

310 GW coal fleet will be less than 40 years of age in 2025. That capacity (units less than 40 years 

of age) shrinks to just 26 GW in 2030. Units repowered with CCS may have more “age tolerance” 

than simple retrofits, because in a repowering project, some of the major components at a power 

plant are replaced. Decisions on whether to retrofit capital intensive hardware, such as CCS 

systems, are based on multiple economic factors, some of which relate to the remaining useful 

life of potential retrofit candidates, and some of which are highly uncertain when projected 15 

years into the future. These uncertainties include the capital cost of competing electricity 

generation technologies, new environmental requirements and the future price of natural gas. 

Nevertheless, mechanisms to accelerate the demonstration of much lower cost CCS systems 

should receive greater attention.

Process Descriptions

Numerous approaches are being pursued to remove or concentrate CO2 from fossil fuel power 

generators. However, options with near-term payoff – meaning those past the laboratory stage 

and in duty at pilot-scale or small commercial units – are limited. These technologies can be 

organized into three major categories: (a) post-combustion, where CO2 is removed from fossilSection D 79 | Page
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fuel combustion products; (b) pre-combustion, where CO2 is captured prior to combustion of the 

gasification-produced synthesis gas, and (c) oxycombustion, where combustion occurs in an 

oxygen rich atmosphere. Further details of the two processes considered prime candidates for 

retrofit – post-combustion and oxycombustion - are described in the NCC report addressing 

CCS128, and also in Appendix B. Highlights are presented below.

Post-combustion Capture. Post-combustion capture is a CO2 retrofit amenable capture 

alternative. CO2 capture from combustion products can utilize a chemical reagent with a strong 

affinity for CO2. Capture processes are based on chemical absorption, physical adsorption, gas 

permeation (membrane separation) or phase separation (e.g., cryogenic), with each approach 

offering advantages and disadvantages. Adsorption and absorption require CO2 to be 

regenerated as a CO2-rich stream. Processes using chemical absorption, including amine-based 

sorbents, appear closest to commercial feasibility, although others are feasible and being 

developed. 

Dry regenerable sorbents may also prove attractive for retrofit CCS applications. These materials, 

which include dry sodium carbonate and amine-grafted zeolites, can physically absorb CO2 and 

can regenerate a high purity CO2 stream while consuming much less energy. Pilot-scale tests 

exploring the efficacy of various solid sorbents are being conducted, and will identify candidate 

sorbents and process conditions for large pilot and commercial testing.129

Capture by gas permeation refers to membrane capture. This technology is interesting because 

CO2 can be separated without the energy expensive regeneration step. However, much energy is 

required to pass the gas across the membrane due to the high pressure drop, membranes are 

susceptible to fouling and membranes will be very large for commercial applications. MTR 

currently has small-scale tests ongoing at locations across the U.S.

Phase separation is not as advanced as other methods of capture, but it is expected to reduce 

parasitic load due to the removal of energy expensive regeneration steps. Cryogenic CO2 capture 

is one method currently in discussion, but it is far from commercial application. Trial tests have 

encountered heat exchanger fouling and plugging issues. However, at least one company, 

Sustainable Energy Solutions, believes it has the solution. Tests of this process will soon begin at 

the National Carbon Capture Center in Wilsonville, AL.

Oxycombustion. As the name implies, oxycombustion is based on firing coal with oxygen instead 

of air (which is 80% nitrogen). The result is a flue gas nearly exclusively comprised of CO2 and 

water vapor. This CO2-rich “flue gas” has a different emissivity and therefore different heat 

transfer properties than traditional power plants, and a relatively concentrated CO2 stream would 

facilitate a CO2 capture and storage system. The gas stream contains trace constituents of sulfur 

(SO2 and SO3), mercury and NOx derived from the fuel that must be removed. Oxycombustion is 

applicable to both new generation and retrofit to existing units. The most notable example of 

oxycombustion retrofit to an existing unit is the FutureGen2 project. 

Several variants of oxycombustion exist. One variant is characterized by the method of air 

separation, typically either cryogenic or membrane-based technologies. A second variant is 

defined by how combustion products (primarily CO2) are recirculated within the boiler to control 

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heat transfer and operating temperature, assuring safe operating limits of available boiler 

materials. All of these oxycombustion variants appear feasible at this time.

The Status of CCS Technology

Post-combustion CCS projects. A summary of post-combustion pilot and demonstration projects 

relevant in early 2014 is presented in Appendix B (Tables Appendix B-1 and Appendix B-2). An 

abbreviated description follows.

The only project shown as complete in Table Appendix B-1 is the American Electric Power (AEP)

Mountaineer project, a 20 MW pilot plant based on Alstom’s chilled ammonia process. This pilot 

plant captured CO2 from approximately 1.5% of the plant’s total output and transported the CO2

to onsite injection wells for deep saline aquifer storage. The system operated over a period of 20 

months and was shut down, although monitoring of the injected CO2 continues. AEP is

monitoring the injected CO2 plume at the sequestration sites, and Alstom is further testing the 

chilled ammonia process on a 40 MW-equivalent pilot plant fueled by natural gas, at a test center 

in Mongstad, Norway. 

Four other coal-fired units shown in Table Appendix B-1 provide flue gas for CO2 capture: for 

three the CO2 is used for either commercial purposes or released. These plants are: 

• AES/Warrior Run, with a 12 MW-equivalent slipstream from a 225 MW coal-fired plant 

with CO2 supporting food processing at an adjacent site, 

• AES/Shady Point, with a 7 MW-equivalent slipstream from a 175 MW coal-fired power 

plant, also for food processing, and 

• Nirma/Searles Valley Minerals, with CO2 from this 28 MW coal-fired plant used for on-site 

mineral processing. 

Southern Company’s Plant Barry is the only remaining pilot scale demonstration project (25 MW) 

at an operating power plant which includes capture, transport and sequestering of CO2. 

Operation of Plant Barry’s system started in June of 2011 (capture only), with sequestration in a

saline reservoir initiated in August of 2012. Capture operations will continue through 2014, and 

monitoring of the sequestration site will continue through 2016. 

Two North American post-combustion CCS projects are either in final construction stages, or are 

engaged in planning and financing efforts. Unit 3 of SaskPower’s Boundary Dam station will 

utilize an amine-based process to remove CO2 (and SO2). This 110 MW unit will produce 1 million

tons of CO2 per year, most of which will be used for EOR at the Weyburn fields. The unit is 

expected to be operating in 2014. In addition, NRG Energy’s W.A. Parish project, is conducting an 

engineering study for a 240 MW-equivalent demonstration project using Fluor’s Econamine 

amine-based CO2 control process. The Parish demonstration has not yet secured financing130. 

The earliest the unit will operate is 2015 – pending financing.

Additional post-combustion CCS projects are underway outside North America. Differences in 

fuel composition, plant design and plant operating duty, may limit their applicability to North 

American units. 

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Four pilot plants presently operate outside North America. These are at:

• Wilhelmshaven, where E.ON operates a 3.5 MW equivalent pilot plant at this North Sea 

site, 

• Brinidisi where ENEL operates a 48 MW pilot plant, capturing CO2 since 2011 for use at 

the nearby Stogit oil field for EOR, 

• Ferrybridge, where Scottish and Southern Energy operate a 5 MW pilot plant which 

commenced operation in 2012 and will operate through 2013, and 

• EDF LeHarve, where Alstom and Dow Chemical are experimenting with state-of-the-art 

amines.

The captured CO2 is not transported or sequestered. Further details are provided in Appendix B.

The status of post-combustion CCS is that: 

• No power plant employing commercial scale post-combustion CCS exists; 

• One such commercial scale project, Boundary Dam, is scheduled to begin operations later

in 2014, but the actual cost of this system would probably be prohibitively expensive for 

general application; and 

• One additional demonstration project (W.A. Parish) is on the horizon and, if built and 

operated, could provide valuable information on CCS after 2016. 

Additional pilot scale activity is underway and could help NETL achieve its research goal of having 

a more affordable 2nd Generation CCS technology available for demonstration by 2020-2025, with 

commercial deployment a few years later.

Oxycombustion CCS Projects. Table Appendix B-3 summarizes projects involving oxycombustion

and CCS systems. Two pilot plant test programs have been completed and a third is in progress 

to provide exploratory data at small scale, and the basis for generalizing design to larger 

capacities. The first is a Babcock & Wilcox 10 MW-equivalent pilot plant, which provided process 

data as a precursor to the FutureGen2.0 project. The test totaled less than 300 hours but results 

provide a first step for a demonstration plant. Testing included oxygen separation and 

production of a nearly pure CO2 effluent. 

The second is the Total (Lauq, France) 10 MW pilot plant – although firing natural gas – and 

operated at Total’s Lacq Refinery from 2010 through 2013. Although not fueled by coal this unit 

is of interest as there is little relevant process information on oxycombustion systems. The 

75,000 tons of CO2 collected were injected into a depleted natural gas field. 

A third pilot plant – jointly funded by DOE and Jupiter Oxygen – addresses a promising variant of 

oxycombustion. This 5 MW-equivalent pilot facility evaluated burners for firing coal with oxygen, 

operating periodically in test modes from 2006 through 2012.

Two oxycombustion pilot scale CCS projects are now operational and conducting all three steps of

oxycombustion, CO2 separation and reuse or sequestration. The 10 MW Vattenfall AB project in 

Schwarze Pumpe, Germany fires coal and is halfway through a decade long test. This test started 

in 2008 and includes oxycombustion, CO2 capture and injecting 75,000 tons of CO2 annually into a 

depleted gas field. A decade of operation reflects the time required to acquire data from 

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different fuels and operating conditions. CS Energy has operated a 30 MW equivalent pilot plant 

– at present the largest in the world – at the Callide Station since 2012. Two years of tests are 

planned and include sequestering CO2 in a saline reservoir. Pending successful results a 150-200 

MW unit will be built and tested for 3-4 years. 

The only North American coal-based large-scale oxycombustion project is the DOE-funded 

FutureGen2.0 at Ameren’s Meredosia station. This demonstration project entails converting a 

167 MWe (gross) conventional unit to oxycombustion. The plant is designed to fire fuel using 

oxycombustion; clean and compress 90% (1.3 M tons) of the CO2 produced; and transport it 175 

miles by pipeline for sequestration in a saline reservoir in Mattoon, Illinois. The project plans to 

commence operation by 2017.

Two additional commercial-scale oxycombustion projects - the White Rose and OXYCFB 300 - are 

being considered in the UK and Spain. White Rose is scheduled to make a final investment 

decision in 2015, if favorable to commence construction in 2016, and become operational in 

2016.131 It is unclear whether the OXYCFB 300 project will move forward.132 

In summary, oxycombustion CCS systems somewhat lag the development of post-combustion 

systems. Current experience is limited to pilot scale projects ranging from 10 MW to 30 MW in 

capacity. However, FutureGen2, when built, will provide commercial scale experience with this 

technology, and startup is scheduled for 2017. Additionally, FutureGen2 will be one of the few 

commercial scale projects integrating CO2 capture with storage in a saline reservoir. 

The Status of CO2 Storage Technology

CO2 once captured at a power plant must be transported and permanently stored, or reused in a 

manner that does not allow eventual release. CO2 transport by pipeline is mature, but the 

pipeline infrastructure within most states for transport to a storage site must be expanded to 

broadly deploy CCS. Significant investment will be required. As of 2010, industry had invested 

over $2.2 B for 2,200 miles of CO2 pipelines in the Permian Basin alone. Technical challenges to 

safe and reliable CO2 transport exist but can likely be overcome – such as specifying the proper 

materials-of-construction and minimizing corrosive species in the gas stream. Non-technical 

issues are likely more significant. These include right-of-way access, multi-state jurisdictions and 

issues related to worksites and population centers.

Saline Storage. The DOE and the United States Geological Survey (USGS) have estimated the 

potential CO2 storage capacity available in deep saline reservoirs, with DOE reporting capacity by 

state133 and the USGS by storage basins.134 The USGS concluded the Gulf Coast area contains 

almost 60% of the national CO2 storage capacity. The DOE identifies many locations in the U.S. 

that have access to potential significant sequestration capacity, but numerous locations remain 

under-served. 

The CO2 storage capability of any saline site is unknown until the site is assessed for specific 

physical and geotechnical features. Such assessments are sophisticated and typically cost tens of 

millions of dollars. Both the International Energy Agency (IEA) and the Global CCS Institute state 

between 5 and 10 years are required to qualify a new saline formation for CO2 storage, and in 

some cases even longer.135, 136 As noted in the 2012 (First) Edition of the North American Carbon 

Storage Atlas, “It is important that a regionally extensive confining zone (often referred to as 

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caprock) overlies the porous rock layer and that no major faults exist.”137 The same reference 

cites the importance of documenting the CO2 storage capability, “injectivity” and the ability of the 

porous rock to permanently trap CO2. 

Saline storage of CO2 also poses non-technical challenges, including establishing pore space 

ownership and other property rights issues, and long-term liability. The legal framework based 

on oil and gas rights may not apply to injecting and storing large CO2 quantities as required for 

power plants. Further complicating matters is the extended time for monitoring and site 

responsibility, well beyond that for oil/gas experience.

The long-term liability of CO2 storage, due to potential migration of the plume or leaks or 

diversion of CO2 to pore spaces not in the confining area, poses a possible financial risk. The time 

scale of liability could exceed the life of the corporate or business entity. Moreover, the time 

scale of present RD&D projects to demonstrate securing CO2 – perhaps 5 years – does not match 

the time scale of liability. This latter risk exposure will exceed 100 years, assuming 50 years of 

injection at a site and an additional 50 years of post-injection monitoring. All risks may not be 

identified. 

Storage of CO2 in EOR Projects. Almost all current integrated CCS projects underway or planned 

in the U.S. employ EOR for CO2 storage (FutureGen2 is a notable exception). CO2 has been used 

to increase production of oil or gas in partially depleted reservoirs for decades, but it has not 

been used in conjunction with coal-fired power generation. 

DOE estimates CO2 can be productively used for EOR; but sites are not uniformly distributed in 

the U.S. Certain Midwestern and Gulf Coast states have notable EOR potential, but the Pacific 

Northwest and much of the eastern seaboard area do not.138 This regional availability of EOR is 

unlikely to be resolved by additional RD&D; it is a limiting physical reality. Because EOR sites have 

already been extensively characterized for primary and secondary oil production, their subsurface 

physical characteristics are generally better understood than those of potential saline sites. As a 

result, the time period for full characterization for CO2 injection is expected to be less than the 5-

10 years for saline reservoirs.139

Not all states clearly specify surface versus subsurface property rights – which will lead to 

conflicts of interest and potential litigation. In addition to property rights issues, environmental 

responsibilities associated with CO2 stored in EOR reservoirs are still evolving. EPA regulations 

reserve the right to change storage requirements after a project is initiated if the permitting 

authority or EPA anticipates an increased risk to drinking water resources. The recently proposed 

CO2 NSPS rules specified more stringent monitoring and reporting requirements for power plant 

CO2 used for EOR versus “natural” CO2 used for EOR. According to a major EOR operator, “the 

proposed NSPS rule will foreclose – not encourage – the use of CO2 captured by emissions 

sources in EOR operations.”140 It is unclear whether these rules, when finalized, will allow the 

flexibility needed by EOR operators in practical EOR projects.

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iii. Findings

• Commercial scale CCS has yet to be demonstrated due to a number of significant 

technical, financial, legal and regulatory challenges. Because of the broad scope and 

magnitude of CCS development issues, the timeline for any commercial-scale project 

could be expected to require at least a decade from the project concept to assessment of 

operational data. As a result, there are practical limits to how soon RD&D results can be 

applied in the marketplace. 

• Nevertheless, if CCS is to become a viable technology, then a focused and aggressive 

effort to overcome the technical, financial, regulatory and legal barriers is needed on 

behalf of industry, regulators and technology developers. This would include a broad set 

of projects to demonstrate the feasibility of the technology, and establish a basis for an 

industry using the range of coal types mined in the U.S., various power plant types and

both EOR and saline CO2 storage options. Two previous reports by the National Coal 

Council,141 as well as the report by the Interagency Task Force on Carbon Capture and 

Storage,142 all recommended 5-10 GW of commercial scale CCS demonstrations.

• No power plant with commercial scale CCS presently operates. One post-combustion

project fueled by lignite is scheduled to begin operation in 2014 and will provide process 

design and integration experience. 

• Retrofitting CCS creates challenges that go far beyond those that apply to greenfield CCS 

applications: including integration with unit operations, less design and operational 

flexibility, fixed locations, limits on available space, significant concerns regarding the 

availability of geologic sequestration options, immature state regulatory programs and,

perhaps most importantly, a limited time window.

• Expeditiously conducting this research and demonstration is critical to serve the existing 

fleet. The capacity-weighted average age of existing U.S. coal-fired power plants is 39 

years. Significant progress must be achieved in the next decade to support the existing 

fleet, which in 2025 will average 50 years of service.

• In general, the DOE R&D program has sufficient scope to address the technical challenges 

posed by current gaps in understanding related to carbon capture and compression 

technology. However, the program has no financial resources to move viable R&D 

concepts through commercial scale demonstration, which is essential to making those 

concepts commercially viable. Additionally, there is no effort underway to address the 

long-term legal liability associated with CO2 storage in the decades following completion 

of a CO2 injection project. 

• Considerable challenges still exist with respect to carbon storage and EOR, both technical 

and non-technical.

• Approximately 12 large scale carbon capture and storage demonstration projects are 

needed to adequately demonstrate CCS is technically feasible and commercially-viable for 

coal-based generating units; half for EOR and half for saline formations. 

• System optimization for partial CO2 capture may yield benefits in reduced parasitic power 

consumption and easier integration with existing power plants.

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iv. Recommendations

• DOE should lead collaborative work with industry to demonstrate at commercial scale 

lower cost post-combustion CCS systems with less parasitic power consumption for 

bituminous and subbituminous coals.

• DOE should lead a collaborative program to demonstrate retrofit of existing units with 

oxycombustion technology as an approach that would require lower resources and less 

time to implement than greenfield oxycombustion applications.

• At the research level, DOE efforts should evaluate and develop small footprint concepts 

for post-combustion capture, systems with reduced parasitic energy needs and dry 

sorbents producing carbonates. Process integration resulting in greater recovery of low 

quality heat energy should also be a priority. Given the potential role of oxycombustion, 

lower cost oxygen separation technologies should continue to receive attention.

• DOE R&D should explore partial CO2 capture by processing not the entire gas stream but a 

fraction for high CO2 removal, as a means to reduce parasitic power consumption and 

ease integration at existing sites.

• DOE should lead collaborative efforts with industry to improve CO2 plume monitoring 

techniques for both saline and EOR formations. Similarly, DOE should lead R&D efforts to 

develop improved systems for evaluating potential CO2 storage formations at lower cost 

and with greater certainty than current systems. 

• DOE should work with regulatory agencies to ensure that monitoring requirements placed 

on EOR systems used for compliance with CO2 emission limits at power plants do not 

extend beyond provisions that ensure that CO2 is not released from the EOR field to the 

atmosphere. 

• DOE should continue work on “best practices” reports related to CCS legal framework 

issues. The Department should also collaborate with regulatory agencies to target 

development of plume modeling and monitoring technologies that could mitigate the 

financial risk exposure from RCRA, CERCLA and long term liability under UIC.

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APPENDIX A

Turbine Upgrade or Efficiency Improvement Projects Cited in NSR 

Enforcement Initiative

Appendix A
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX A

Turbine Upgrade or Efficiency Improvement Projects Cited in NSR 

Enforcement Initiative

This list is limited to turbine upgrades or replacements – the list would be much longer if 

improved materials of construction and improved designs of heat transfer surfaces were 

included.

1. Turbine Upgrade or Efficiency Improvement Projects Cited in NSR Enforcement Initiative

• United States v. Duke Energy Corp., No. 00-cv-01262 (M.D.N.C. Dec. 22, 2000) (GE Dense 

Pack turbine upgrades at Belews Creek Units 1 and 2 and Marshall Unit 3);

• New York v. Niagara Mohawk Power, No. 02-CV-24, Compl. (W.D.N.Y. Jan. 10, 2002), ¶ 

202 (“upgraded the turbine” on Huntley Unit 63 in 1987), ¶ 323 (“replaced the turbine” 

on Huntley Unit 67 in 1991); 

• United States v. East Kentucky Coop., No. 04-34-KSF, Compl. (E.D. Ky. Jan. 28, 2004), ¶ 60 

(“replacement or renovation ... of major components of the ... turbine at the unit” on Dale 

4 in 1995-1995), ¶ 76 (“replacements or renovations of major components of the ... 

turbine” on Dale 3 in 1996); 

• Sierra Club v. Portland General Electric, No. 08-cv-01136, Am. Compl. (D. Or. Nov. 29, 

2010), ¶ 134 (“a plant turbine upgrade” at Boardman in 2003); 

• United States v. Ameren Missouri, No. 4:11-cv-77, Am. Compl. (E.D. Miss. June 28, 2011), 

¶ 67 (“associated turbine replacements” at Rush Island Unit 1 in 2001-2002), ¶ 73 

(“associated turbine replacements” at Rush Island Unit 2 in 2003-2004); 

• Conservation Law Foundation, Inc. v. Public Service of New Hampshire, No. 11-cv-00353, 

Compl. (D.N.H. July 21, 2011), ¶ 49 (“removed a high pressure/intermediate pressure 

turbine, and replaced it with a new HP/IP turbine” at Merrimack Unit 2 in 2008); 

• Dine Citizens Against Ruining Our Environment v. Arizona Public Service Company, No. 

1:11-cv-889, Am. Compl. (D.N.M. Jan. 6, 2012), ¶ 48 (“replacement of the high pressure 

turbines” at Four Corners Units 4 and 5 in 2007), id. (“Plaintiffs are informed and believe ... 

that these high-pressure turbine upgrades increased the design-level heat input rate of 

each of these units, thereby increasing each unit’s generating capacity and its potential to 

emit air pollution.”); 

• United States v. Dairyland Power Coop., No. 12-cv-462, Compl. (W.D. Wisc. June 28, 2012), 

¶ 38 (“upgrading of the turbine at the J.P Madgett Unit in 2004”); 

• Sierra Club v. PPL Montana LLC, No. 1:13-cv-32, Am. Compl. (D. Mont. Sept. 27, 2013), ¶ 

55 (“Replacement of the Low Pressure Turbine” on Unit 3 in 2011), ¶ 57 (“High 

Pressure/Intermediate Pressure Turbine Replacement” at Unit 2 in 2008), ¶ 58 (“High 

Pressure Turbine Replacement” at Unit 3 in 2007), ¶ 59 (“High Pressure Turbine 

Replacement” at Unit 4 in 2006), ¶ 60 (“Replacement of the High Pressure and 

Intermediate Pressure Turbines” at Unit 1 in 2006). 

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2. Standard Turbine Overhauls or other Turbine Projects Cited in NSR Enforcement Initiative

• United States v. Cinergy, No. IP99-1693, Third Am. Compl., (S.D. Ind. June 29, 2006) at ¶ 

172 (replacement of “turbine blades” on Beckjord Unit 6 in 1994); 

• United States v. Duke Energy Corp., No. 00-cv-01262, Compl. (M.D.N.C. Dec. 22, 2000), ¶ 

32 (“turbine overhaul” at Allen Unit 5 in 2000), ¶ 60 (“turbine overhaul” at Allen Unit 4 in 

1998), ¶ 195 (“turbine rehabilitation” at Cliffside Unit 4 in 1990);

• Sierra Club v. Dayton Power & Light, Inc., No. C2-04-905, Compl. (S.D. Ohio Sept. 21, 

2004), ¶ 43 (“overhaul of the turbine” on Stuart Unit 1 in 1980); 

• United States v. American Electric Power, No. C2-05-360, Compl. (S.D. Ohio Apr. 8, 2005), 

¶ 97 (“replacement of the low pressure turbine rotor” on Conesville Unit 5 in 1997), id.

(“replacement of the low pressure turbine rotor” on Conesville Unit 6 in 1997);

• Sierra Club v. PPL Montana LLC, No. 1:13-cv-32, Am. Compl. (D. Mont. Sept. 27, 2013), ¶¶ 

53 (“Low Pressure Turbine Overhaul” at Unit 1 in 2012), id. (“Turbine/Generator Base 

Overhaul” at Unit 1 in 2012), ¶ 54 (“Turbine Generator Base Overhaul” on Unit 2 in 2011), 

¶ 55 (“Turbine Generator Base Overhaul” on Unit 3 in 2011), ¶ 55 (“Intermediate Pressure 

Turbine Overhaul” on Unit 3 in 2011), id. (“Turbine/Generator Base Overhaul” on Unit 3 in 

2011), ¶ 56 (“LP1 & LP2 Turbine Rebuild” at Unit 4 in 2009), id. (“Low Pressure Turbine” at 

Unit 4 in 2009), id. (“Turbine/Generator Base Overhaul” at Unit 2 in 2008), id. (“Low 

Pressure Turbine Overhaul” at Unit 2 in 2008), ¶ 59 (“Intermediate Pressure Turbine 

Overhaul” at Unit 4 in 2006).

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APPENDIX B

Present Technical Status of CCS

Appendix B
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX B

Present Technical Status of CCS

1. Introduction

Appendix B presents a summary of the technical status of CCS in 2014 in more detail than 

addressed in the text of this report. The status of the two options featured in this report that are 

considered the best candidates for retrofit – post-combustion control and oxycombustion –are 

addressed in Appendix B.

2. Post-combustion Control

The key post-combustion control processes that are relevant to the technical status of CCS are 

summarized in Table Appendix B-1. These operating processes, demonstrations, or pilot plants 

(greater than 3 MW-equivalent capacity) are discussed according to the status: Completed; 

Operating; or Planning. A sampling of projects (not a complete or comprehensive list) that are 

proposed or planned outside North America is also presented.

Post-combustion Control Projects: Completed. The sole project completed is the American 

Electric Power (AEP) 20 MW pilot plant based on Alstom’s chilled ammonia process, which 

operated for a period of 20 months. 

Post-combustion Control Projects: Operating. Five coal-fired units are the source for captured 

CO2 that is used for either commercial purposes or for a pilot plant test. 

Three units support producing of food or chemicals and do not transport or sequester CO2. These 

plants are: (a) AES/Warrior Run, with a 12 MW-equivalent slipstream from a 225 MW coal-fired 

plant supporting food processing at an adjacent site, (b) AES/Shady Point, with a 7 MWequivalent slipstream from a 175 MW coal-fired power plant, also for food processing, and (c) 

Nirma/Searles Valley Minerals, with flue gas from this 28 MW coal-fired plant provides CO2 for 

on-site mineral processing. A fourth 5 MW-equivalent pilot plant operates at EDF’s Le Havre 

station, testing advanced amine compounds developed by Alstom and Dow Chemical.

Only the fifth pilot plant, Southern Company’s 25 MW-equivalent Plant Barry demonstration, 

includes a scope that includes transporting and sequestering CO2. This demonstration of MHI’s 

amine-based technology removes approximately 500 tons of CO2 per day from flue gas at 

Alabama Power’s Barry Unit 3. This project, in addition to demonstrating CO2 capture, employs 

compression, pipeline delivery, and sequestration of CO2 in saline aquifers. Operation started in 

June of 2011 (capture only), with sequestration initiating in August of 2012. Operations will 

continue through 2014, including monitoring of the sequestration site through 2016.

Post-combustion Control Projects: Planning. Two North American projects are relevant: one in 

final construction, and one in planning and financing.

SaskPower. Unit 3 of SaskPower’s Boundary Dam station will utilize an amine-based process to 

remove CO2 (and SO2). This 110 MW unit will produce 1 M tons of CO2 per year, most of which 

will be deployed for EOR at the Weyburn fields. The unit is expected to be operating in 2014.

Appendix B 1 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

W.A. Parish. An engineering study is underway for a 240 MW-equivalent demonstration plant 

using Fluor’s Econamine amine-based CO2 control process. The Parish demonstration is not 

finalized as financing is not secured - a late 2013 decision anticipated.xv The earliest the unit will 

operate is 2015 – pending financing.

Post-combustion Control Projects: Outside North America. Several post-combustion CO2 control 

projects operate outside of North America, with additional demonstration plants planned. 

Differences in fuel composition, plant design, and plant operating duty, may limited applicability 

to North American units. 

Three pilot plants – ranging in equivalent generating capacity from 3.5 to 48 MW – presently 

operate. These are at (a) Wilhelmshaven, where E.On operates a 3.5 MW equivalent pilot plant 

at this North Sea site, (b) Brinidisi where ENEL operates a 48 MW pilot plant, capturing CO2 since 

2011 for use at the nearby Stogit oil field for EOR, and (c) Ferrybridge, where Scottish and 

Southern Energy operate a 5 MW pilot plant which commenced operation in 2012 and will 

operate through 2013. The captured CO2 is not transported or sequestered.

Additional post-combustion control demonstrations at commercial scale are planned, but status 

is uncertain as financing is not complete. Examples of such projects, for which capture of CO2 will 

not be attained until 2015 at the earliest, are a scale-up of the 5 MW pilot plant at Ferrybridge 

(UK) and ROAD (Netherlands). 

Analysis Summary: The sole relevant experience in North America with post-combustion CO2

control is with Plant Barry’s 25 MW-equivalent pilot plant. The SaskPower 110 MW Boundary 

Dam unit may soon be operating and provide similar information. The commercial units (Warrior 

Run, Shady Point, Searles Valley Minerals) do not provide authentic utility experience or a 

complete scope. A summary of experience derived, additional experience required, and possible 

future actions for selected pilot plants is presented in Table Appendix B-2. 

xv DOE Issues Final EIS for W.A. Parish, GHG Monitor, March 13, 2013, available at http://ghgnews.com/index.cfm/doe-issues-finaleis-for-wa-parish/

Appendix B 2 | Page

 
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Table Appendix B-1. Summary of Post-combustion CO2 Pilot Plant and Demonstration Projects: North America and Europe.

Project Host 

(Co-Sponsors)

Capacity (MW)

CO2 Removed/Yr

CO2 Capture 

Technology CO2 Fate

Construction 

Initiated/

Operational

Cost, $M

Mountaineer AEP (Alstom, 

others)1

20 MW pilot plant.

51,300 metric tons CO2 

captured and 37,400

metric tons CO2 stored

Post-combustion: 

Chilled ammonia

Saline: 1.5-mile 

depth in Mt. Simon 

Sandstone 

Operations: Sep ’09 

thru May ’11. Postinjection monitoring 

ongoing.

100

Warrior Run AES 12 MW. 110,000 

tons/yr

Post-combustion 

amine

On-site food 

production

Operating since 2000 N/A

Shady Point AES 7 MW. 66,000 tons/yr Post-combustion 

amine

On-site food 

production

Operating since 2000 N/A

Searles Valley 

Minerals

Nirma 28 MW. 270,000 

tons/yr

Post-combustion 

amine

Chemicals 

production 

Operating since 1995 N/A

Plant Barry Southern 

Company, MHI, 

EPRI

25 MW pilot plant; 

550 tons/day CO2

Post-combustion: MHI 

KM-CDR amine process

Saline: 11-mile 

pipeline to 

Citronelle dome 

(0.44 tons/4 yrs)

Operations: 2Q/2011 

to 4Q/2014

TBD

W.A. Parish NRG Energy (DOE) 240 MW

1.65 M tons CO2/year

Post-combustion: Fluor 

Econamine, 

experimental reagents

EOR: 80 miles to 

Hilcorp’s West 

Ranch

Operations: planned 

2015

339

Boundary Dam 

(Unit 3)

SaskPower 

Alliance

110 MW 

1 M tons CO2/year

Post-combustion: 

Cansolv

EOR at Weyburn, 

excess CO2 to saline 

reservoir

Construct: 2012 

Operation: 2014

1,335 (Canadian)

Brindisi ENEL, Eni 48 MW pilot plant 8,000 

tons/y

Post-combustion –

amine, others

EOR: Stogit field 

north Italy

Anticipated 2012 

operation

400 (€)

Ferrybridge Scottish Southern 

Energy

5 MW pilot plant 

350,000 tons/yr

Post-combustion 

amines

Release after 

capture

Nov 2012 through 

2013

21 (£)

Le Havre EDF 5 MW pilot plant Post-combustion 

amines

Release after 

capture

July 2013 through 

March 2014

N/A

Wilhelmshaven E. On 3.5 MW pilot plant Fluor Econamine Release 2012-present N/A

Note: Capacity reported as gross electric MW, unless noted otherwise.

1 Chilled ammonia work continues at the European CO2 capture pilot plant, the Test Center Mongstad, Norway, on natural and refinery gas products.

Appendix B 3 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Table Appendix B-2. Post-combustion CO2 Controls: Experience and Lessons Learned.

Project

Capacity (MW)

Technology Status Experience Derived

Additional 

Experience 

Required

Possible Future 

Actions

AEP/Mountaine

er

20 MW pilot plant: chilled 

ammonia

Complete Confirm process chemistry, 

control system strategies

Scale-up of heat 

exchangers, absorbers, 

process controls 

200 MW demo for E. bit, 

subbit coal

Plant Barry 25 MW pilot plant: advanced 

amine reagent

In operation Experience with advanced (MHI 

KM-CDR) reagent; integrate 

heat balance

Scale up of heat 

exchangers, absorbers 

and regeneration 

towers, process control

200 MW demo for E. bit, 

subbit coal

W.A. Parish 240 MW

1.65 M tons CO2/year

Design & 

planning

This will represent the largest 

amine-based CO2 capture test in 

the world 

Process integration at 

commercial scale, 

operating in support of 

EOR 

Long-term operation 

exercising various loadfollowing modes.

Boundary Dam 

(Unit 3)

110 MW 1 M tons CO2/year Startup in 2014 Small commercial size (100 MW) 

but a valued step to address 

process integration 

Same as above Same as above

Brindisi 48 MW pilot plant 8,000 tons/y In operation 

(confirm)

Confirm process chemistry, 

control system strategies

Generalize results to 

250-500 MW

Exercise various loadfollowing modes

Ferrybridge 5 MW pilot plant 350,000 tons/yr Complete Confirm process chemistry, 

control system strategies

Generalize results to 

250-500 MW

Apply design basis to 

larger scale

Le Havre 5 MW pilot plant In operation Develop advanced amines Generalize results to 

250-500 MW

Apply design basis to 

larger scale

Wilhelmshaven 3.5 MW pilot plant In operation Confirm process chemistry, 

control system strategies

Generalize results to 

250-500 MW

Apply design basis to 

larger scale

Appendix B 4 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

3. Oxycombustion

Oxycombustion: Completed. Two pilot plant test programs have been completed and provide 

exploratory data at small scale and limited operation. 

Babcock & Wilcox. A 10 MW-equivalent pilot plant provided process data as a precursor to the 

FutureGen2.0 project.16 The test totaled less than 300 hours but results provide a first step for a 

demonstration plant. Testing included oxygen separation and production of an exclusive CO2

effluent.

Total (Lauq, France). A 10 MW-equivalent pilot plant firing heavy fuel oil operated at Total’s Lacq 

Refinery from 2010 through 2013. This unit is cited even though experience is with natural gas 

and not coal as there is little process information on any fuel. The 75,000 tons of CO2 collected 

are injected into a depleted natural gas field.

Jupiter Oxygen (Hammond, IN). A 5 MW-equivalent burner test facility, funded by DOE and 

Juniper Oxygen, addressed combustion of coal in oxygen, heat transfer, and materials 

performance. Tests were conducted periodically from 2006 through 2012. A smaller 20 kWequivalent test apparatus simulates the train of process equipment for combustion product 

clean-up. CO2 captured is released as research activities focus on developing and refining 

engineering principles for oxycombustion. 

Oxycombustion Control Projects: Operating. Two demonstration units at small scale simulate a 

complete scope of CO2 separation and reuse or sequestration. 

Vattenfall AB. This 10 MW pilot plant in Janschwalde, Germany fires coal and is halfway through 

a decade long test. This test started in 2008 represents a complete scope of activity, injecting 

75,000 tons of CO2 annually into a depleted gas field. The planned decade of operation 

demonstrates the time that is required to methodically acquire data from different fuels and 

operating conditions.

Callide A Station. CS Energy has operated a 30 MW equivalent pilot plant – at present the largest 

in the world – at the Callide Station since 2012. Two years of tests are planned and include 

sequestering CO2 effluent in a saline reservoir. Pending successful results a 150-200 MW unit will 

be built and tested for 3-4 years. 

Oxycombustion Control Projects: Planning. The sole North American project is the U.S. DOEfunded FutureGen2.0. This demonstration entails converting a 167 MWe (gross) conventional 

unit at Ameren’s Meredosia station to oxycombustion. A complete scope of activities is planned: 

cleaning and compressing 90% (1.3 M tons per year) of the CO2 captured and transported 175 

miles by pipeline for sequestration in a saline reservoir in Mattoon, Illinois. The project is planned 

to commence operation by 2017.

Oxycombustion Projects: Outside North America. Two demonstration projects are planned with 

2018/2019 start dates but permit and finance fate are uncertain. The White Rose project was 

16 Technical Considerations for Oxycombustion Flue Gas Conditioning, Babcock & Wilcox Technical Paper BR-1842, EPRI Power Plant 

“Mega” Symposium, Baltimore, MD, August 2010. This work is widely reported on the thermal-throughput basis, or 30 MW. 

Appendix B 5 | Page

 
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

selected by the UK government as one of two key projects to receive a considerable subsidy. The 

OXYCFB 300 project – a 323 MW demonstration of a circulating fluid bed boiler fired as 

oxycombustion mode – is also being evaluated in a design study.

Analysis Summary: The only operating oxycombustion process experience is with four pilot 

plants. FutureGen 2.0 is planned for 2016 operation; two units in the U.K. are proposed but 

highly uncertain. 

Appendix B 6 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Table Appendix B-3. Status of Oxycombustion Demonstration Tests.

Utility/Operator

Electrical/Heat 

Throughput CO2 Fate

Construction or Test/ 

Schedule

Cost, $M

(Total/Subsidy)

Jupiter Oxygen (Hammond, IN) 5 MW(e) Capture and release Periodic 5 MW-equivalent tests 

(2006–2012)

$8.1 M ($6.5 M from DOE, $1.5 M 

from Jupiter Oxygen)

Lacq, Total, France 30 MWt /10 MW(e) 

Natural gas

75,000 CO2 tons/yr 

injected in depleted gas 

field 

Demonstration test starting 2010; 

completed 2013

Two year test 2010-2013. 

Government support for the 60 M € 

project is unknown.

Vattenfall AB Janschwalde, 

Germany

30 MW (thermal)

(equivalent to 10 MW)

75,000 tons/yr, 

transported 400 m to 

gas field

Demonstration test starting 2008; 

continues through 2018

Continued commercial 

demonstration through 2018.

Callide A Station, CS Energy, 

Australia

30 MW(e) 0.27 tons/yr, 

sequestered on-site 

saline reservoir

Demonstration test starting 2012; 

continue through 2014

$241 M (AUS). Startup operations 

commenced in early 2012.

FutureGen 2.0 Alliance 167 gross MW(e) 1. 1 M tons/yr, 

transport via 29 mile 

pipeline to saline 

reservoir

2013 start of construction. Planned 

completion by 2017

1,650/1,000

Preliminary engineering complete. 

Completing financing and permitting.

White Rose 436 MW(e) 2 M tons/yr; offshore 

sequestration: saline 

reservoir

Final investment decision in 2015, 

possible initiation of construction 

in 2016. Start up 2020.

Selected by UK government in CCS 

Competition to receive funding. 

Preliminary engineering in progress. 

Endesa/OXYCB 300 

Compostilla 

323 MW(e) 1.2 M tons/yr; 

sequestration: deep 

saline reservoir

Process design presently being 

defined. Possible initiation of 

construction in 2016. Start up 

2018.

Preliminary engineering in progress. 

Appendix B 7 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX C 

2012 Generation, Million MWH by State

Appendix C
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX C

2012 Generation, Million MWH by State

State 2012 Generation, Million MWH Price

(Data Source: USDOE/EIA)

Coal Natural Gas Hydro Nuclear Wind Other Total c/kWh 

AK 0.64 3.86 1.43 - 0.01 1.04 6.98 16.33 

AL 45.69 55.42 7.16 40.84 - 3.56 152.66 9.18 

AR 28.43 17.50 2.17 15.49 - 1.79 65.38 7.62 

AZ 40.21 30.32 6.73 31.93 0.26 1.25 110.69 9.81 

CA 1.59 121.09 25.96 18.51 9.94 24.25 201.34 13.53 

CO 34.64 10.83 2.00 - 6.04 0.07 53.59 9.39 

CT 0.10 16.51 0.47 17.08 - 1.57 35.73 15.54 

DC - 0.08 - - - 0.01 0.09 11.85 

DE 1.46 6.94 - - 0.00 0.40 8.81 11.06 

FL 44.37 149.25 0.15 17.87 - 9.11 220.75 10.44 

GA 40.70 42.78 2.33 33.94 - 2.95 122.70 9.37 

HI 1.53 - 0.09 - 0.37 8.09 10.08 34.04 

IA 35.56 1.97 0.82 4.35 13.94 0.27 56.92 7.71 

ID 0.08 1.94 11.75 - 1.82 0.59 16.18 6.92 

IL 80.84 11.36 0.10 96.40 7.71 1.33 197.74 8.40 

IN 92.58 14.61 0.46 - 3.16 3.87 114.68 8.29 

KS 27.98 3.29 0.01 8.28 5.12 0.10 44.78 9.33 

KY 82.57 2.97 2.38 - - 1.91 89.82 7.26 

LA 21.43 59.20 0.68 15.66 - 6.80 103.77 6.90 

MA 2.10 24.42 0.97 5.86 0.09 1.96 35.40 13.79 

MD 16.13 4.96 1.66 13.58 0.31 1.16 37.82 11.28 

ME 0.05 6.18 3.53 - 0.88 4.41 15.05 11.81 

MI 53.35 22.28 1.31 28.02 1.11 2.67 108.73 10.98 

MN 23.06 7.18 0.74 11.94 7.53 2.11 52.56 8.86 

MO 72.87 6.24 0.72 10.72 1.25 0.19 91.98 8.53 

MS 7.21 38.25 - 7.30 - 1.43 54.19 8.60 

MT 14.21 0.17 11.30 - 1.24 0.81 27.73 8.25 

NC 51.01 19.42 3.52 39.39 - 2.70 116.02 9.15 

ND 28.23 0.03 2.48 - 5.32 0.13 36.18 7.83 

NE 25.11 0.86 1.51 5.80 1.27 0.09 34.64 8.37 

NH 1.27 7.03 1.29 8.19 0.26 1.23 19.27 14.19 

NJ 1.90 27.22 0.03 33.11 0.01 1.82 64.09 13.68 

NM 25.00 8.75 0.20 - 2.23 0.40 36.57 8.83 

NV 4.08 25.66 2.44 - 0.13 3.26 35.57 8.95 

NY 4.55 59.99 25.06 40.77 3.03 3.56 136.97 15.15 

OH 86.02 22.63 0.38 17.09 0.99 2.20 129.31 9.12 

OK 29.28 39.41 1.14 - 8.23 0.20 78.27 7.54 

OR 2.63 11.63 39.26 - 6.07 0.79 60.37 8.21 

PA 88.03 53.11 2.31 75.17 2.21 3.88 224.71 9.91 

RI - 8.22 0.01 - 0.00 0.14 8.37 12.74 

SC 28.49 14.13 1.40 51.15 - 1.35 96.51 9.10 

SD 2.97 0.31 5.96 - 2.91 0.01 12.17 8.49 

TN 35.59 7.69 8.01 25.10 0.05 1.01 77.45 9.27 

TX 138.09 215.41 0.51 38.44 31.86 6.70 431.02 8.55 

UT 30.79 6.40 1.14 - 0.71 0.61 39.65 7.84 

VA 14.33 25.13 1.01 28.72 - 1.71 70.90 9.07 

VT - 0.00 1.20 4.99 0.11 0.41 6.71 14.22 

WA 3.76 5.49 88.53 9.33 6.69 2.16 115.97 6.94 

WI 32.76 11.79 2.02 14.30 1.55 2.07 64.48 10.28 

WV 70.30 0.24 1.33 - 1.29 0.18 73.33 8.14 

WY 43.64 0.55 0.89 - 4.39 0.33 49.81 7.19 

 1,517 1,231 277 769 140 121 4,054 9.84 

Appendix C 1 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX D 

Reports of the National Coal Council – June 1986-May 2014

Appendix D
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX D

Reports of the National Coal Council – June 1986-May 2014

June 1986 Coal Conversion

Clean Coal Technologies

Interstate Transmission of Electricity

Report on Industrial Boiler New Source Performance Standards

June 1987 Reserve Data Base: Report of The National Coal Council

Improving International Competitiveness of U.S. Coal and Coal Technologies

Nov. 1988 Innovative Clean Coal Technology Deployment

Dec. 1988 Use of Coal in Industrial Commercial, Residential & Transportation Sectors

June 1990 Industrial Use of Coal and Clean Coal Technology – Addendum Report

The Long Range Role of Coal in the Future Energy Strategy of the United States

Jan. 1992 The Near Term Role for Coal in the Future Energy Strategy of the United States

Improving Coal’s Image: A National Energy Strategy Imperative

May 1992 Special Report on Externalities

Feb. 1993 Role of U.S. Coal in Energy, the Economy& the Environment 

A Synopsis of NCC Reports (1986 – 2003) 

Nov. 1993 The Export of U.S. Coal and Coal Technology

Feb. 1994 Clean Coal Technology for Sustainable Development

May 1995 Critical Review of Efficient & Environmentally Sound Coal Utilization Technology

Nov. 1995 The Implications for Coal Markets of Utility Deregulation & Restructuring

Feb. 1997 Vision 2020: The Role of Coal in U.S. Energy Strategy

Oct. 1997 Clean Air Act Rules, Climate Change & Restructuring of the Electricity Industry 

Nov. 1998 Coal’s Role in Achieving Economic Growth and Environmental Stability

May 2000 Research & Development Needs for the Sequestration of Carbon Dioxide 

May 2001 Increasing Coal-Fired Generation Through 2010: Challenges and Opportunities 

May 2003 Coal-Related Greenhouse Gas Management Issues

Nov. 2004 Opportunities to Expedite the Construction of New Coal-Based Power Plants

March 2006 Coal: America’s Energy Future (Volumes I & II)

June 2007 Technologies to Reduce or Capture and Store Carbon Dioxide Emissions

Appendix D 1 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

May 2008 The Urgency of Sustainable Coal

Dec. 2009 Low Carbon Coal: Meeting U.S. Energy, Employment & Carbon Dioxide 

Emission Goals with 21st Century Technologies

March 2011 Expediting CCS Development: Challenges and Opportunities

June 2012 Harnessing Coal’s Carbon Content to Advance the Economy, Environment & Energy 

Security

May 2014 Reliable & Resilient: The Value of Our Existing Coal Fleet

Reports can be found on the NCC web site at www.nationalcoalcouncil.org

Appendix D 2 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX E 

Member Roster – 2014

Appendix E
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX E 

Member Roster – 2014

Robert O. Agbede, President / CEO

Chester Engineers

1555 Coraopolis Heights Road

Moon Township, PA 15108

412-809-6576; Fax: 412-809-6006

ragbede@chester-engineers.com

www.chester-engineers.com

Nicholas K. Akins

Chairman, President & CEO

American Electric Power Company

One Riverside Plaza

Columbus, OH 43215

614-716-3800; Fax: 614-716-1603

nkakins@aep.com

Sy Ali, Principal

Clean Energy Consulting 

7971 Black Oak Drive

Plainfield, IN 46168 

317-839-6617

sy.ali@cleanenergyconsulting.com

Barbara Farmer-Altizer

Executive Director

Virginia Coal & Energy Alliance Inc.

P.O. Box 339

Lebanon, VA 42266

276-889-4001; Cell: 276-970-5580

Fax: 276-889-3055

barb@virginiacoalenergy.com

Phil Amick, Director

Gasification Business Development

CB&I

Two Riverway, Ste. 1300

Houston, TX 77056

713-375-8013; Cell: 832-641-9536

Phil.Amick@cbi.com

Rodney Andrews, Director

Center for Applied Energy Research “CAER”

University of Kentucky

2624 Research Park Drive 

Lexington, KY 40511-8479

859-257-0200; Fax: 859-257-0220

Rodney.andrews@uky.edu

Carol J. Bailey, Sr. Associate

Booz/Allen/Hamilton

1550 Crystal Dr., Ste. 1100

Arlington, VA 22202-4158

703-412-7790; Cell: 703-939-4434 

bailey_carol@bah.com; www.bah.com

Richard Bajura, Director

Nat’l Research Center for Coal & Energy

385 Evansdale Drive, Suite 113

Morgantown, WV 26506-6064 

304-293-6034; Cell: 304-216-0360 

Fax: 304-293-3749; 

bajura@wvu.edu; richard.bajura@mail.wvu.edu

www.nrcce.wvu.edu

Theodore K. Barna, Ph.D.

BarnaSolutions LLC

47 Smith Point Circle

Reedville, VA 22539-3053

Cell: 703-568-7492 

tbarna2@cox.net

Robert A. Beck

Former NCC Executive Director 

 & Chair Pittsburgh Coal Conference

335 E. Bluebell Lane

Tempe, AZ 85281

Cell: 703-608-1191

rbeck82851@aol.com

Appendix E 1 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Janos M. Beer, Prof. of Chemical & Fuel Engineering/ 

Dept. of Chemical Engineering

Massachusetts Institute of Technology

25 Ames Street Room 66-301

Cambridge, MA 02139

617-253-6661; Fax: 617-252-1651

jmbeer@mit.edu

Robert A. Bibb, P.E., Chairman

Bibb Engineers, Architects & Constructors

3131 Broadway

Kansas City, MO 64111

816-285-5500; Cell 913-961-4477

Fax: 816-285-5555 

bobbibb@bibb-eac.com

www.bibb-eac.com

Jacqueline F. Bird

1481 Fahlander Dr N

Columbus, OH 43229

614-846-7498; Cell: 614-218-4427

Jbird1@insight.rr.com

Bill Bissett, President

Kentucky Coal Association

2800 Palumbo Dr., Ste. 200

Lexington, KY 40509

859-233-4743; Fax: 859-233-4745

David C. Boyd, Commissioner & Vice Chair

Minnesota Public Utilities Commission

121 7th Place E., Ste. 350

St. Paul, MN 55101-2147

651-201-2220

David.C.Boyd@state.mn.us

Lisa J. N. Bradley, PhD, DABT,

Vice President and Senior Toxicologist

AECOM

250 Apollo Drive

Chelmsford, MA 01824

978-905-2100

Lisa.bradley@aecom.com

F. William Brownell, Esquire

Hunton & Williams

2200 Pennsylvania Ave. NW

Washington, DC 20006

202-955-1555; Fax: 202-778-2201

bbrownell@hunton.com

Wanda I. Burget

Vice President, Environmental Services

Norwest Corporation

136 East South Temple, 12th Floor

Salt Lake City, Utah 84111

801-539-0044; Fax: 801-539-0055 

wburget@norwestcorp.com

Jim Butz

Vice President, Product Management

Novinda Corporation

999 18th Street #1755 North Tower

Denver, CO 80202

720-473-8338; Fax: 720-473-8360

jbutz@novinda.com

Michael Carey, Chairman

Ohio Coal Association

17 South High Street, Suite 640

Columbus, OH 43215-3413

614-228-6336; Fax: 614-228-6349

info@ohiocoal.com

www.ohiocoal.com

Desmond W. Chan, Ph.D. 

Manager of Technology

Bechtel Power Corporation

5275 Westview Dr., Frederick, MD 21703

301-228-8764 

dchan@bechtel.com

Robert J. Ciavarella, President/CEO

Stock Equipment Company

16490 Chillicothe Rd. 

Chagrin Falls, OH 44023 

440-543-6000 x276; Cell: 440-724-8096 

Fax: 440-543-9416

Robert.ciavarella@stockequipment.com

www.stockequipment.com

Joseph W. Craft, III, President

Alliance Coal

1717 South Boulder Ave.

Tulsa, OK 74119

918-295-7602; Fax: 918-295-7361

josephc@arlp.com

Appendix E 2 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Michael D. Crotty, President

MKT & Associates, LLC

1776 Mentor Ave, Ste. 402

Cincinnati, OH 45212

513-703-2569; 

Mcrotty@MKTassociates.com

15 Dong Ping Rd, Ste. 308, 

Shanghai 200031 PRC

Cell: 86 1391 723 9971 (China) Skype: 

www.mktassociates.com

Kevin S. Crutchfield, Chairman & CEO

Alpha Resources, Inc.

P.O. Box 16429, One Alpha Place

Bristol, VA 24212

276-619-4441 

kcrutchfield@alphanr.com

Christopher C. Curfman, President

Global Mining Division- Caterpillar

300 Hamilton Blvd., Suite 300

Peoria, IL 61629-3810 

309-675-5127; Fax: 309-675-4777

Curfman_christopher_c@cat.com

(John Disharoon ~ representative)

Stuart Dalton, Sr. Govt. Rep Generation

Electric Power Research Institute (EPRI)

3420 Hillview Avenue

Palo Alto, CA 94304

650-855-2467 

sdalton@epri.com

Jack Daly, Executive Vice President & Director

Fossil Power Technologies

Sargent & Lundy, LLC

55 East Monroe

Chicago IL 60603-5780

Jack.daly@sargentlundy.com

Michael R. DeLallo

Director/Power Business Group

Services and Consulting

CH2M Hill Engineers

11301 Carmel Commons Boulevard

Charlotte, NC 28226

704-544-4040; Direct: 704-543-3085

Cell: 610-507-5189

michael.delallo@ch2m.com

Edward (Ted) Doheny, II

President & CEO

Joy Global Inc.

100 E. Wisconsin Ave., Suite 2780

Milwaukee, WI 53202

(Skip Stephens ~ representative)

George Duggan

Vice President, Coal Marketing

BNSF Railway

2650 Lou Menk Dr., 2nd Floor

PO Box 961057 

Ft. Worth, TX 76131-2830

800-795-2673

George.duggan@bnsf.com

Michael D. Durham, President

Advanced Emissions Solutions

9135 S. Ridgeline Blvd., Suite 200

Highlands Ranch, CO 80129 

303-737-1727; Fax: 303-734-0330 miked@adaes.com

John Dwyer

7350 162nd Avenue, N.W

Bismarck, ND 58503

701-426-8660

johndwyer@bektel.com

John W. Eaves, President/CEO

Arch Coal, Inc.

1 CityPlace Dr., Ste. 300

St. Louis, MO 63141

314-994-2700; Fax: 314-994-2917 

jeaves@archcoal.com

George L. Ellis, President

Pennsylvania Coal Association

212 N. 3rd St, Ste 102

Harrisburg, PA 17101

717-233-7900 ext. 22; Fax: 717-231-7610

ellis@pacoalalliance.com www.pacoalalliance.com

Amy Ericson, U.S. Country President

ALSTOM, Inc.

801 Pennsylvania Ave NW #855

Washington, DC 20004

202-495-4971

Amy.ericson@alstom.com

Appendix E 3 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Alex G. Fassbender, CEO

Ecovia Corporation

2004 Byrd Rd

Vienna, VA 22182

703-229-9423 

alex.fassbender@ecoviacorp.com

Paul J. Feldman, Chairman

Midwest ISO

51 Warwick Stone Way

Great Falls, VA 22066

317-249-5400; Cell: 703-623-1762

PaulFeldman@gmail.com

Robert J. Finley, Director

Advanced Energy Technology Initiative

Illinois State Geological Survey

615 E. Peabody Dr.

Champaign, IL 61820-6964 

217-244-8389; Fax: 217-333-2830

finley@illinois.edu

John S. Fischer, CEO

Breakthrough Energy, LLC

1919 14th Street, Suite 609

Boulder, CO 80302

307-682-2529

jfischer@breakthrough-energy.net

David M. Flannery, Member

Steptoe & Johnson, PPLC

P.O. Box 1588, Charleston, WV 25326-1588

Chase Tower, 8th Fl., 707 Virginia St. East

Charleston, WV 25301 

304-353-8171; Cell: 304-539-1458 

Fax: 304-353-8183 

dave.flannery@steptoe-johnson.com

Sarah Forbes, Sr. Associate

World Resources Institute (WRI)

10 G St., NE, Ste. 800

Washington, DC 20002

202-729-7714; Fax: 202-729-7610

sforbes@wri.org

Mark Fraley Director/Coal Procurement

FirstEnergy Solutions Corporation

341 White Pond Drive

Akron, OH 44320

330-315-6767; Cell: 330-289-1513

fraleym@firstenergycorp.com

Robert D. Gabbard, President

PPL EnergyPlus, LLC

2 North 9th Street, GENPL7

Allentown, PA 18101

610-774-4168; Fax: 610-774-6523

RDGabbard@pplweb.com

Dr. Zhongxue Gan, Chief Executive Officer

ENN Intelligent Energy Group

Room 506, Bldg. B, South Xin’ao Science Park,

Xin Yaun St., Hua Lang Fang, China 065001 

86-316-259-7051; Fax: 86-316-259-5838 

ganzhongxue@enn.cn

Paul Gatzemeier

CBCC

7256 Hwy 3

Billings, MT 59106

406-245-8542; Cell: 406-696-9842 

paul.gatzemeier@earthlink.net

Clark D. Harrison

Sr. Mgr./Business Development

CH2M Hill

4697 Logan Ferry Rd

Murrysville, PA 15668

Cell: 412-916-9300 

Clark.Harrison@ch2m.com

William Hoback, Deputy Director

IL Office of Coal Development 

500 East Monroe

Springfield, IL 62701

217-785-2001; Cell: 217-836-4246

bill.hoback@illinois.gov

Clarence Joseph Hopf

Vice President Wholesale Origination

PPL EnergyPlus, 2 North 9th Street

Mail Code GENPL7

Allen Town, PA 18101

610-774-4548; Cell: 610-709-4451 

Fax: 610-774-5141

CJHOPF@pplweb.com

Marty Irwin, Director

IN Center for Coal Tech. Research

1 North Capital, Ste 600

Indianapolis, IN 46204 

317-232-8970

mirwin@oed.in.gov

Appendix E 4 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Daniel R. Jack, Sr. Vice President

Reschini Agency, Inc.

Laurel Place, 922 Philadelphia Street

Indiana, PA 15701 

724-349-1300 

danjack@reschini.com

Christopher P. Jenkins 

Vice President/Coal & Automotive 

CSX Transportation

500 Water Street

Jacksonville, FL 32202

904-366-5693; Fax: 904-359-3443

Chris_Jenkins@csx.com

Brian Kalk Ph.D., Chairman

North Dakota Public Service Commission

3208 Chisholm Trail

Bismarck, ND 58503

701-328-2400; Fax: 701-328-2410

bkalk@nd.gov - www.ndpsc.nd.gov

Michael Karmis

Virginia Tech, Mining & Mineral Engineering

100 Holden Hall

Blacksburg, VA 24061

540-231-7057; Fax: 540-231-4070

mkarmis@vt.edu

Norman Kettenbauer

Vice President Engineering & Contracting

GenPower Services LLC & Longview Power LLC

1375 Fort Martin Road

Maidsville, WV 26541

304-599-0930 Ext. 3034

Cell: 304-276-1101

Norman_Kettenbauer@genpower.net

Holly Krutka, Executive Editor

Cornerstone Magazine

Shenhua Science & Tech. Research Institute

7763 South Vine Street

Centennial, CO 80122

Cell: 303-588-4322

hkrutka@yahoo.com

Klaus Lambeck

Public Utilities Commission of Ohio

180 East Broad Street

Columbus, OH 43215-3793

614-764-1295 

Klaus.lambeck@puc.state.oh.us

David Lawson, Vice President, Coal

Norfolk Southern Corporation

3 Commercial Place

Norfolk VA 23510

dtlawson@nscorp.com

John T. Long, COO

Connemara Ltd.

10662 Misty Hill Rd

Orland Park, IL 60462

708-205-1930 

Jtlong11@gmail.com

Richard P. Lopriore, President

PSEG Fossil LLC

80 Park Plaza, T25A

Newark, NJ 07102-4194 

973-430-7533; Fax: 973-643-8229 

Richard.lopriore@pseg.com

Thomas Lorenzen, Partner

Dorsey & Whitney, LLP

1801 K St. NW, Ste. 750

Washington, DC 20006

202-442-3525; Fax: 202-442-3199

Lorenzen.thomas@dorsey.com

Jason Makansi, President

Pearl Street, Inc.

3963 Flora Place, 2nd Floor

St. Louis, MO 63110 

314-495-4545

jmakansi@pearlstreetinc.com

www.pearlstreetinc.com

Daniel T. Martin, Sr. Vice President

Sales/Customer Service

Ingram Barge Company

One Belle Meade Pl, 4400 Harding Rd.

Nashville, TN 37205-2290

615-298-8373; Fax: 615-298-8213

martind@ingrambarge.com

John S. Mead

Former Director

SIU Coal Research Center

11101 North Pomegranate Dr.

Oro Valley, AZ 85737

618-521-4270

jmead@siu.edu

Appendix E 5 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Emmanuel R. Merle, President

Energy Trading Company

15 East Putnam Avenue, #3210

Greenwich, CT 06830

203-618-0161; Fax: 203-618-0454

thion@mindspring.com

Jeffrey Miller, Production Services Manager Luxottica 

Retail

4199 Silver Streak Drive

Cincinnati, OH 45245

513-765-6678

Jmiller@luxotticaRetail.com

Rafic Y. Minkara

Vice President/Technology

Headwaters, Inc.

204 Lakeside Dr.

Kennesaw, GA 30144

770-330-0689 

rminkara@headwaters.com

Nancy Mohn, Director/Marketing Strategy

ALSTOM 

2000 Day Hill Road

Windsor, CT 06095

860-285-5748; Fax: 860-285-9991

nancy.c.mohn@power.alstom.com

Betsy B. Monseu, CEO

American Coal Council

1101 Pennsylvania Avenue, NW #600

Washington, DC 20004

202-756-4540

bmonseu@americancoalcouncil.org

Clark A. Moseley, President & CEO

The Morrow-Pacific Project/Ambre Energy

1211 SW Fifth Ave., Ste. 700

Portland, OR 97204

503-224-3352; Cell: 214-275-5785

c.moseley@ambreenergy.com

Michael G. Mueller

Vice President Energy Mgt. & Trading

Ameren Missouri

1901 Chouteau Avenue

St. Louis, MO 63103 

314-554-4174; Fax: 314-206-1250 

mmueller@ameren.com

Georgia Nelson, President and CEO

PTI Resources, LLC

401 N. Wabash Ave., #42A

Chicago, IL 60611

262-248-8373; Cell: 312-286-9393

geopti@aol.com

Kenneth J. Nemeth, Executive Director

Southern States Energy Board

6325 Amherst Court

Norcross, GA 30092

770-242-7712; Fax: 770-242-0421

nemeth@sseb.org

Mary Eileen O’Keefe, President & CEO

Lake Shore International, Ltd.

1362 N. State Parkway

Chicago, IL 60601

312-482-9701; Cell: 312-420-4094 

Fax: 312-482-9703 

maryeileenokeefe@aol.com

Jerry J. Oliver, President

Global Tech Management Services

9519 Tarrant Court

Houston, TX 77064

Cell: 832-661-5103

Jjoliver826@aol.com

Fredrick D. Palmer, Sr. Vice President

Peabody Energy

701 Market St.

St. Louis, MO 63101-1826

314-342-7624; Fax: 314-342-7614

fpalmer@peabodyenergy.com

Ronald W. Pircon, President/CEO

Benetech

2245 Sequoia Rd., Ste. 300

Aurora, IL 60506 

630-844-1300; Fax: 630-806-7253 

pirconr@benetechusa.com

Robert M. Purgert, President

Energy Industries of Ohio

Park Center Plaza, Suite 200

6100 Oak Tree Blvd.

Independence, OH 44131 

216-643-2952; Fax: 216-643-2901 

purgert@energyinohio.com

Appendix E 6 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

Randall L. Rahm, President

CoalTech Consultants, Inc.

6800 NE Indian Creek Rd.

Topeka, KS 66617 

785-249-3981; Fax: 785-246-0959 

rrahm1@cox.net

Massood Ramezan, PhD, PE

Sr. Technical Advisor/Div. Director

Leonardo Technologies Inc. (LTI)

M/S B922, P.O. Box 10940 

Pittsburgh, PA 10940

412-386-6451: Cell: 724-554-3596

mramezan@lti-global.com

William Raney, President

West Virginia Coal Association

PO Box 3923

Charleston, WV 25339

304-342-4153 

braney@wvcoal.com

Bill Reid, Managing Editor

Coal News

106 Tamarack Street

Bluefield, WV 24701-4573

304-327-6777; Fax: 304-327-6777

billreid007@comcast.net

Frederick M. Reuter, III

21 East 11th St.

Covington, KY 41011

859-291-7044; Fax: 859-291-1939

Fmreuter3@fuse.net

Todd Savage

Executive Vice President/Group Leader

Savage Companies

901 W. Legacy Center Way

Midvale, UT 84047

801-944-6600

info@savageservices.com

www.savageservices.com

Mark Schoenfield, Sr. VP/Operations

Jupiter Oxygen Corporation

4825 North Scott Street, Ste. 200

Schiller Park, IL 60176

219-712-5206; Fax: 847-928-0795

M_schoenfield@jupiteroxygen.com

Debra L. Schumacher, President

Women In Mining

915 Mayfair Dr.

Booneville, IN 47601-2319

812-749-0040 

wolfie66@msn.com

dschumacher@peabodyenergy.com

John J. Siegel, Chairman

Bowie Resource Partners, LLC

6100 Dutchmans Lane, 9th Floor

Louisville, KY 40205

502-584-6022; Fax: 502-587-6579

www.bowieresources.com

Michael J. Sierra, President

The Ventura Group, Inc.

44675 Cape Court, Unit 150

Ashburn, VA 20147

703-208-3303; Fax: 703-208-3305

msierra@theventuragroup.com

Michael G. Sorensen

Sr. Mgr. Fuel & Water Resources

Tri-State Generation & Transmission Assn., Inc.

P.O. Box 33659

Denver, CO 80233-0695

303-254-3208; Cell: 303-229-5039

mgsorensen@tristategt.org

William J. Spengel, Sr. VP/Fossil Operations

URS – Washington Division

510 Carnegie Center

Princeton, NJ 08540

609-720-2560; Cell: 609-937-2902

Fax: 609-720-2280

bill.spengel@wgint.com

David F. Surber

Syndicated Environmental TV Journalist 

PO Box 15555

Covington, KY 41015-0555

859-491-5000; Fax: 859-291-5000

surber@surber.com

Daniel Thompson

Vice President and General Manager

Dynegy Midwest Generation, LLC

604 Pierce Boulevard

O’Fallon IL 62269

618-206-5918

Daniel.P.Thompson@dynegy.com

Appendix E 7 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

John W. Thompson, Director

Fossil Transition Project, Clean Air Task Force

705 W. Main St., Suite 101

Carbondale, IL 62901

618-457-0137; Cell: 618-203-6233

Fax: 618-457-0513

jthompson@catf.us;

www.catf.us; www.fossiltransition.org

Pamela Tomski, Sr. Advisor

Policy and Regulatory, The Americas

Global CCS Institute

1358 Perry Place NW

Washington DC 20010

202-390-8896

ptomski@mac.com

David D. Turnbull, CEO

Hillsborough Resources Limited

1090 W. Georgia St., Suite 950

Vancouver, BC V6E 3V7 Canada

604-684-9288 ext. 222; Cell: 604-910-1845

US Cell: 304-859-7588 

ddt@hillsboroughresources.com

Daman S. Walia, President/CEO

ARCTECH, Inc.

14100 Park Meadow Dr.

Chantilly, VA 20151

703-222-0280 

dwalia@archtech.com

www.archtech.com

Kathy Walker, President

Elm Street Resources, Inc.

P.O. Box 1718

Paintsville, KY 41240

606-789-4036 Ext. 14

kwelmst@bellsouth.net

Jeffrey L. Wallace

Vice President Fuel Services

Southern Company Services

6000 North 18th St., 14N-8160

Birmingham, AL 35203

205-257-6111

jlwallac@southernco.com

Kathy Walton, Principal

The Basic Industries Group, LLC

1407 Second Ave., Suite 3A

New York, NY 10021 

917-836-2000

kwalton@thebasicindustries.com

Richard M. Whiting, President

Kinder Morgan Resources, LLC

7733 Forsyth Blvd., Suite 1100

St. Louis, MO 63105

Richard_Whiting@kindermorgan.com

Jennifer Wilcox, Assistant Professor

Stanford University/Energy Resources Engineering

367 Panama Street

Stanford, CA 94305

650-724-9449; Fax: 650-725-2099

wilcoxj@stanford.edu

www.cec-lab.stanford.edu

Robert Williams

Sr. Research Scientist & Associated Faculty

Princeton Environmental Institute

Princeton University

140 Guyot Hall, Washington Road

Princeton, NJ 08544

609-258-5448

rwilliam@princeton.edu

Kemal Williamson, President, Americas

Peabody Energy

701 Market Street, Suite 1400

St. Louis, MO 63101

kwilliamson@peabodyenergy.com

Gregory A. Workman, Director/Fuels

Dominion Resources

120 Tredegar Street – DC3

Richmond, VA 23219 

804-787-5702

greg.workman@dom.com

Appendix E 8 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

NCC STAFF

Janet Gellici, Executive Vice President/COO

1730 M Street NW, Ste. 907

Washington, DC 20036

202-223-1191; Cell: 602-717-5112

Fax: 202-223-9031

jgellici@NCC1.org

Hiranthie Stanford

Membership & Meetings Manager

1730 M Street NW, Ste. 907

Washington, DC 20036

Cell: 202-765-4349

Fax: 202-223-9031

hstanford@NCC1.org

LEGAL COUNSEL

Karen Bennett, Counsel

Hunton & Williams LLP

2200 Pennsylvania Ave. NW

Washington, DC 20006

202-955-1958; Fax: 202-828-3743

kbennett@hunton.com

Appendix E 9 | Page
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX F

Dissenting Opinion

Appendix F
May 29, 2014

The Honorable Dr. Ernest Moniz

U.S. Secretary of Energy

U.S. Department of Energy

1000 Independence Avenue, SW

Washington, D.C. 20585

RE:   Reasons for My Dissenting Vote on the National Coal Council Report  

“Reliable & Resilient, The Value of Our Existing Coal Fleet: An Assessment of Measures

to Improve Reliability & Efficiency While Reducing Emissions”

Dear Mr. Secretary:

The National Coal Council’s report, “Reliable & Resilient, The Value of Our Existing Coal Fleet:

An Assessment of Measures to Improve Reliability & Efficiency While Reducing Emissions” (“NCC

Report”) provides some valuable information on the importance of the U.S. coal fleet and the

challenges it faces. But in other respects it is non‐responsive to the charge you made to the group,

namely to address the question: “What can industry and the Department of Energy, separately and

jointly, do to facilitate enhancing the capacity, efficiency and emissions profiles of the existing coal

generation fleet in the United States through application of new and advanced technology?” Instead,

the Report too often describes what the industry believes can’t be done, rather than what we can

and must do, to achieve reliable baseload generation as well as the public health and climate

objectives that are central to our country’s healthy future. I do not consider the Report responsive to

your charge, and for that reason, and as more specifically detailed in this letter, I dissented from the

vote adopting this Report at the last National Coal Council meeting.  

Our world is changing now – significant damage already is occurring as a result of climate

change caused by manmade emissions of greenhouse gases. As the National Climate Assessment

notes, “Global climate is changing and this is apparent across the United States in a wide range of

observations. The global warming of the past 50 years is primarily due to human activities,

predominantly the burning of fossil fuels.”1 This is the context within which continued reliance on

the existing coal fleet must be considered.

In order to ensure that the U.S. can continue to rely on fossil fuels for baseload electricity

generation, currently available and new greenhouse gas controls – particularly carbon capture and

sequestration, the best developed such control for the power sector – must be rapidly advanced. But

the NCC Report belittles the viability of carbon capture and storage (“CCS”) technology today. It

omits solutions that could speed the retrofit of CCS technology now on many plants in the existing

fleet, and as a result, fails to describe the potential long‐term value of the existing coal fleet in

advancing the President’s climate objectives. Moreover, the Report also shortchanges the significant

public health benefits to be realized by a modernized, better‐controlled existing coal fleet. It is not

enough to say that uncontrolled coal plants have historically provided inexpensive baseload power,

without also discussing the public health costs associated with that historical behavior. Nor is the

Polar Vortex event sufficient justification for the industry to avoid its obligations to achieve required

																																																								

1	U.S.	National	Climate	Assessment,	US	Global	Change	Research	Program,	Climate Change Impacts in the United

States, May	2014,	15.
2

further public health and climate improvements. Indeed, the NCC Report in many places seems

purposely intended to undermine such continued improvements, containing misleading assertions

about the Polar Vortex event. Mr. Secretary, I won’t detail in this letter each and every factual point I

disagree with in the NCC Report, but I will lay out below my concerns about several significant issues

that led me to vote “no” on forwarding the NCC Report to you.  

1. CCS Technology is Available and Adequately Demonstrated for New and Retrofit

Applications

Retrofitting CCS on existing fossil fuel‐fired power plants ‐‐ particularly on the existing coal

fleet, which is the subject of the NCC Report, is essential if the worst climate change impacts are to

be avoided. And this is possible. A 2011 DOE NETL study found that 85 percent of the existing coal

fleet was potentially suitable for CCS retrofit.2  

By contrast, the NCC Report makes several erroneous findings about CCS including that it

“has yet to be demonstrated,” is not currently a “viable technology,” that EOR storage and carbon

saline sequestration have limited knowledge base and that “12 large scale carbon capture projects

are needed to adequately demonstrate CCS.”3

These statements are incorrect, and they seem purposely intended to undermine the

Environmental Protection Agency’s (“EPA’s”) efforts to set meaningful new and existing source

performance standards based in some part on this technology. In fact, “adequately demonstrated” is

a legal term of art under the Clean Air Act, and CCS technology more than meets this standard.4

“Adequately demonstrated” does not require that twelve existing sources deploying a particular

control technology be in existence before that technology can form the basis for a performance

standard;5 or even that the technology be in active use in the industry at the time of the

rulemaking.6 Instead, the EPA Administrator is to look at the state of technology now and out to the

future, to make a reasonable projection of availability of controls in setting standards for a particular

industry.7

																																																								

2	Global	CCS	Institute,	“What	to	do	with	existing	coal‐fired	electricity	generation	plants”	(Nov.	8,	2013),	available at:

http://www.globalccsinstitute.com/insights/authors/davidhanly/2013/11/08/what‐do‐existing‐coal‐fired‐

electricity‐generation‐plants.	

3	NCC	Report	at	6,	89.	

4	Performance	standards	for	stationary	sources	are	set	to	reflect	“the	degree	of	emission	limitation	achievable	

through	the	application	of	the	best	system	of	emission	reduction	which	(taking	into	account	the	cost	of	achieving	

such	reduction	and	any	nonair	quality	health	and	environmental	impact	and	energy	requirements)	the	

Administrator	determines	has	been	adequately demonstrated.”	42	U.S.C.	§	7411(a)(1)	(emphasis	added).	

5 Nat’l Asphalt Pavement Ass’n v. Train, 539	F.2d	775,	785‐86	(D.C.	Cir.	1976).	

6 See Portland Cement v. EPA (Portland Cement I),	486	F.2d	375,	391	(D.C.	Cir.	1973).	

7 Portland Cement I,	486	F.2d	at	391‐92	(citing	and	quoting	Int’l Harvester v. Ruckelshaus,	478	F.2d	615,	629	(D.C.	

Cir.	1973)).	My	specific	views	on	CCS	readiness	for	new	sources	within	the	fossil‐fuel	fired	power	plant	fleet	are	

detailed	in	comments	submitted	by	the	Clean	Air	Task	Force	in	the	docket	for	EPA’s	proposed	111(b)	CO2	emission	

limits.	See	Doc.	No.	EPA‐HQ‐OAR‐2013‐0495‐9664.
3

As you well know, integrated CCS systems are now, and will be available for commercial

application on existing coal‐fired power plants. Further, the component elements of these systems

have been in long‐standing use in other similar industrial applications in the U.S. and abroad. Several

CCS retrofit projects are moving forward, many of which the NCC Report outlines. The Report,

however, downplays the significance of these projects calling them limited in scope or in authentic

experience.   See NCC Report at Appendix B. But, the Clean Air Act allows ‐‐ even demands ‐‐ EPA to

“extrapolat[e] . . . a technology’s performance in other industries,” and look beyond domestic

facilities to those used abroad.8  The Global CCS Institute maintains a list of integrated CCS projects,

including a number of current retrofit CCS projects on coal and gas fired power plants.9

  

The NCC Report fails to mention decades of commercial CCS experience in industrial settings

such as natural gas cleaning, refinery operations and fertilizer production. It fails to mention CCS

experience on flue gas from burning natural gas. It fails to describe decades of pre‐combustion

capture experience in coal gasification settings. As a result, the Report fails to consider the

transferability of this extensive expertise and experience to the power sector and the coal sector in

particular.

These omissions are material and contribute significantly to the NCC Report’s failure to

respond to your charge by accurately describing CCS as ready now for deployment on existing coal

plants, and then discussing what steps need to be taken to facilitate that process.  

If we are to meet the President’s climate goals, our country must move towards controlling

the carbon emissions from the existing power plant fleet now, including through CCS retrofits in

appropriate situations. Two changes must take place. First, regulations must signal that CO2

reductions from the existing fleet are required, and second, new or expanded financial programs

must be established to help pay for the needed retrofits. These conditions are explored below.

a. Regulations to Support CCS Deployment

Next week, EPA will announce new CO2 emission restrictions aimed at curbing the existing

power plant’s emissions under 111(d). It is important to note that the U.S. is not alone in establishing

coal‐fired power plant emission restrictions. In 2012, Canada finalized regulations that set new CO2  

																																																								

8 Lignite Energy Council v. EPA, 198	F.3d	930,	933‐34	&	n.3	(D.C.	Cir.	1999).	

9	Global	CCS	Institute,	“Large‐Scale	Integrated	CCS	Projects,”	http://www.globalccsinstitute.com/projects/browse.	
4

emission limits for both existing and new coal plants.10 And a retrofit CCS project on an existing coal

fired power plant is scheduled to begin operations in 2014.11  

The importance of EPA regulations limiting CO2 to a utility’s ability and willingness to

undertake CCS as a control option is illustrated by the July 2011 statements of AEP’s then‐CEO Mike

Morris, about the company’s decision to table efforts to advance CCS on the Mountaineer power

plant after failing to win approvals from the state’s economic regulators.12

“We are clearly in a classic ‘which comes first?’ situation,” Morris said. “The

commercialization of this technology is vital if owners of coal‐fueled generation are to comply

with potential future climate regulations without prematurely retiring efficient, cost‐effective

generating capacity. But as a regulated utility, it is impossible to gain regulatory approval to

recover our share of the costs for validating and deploying the technology without federal

requirements to reduce greenhouse gas emissions already in place. The uncertainty also

makes it difficult to attract partners to help fund the industry’s share.”

DOE can play an important role in working with EPA, sharing its experience with Mountaineer

and other projects to ensure that EPA’s final performance standard rules and guidelines can enable

power companies to justify retrofits on existing plants to both investors and regulators.  

																																																								

10	On	September	12,	2012,	Canada’s	Minister	for	the	Environment	published	final	CO

2	

performance	standards	

applicable	to	both	new	coal‐fired	EGUs	and	to	coal‐fired	units	that	have	reached	the	end	of	their	useful	lives.	

Reduction of Carbon Dioxide Emissions from Coal‐fired Generation of Electricity Regulations, SOR/2012‐167	§§	3(1),	

2	(definitions	of	“old	unit”	and	“useful	life”),	146	C.	Gaz.	II,	19	(Sept.	12,	2012)	available at:	

http://www.gazette.gc.ca/rp‐	pr/p2/2012/2012‐09‐12/html/sor‐dors167‐eng.html	[hereinafter,	“Canadian	

Rule”].	The	standard,	promulgated	under	the	Canadian	Environmental	Protection	Act	of	1999,	is	set	at	an	emissions	

rate	of	420	metric	tons	per	gigawatt	hour	(GW‐	hr),	a	rate	equivalent	to	925.10	lbs/MWh	(partial	net),	comparable	

to	EPA’s	proposal.	The	Environment	Ministry	states	that	this	rate	is	based	on	“the	emissions	intensity	level	of	NGCC	

technology,”	Backgrounder	2012‐09‐05,	Canadian	Rule,	available at:	

http://www.ec.gc.ca/default.asp?lang=En&n=5C4438BC‐1&news=D375183E‐0016‐4145‐	A20B‐272BDB94580A.	

The	Canadian	Rule	provides	for	a	temporal	exemption	until	2025,	which	may	be	sought	by	new	and	end‐of‐life	units	

that	use	CCUS	technologies	to	meet	the	performance	standard.		

11	The	Boundary	Dam	project,	in	Saskatchewan,	will	retrofit	post‐combustion	capture	to	a	110	MW	existing	coal‐

fired	electric	generating	unit	(EGU)	(Unit	3	at	Boundary	Dam	Power	Station).			SaskPower,	“Boundary	Dam	

Integrated	Carbon	Capture	and	Storage	Demonstration	Project,”	

http://www.saskpower.com/sustainable_growth/assets/clean_coal_information_sheet.pdf.		It	is	scheduled	to	begin	

commercial	operation	in	2014,	and	will	sequester	through	enhanced	oil	recovery	operations	approximately	90	

percent	of	the	CO2 from	the	110	MW	unit	or	approximately	1	million	tons	per	year.

12	“AEP,	“AEP	Places	Carbon	Capture	Commercialization	On	Hold,	Citing	Uncertain	Status	Of	Climate	Policy,	Weak	

Economy,” AEP News Release,	July	11,	2014.	
5

b. Costs of CCS Retrofits Need Not and Must Not Be a Barrier to CCS Deployment

The NCC Report does discuss technology innovation to lower costs and improve performance,

but in so doing fails to note that although ensuring that new plants install new technology is

important, that does not mean that existing coal plants should not also begin to install CCS

technology now.13 Indeed, while the Report correctly notes that the past few decades have seen

rapid advancement in conventional pollution controls on this industry, and corresponding rapid and

deep reduction in pollutants like SO2, NOx, and particulate matter, it does not at the same time

accurately assess the potential for the same trajectory for carbon pollution reductions from this

industry. Indeed, the NCC Report tends to describe the role of CCS in the existing fleet as some

distant event that takes place after many decades and much technology innovation. In fact, deep

reductions occurred with some speed from the point at which the retrofit technology was available

for installation (as CCS technologies are today). During the first 25‐year time period that started in

1980, sulfur emissions dropped 30 percent, mostly as utilities switched from high‐sulfur coals to low‐

sulfur coals. Scrubbers were installed during this 25‐year period, but the dominant control measure

was fuel switching. In 2005, sulfur emissions fell an additional 30 percent, but this time the reduction

was achieved in only 5 years – and it was due to wide installation of scrubbers on the existing US coal

fleet. Where we were in the early 2000s is close to where we are today with CCS technologies, for

existing facilities located near sequestration resources.

Retrofitting existing coal‐fired power plants may be a least cost option for avoiding the worst

effects of climate change. Contrary to the NCC Report’s assertion,14 the capital cost of CCS retrofits is

not a barrier to their deployment. Construction and operating costs associated with CCS technologies

will decrease as further experience with them is gained in response to the standard.15 This is

supported by statements that SaskPower plans to retrofit additional units with CCS after Boundary

Dam and expects the next retrofit will cost 30 percent less in capital costs and 20 percent less in

operating costs.16  

																																																								

13	Under	the	Clean	Air	Act,	EPA’s	standards	must	be	“reasonably	reliable,	reasonably	efficient,	and	.	.	.	reasonably	.	.	.	

expected	to	serve	the	interests	of	pollution	control	without becoming exorbitantly costly in an economic or

environmental way.”	Essex Chemical Corp. v. Ruckelshaus, 486	F.2d	427,	433	(D.C.	Cir.	1973)	(emphasis	added).	A	

standard	that	promotes	some	CCS	retrofits	on	existing	coal‐fired	power	plants	meets	this	directive.

14	NCC	Report	at	82.	

15 See generally Nicholas	A.	Ashford,	et	al.,	“Using	Regulation	to	Change	the	Market	for	Innovation,”	9	Harv.	L.	Rev.	

419	(1985)	(providing	several	examples	of	industry	response	to	new	regulation	where	the	industry	creates	new	

technology	and	a	market	niche	yet	product	change	occurs	rapidly	as	technology	improves	in	order	to	compete	on	

the	basis	of	price).	See also	Margaret	R.	Taylor,	et	al.,	“Regulation	as	the	Mother	of	Innovation:	The	Case	of	SO2	

Control”	27	Law	&	Pol’y	348	(Apr.	2005)	(using	the	history	of	SO2	control	to	show	that	increased	diffusion	of	

technology	results	in	significant	and	predictable	operating	cost	reduction	in	existing	systems,	as	well	as	notable	

efficiency	improvements	and	capital	cost	reductions	in	new	systems).	

16	Graham	Lanktree,	“Nothing	Ventured,	Nothing	Recovered:	SaskPower’s	Boundary	Dam	Project	a	Test	Case	for	

Carbon	Capture	and	Storage,”	CIM	Magazine	(Mar./Apr.	2014),	available at:	

http://magazine.cim.org/en/2014/March‐April/special‐report/Nothing‐ventured‐	nothing‐recovered.aspx;	See e.g.

also,	Meg	Alexander,	“Refrigeration	Could	Cool	Down	Costs	of	Carbon	Capture	and	Storage,”	GizMag	(Apr.	22,	2014),	

available	at:	http://www.gizmag.com/sintef‐refrigeration‐carbon‐capture‐storage/31718/.	“New	research	by	

Scandinavian	research	organization	Sintef	has	found	that	refrigeration	technology	may	reduce	costs	[of	CCS]	by	up	

to	30	percent,	increasing	the	potential	for	faster	implementation.”	Id.
6

Moreover, the costs of existing CCS technology can be managed with a series of incentives –

and the Department of Energy can be instrumental in this regard. In combination with EPA 111(d)

standards, incentives could make retrofit existing coal plants attractive to some power companies.

These incentives include:

• Tax‐exempt financing. Tax‐exempt financing played a central role in deploying coal‐fired

power plant conventional pollution controls such as scrubbers and NOx controls. If significant

tax‐exempt financing were to be made available for CCS retrofits, it could lower the cost of

capital by 2 percent or more. Given that CCS technology is inarguably capital intensive for

both coal and gas plants, such a lower interest rate, coupled with longer repayment times,

could reduce LCOE by tens of $/MWh on both coal and gas equipped with CCS. DOE could

draw upon its decades of understanding how tax‐exempt financing played a key role in

pollution control deployment in the past to identify the kinds of financing programs to

advance CCS retrofits.

• EOR incentives. Revenue generated by the sale of captured CO2 for use in enhanced oil

revenue significantly reduces costs associated with CCS. Whether implemented on a new

plant or as a retrofit, using EOR to sequester the captured carbon dioxide can add as much as

$40/ton in revenue to a CCS project. Incentives for using anthropogenic CO2 in EOR could add

to this amount, lowering LCOE of CCS equipped coal and gas plants. Depending on the scale

of the program, these incentives could be worth tens of $/MWh on both coal and gas CCS

plants. Working together, industry and DOE could help identify options for these incentives

that are both affordable and increase domestically produced transportation fuels.

Further, the NCC Report overlooks some key cost advantages of the existing fleet with

respect to CCS retrofits. These include that the existing fleet is extensive and already largely fully

paid for and depreciated. And, the time it takes to retrofit an existing plant is much shorter than the

time needed to build a new plant with CCS. While challenged by advancing age and competition

from abundant, low cost of natural gas, incentives can help overcome these challenges to speed CCS

retrofits on existing plants.

c. Compliance with Subpart RR Will Not Deter EOR Operators from Purchasing Captured CO2

The NCC Report asserts that there is uncertainty surrounding whether electric generating unit

operators, if they are required to demonstrate that captured CO2 is sent to a facility reporting under

Clean Air Act Greenhouse Gas Reporting Rule subpart RR, will choose the cost advantageous EOR

sequestration.  NCC Report at 10, 88. While some EOR operators have baldly asserted that if they are

required to comply with subpart RR, that would cause them to avoid the purchase of captured CO2, I

do not agree.

First, it is not inconsequential that available sources of naturally mined CO2 are declining, and

that there is therefore a significant demand for anthropogenic CO2 in this industry.17 Specifically, a

																																																								

17 See V.	Kuuskraa,	Advanced	Resources	International,	Inc.,	“Using	the	Economic	Value	of	CO2‐	EOR	to	Accelerate	

the	Deployment	of	CO2	Capture,	Utilization	and	Storage	(CCUS),”	in	Proceedings from the 2012 CCS Cost Workshop,

Global CCs Institute (April	25‐26	2012)	at	slide	9,	available at

http://cdn.decarboni.se/sites/default/files/publications/100356/proceedings‐	2012‐costs‐workshop.pdf.	
7

2012 analysis found that the economic demand is for 25 billion metric tons of CO2, as compared with

current available volumes of about 3 billion metric tons from natural resources, and existing natural

gas processing facilities.18 The additional anthropogenic CO2 supply is estimated to represent a $1

trillion market (less costs of CO2 transportation). It seems unlikely that existing operators would

prefer to go out of business rather than access this market, simply because of the need for better

reporting of the amounts of CO2 managed in EOR activity.

Second, the costs of opting in to subpart RR reporting by an existing EOR operator with a

Class II permit are simply not significant, particularly when compared to the potential revenue from

the sale of the produced oil, a calculation EPA performed in the Economic Impact Analysis for the

Subpart RR rules.19 When EPA compared the average annualized costs of meeting the RR

requirements at an EOR field with a Class II UIC permit, to the estimated revenue per field, the

resulting “cost/sales ratio” ranged from 3.1‐4 percent.20 The cost per field is estimated to be on the

order of $2 million dollars per year for the full monitoring and reporting program. As compared not

just with the expected revenue to the operator, but also the cost to the environment of

unmonitored, unreported (and therefore unknown and unchecked) CO2 leakage to the atmosphere,

this cost is reasonable.

2. The Long‐Term Value of the Existing Coal Fleet is Inextricably Linked to Providing Low‐

Carbon Base Load Power Through CCS Retrofits.

The NCC Report correctly notes that the historical value of the existing coal fleet has been

providing low cost, base load power. This role is the basis for the NCC Report’s many descriptions of

coal’s economic benefits to the US economy. But uncontrolled coal plants also present costs to the

economy, in the form of public health and climate damage.21 If the existing coal fleet is to continue

to provide this base load function for many decades to come, we must adjust its mission to the new

reality – which is the implementation of long‐overdue conventional air pollution controls, and action

to address coal plants’ contribution to the damage caused by global warming pollution.

Specifically, the existing coal fleet must, over time, be retrofit with CCS to provide the United

States with a backbone of sustainable, low‐carbon base load power. This backbone should not be

limited to just coal with CCS, but must include gas power plants with CCS controls, and nuclear

power too, if we are to achieve our climate objectives and maintain the reliable electricity system we

have enjoyed to date.

An “all of the above” approach to providing this reliability can enable deep CO2 cuts by mid‐

century, which otherwise will be significantly impaired and needlessly costly. Low‐carbon base load

																																																								

18 Id.

19 See	75	Fed.	Reg.	75,060,	75,072‐75,074	(Dec.	10,	2010)	&	Economic	Impact	Analysis	for	the	Mandatory	Reporting	

of	Greenhouse	Gas	Emissions	Subpart	RR:	Proposed	Carbon	Dioxide	Injection	and	Geologic	Sequestration	Reporting	

Rule,	EPA‐HQ‐OAR‐	2009‐0926‐0830	§§	4.5‐4.10,	5.3‐5.4,	Tables	5‐8	&	5‐9.	

20 Id. §	5.4,	Tables	5‐8	&	5‐9.	

21 See, e.g. Clean	Air	Task	Force,	Power	to	Kill:	Death	and	Disease	from	Power	Plants	Charged	with	Violating	the	

Clean	Air	Act,	(July	2001),	available at:	http://www.catf.us/resources/publications/files/Power_to_Kill.pdf.	
8

power reduces total system integration costs for clean, variable resources such as wind and solar.

Integration includes several items: profile costs (to accommodate the fluctuating output of

intermittent sources), balancing costs (to address output uncertainties) and grid costs. As wind and

solar reach higher levels of system penetration, these costs become more significant. One European

study estimates the integration costs of wind above 20 percent system penetration exceed the cost

of generating electricity from wind.22 In another study, Idaho Power estimates the cost of integrating

wind at 11 percent penetration at 17 dollars/MWH and 16 percent penetration at 50 dollars/MWH.

23 Other studies report lower integration costs, but integration in these studies does not include the

costs of back‐up capacity.  

“All of the above” is more than just a slogan for describing a path for achieving GHG

reductions. It allows the electric system as a whole to be optimized. CCS retrofits on the existing fleet

provide an essential element of this approach – allowing wind and solar resources to be integrated

within an important, but likely range of 25‐30 percent within the system. And it supports continued

system reliability.

The NCC Report, however, diverts attention from this function of the existing coal fleet,

instead repeating warnings about a future in which the existing fleet is better controlled for both its

conventional and its climate pollution emissions. These statements are misleading. While I do not

mean to minimize the important role played by the existing coal fleet in assuring system reliability

during the recent Polar Vortex event, that experience does not justify failing to continue to move

forward with needed modernization and additional pollution controls.

3. The Polar Vortex Does Not Justify Weakening Environmental Regulations in an Attempt to

Preserve Small, Aging Coal Plants.  

In January and February 2014, the Polar Vortex, a weather phenomenon generally confined

to the Arctic, made its way into much of North America. The extreme weather increased demand on

our electric system and older coal plants, some of which are scheduled for retirement, were relied

on heavily. The NCC Report takes the position that “[o]nly the availability and operation of coal units

now scheduled for retirement over the next two years enabled the power sector to meet demand

during periods of harsh weather events,” and that “the U.S. power grid is less resilient than

previously believed.” NCC Report at 16.This is an overstatement. Terry Boston, President and CEO of

PJM, the world’s largest competitive wholesale energy market, recently stated:  

...we are still in the midst of the largest fuel switch in history and managing the

retirement of 26,000 megawatts of coal generation – largely being replaced by new

natural gas plants, demand response and transmission upgrades. Many remain

skeptical about this fuel transition, but PJM and our members are navigating this

challenge. Next year our reserve margins will be tighter, but the PJM system will be

reliable – meeting all NERC standards.24

																																																								

22	Falko	Ueckerdt,	et.al,	System LCOE: What are the Costs of Variable Renewables? Paris,	32th	International	Energy	

Workshop,	June	20,	2013.		

23	Idaho	Power,	Wind	Integration	Study	Report,	February	2013.	
9

MISO, the regional transmission organization serving the Midwest also recently reported that

it will meet demand in the coming years.25  

Further, older coal plants were only relied upon during the Polar Vortex event because of an

unusual number of exceptional events occurring at other plants.26 These events were generally

weather‐related, operational, and mechanical failures and will be fixed going forward.27 Grid

operators will require testing to ensure that plants will not have difficulty coming online after

periods of dormancy.28 They will also improve generator availability and performance during

extreme weather events; implement performance verification or testing of generation in advance of

winter operations; implement market mechanisms that encourage better generator availability, such

as incentives for ensuring fuel availability or dual‐fuel capability; and review the cost allocation for

uplift charges and investigate a mechanism to allocate uplift costs during emergency operations that

minimizes volatility.29

Additionally, even though there was sufficient natural gas to meet demand, procurement

practices stalled effective market response.30 FERC is currently proposing a series of "small market

fixes" to lessen the volatility in the price of electricity and natural gas during extreme cold events.31

The proposed orders will better coordinate the scheduling of natural gas and electricity markets in

light of increased reliance on natural gas for power generation.32

																																																																																																																																																																																												 24	Terry	Boston,	President	and	CEO,	Prepared	Remarks	at	the	PJM	Annual	Meeting	(May	15,	2014)	available at:	

http://www.pjm.com/~/media/documents/presentations/20140515‐terry‐boston‐2014‐annual‐meeting‐

prepared‐remarks.ashx.	See also	PJM	Interconnection,	Analysis of Operational Events and Market Impacts During the

January 2014 Cold Weather Events,	(May	8,	2014),	available at:	

http://www.pjm.com/~/media/documents/reports/20140509‐analysis‐of‐operational‐events‐and‐market‐

impacts‐during‐the‐jan‐2014‐cold‐weather‐events.ashx	(explaining	that	grid	reliability	was	maintained).	

25	MISO,	Press	Release,	“MISO	Clears	Second	Annual	Capacity	Auction”	(Apr.	15,	2014)	available at:	

https://www.misoenergy.org/AboutUs/MediaCenter/PressReleases/Pages/MISOClearsSecondAnnualCapacityAuc

tion.aspx.	

26	John	Moore	and	Allison	Clements,	Sustainable	FERC	Project,	“The	Polar	Vortex	and	the	Power	Grid:	What	Really	

Happened	and	Why	the	Grid	will	Remain	Reliable	without	Soon‐to‐Retire	Coal	Plants,”	(Apr.	29,	2014)	available at:	

http://sustainableferc.org/the‐polar‐vortex‐and‐the‐power‐grid‐what‐really‐happened‐and‐why‐the‐grid‐will‐

remain‐reliable‐without‐soon‐to‐retire‐coal‐plants/.	

27 Id.		

28 Id. 29	PJM	Interconnection,	Analysis of Operational Events and Market Impacts During the January 2014 Cold Weather

Events,	(May	8,	2014),	available at:	http://www.pjm.com/~/media/documents/reports/20140509‐analysis‐of‐

operational‐events‐and‐market‐impacts‐during‐the‐jan‐2014‐cold‐weather‐events.ashx

30 Id.

31	Rod	Kuckro	and	Hannah	Northy,	“Federal	Regulators	Aim	to	Fix	Power	Markets	by	Next	Winter,”	Energywire	

(Apr.	3,	2014)	available at:	http://www.eenews.net/energywire/stories/1059997226	

32	Coordination	of	the	Scheduling	Processes	of	Interstate	Natural	Gas	Pipelines	and	Public	Utilities,	79	Fed.	Reg.	

18,223	(Apr.	1,	2014)	(Notice	of	Proposed	Rulemaking).		
10

The NCC Report further makes several misleading statements that distort the effect and

lessons of the Polar Vortex:

 The Report compares the sources of electricity generation in 2012 and 2013 with 2014,

however 2012 was the warmest winter in 80 years, resulting in very low gas prices and

low coal generation. NCC Report at 11‐12. Using 2012, and to a lesser extent 2013, as a

basis for comparison with the very cold winter of 2014 will yield incorrect conclusions

with respect to coal generation and gas prices.33

 The Report cites America Electric Power’s claim that “[n]atural gas delivery is challenged.

NCC Report at 13. However, the high prices and limitations on gas delivery to gas‐based

generation with interruptible service occurred in a limited number of locations on only a

few days in 2014.34 Of course, average values for January and February will reflect

broader factors than the short‐term weather events.  

 Gas storage refill rate is not dependent on "coal‐to‐gas" switching. NCC Report at 11‐12.

Rather gas gets dispatched in the power sector based on demand and price.35 The gas

availability for injection into the transmission system is primarily related to weather

dependent gas demand (e.g., winter heating capacity available for injection in the

summer).

 The NCC Report also claims “the capacity factor of America's coal plants averages almost

70% while many gas plants could not get fuel this winter and will continue to be replaced

by coal throughout the year." NCC Report at 13‐14. Gas supply, however, was interrupted

only for a matter of days – and certainly not for the rest of the year.36

While the Polar Vortex called attention to fixable flaws in the power system, it did not, as the

NCC Report concludes, render essential the future reliance on coal plants that are now set for

retirement. The NCC Report notes that those plants scheduled for retirement in the coming years are

about 145 MW in size with a heat rate of 10,398.37 These are small, older units. The more enduring

contribution the existing coal fleet can make is through larger units retrofit with CCS. These retrofit

units can provide a more lasting option to address extreme weather events. During normal

operations, these retrofitted coal units would capture CO2 and keep it from reaching the

atmosphere. But on days with extreme weather, the CCS units could be by‐passed, providing an

additional 20‐30 percent increase in power to the system because the units would not experience

CCS‐related derates.

																																																								

33	ICF	International,	Presentation,	“The	Polar	Vortex	and	Future	Power	System	Trends,”	National	Coal	Council	‐‐	

2014	Annual	Spring	Meeting.	

34 Id.

35 Id.

36 Id.

37	NCC	Report	at	16.	
11

Finally, despite the NCC Report’s complaints regarding insufficient time to comply with new

regulations, many of the rules cited (MATS, cooling tower rules and coal combustion residual rules,

for example) have been pending for well over ten years and the industry has had ample time to

accommodate their expected requirements. NCC Report at 10.  

4. New Source Review is Not an Impediment to Efficiency Upgrades.

The NCC Report’s cursory treatment of the New Source Review (“NSR”) regulations and

conclusory statements regarding their deterrent effect on efficiency upgrades are misleading. NCC

Report at 44‐46.  

A source undergoing a major modification that results in a significant increase in emissions of

a regulated pollutant must go through NSR, 42 U.S.C. § 7475(a), 40 C.F.R. § 51.165(a)(1)(v)(A); and as

determined necessary through that process, must apply the best available control technology (or

achieve the lowest available emissions limit) as relevant, for the pollutant in question based on the

location of the plant. Among other things, the purpose of NSR is to protect public health and welfare

and to

assure that any decision to permit increased air pollution in any area to which this

section applies is made only after careful evaluation of all the consequences of such a

decision and after adequate procedural opportunities for informed public

participation in the decisionmaking process.

42 U.S.C. § 7470. These are laudable goals. Improving an existing plant’s efficiency, however, should

not lead to a significant increase in regulated pollutants and therefore should not trigger NSR. The

NCC Report assumes that this will occur – based on the increased demand for the more efficient

source. But increased hours of operation or production rate increases do not subject a facility to

NSR. 40 C.F.R. § 51.165(a)(1)(v)(C)(6), and there is additional flexibility in the regulations for sources

operating under a plant‐wide applicability limit. 40 C.F.R. § 51.165(f)(1)(v).

Historically, the coal industry has tried to avoid triggering NSR. Unfortunately that attitude

continues to be reflected in the NCC Report. In fact, though, compliance with the Mercury Air Toxics

Standards (“MATS”) and Cross State Air Pollution Rule (“CSAPR”) will go a long way toward a source’s

achievement of the emissions limits that would be required by NSR required controls. Indeed, it is

possible, that simply optimizing these control systems will achieve not only the MATS and CSAPR

limits but also BACT or LAER – in other words little additional investment in control would result

even if NSR review is required for an efficiency upgrade. And, it should go without saying that if a

coal‐fired power plant is sufficiently under‐controlled that it cannot meet MATS and CSAPR,

upgrades are appropriate to protect public health and welfare as envisioned under the NSR Program.

5. Conclusions

Mr. Secretary, I drafted this dissent because the NCC Report fails to adequately place the

existing coal fleet in the context of our most pressing environmental challenge of the 21st century—

climate change. Our nation can’t wait. Each year, America’s aging coal fleet grows older. With each

year, more carbon dioxide is emitted to the atmosphere, and once released, it stays in the

atmosphere for periods measured in centuries. And yet, the NCC Report more often emphasizes
12

what can’t be done rather than what can be done to control CO2 and other air pollutant emissions

from the existing fleet, while maintaining its essential character as an important part of our energy

backbone.

The existing coal fleet is a long‐term asset. With CCS retrofits, the existing coal fleet can be

transitioned over time to be a decisive solution to de‐carbonizing the electric sector. Indeed, it will

be impossible to reach mid‐century CO2 reductions without a backbone of low‐carbon base load

power that coal with CCS can help provide.

CCS is demonstrated today – for new plants and as a retrofit control on existing power plants.

With CO2 emission limits to support CCS deployment and with incentives to address CCS costs, the

technology can be installed rapidly on plants within the existing coal fleet, a point that the NCC

Report fails to recognize.

And, finally, retrofitting coal plants in the existing fleet with CCS, allows the fleet to maintain

its historic base load advantages to the US economy without harmful CO2 emissions, and support

system reliability during future short‐term weather emergencies.

I strongly urge you to consider an expansive set of options that help bring this potential to

reality.

Thank you for your consideration,

John Thompson

Director, Fossil Transition Project

Clean Air Task Force

705 W. Main, Suite 101

Carbondale, IL 62901
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX G 

References

Appendix G
National Coal Council – Reliable & Resilient: The Value of Our Existing Coal Fleet

APPENDIX G

References 

1 Annual Energy Outlook – 2014er, USDOE/EIA, December 16, 2013.

2 Ibid.

3 Technical Support Document for the Advanced Notice of Proposed Rulemaking for Greenhouse Gases; 

Stationary Sources, Section VII, USEPA, June 5, 2008, Docketed item # EPA-HQ-OAR-2008-0318-0081.

4 The Return on Investment of the Clean Coal Technology Program in the USA, R. Bezdek and R. Wendling, Energy 

Policy, March 2013, Vol. 54, pp. 104-112.

5 “By 2050, the Obama administration’s goal is to reduce U.S. greenhouse gas emissions approximately by 83 percent 

from 2005 levels.” U.S. Climate Action Report, 2010, (the 5th National Communication of the USA under the UNFCC), 

June 2010. 

6 Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, USEPA, February 21, 2014.

7 Obama Administration Launches Quadrennial Energy Review, The White House, January 9, 2014, 

http://www.whitehouse.gov/the-press-office/2014/01/09/obama-administration-launches-quadrennial-energyreview .

8 White House Advanced Manufacturing Initiatives to Drive Innovation and Encourage Companies to Invest in the 

U.S., The White House, July 17, 2012, http://www.whitehouse.gov/the-press-office/2012/07/17/fact-sheet-whitehouse-advanced-manufacturing-initiatives-drive-innovati .

9 Subpart RR Flaws Preclude EPA’s Reliance on CO2-EOR in the Proposed NSPS Rule, Denbury, (undated), quoted by 

Rep. Weber at hearing of House Environment Subcommittee, Committee on Science, Space, and Technology, March 

12, 2014.

10 Coal to the Rescue, but Maybe Not Next Winter, M. Wald, New York Times, March 10, 2014.

11 2013-2013 Winter Reliability Assessment, North American Electric Reliability Corporation, November 2013 

(published December 4, 2013).

12 Electric Power Monthly – Data through February 2014, USDOE/EIA, April 22, 2014.

13 Ibid.

14 Weekly Working Gas in Underground Storage, USDOE/EIA, http://www.eia.gov/dnav/ng/ng_stor_wkly_s1_w.htm

15National Electricity Reliability Corporation, 2013–2014 Winter Reliability Assessment, November 2013.

16 Owner reaffirms 2017 closing of Brayton Point Plant, The Boston Globe, January 17, 2014.

17 2013 Long-term Reliability Assessment, North American Electric Reliability Corporation, December 2013.

Appendix G 1 | Page

 
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18 Avoided Energy Supply Costs in New England: 2013, Synapse Energy Economics, Inc., prepared for the Avoided 

Energy Supply Component Study Group, July 12, 2013.

19 Electric Power Monthly, USDOE/EIA, retrieved as “Net Generation by State”, 

http://www.eia.gov/electricity/data/state/ .

20 ”Coal Unit Shutdowns,” Table 2, American Coalition for Clean Coal Electricity, January 26, 2014.

21 Process Innovation and Changes in Industrial Energy Use, C. Berg, Science, Vol. 199, February 10, 1978.

22 Pearl Street Station, IEEE, http://www.ieeeghn.org/wiki/index.php/Pearl_Street_Station .

23 Paleofuture, http://paleofuture.gizmodo.com/how-the-1920s-thought-electricity-would-transform-farms510917940 .

24 Data taken from Annual Energy Review, 2011, USDOE/EIA, 2011.

25 Annual Energy Outlook 2014, Table A2, USDOE/EIA, December 2013.

26 Annual Energy Review 2011, Table 2.1a,USDOE/EIA.

27 “Greatest Engineering Achievements of the 20th Century,” U.S. National Academy of Engineering, 2000.

28 “The 50 Greatest Breakthroughs Since the Wheel,” James Fallows, Atlantic, November 2013, pp. 56-68.

29 Data from supporting materials for Annual Energy Review, 2012, USDOE/EIA, 2012.

30 Ibid., calculations by author.

31 Detailed State Data, USDOE/EIA, November 2013, http://www.eia.gov/electricity/data/state/ .

32 Power plant emissions of sulfur dioxide and nitrogen oxides continue to decline in 2012, USDOE/EIA, February 27, 

2013, http://www.eia.gov/todayinenergy/detail.cfm?id=10151 .

33 Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards, Figure 3-6, USEPA, December 2011.

34 Public Power Annual Directory & Statistical Report 2013-2014, American Public Power Association.

35Graphics provided by National Rural Electric Cooperative Association, based on 2012 EIA and Rural Electric Service 

data.

36 Op. Cit., Public Power Annual Directory & Statistical Report.

37 Climate Policy and Labor Markets, O. Deschenes, Working Paper 16111, National Bureau of Economic Research, 

June 2010, http://www.nber.org/papers/w16111 . 

38 Real Gross Domestic Product, Economic Research, Federal Reserve Bank of St. Louis, 

http://research.stlouisfed.org/fred2/series/GDPC1 . All Employees: Total non-farm, 

http://research.stlouisfed.org/fred2/series/PAYEMS?cid=32305 .

39Electric Power Monthly – February 2014, USDOE/EIA, 2014. Eurostat database, Electricity and natural gas price 

statistics, European Commission, 

http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Electricity_and_natural_gas_price_statistics .

40 Data taken from Net Generation by State by Type of Producer by Energy Source (EIA-906, EIA-920, and EIA-923), 

USDOE/EIA, November 2013, http://www.eia.gov/electricity/data/state/ .

41 Data taken from Average Price by State by Provider (EIA-861), USDOE/EIA, November 2013, 

http://www.eia.gov/electricity/data/state/ .

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42 Obama Administration Launches Quadrennial Energy Review, The White House, January 9, 2014, 

http://www.whitehouse.gov/the-press-office/2014/01/09/obama-administration-launches-quadrennial-energyreview .

43 White House Advanced Manufacturing Initiatives to Drive Innovation and Encourage Companies to Invest in the 

U.S., The White House, July 17, 2012, http://www.whitehouse.gov/the-press-office/2012/07/17/fact-sheet-whitehouse-advanced-manufacturing-initiatives-drive-innovati .

44 Electric Power Monthly, March 2014, Table ES2.A, USDOE/EIA, March 21, 2014.

45 ”Energy Weekly,” Citi Research, February 10, 2014, https://www.citivelocity.com .

46 “Northeast Switched from Natural Gas to Oil,” Institute for Energy Research, February 10, 2014, 

http://www.instituteforenergyresearch.org/2014/02/10/northeast-switched-from-natural-gas-to-oil-due-to-lack-ofinfrastructure/ . 

47 “West Coast Gas, Power Surge on Frigid Northwest Cold Forecasts,” N. Malik, Bloomberg, February 5, 2014.

48 “Midwest, West Coast Cash Points Spike,” A. Steis, Natural Gas Intelligence, February 5, 2014.

49 Ibid.

50 “The Economic Impacts of Coal Utilization,” A. Rose, et. al., Penn State University, July 2006.

51 CURC/EPRI Roadmap, 2012, Coal Utilization Research Council.

52 Technical Support Document for the Advanced Notice of Proposed Rulemaking for Greenhouse Gases; 

Stationary Sources, Section VII, EPA, June 5, 2008, EPA Regulatory Docket No. EPA-OAR-2008-0318-0081.

53 “Economic and Jobs Benefits of U.S. Coal Generation,” Management Information Services, Inc., prepared for the 

National Coal Council, March 2014.

54 Ibid.

55 Ibid.

56 Obama Administration Launches Quadrennial Energy Review, The White House, January 9, 2014, 

http://www.whitehouse.gov/the-press-office/2014/01/09/obama-administration-launches-quadrennial-energyreview .

57 White House Advanced Manufacturing Initiatives to Drive Innovation and Encourage Companies to Invest in the 

U.S., The White House, July 17, 2012, http://www.whitehouse.gov/the-press-office/2012/07/17/fact-sheet-whitehouse-advanced-manufacturing-initiatives-drive-innovati .

58 Real Gross Domestic Product, US Department of Commerce, Bureau of Economic Analysis.

59 Data from supporting materials for Annual Energy Review, 2012, USDOE/EIA, 2012. 

60 Data from Annual Energy Outlook, 2014 early release, Reference Case, USDOE/EIA, December 2013.

61The Society of Manufacturing Engineers concluded that “We are not going to get out of this economic crisis without 

a strong, innovative manufacturing sector,” Manufacturing Business Technology, April 23, 2009. www.mbtmag.com; 

see also, Nina Ying Sun, “U.S. Manufacturing Vital to Crisis Recovery,” February 22, 2009, http://plasticsnews.com; 

James W. Owen, “The Financial Crisis and the U.S. Economy – a CEO’s Perspective,” Council on Foreign Relations, 

Washington, D.C., April 2009; and Susan Helper, “The High Road for U.S. Manufacturing,” Issues in Science and 

Technology, Winter 2009. To the extent that a global recovery will require a rebalancing of trade – the U.S. deficit 

must be reduced as China’s surplus must fall – the U.S. will suffer a decline in living standards, since the U.S. will be 

producing more than it has been consuming, unlike the previous decades when the U.S. was consuming more than it 

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was producing. This impact on living standards will be apart from any negative impact on living standards owing to 

U.S. citizens paying higher energy costs.

62 Natural gas generation lower than last year because of differences in relative fuel prices, USDOE/EIA, September 

25, 2013, http://www.eia.gov/todayinenergy/detail.cfm?id=13111 .

63 US natural gas spot prices increased during first-half 2013, USDOE/EIA, July 22, 2013, 

http://www.eia.gov/todayinenergy/detail.cfm?id=12191 .

64 The State of the National Pipeline Infrastructure, USDOT, October 2011.

65 Based on data published by USDOE/EIA in AEO Retrospective Review: Evaluation of 2012 and Prior Reference Case 

Projections, March 15, 2013, http://www.eia.gov/forecasts/aeo/retrospective/ (and similar data from the AEO 

Retrospective Review for AEO-2008).

66 Based on analysis of data published by Sourcewatch, 

http://www.sourcewatch.org/index.php/Coal_plant_retirements , accessed March 6, 2014.

67 Office of Information and Regulatory Affairs, Office of Management and Budget, 

http://www.reginfo.gov/public/jsp/EO/eoDashboard.jsp .

68 Presidential Memorandum – Power Sector Carbon Pollution Standards, The White House, June 25, 2013.

69 “By 2050, the Obama administration’s goal is to reduce U.S. greenhouse gas emissions approximately by 83 percent 

from 2005 levels.” U.S. Climate Action Report, 2010, (the 5th National Communication of the USA under the UNFCC), 

June 2010.

70 Climate Change 2014: Mitigation of Climate Change – Summary for Policy Makers, IPCC Working Group III, April 

2014.

71 Database of State Incentives for Renewables & Efficiency, website hosted by the North Carolina Solar Center, 

http://www.dsireusa.org/documents/summarymaps/RPS_map.pdf .

72 AEO2014 projects more coal-fired power plant retirements by 2016 than have been scheduled, USDOE/EIA, 

February 14, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=15031 .

73 AEO2013, Online Table Browser, USDOE/EIA, 2013.

74 New Source Review for Stationary Sources of Air Pollution, National Research Council, 2006.

75 See, e.g., 40CFR51.21.

76 Op.Cit., NRC, 2006, Table 2-3.

77 New Source Review: Report to the President, USEPA, June 2002.

78 Ibid., p.16.

79 Ibid., p.16.

80 Letter from Francis X. Lyons, Regional Administrator, EPA, to Henry Nickel (May 23, 2000) (“Detroit Edison 

Determination”) (emphasis added), available at www.epa.gov/ttn/nsr/gen/letterf3.pdf.

81 Ibid., p. 27.

82 Ibid.

83 Ibid.

84 Ibid., p. 21-22.

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85 Data for Figures 15-17 are taken from responses to EIA Form 860, as published by DOE/EIA, 

http://www.eia.gov/electricity/data.cfm .

86 FY2015 Summary Control Table by Organization, USDOE, http://energy.gov/cfo/downloads/fy-2015-budgetjustification .

87 Electric Power Monthly, USDOE/EIA, February 2014.

88 The Return on Investment of the Clean Coal Technology Program in the USA, R. Bezdek and R. Wendling, Energy 

Policy, March 2013, Vol. 54, pp. 104-112.

89 See, for example: Mitigating the Effects of Flexible Operation on Coal-Fired Power Plants, S. Hesler, EPRI, Power 

Magazine, August 1, 2011; and Managing Large-Scale Penetration of Intermittent Renewables, MIT, April 20, 2011, 

https://mitei.mit.edu/system/files/intermittent-renewables-full.pdf .

90 Impacts of Wind Generation Integration, EPRI, May 6, 2011, 

http://www.epri.com/abstracts/pages/productabstract.aspx?ProductID=000000000001023166 .

91 Wind Assisted Heating, P. Staffes, 

http://www.google.com/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=1&cad=rja&uact=8&ved=0CCoQFjAA&

url=http%3A%2F%2Fwww.steffes.com%2FLiteratureRetrieve.aspx%3FID%3D60620&ei=bjIeU9jrFM_woATSv4DwCg&

usg=AFQjCNHkJkBiT99Ok75SDLIVbsOhGRJ0uw&sig2=e7MrB0QWAeZVWxo4n3NPtQ&bvm=bv.62788935,d.cGU .

92 Western Wind and Solar Integration Study, GE Energy for National Renewable Energy Laboratory, May 2010.

93 Based on analysis of data published by Sourcewatch, 

http://www.sourcewatch.org/index.php/Coal_plant_retirements , accessed March 6, 2014.

94 Northeast’s Record Natural Gas Prices Due to Pipeline Dearth, Bloomberg Businessweek, February 6, 2014, 

http://www.businessweek.com/articles/2014-02-06/northeasts-record-natural-gas-prices-due-to-pipeline-dearth .

95 Available and Emerging Technologies for Reducing GHG Emissions from Coal-Fired Electric Generating Units, EPA/ 

OAR, Oct 2010.

96 Remote Monitoring and Diagnostics Within a Smart Integrated Infrastructure, U. Nowling, Power Magazine, Vol 

158, No. 2, February 1, 2014.

97 DryFining Fuel Enhancement Process, Great River Energy, 2013, available at 

http://www.greatriverenergy.com/makingelectricity/newprojects/dryfining.html

98 Clean Coal Technology, Professor Sunggyu Lee’s Research Program at Ohio University, 

http://www.ohio.edu/people/lees1/coal.html .

99 Lopriore, R., PSEG President - Fossil, Personal Communication, February 14, 2014.

100 Coal-fired Power Plant Heat Rate Reduction, Sargent & Lundy final Report SL-009597, January 22, 2009, prepared 

for EPA Project 12301-001.Table 4-3. 

101 Ibid.

102 Op. Cit., Sargent & Lundy.

103 A Review of upgrading and efficiency improvement projects on coal-fired power plants, workshop on upgrading 

and efficiency improvements in coal-fired power plants, Henderson, C., E.On Engineering Academy, Ratcliffe-on-Doar, 

March 2013.

104 Power Generation from Coal – Measuring and Reporting Efficiency Performance and CO2 Emissions, 

CIAB/International Energy Agency, 2010. 

Appendix G 5 | Page

 
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105 Op. Cit., Sargent & Lundy.

106 Ibid.

107 Advanced Sensors and Controls – Techno-Economic Analysis for Existing Coal Generating Units, DOE/NETL342/03082013, March 8, 2013.

108 21st Century Coal: Advanced Technology and Global Energy Solution, Report by the IEA Coal Industry Advisory 

Board, Paris, 2013.

109 MHI High Efficiency System – Proven technology for multi pollutant removal, Y. Nakayama, et. al., Mitsubishi 

Heavy Industries, Ltd., http://www.advatechllc.com/wp-content/uploads/2012/03/High-Efficiency-System-ProvenTechnology-for-Multi-pollutant-Removal-Paper.pdf .

110 Cost and Performance Baseline for Fossil Energy Plants: Volume 1: Bituminous coal and Natural Gas to Electricity, 

Revision 2a, September 2013, DOE/NETL -2010/1397. See Exhibit 4-34.

111 Op. Cit., Sargent & Lundy.

112 Development tendency analysis of (ultra-) supercritical fossil fired power plants in China, Long H. et. al., undated.

113 The Applicability of Supercritical Topping Cycles for Repowering Subcritical Steam-Electric Power Plants, EPRI 

Technical Update Report 1019677, December 2010.

114 Steigelmann, W. et. al., “CHP Bottoming-Cycles: An “Outside-the-Box”

115 Power Generation from Coal – Measuring and Reporting Efficiency Performance and CO2 Emissions, 

CIAB/International Energy Agency, 2010. 

116 Ibid.

117 Transcript of Press Conference by Press Secretary R. Gibbs and Assistant to the President for Energy and Climate 

Carol Browner, (climate statement by Ms. Browner), The White House, November 25, 2009, 

http://www.whitehouse.gov/the-press-office/press-gaggle-press-secretary-robert-gibbs-deputy-national-securityadvisor-internat

118 Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012, USEPA, February 21, 2014.

119 $2.3 B from annual appropriations and $3.4B from the American Recovery and Reinvestment Act, Carbon Capture

and Sequestration: RD&D at the U.S. Department of Energy, Congressional Research Service, April 23, 2013.

120 Renewable Energy and Energy Efficiency Incentives: A Summary of Federal Programs, Appendix A, Congressional 

Research Service, R40913, October 18, 2013.

121 Based on 168 million MWh of wind generation (from DOE/EIA Electric Power Monthly – Feb 2014, and Production 

Tax Credit of 2.3 cents per kWh (IRS Form 8835).

122 Low-Carbon Coal: Meeting U.S. Energy, Employment and CO2 Emission Goals with 21st Century Technologies, 

National Coal Council, December 2008; and Expediting CCS Development: Challenges and Opportunities, National 

Coal Council, March 2011.

123 “Alstom would also point out that it is unaware that any supplier of this technology is ready or able to offer 

commercial guarantees for such full-scale systems of carbon capture.” Testimony of R. Hilton, before the U.S. House 

of Representatives Subcommittee on Environment and Subcommittee on Energy, of the Committee on Science, 

Space, and Technology, March 12, 2014.

124 EPA Utility FGD survey: October –December 1979, Smith, M. et. al., EPA-600/7-80-029a, January, 1980.

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125 Trends In Commercial Application of FGD Technology, Laeske, B. et. al., Proceedings: Symposium on Flue Gas 

Desulfurization, Volume 1, EPRI CS-2897, March 1982

126 Uncertainties in Technology Experience Curves for Energy-Economic Models, S. Yeh & E. Rubin, CMU, 2010, 

http://www.cmu.edu/epp/iecm/rubin/PDF%20files/2010/Yeh&Rubin_Uncertainties%20in%20Experience%20Curves

_18May2010.pdf .

127 Clean Coal Research Program – Carbon Capture Technology Program Plan, (pages 19-20), USDOE/NETL, January 

2013.

128 Low-Carbon Coal: Meeting U.S. Energy, Employment and CO2 Emission Goals with 21st Century Technologies, 

National Coal Council, December 2008; and Expediting CCS Development: Challenges and Opportunities, National 

Coal Council, March 2011.

129 R&D Update, DOE/NETL 2011

130 DOE Issues Final EIS for W.A. Parish, GHG Monitor, March 13, 2013, available at 

http://ghgnews.com/index.cfm/doe-issues-final-eis-for-wa-parish/

131 White Rose Project Fact Sheet, CCS Database, MIT, http://sequestration.mit.edu/tools/projects/white_rose.html .

132 OXYCFB 300 Compostilla Project, Fact Sheet stating that the proposed 300 MW demonstration project is 

considered cancelled, Global Carbon Capture and Storage Institute, 

http://www.globalccsinstitute.com/project/oxycfb-300-compostilla-project .

133 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, Department of Energy, Office of Fossil 

Energy, available at http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasIV/. Hereafter 2012 Carbon 

Atlas

134 National Assessment of Geologic Carbon Dioxide Storage Resources – Results, Circular 1386, Version 1.1, 

September 2013. Hereafter USGS September 2013

135 The Global Status of CCS: 2013, Global CCS Institute, August 2013, page 15.

136 Technology Roadmap: Carbon Capture and Storage, 2013 Edition, International Energy Agency, page 17.

137 The North American Carbon Storage Atlas – 2012, First Edition, page 18. Available at www.nacsap.com.

138 Improving Domestic Energy Security and Lowering CO2 Emissions with Next Generation CO2-Enhanced Oil Recovery 

(CO2-EOR), Report DOE/NETL-2011/1504, June 20, 2011. 

139 Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil 

Recovery (CO2-EOR), Report DOE/NETL-2011/1504, June 20, 2011.

140 Subpart RR Flaws Preclude EPA’s Reliance on CO2-EOR in the Proposed NSPS Rule, Denbury, (undated), quoted by 

Rep. Weber at hearing of House Environment Subcommittee, Committee on Science, Space, and Technology, March 

12, 2014.

141 Low-Carbon Coal: Meeting U.S. Energy, Employment and CO2 Emission Goals with 21st Century Technologies, 

National Coal Council, December 2008; and Expediting CCS Development: Challenges and Opportunities, National 

Coal Council, March 2011.

142 Report of the Interagency Task Force on Carbon Capture and Storage, (multiple agencies), August 2010, 

http://energy.gov/sites/prod/files/2013/04/f0/CCSTaskForceReport2010_0.pdf .

Appendix G 7 | Page