Increasing Electricity Availability From

Coal-Fired Generation in the Near-Term

May 2001

THE NATIONAL COAL COUNCIL

Steam

Clean Syngas

End 

Feeds Products

Gas 

Cleanup

Coal

Oxygen

Electricity

Sulfur

Slag

Gas & Steam

Turbines

Gasification

Combined Cycle

Power Block

 SULFUR

RECOVERY Byproducts:

 SULFUR

REMOVAL

Coal IGCC Process1

1 Texaco Gasification Process (TGP)
ii

Increasing Electricity Availability From

Coal-Fired Generation in the Near-Term

Chair: Mr. Steven F. Leer

Vice Chair: Mr. Wes M. Taylor

Study Work Group Chair: Ms. Georgia Nelson

The National Coal Council

May 2001
iii

THE NATIONAL COAL COUNCIL

Steven F. Leer, Chairman

Robert A. Beck, Executive Director

U.S. DEPARTMENT OF ENERGY

Spencer Abraham, Secretary of Energy

The National Coal Council is a Federal Advisory Committee to the Secretary of Energy. The sole purpose of 

the National Coal Council is to advise, inform, and make recommendations to the Secretary of Energy on any 

matter requested by the Secretary relating to coal or to the coal industry.
iv

Cover Letter to Secretary Abraham 
v
vi

Abbreviations

AQRVs Air quality related values

B&W Babcock & Wilcox

BACT Best available control technology

BGL British Gas/Lurgi

Btu British thermal units

Btu/kWh British thermal units per kilowatt-hour

CAA Clean Air Act

CFB Circulating fluidized bed

CO2 Carbon dioxide

COS Carbonyl sulfide

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

EPRI Electric Power Research Institute

FGD Flue gas desulfurization

FLMS Federal land managers

GADS Generation Availability Data System

GW Gigawatts (109 watts)

HHV Higher heating value

HRSG Heat recovery steam generator

IGCC Integrated gasification combined cycle

kW Kilowatt

lb/MBtu Pounds of emissions per million Btu of heat input

LAER Lowest achievable emission rates

LHV Lower heating value

LNB Low NOx burners

MACT Maximum achievable control technology

Mbtu Million Btu

MDGC Maximum demonstrated generating capacity

MW Megawatts (106 watts)

MWH Megawatt-hour

NAAQS National Ambient Air Quality Standards

NCC National Coal Council

NERC North American Electric Reliability Council

NGCC Natural gas combined cycle

NOVs Notices of violation

NOx Nitrogen oxides

NSPS New Source Performance Standards

NSR New Source Review

O&M Operating and Maintenance

OEM Original Equipment Manufacturer

PPM Parts Per Million

PSD Prevention of significant deterioration

SCR Selective catalytic reduction

SO2 Sulfur dioxide

SOx Sulfur oxides

tpy tons per year

UDI Utility Data Institute

WEPCo Wisconsin Electric Power Company
Table of Contents

Preface 1

Executive Summary 2

Achieving Higher Availability/Reliability From Existing

Coal-Fired Power Plants 5

Reducing Regulatory Barriers 27

Appendix A: Description of The National Coal Council 33

Appendix B: The National Coal Council Membership Roster 34

Appendix C: The National Coal Council Coal Policy Committee Roster 41

Appendix D: The National Coal Council Electricity Availability

Study Work Group 43

Appendix E: Correspondence Between U.S. Department of Energy and 

the National Coal Council 46

Appendix F: Correspondence From Industry Experts 48

Appendix G: Selected Comments on the Report 69

Appendix H: Acknowledgements 83
1

Preface

The National Coal Council is a private, nonprofit advisory body, chartered under the Federal Advisory 

Committee Act.

The mission of the Council is purely advisory: to provide guidance and recommendations as requested by 

the United States Secretary of Energy on general policy matters relating to coal. The Council is forbidden 

by law from engaging in lobbying or other such activities. The National Coal Council receives no funds 

or financial assistance from the Federal government. It relies solely on the voluntary contributions of 

members to support its activities.

Members of the National Coal Council are appointed by the Secretary of Energy for their knowledge, 

expertise, and stature in their respective fields of endeavor. They reflect a wide geographic area of the 

United States (representing more than 30 states) and a broad spectrum of diverse interests from business, 

industry, and other groups, such as:

o large and small coal producers;

o coal users such as electric utilities and industrial users;

o rail, waterways, and trucking industries as well as port authorities;

o academia;

o research organizations;

o industrial equipment manufacturers;

o state government, including governors, lieutenant governors, legislators, and public utility 

commissioners;

o consumer groups, including special women’s organizations;

o consultants from scientific, technical, general business, and financial specialty areas;

o attorneys;

o state and regional special interest groups; and

o Native American tribes.

The National Coal Council provides advice to the Secretary of Energy in the form of reports on subjects 

requested by the Secretary and at no cost to the Federal Government.
2

Executive Summary

Purpose

By letter dated November 13, 2000, then-Secretary of Energy Bill Richardson requested that the National 

Coal Council conduct a study on measures which the government or the government in partnership with 

industry could undertake to improve the availability of electricity from coal-fired power plants. His letter 

requested that the Council address improving coal-fired generation availability in two specific areas:

o improving technologies at coal-fired electric generating plants to produce more 

electricity; and

o reducing regulatory barriers to using these technologies.

The Council accepted the Secretary’s request and formed a study group of experts to conduct the work 

and draft a report. The list of participants of this study group can be found in Appendix D of the report.

Findings

The study group found the following.

o Nationally, approximately 40,000 megawatts of increased electrical production capability is possible 

now from existing coal-fired power plants.

o Such increased electricity supply can be available through the installation of standard improvements 

and clean coal technologies. This will have the important effect of increasing efficiency and 

decreasing emissions per megawatt from such modified plants, thereby improving air quality.

o Such plant efficiency and increased electricity production capability may only be realized if a return 

to historic regulatory policy is made.

o Coal-based electricity will be important for many years into the future. Therefore, regulations and 

policies employed should encourage the clean use of this resource through accelerated installation of

more efficient, cleaner technologies.

The study was divided into two major sections: technology and regulatory reform. The focus of the 

technology section is on achieving more electricity from existing and new coal-fired power plants 

using technologies that improve efficiency, availability, and environmental performance. The 

discussion is divided into three subsections:

a) achieving higher availability/reliability in the existing fleet of coal-fired plants;

b) Increasing generation output of existing coal-fired plants; and

c) Determining opportunities for repowering existing facilities with clean coal technologies as well 

as building new advanced clean coal technology generation facilities.

Analysis of the U.S. utility industry infrastructure of coal plants reveals a significant potential for 

increasing generation capacity by taking well-tested measures to improve the reliability/availability of 

older facilities. This effort, which will come mainly from improvements on the steam generators of these 

older plants, can create 10,000 MW of new capacity.

Techniques to recover lost capacity and increase capacity above nameplate have been collected from a 

combination of research studies by utility industry organizations such as EPRI and actual case studies 

which are detailed in the report. The nameplate capacity of coal units older than 20 years is 

approximately 220,000 MW; however, due to derating, the existing capacity is only about 200,000 MW. 
3

This group of plants has the potential for both capacity restoration (about 20,000 MW) and/or 

improvement (about 20,000 MW). It is estimated that this increased capacity of 40,000 MW could be 

recovered within 36 months. This can allow the economy to grow while new generation facilities are 

sited, constructed, and brought into service.

For new coal-fired power generating capacity, Pulverized Coal Combustion in supercritical steam plants 

(a mature technology) is available with minimal emissions, high efficiency, and at very favorable total 

production cost.

Repowering of an old existing coal fired power plant with a single modern steam generating unit, 

equipped with commercially proven emissions controls results in significant reductions in the total 

amounts of emissions even while substantially increasing the total MWh output of the facility.

Integrated Gasification Combined Cycle (IGCC) has become a commercially available technology for 

both greenfield and repowering applications. IGCC is a clean, new technology option insensitive to fuel 

quality variation.

While natural gas will fuel the majority of new capacity additions during this time period there are 

currently about 321,000 MW of coal-fired capacity in service. While not all of this capacity can be 

targeted for the new technologies discussed in this report, it is estimated that 75% of it can be retrofitted 

with one of these technologies. This additional increase in capacity is estimated to be 40,000 MW and 

much of it could be brought on line in the next three years. This minimizes economic impacts while new 

generation facilities are sited, constructed, and brought into service without increasing emissions at 

existing facilities and, in some cases, lowering emissions. Approximately 25% of existing facilities can 

be targeted for repowering with much cleaner and more efficient coal-based power generation.

However, unless there is a significant change in regulatory interpretation and enforcement regarding the 

installation of new technologies at existing power plants, it is not likely that any of this additional lowcost, low emission electricity will be produced. The recent change in enforcement procedures by EPA 

(reinterpreting as violations of the Clean Air Act what had heretofore been considered routine 

maintenance at power plants) has had a direct and chilling effect on all maintenance and efficiency 

improvements and clean coal technology installations at existing power plants. EPA has brought legal 

action against 11 companies and 49 generation facilities since 1998 under the New Source Review section 

of the 1990 Clean Air Act. The companies involved believe that they were conducting routine 

maintenance needed to keep these plants in good condition. The result has been that no new efficiency, 

availability, or environmental improvement has occurred since 1998 when EPA changed its enforcement 

policy. A return to the historic interpretation of this one regulation alone would allow plant operators the 

opportunity to install technologies discussed in the report. If just a three percent increase in capacity 

could be achieved through reducing outages and increasing plant efficiency, it could result in over 11,500 

MW of coal-based capacity being added to the current fleet while continuing the downward trend in 

emissions.

Several other existing regulations seem to be in conflict with the country’s attempt to maximize the use of 

domestic energy sources. Environmental regulation should be harmonized with the energy and national 

security goals of the country.
4

Recommendations

The National Coal Council strongly recommends that the country, with the Department of Energy in the 

lead, develop a clear, comprehensive energy policy that supports the maximum use of domestic fuel 

sources, continues to protect the environment by implementing strong but balanced environmental 

regulations, and harmonizes conflicting regulations affecting energy development and use. Government 

and industry should work in partnership to achieve the desired goals and remove those regulatory barriers 

that create obstacles to achieving those goals while preserving environmental performance. 

Specifically, the Council recommends that the Department of Energy take the following actions.

o Initiate and lead a dialogue with EPA, with the goal of returning to the traditional pre-1998 

interpretation of the New Source Review section of the 1990 Clean Air Act.

o Promote accelerated installation of clean and efficient technologies at new and existing coal-fired 

power plants.

o Initiate and lead a dialogue with EPA to promote coordinated regulations for ozone attainment

into a single compliance strategy.

o Initiate and lead a dialogue with EPA and electricity generators to establish credible and uniform 

emissions targets, which will provide regulatory certainty for a sufficient period in the future to 

assure electricity generators that they can achieve a return on investments for performance and 

environmental improvements.

o Lead the country’s effort to develop a clear, comprehensive, and secure energy policy that 

maximizes the use of domestic fuels, including coal, while continuing the downward trend in 

emissions.
5

Achieving Higher Availability/Reliability From

Existing Coal-Fired Power Plants

This section will focus on recommendations that will improve existing coal-fired power plants’ reliability 

and availability to eliminate or reduce forced outages and extend the time between planned maintenance 

outages. This suggested availability improvement program is meant to restore the plants’ infrastructure to 

a level that restores the original reliability of the plants. Implementation of these recommendations will 

allow the plants to increase generation output above recent historical output without increasing gross 

generating capability. 

We will show from the use of industry sources on reliability (GADS/NERC) and generation capacity 

(EIA) that there is a significant opportunity for the utility industry to increase the generation output from 

our existing fleet of coal-fired power plants by restoring portions of the plant infrastructure to their 

original condition.

Analysis of the U.S. utility industry’s coal-fired plant infrastructure reveals a significant opportunity for

increasing electricity output from these plants by taking measures to improve the reliability/availability of 

the older facilities. Maintaining or restoring plants that are over 20 years old to a condition similar to

plants that are under 20 years old can result in more reliable facilities that will be available to play an

important role in supporting the increasing strain on our electrical system’s reserve margins and electrical 

demand growth.

Specifically, our analysis has shown that this reliability improvement effort can create 10,000 MWs of

equivalent generation capacity within our existing coal-fired fleet of plants. Of particular note is that over 

90% of these MWs of capacity will come from component replacement and material upgrades of the

boiler/steam generator at our facilities that are more than 20 years old. The U.S. EPA has focused on

boiler/steam generator component replacement projects in its recent enforcement actions, applying New

Source Review (“NSR”) standards to repairs formerly considered routine maintenance, repair, or

replacement. The potential regulatory consequences of the EPA's enforcement actions may prevent the

utility industry from taking full advantage of this relatively inexpensive way to increase the availability of 

our national electric generating capacity, which could be implemented in a two to three year time frame.

The U.S. electric generating system’s reserve margins have declined dramatically over the last 20 years. 

This situation has put pressure on the operators of our existing coal-fired fleet to restore, maintain, or 

improve the reliability and availability of their facilities to keep pace with the growing demand for

electricity in the face of limited new capacity coming on line. The mandate for higher availability, lower 

forced outage rates, and longer time spans between planned outages is more critical today than ever in our 

history.

The causes of plant unavailability are well defined, and sound, technology-based solutions are 

commercially available to improve plant availability and help restore our historic reserve margins.

Causes of plant unavailability and recommendations for solutions have been generally categorized 

according to the magnitude of their impact on plant availability in the following list:

Area 1: Boiler/Steam Generator 

The primary cause of unavailability of our coal-fired plants is the reliability of the boiler/steam generator. 

Severe duty on both the fire side and the water/steam side of the various heat transfer surfaces in the 

boiler/steam generator cause frequent unplanned outages and lengthening of planned outages to repair 
6

failures to these critical components of the power plant. Replacement of these components will 

significantly reduce outages and increase the facility's availability and total generation output capability. 

Examples of our recommendations for improving the availability of the boiler/steam generator are:

a. furnace wall panel replacements;

b. reheater component replacements;

c. primary superheater component replacements;

d. secondary superheater component replacements;

e. economizer replacements;

f. various header replacements;

g. furnace floor replacements;

h. cyclone burner replacements; and

i. incorporation of improved materials of construction for items a-h.

This area represents between 50% and 70% (depending on age, design, and operating history of the unit) 

of all lost generation from our coal-fired fleet. The industry data sources referenced above indicate that if 

improvements to the boilers/steam generators on our plants that are older than 20 years can be made to 

restore these facilities to the condition of plants that are under 20 years, we will benefit from an attendant 

improvement in reliability/availability. To help quantify this finding, plants older than 20 years are, on 

average, currently experiencing nearly 10% loss of achievable generation due to problems in the 

boiler/steam generator. This compares to approximately 5% loss for plants that are less than 20 years old. 

If we can recover only this differential through restoration of the boiler/steam generator, we will be taking 

advantage of nearly 9,000 MWs of available generation capacity in our existing coal-fired generating 

fleet. This figure is expected to increase significantly as our older generating units are dispatched more 

often to meet the growing demand for electricity considering the less than adequate new capacity coming 

on line.

Although the implementation of any (or all) of these recommendations will significantly increase plant 

availability, recent regulatory treatment of previously routine repairs, maintenance, and replacement as 

modifications by the EPA discourages utilities from pursuing these kinds of projects in their future plans 

for availability improvement for fear of triggering NSR with accompanying permitting and modeling 

requirements. NSR can radically undermine the economic feasibility of these projects, preventing 

recapture of lost generating capacity or increased reliability. 

Area 2: Steam Turbine/Generator

Problems with the steam turbine/generator represent the second largest source of reduced generation 

capability in coal-fired plants. This area represents a 3% loss of generation compared to up to 10% for 

the boiler/steam generator. An interesting finding from our analysis is that the data sources referenced 

above show very little difference in loss of generation capability due to turbine/generator problems 

between plants older than 20 years and plants younger than 20 years. This phenomenon may be due to 

the regimented safety and preventative maintenance program typically mandated by turbine 

manufacturers and followed by plant owners for the steam turbine/generator. 

Section 2 describes turbine/generator improvements (e.g., uprating) that can change gross plant outputs 

without changing the turbine/generator's relatively good track record on availability. In addition to 

turbine uprating, some of the general improvements that have occurred in steam turbine design will also 

improve the availability/reliability of existing steam turbines. Recommendations include:
7

a. turbine blading replacements with improved shapes (CFD modeling) and materials of construction to 

increase turbine efficiency and reliability;

b. implementation of measures to reduce or eliminate droplet formation and the resultant blade erosion 

preserving turbine reliability and performance; and

c. turbine/generator inclusion in plant diagnostic and data acquisition system for predictive 

maintenance (reference area 7c below) to reduce unnecessary maintenance and associated outage 

time.

Area 3: Plant Auxiliaries

This area focuses on plant auxiliaries including the air heater, feedwater system, cooling water systems, 

electrical systems, etc. Plant auxiliaries cause approximately 1-2% of lost megawatt-hour (MWh) 

generation from our coal-fired plants over 20 years old. This can be improved to under 1% with 

restoration of critical components in this area of the plant. Some examples of recommendations for 

improved reliability and increased operating efficiencies in these areas are:

a. air heater or air heater basket replacement with the attendant modern sealing systems;

b. improved air heater surface design and cleaning system installation to address fouling;

c. feedwater heater retubing or replacement with upgraded materials to reduce failure rates; and

d. cooling tower fill improvements.

Area 4: Environmental (Focus on Electrostatic Precipitators)

Precipitator performance has the fourth largest impact on loss of plant availability. This problem almost 

always manifests itself in the form of load curtailment caused by the potential for opacity excursions. To 

exacerbate the problem, these curtailments typically occur at very critical capacity supply situations such 

as periods with high load requirements. Recommendations for mitigation are:

a. collection plate and electrode upgrades and/or replacement;

b. collection surface additions (new fields);

c. various flue gas treatment system installations;

d. addition of modern control system installations; and

e. general correction of leakage and corrosion problems.

Area 5: Fuel Flexibility

Many utilities have expanded their coal purchase specifications to leverage the variability in the cost of 

coal as a means of providing low-cost electricity to their customers. This practice, however, can have an 

adverse affect on plant reliability due to stress on the plant. It should be noted that although this area is 

not statistically recognized as a cause of loss of plant availability, fuel related problems are a major part 

of loss of availability from Area 1 "boiler/steam generator" due to such phenomena as boiler 

slagging/fouling, limited pulverizer throughput, reduced coal grindability, inadequate primary air systems, 

etc. Recommendations to reduce or eliminate these limitations are:

a. coal handling system upgrades to accommodate lower Btu coal;

b. mill upgrades to accommodate reduced grindability of coal;

c. ash (bottom and/or fly) system upgrades to accommodate higher ash coal or different ash classes;

d. additional furnace-cleaning equipment to mitigate different slagging and fouling characteristics of 

the coals;

e. draft system upgrades including FD fans, ID fans, combustion air temperature, and related electrical 

systems to accommodate higher gas volume flow rates; and
8

f. precipitator upgrades to accommodate changes in fly ash resistivity and/or quantity.

Area 6: Boiler Water Treatment

This issue goes hand-in-hand with Area 1 described above. Performance of boiler heat transfer surface is 

highly dependent on the chemistry of the water/stream that keeps the surface cool. Upgrades of the boiler 

water treatment system should be coordinated with the upgrades described in Area 1. An added benefit of 

higher water purity standards is faster plant start-ups; and, therefore, a unit can come on-line more quickly 

and ramp up generation faster resulting in a higher overall generation output. In addition, water purity 

has a cascading effect increasing the reliability of feedwater heaters and turbine blades and improving 

condenser performance.

Area 7: Controls and Plant Diagnostic Systems

Modern digital control and diagnostic systems can improve heat rates (generation efficiency), lower 

emissions, reduce plant startup times, and provide valuable information for outage planning. 

Recommendations in this regard include:

a. replacement of outdated analog control with advanced digital control systems;

b. replacement and/or addition of instrumentation for better control of the unit over a wider range of 

loads and improved monitoring of critical system components for outage planning;

c. installation of plant diagnostic and data acquisition systems to perform predictive maintenance 

reducing unplanned outages and extending on-line time durations between planned outages; and

d. installation of turbine bypass system hardware and controls to facilitate lower load capabilities, 

faster unit start-ups and faster ramp rates increasing overall unit productivity.

Area 8: Plant Heat Rejection

For many plants, the highest capacity requirements of the year occur at the same time that they experience 

severe heat rejection limitations. Summertime cooling lake and river temperatures/water levels can cause 

load curtailments. Recommendations include:

a. water intake structure modifications to provide more flexibility during low water levels;

b. cooling tower additions to provide an alternate heat rejection mechanism; and

c. cooling lake design modifications (additional surface, redirected flow path, etc.) to increase heat 

rejection capability.

Summary

Restoration of our 20+-year-old coal-fired plants to a condition similar to those that are under 20 years 

through the recommendations described in these eight areas can create approximately 10,000 MWs of 

additional availability from existing assets. We would expect this number to grow significantly as we 

increase utilization of our older plants to meet growing demand. Without implementing these 

recommendations, the forecasted increases in utilization will accelerate failures in these older facilities 

increasing the need for the recommendations we have identified here.
9

Of particular interest is that 90% of the increased availability identified will come from component 

replacement and other projects involving the boiler/steam generator. The boiler/steam generator has been 

the focus of the EPA’s allegations in its recent reinterpretation of the New Source Review program as part 

of its power plant enforcement initiative. 

Increasing Generation Output of Existing Units

The maximum demonstrated generating capacity (MDGC) of coal units older than 20 years, as identified 

above, is conservatively estimated to total approximately 220,000 MWs. The existing operating capacity 

is estimated to be 200,000 MWs (due to deratings). This group of plants has the potential for both 

capacity restoration (20,000 MWs) and/or capacity maximization (20,000 MWs). Thus, the total amount 

of potential increased MW output of this existing group of units is approximately 40,000 MWs. This 

increased capacity could be achieved within 36 months. 

If all existing conditions resulting in a derating could be addressed, approximately 20,000 MWs of 

increased capacity could be obtained from regaining lost capacity due to unit deratings. This increase 

would be achieved using the approaches and techniques in Table 1 below.

Approximately an additional 20,000 MWs of capacity could be gained if it were possible to increase heat 

input and/or electrical output from generating equipment while still maintaining the acceptable design 

margins and allowable code ratings of the equipment. The approaches and techniques would be similar to 

those for regaining capacity, as indicated in Table 1. 

These approaches and techniques could only be logically pursued by the facility owners if it was clearly 

understood that the increased availability and/or electrical output would not trigger New Source Review 

(NSR) and if repowering or construction of new clean coal technologies would be subject to the 

streamlined permitting authorized by the 1990 CAA Amendments.

The techniques to recover lost capacity and to increase capacity above MDGC have been collected from a 

combination of research studies by utility industry organizations (such as EPRI) and actual case studies 

(such as those outlined below) which had benefits for plant owners. They are summarized in Table 1 

below.
10

TABLE 1

Techniques and Approaches for Coal-Fired

Power Plants Capacity Restoration and Increase

Capacity

Increase Method

Capacity 

Restoration

Efficiency/ 

Capacity 

Increase

Fuel 

Conversion/ 

Repowering

Installation of improved air pollution control 

equipment X X X

Steam turbine modernization improvements and 

upgrades X X

Coal washing X X

Coal switching X X

Repowering with CFB technology X

Consolidation of multiple, smaller inefficient 

units to larger, more efficient units X X

Operating above the nameplate but within the 

plant design X X

Control system improvements X X

Plant efficiency improvements X X

The techniques and approaches listed in Table 1 have been implemented with proven results. The

following highlights are from case studies. 

o SCR and FGD emissions control equipment was installed on a coal- fired generating station to 

reduce emissions of SOx and NOx. In order to offset the increased auxiliary load (16 MWs) of these 

new systems, an upgrade of the original 500-MW (nominal rating) steam turbine was performed. The 

upgrade consisted primarily of a new high-efficiency, high-pressure rotor with increased number of 

stages and an optimized steam path. The upgrade resulted in an output increase of approximately 15 

MWs, almost offsetting the auxiliary load increase from the new emission controls. 

o Turbine upgrades were completed on two 400-MW rated units to obtain an additional 25 MWs per 

unit. No additional steam was required from the boiler. No changes were made to the boiler. A more 

aerodynamic steam path through the turbine was designed and installed.

o Turbine upgrades were incorporated into another unit, nominally rated at 500 MWs achieving an 

additional 25 MWs. In this case, more steam had to be generated in the boiler and the steam turbine 

was upgraded.

o Coal cleaning is a process whereby a coal that is high in ash and sulfur is “washed.” As a result, the 

coal is lower in both ash and sulfur content and higher in thermal value. The method consists of a 

multi-circuit wet process where water is used for screening and separation. Coal cleaning is a costeffective means of separating ash and sulfur from coal, which in turn reduces opacity and SO2

emissions. This enables one facility to continue to use local, lower cost, higher ash and sulfur coal 

and meet environmental limits. Without this coal cleaning process, the facility’s load would be 

limited by approximately 10% due to opacity restrictions.

o Coal switching is an alternative to coal cleaning. In some cases where coal has been switched to 

reduce SOx emissions, the capacity may be impaired unless fuel handling systems are upgraded to 

allow efficient use of lower sulfur fuels.

o Repowering with CFB technology is an alternative to installing NOx and SOx emissions equipment. 

The use of this technique is highly site and fuel specific.

o Capacity increases can be accomplished by taking a brownfield site with several smaller old units, 

and repowering the site with a single large unit. This will require the full environmental permitting 
11

process. It is a technique that is highly site specific and economically driven. To make the economics 

attractive, it is important that the units are running at low dispatch levels, so income losses are 

minimized, and the site can be readily cleared for construction of the larger unit. 

o Control system improvements can increase capacity in older plants. Modern control systems can 

improve efficiency and reduce emissions by optimizing the combustion process. General 

improvements to plant efficiency can be obtained by improved operating and maintenance practices 

along with targeted equipment improvements.

Note: The additional 20,000 MW that can be achieved by capacity restoration described in this section 

includes the 10,000 MW of capacity that can be recovered due to deteriorated availability described 

earlier in the report.

Opportunities for Greenfield Sites and Repowering

Existing Facilities with Pulverized Coal Power Generation

As a result of ongoing technology development, new and retrofitted pulverized coal power plants have 

achieved outstanding emissions performance for NOx, SOx, and particulates. Similarly, continued 

advances in the steam cycle continue to provide higher net plant efficiencies. As a result, new pulverized 

coal-fired power plants are now commercially available with minimal emissions and with very favorable 

total production cost. Repowering of an old existing coal-fired power plant with a single modern 

generating unit equipped with commercially proven emissions controls results in significant reductions in 

total tons of emissions, even while substantially increasing the total megawatt-hour output of the facility. 

A case study of repowering an actual old coal-fired plant with a unit utilizing current technology showed 

a 32% higher design capacity, achieving triple the total electrical output, an 87% reduction in tons of NOx 

and SOx up the stack, and a 42% reduction in total electricity production costs.

Pulverized Coal Technology Options

The configuration of today’s state-of-the-art pulverized coal power plant is primarily dependent on the 

sulfur quantity of the coal to be utilized.

Low sulfur coals will most economically utilize a dry scrubber and baghouse for SO2 and particulate 

control. Wet scrubbers can also be utilized with the benefit of producing a useful byproduct (gypsum).

Higher sulfur coals will utilize a wet scrubber and precipitator or baghouse for SO2 and particulate 

control.

NOx emissions will be controlled by both Low NOx Burners (LNB )and Selective Catalytic Reduction 

(SCR).

The boiler/turbine steam cycle will vary from a standard subcritical cycle to an advanced supercritical 

cycle depending on project requirements and fuel costs.
12

Example: Low Sulfur Coal Configuration with representative emissions performance.

Subcritical or 90% + NOx 90-95% SO2 Removal Particulate

Supercritical Removal SO2 < 0.25 lb/MBtu 0.03 lb/MBtu

NOx = 0.15 lb/MWh

Example: High Sulfur Coal Configuration with representative emissions performance.

Subcritical or 90% + NOx Particulate 95%+ SO2 

Removal

Supercritical Removal 0.03 lb/MBtu SO2 = 0.25 

lb/MBtu

NOx = 0.15 lb/MWh

Heat Rate

Over the last 10 years, higher efficiency pulverized coal plants have been placed in commercial 

operation. The higher efficiencies are due not only to advanced pressure and steam cycles, but 

also to improvements in turbines and reductions in auxiliary power requirements. Pulverized coal 

power plant heat rate improvements versus steam parameters are shown below. (The actual 

operating plants have steam parameters close to the examples under which they are listed.)

slide #6

0

1

2

3

4

5

6

7

3600psi,

1000F/1000F

3600psi,

1000F/1050F

3600psi,

1050F/1050F

3600 psi,

1050F/1100F

3600 psi,

1100F/1100F

4500psi,

1100F/1100F

4500 psi,

1100F/1150F

4500psi,

1100F/1100F/1100F

Net Plant Efficiency Improvement

 (percentage points) HHV

Matsuura 2-1997

Misumi 1-1998

Haramachi 2-1998

Tachibana Bay-2000

Bexbach-2002

Nanaoota 1-1995 Nordjylland -1998

Noshiro 2-1995

Haramachi 1-1997

Millmerran-2002

Lubeck-1995

Alvedore 1-2000

Westfalen-2004

Net Plant Efficiency Improvement

Advanced Supercritical Plants versus Subcritical 2400psi/1000F/1000F

Boiler SCR Dry Scrubber Baghouse

Boiler SCR

Precipitator

 or

Baghouse

Wet Scrubber
13

The summary point is that higher efficiency cycles are now being demonstrated with commercially 

required availability/reliability. Higher efficiency cycles will reduce the production cost by 

reduced fuel consumption and will result in a lower capital cost for all of the environmental 

equipment (on a $/kW cost basis). The ambient air emissions levels (NOx, SOx, particulate, and 

mercury) will primarily be a function of the emissions control devices installed (SCR, scrubber, 

baghouse, etc.). More efficient plants will provide an emissions reduction as well. For the U.S. 

market, the economically optimum cycle efficiency will be very project specific. However, 

today’s advanced cycles have been demonstrated commercially and can be applied where project 

economics dictate.

Emissions Performance

NOx

Significant improvements in NOx emissions are being achieved in pulverized coal-fired power plants 

today. This is through both advances in Low NOx Burner Combustion technology and advances in 

Selective Catalytic Reduction systems, both of which are being widely applied. Low NOx Burner 

Combustion technology has resulted in combustion NOx levels being in the range of 0.15 to 0.30 

lb/MBtu, depending on the coal. Selective catalytic reduction systems are in operation with NOx removal 

efficiencies up to 90-95%. An existing plant retrofit this year with an SCR will result in NOx emissions 

of approximately 0.30 lb/MWh, (approximately .03 lb/MBtu which is lower than the best natural gas 

combined cycle unit utilizing dry Low NOx Combustion, according to the most recent EPA actual 

operating data). 

New pulverized coal power plants, through the application of commercially demonstrated Low NOx 

Burners and SCRs, can achieve NOx emissions as shown in the table below. In order to compare NOx 

emissions with natural gas-based power generation, the performance is reported in lb NOx per MWh.

NOx Emissions Performance

New Pulverized Coal Power Plant

0

1

2

3

4

5

6

NOx Emissions lb/MWh

5.5

1.68

0.29 to 0.70 0.19 to 0.70

5,407,999 tons 1998

Ck/NCC2-26-01.ppt

1998

National*

Average

Coal

EPA New

Source

Perf

New Bitiminous Coal

Low NOx Brnr

SCR

New Powder River

Basin Coal

Low NOx Brnr

SCR

*EPA Actual 1998

}

Project

Dependent
14

The NOx emissions performance represented in this section of the report and in the two case studies is 

derived from applying the state of the technology, Low NOx Burners, with the state of the technology 

Selective Catalytic Reduction Controls. These are applied to representative Eastern and Western coals 

and typical project parameters. The actual NOx emissions that can be obtained from a given new coalfired project will depend on the analysis of the actual coal to be burned. It will also depend to some 

extent on the local ambient air conditions and condenser water availability and temperatures, which will 

impact the available heat rate of the cycle. The actual achievable NOx emissions rate for a given project 

can only be determined after the specific project and fuel parameters have been defined.

It should also be noted that this section of the report only addresses new, coal-fired generating plants. 

Whereas significant NOx reductions can be achieved from retrofits to an existing coal-fired generating 

unit, in many cases constraints from the original furnace design or other project constraints that cannot be 

modified will result in it not being possible to achieve the same NOx reductions on a retrofit as will be 

available for a greenfield generating unit that has maximum design flexibility for the boiler and 

environmental equipment.

SOx

Similarly, outstanding performance is being demonstrated on low SOx emissions technology, from 

a number of pulverized coal-fired power plants ranging from high sulfur Eastern bituminous coals 

to low sulfur Western coals. The graph shown below reflects actual SOx emissions from a number 

of coal-based power generating facilities as reported in the EPA 1998 Annual Emissions. In 

summary, the technology is available and is being commercially demonstrated to achieve 

extremely low SO2 emissions.

SOx Emissions Performance

EPA 1998 Annual Emissions

0.0

0.5

1.0

1.5

SOx Emissions lb/Mbtu

1.22

.51

.09

.06 .04

Ck/1-22-01.ppt

98 National

Average

Coal

98 Avg.

Wet

Scrubbers

Harrison

WVA

Bituminous

Coal

3.4%S

WFGD

Navajo

AZ

Sub-Bit.

0.52% S

WFGD

Intermountain

Utah

Sub-Bit.

0.52%S

WFGD

12.4M TonsSO2

Clover

VA

Bituminous

Coal

1.1%S

WFGD

.06 .10 .09

Craig 3

Colorado

Sub-Bit.

Coal

0.39% S

DFGD

Rawhide

Colorado

Sub-Bit.

Coal

0.25% S

DFGD

WFGD = Wet Scrubber

DFGD = Dry Scrubber
15

Particulate

High efficiency precipitators and baghouses are routinely achieving particulate emissions levels 

under .020 lb/MBtu. 

Mercury

Significant mercury removal research from pulverized coal power plants has been underway over 

the last 10 years. In 2001, this will culminate in plant demonstrations for Advanced Mercury 

Removal Systems at Alabama Power’s Gaston Station, Michigan South Central’s Endicott Station, 

and Cinergy’s Zimmer Station. These demonstrations are aimed at positioning coal-fired power 

plants for the announced future regulation of mercury emissions. Additionally, aggressive 

research and plant demonstrations are underway to substantially reduce mercury emissions. 

Pulverized Coal Power Plant Applications

Following are two cases, which illustrate the impact of building new pulverized coal power 

generation plants. 

1. Greenfield site or addition of a new generating unit to an existing power plant.

This case shows typical plant efficiencies, emissions levels, electricity produced, 

and production costs for new pulverized coal power plants for both a low and high 

sulfur coal options.

2. Repowering of an old existing pulverized coal-fired power plant.

This case examines the performance emissions and production cost of repowering an entire old, 

coal-fired power plant consisting of multiple old, low-efficiency units that have high emissions 

rates with a single modern pulverized coal-fired generating unit.

Case 1

This case examines the efficiency, emissions performance, and production cost for adding a new coalfired generating unit, either to a Greenfield site or to an existing power plant. Performance is shown for 

both an eastern bituminous coal and a Powder River Basin Coal Plant.
16

TABLE 2

New Pulverized Coal Power Plant

Low Sulfur PRB Coal High Sulfur Bit. Coal

Coal Heating Value Btu/lb 8,000 12,500

Coal % Sulfur % 0.4 3.5

Steam/Turbine Cycle Supercritical Subcritical Supercritical Subcritical

Net Plant Heat Rate Btu/kWh 8900 9600 8500 9200

Net Plant Efficiency HHV 38.3% 35.6% 40.1% 37.1%

Net Plant Efficiency LHV 41.6% 39.8% 42.2% 39.0%

Emissions - Ranges

Combustion NOx lb/Mbtu 0.20 to 0.40 same 0.40 to 0.50 same

SCR % NOx Removal % 80 to 90 same 85 to 92 same

Outlet NOx lb/Mbtu 0.020 to .080 same 0.032 to .075 same

Outlet NOx @ 3% 02 ppm 14 to 58 same 23 to 54 same

Outlet NOx @ 15% 02 ppm 5 to 20 same 8 to 18 same

Outlet NOx lb/MWh .18 to .70 .19 to .75 .28 to .66 .29 to .69

Uncontrolled SO2 lb/Mbtu 1.0 same 5.6 same

Scrubber % SO2 Removal % 90 same 95 same

Outlet SO2 lb/Mbtu .10 same .28 same

Outlet SO2 lb/MWh .89 .96 2.38 2.58

Coal Cost $/MBtu 1.22 1.22 1.22 1.22

Fuel Production Cost $/MWh 10.86 11.71 10.37 11.22

Non-Fuel O&M Cost $/MWh 3.50 3.50 3.50 3.50

Total Production Cost $/MWh 14.36 15.21 13.87 14.72

Total Production Cost

The curve below shows the variable production cost (Fuel + O&M, excluding capital investment 

costs) for all the coal-fired power plants in the U.S. in 1998 (UDI data). 

The curve is a plot of the variable production cost of every coal-fired power plant, ranked from the 

lowest to the highest. It only shows the fuel and O&M cost, and not the sunk capital costs. This 

would also indicate the relative order of competitive dispatch.

Also shown on the curve is the variable production cost for the two plants discussed in the case 

studies. This shows that the total production costs for a new pulverized coal plant will be 

significantly lower than most of the existing coal fleet and will assure high capacity factors.
17

Case 1

Total Emissions Level

The total NOx and SOx emissions are significantly lower than what is being achieved in the 

existing coal-fired power plants today.

Total Emissions Performance

Table 3 (below) places a value on the total NOx and SOx emissions based on assumed allowance 

values for the examples in this case. To illustrate the low emissions level, the total outlet NOx and 

SOx emissions are given a monetary cost based on assumed allowance costs. When the emissions 

costs are stated as a production cost in $/MWh, it can be seen that these do not change the very 

favorable total production cost of electricity.

Ck/1-22-01.ppt

$/Mwh

US Coal Plant Production Costs (UDI 1998)

Excluding capital charges for past Investment (sunk costs)

New PC

Coal Plants
18

TABLE 3

Low Sulfur PRB Coal Eastern Bituminous Coal

Supercritical Subcritical Supercritical Subcritical

NOx Allowance Value (assumed) $/ton 1000 1000 1000 1000

Outlet NOx lb/MWh .18 .19 .28 .29

NOx Allowance Cost $/MWh .09 .10 .14 .15

SOx Allowance Value (assumed) $/ton 200 200 200 200

Outlet SO2 lb/MWh .89 .96 2.38 2.58

SOx Allowance Cost $/MWh .09 .10 .24 .26

Total Emission Allowance Cost $/MWh .18 .20 .38 .41

Case 2: Coal Power Plant Repowering

This case considers the repowering of an existing Eastern U.S. coal-fired power plant, burning low 

sulfur Eastern bituminous coal. The plant consists of six generating units that were built between 

1949 and 1956, with a composite average net plant efficiency of 29.4%. The total gross 

generating capacity from all six units is 387 MW. The plant has no emission controls for NOx and 

SOx except for Low NOx Burners on one of the units. 

The plant is repowered by replacing the boiler and turbine islands for all six units with a single 

506-MW supercritical boiler/turbine, with an average net plant efficiency of 38.8%. The plant’s 

coal receiving and handling, ash disposal, and electrical distribution infrastructure is retained 

where possible. The repowered unit is redesigned for the same heat input as the original six units; 

Low NOx Burners, an SCR, a dry SO2 scrubber, and baghouse are added. The same coal is used 

in the repowered unit as is currently being burned.

Table 4 shows the actual operating performance from this plant for 1998 and the projected 

repowered performance in 2004. 

In summary, with the plant repowered at the same heat input, it will now be rated at 31% higher 

megawatt output and operating efficiency. Both the NOx and SOx emissions will be reduced by 

87% of the actual 1998 emissions in tons. The total production cost per megawatt-hour will be 

reduced 42%. Because of the low production cost, the unit will be base loaded with a high 

capacity factor, which will result in more than triple the actual megawatt hours produced during 

the year.
19

TABLE 4

Case 2

Repowering Existing Coal Plant

Existing Plant

1998 Actual

Operating Data

Repowere

d 2004 

Performan

ce

Improve

ment

%

Design Plant Total Heat Input 

MBtu/hr

4140 4140

Nameplate MW 387 506

Total # of Units 6 1

Total Actual MWh 1,082,180 3,544,296 +327%

Total Actual Capacity Factor 31% 85%

Heat Rate – Annual Average Btu/kWh 11,594 8,800

Average Plant Efficiency HHV 29.4% 38.8% +32%

Average Plant Efficiency LHV 30.9% 40.8%

NOx Tons – annual 3536 468 -87%

NOx Emission Rate lb/MBtu 0.509 .03

NOx Emissions Rate lb/MWh 5.9 0.26

Coal % S 1.08 1.08

SOx Tons Annual 12,881 1565 -88%

SOx Emissions Rate lb/MWh 23.8 0.88

Fuel Cost $/MBtu 1.05 1.05

Fuel Production Cost

Annual Avg $/MWh

12.18 9.26

Non-Fuel (OEM) Production Cost 

Annual Average $/MWh

9.87 3.57

Total Production Cost $/MWh $22.04 $12.83 -42%
20

Opportunities for Greenfield Sites and Repowering

Existing Facilities with Coal-Based Power Generation

When considering coal-based technologies for both greenfield applications and repowering of 

existing facilities, utilities have several primary options to consider. In addition to the modern 

pulverized coal technologies described earlier, integrated gasification combined cycle (IGCC) has 

become a viable, commercially available technology. With successes from the Clean Coal 

Technology Program in both new and repowered projects, much has been learned about IGCC 

performance, heat rate, cost, and emissions performance. This information, which has been widely 

published, has become an important tool for evaluation of this technology by electric utilities. 

IGCC Technology Options

The diagram below shows a typical IGCC plant. The coal gasification process replaces the 

conventional coal-burning boiler with a gasifier, producing syngas (hydrogen and carbon 

monoxide) that is cleaned of its sulfur and particulate matter, and used as fuel in a gas turbine. The 

power generation cycle is completed through the use of the Heat Recovery Steam Generator 

(HRSG) and steam turbine, just as in a natural gas-fired combined cycle (NGCC) plant, offering 

the high efficiency and continual advances achieved with this equipment configuration. 

The two primary technologies which have had the most success in the U.S. are Texaco’s oxygen-blown, 

entrained-flow gasifier (Tampa Electric Company’s Polk Power Station, a greenfield plant) and the 

Global Energy E-Gas (formerly Destec) oxygen-blown, entrained-flow gasifier (Cinergy/PSI Energy’s 

Wabash River Station, a repowering project at an existing power plant). 

In the Texaco gasification process, a down-flow slurry of coal, water, and oxygen, are reacted in the 

process burner at high temperature and pressure to produce a medium-temperature syngas. The syngas 

moves from the gasifier to a high-temperature heat recovery unit, which cools the syngas while generating 

Steam

Clean Syngas

End 

Feeds Products

Gas 

Cleanup

Coal

Oxygen

Electricity

Sulfur

Slag

Gas & Steam

Turbines

Gasification

Combined Cycle

Power Block

 SULFUR

RECOVERY Byproducts:

 SULFUR

REMOVAL

Coal IGCC Process1

1 Texaco Gasification Process (TGP)
21

high-pressure steam. The cooled gases flow to a water wash for particulate removal. Molten ash flows out 

of the bottom of the gasifier into a water-filled sump where it is forms an inert solid slag. Next, a COS 

hydrolysis reactor converts COS into hydrogen sulfide. The syngas is then further cooled in a series of 

heat exchangers before entering a conventional amine-based acid gas removal system where the hydrogen 

sulfide is removed. The sulfur may be recovered as sulfuric acid or molten sulfur. The cleaned gas is then 

reheated and sent to a combined-cycle system for power generation. 

The Global Energy E-Gas process uses a slurry of coal and water in a two-stage, pressurized, upflow, 

entrained-flow slagging gasifier. About 75% of the total slurry is fed to the first (or bottom) stage of the 

gasifier. All the oxygen is used to gasify this portion of the slurry. This stage is best described as a 

horizontal cylinder with two horizontally opposed burners. The gasification/oxidation reactions take place 

at temperatures of 2,400 to 2,600oF. Molten ash falls through a tap hole at the bottom of the first stage 

into a water quench, forming an inert vitreous slag. The hot raw gas from the first stage enters the second 

(top) stage, which is a vertical cylinder perpendicular to the first stage. The remaining 25% of the coal 

slurry is injected into this hot raw gas. The endothermic gasification/devolatilization reaction in this stage 

reduces the final gas temperature to about 1,900oF. The 1,900oF hot gas leaving the gasifier is cooled in 

the fire-tube product gas cooler to 1,100oF, generating saturated steam for the steam power cycle in the 

process. 

Particulates are removed in a hot/dry filter and recycled to the gasifier. The syngas is further cooled in a 

series of heat exchangers. The syngas is water scrubbed to remove chlorides and passed through a COS 

hydrolysis unit. Hydrogen sulfide is removed in the acid gas columns. A Claus unit is used to produce 

elemental sulfur as a salable by-product. The clean syngas is then moisturized, preheated, and sent to the 

power block. 

In Europe, Global Energy has successfully used the British Gas/Lurgi (BGL) gasification process. In the 

BGL process, the gasifier is supplied with steam, oxygen, limestone flux, and coal. During the 

gasification process, the oxygen and steam react with the coal and limestone flux to produce a raw coalderived fuel gas rich in hydrogen and carbon monoxide. Raw fuel gas exiting the gasifier is washed and 

cooled. Hydrogen sulfide and other sulfur compounds are removed. Elemental sulfur is reclaimed and 

sold as a by-product. Tars, oils, and dust are recycled to the gasifier. The resulting clean, medium-Btu fuel 

gas is sent to a gas turbine. Based on the success of the BGL process at the Schwarze Pumpe GmbH plant 

in Germany, Global Energy is building two plants in the U.S. The 400-MW Kentucky Pioneer Project and 

the 540-MW Lima Energy Project will both use BGL gasification of coal and municipal solid waste to 

produce electric power. The Kentucky project is being partially funded by DOE. 

Heat Rate

DOE reports the Polk Power Station heat rate to be 9,350 Btu/kWh, with Wabash River at 8,910 

Btu/kWh. These equate to about 38.4% and 40.2% (LHV) respectively. Overall IGCC plant efficiency of 

45% LHV is likely to be demonstrated with the enhancements developed from the Clean Coal 

Technology Program projects and continued advances in gas turbine technology. As part of its Vision 21 

Program, DOE has set a 2008 performance target of 52% on an HHV basis (about 55% LHV) for IGCC.

Emissions Performance

With gas becoming the fuel of choice for most new units, permitting agencies and environmental groups 

have become used to seeing very low emission limits for new units. Further, they have come to expect 

that repowering existing units should also meet those same low levels, regardless of economics or fuel 

choice. IGCC can approach the environmental performance of natural gas-fired power plants, opening 

the door for its application in new and repowered plants. As part of the Vision 21 Program, DOE has set a 
22

2008 performance target of 0.06 lb/mmBtu for SO2, 0.06 lb/mmBtu for NOx, and 0.003 lb/mmBtu for 

particulate matter. 

Conventional power plants that are candidates for repowering are typically 40-50 years old. Historically, 

the small upgrades and modifications that were made to maintain capacity or increase efficiency did not 

subject the utility to the New Source Review (NSR) process. With EPA’s coal-fired power plants 

enforcement activities, many utilities are under enforcement pressure to meet very strict NSR limitations 

for SO2, NOx, and particulates. Compliance with these limitations usually means retrofit with flue gas 

desulfurization (FGD) for SO2 control, selective catalytic reduction (SCR) for NOx control, and possibly 

even upgrades to the electrostatic precipitator for increased particulate control. With such units being near 

the end of their economically useful lives, adding additional controls may not make economic sense for a 

unit that may be shut down in a few years.

Repowering with IGCC allows the utility to maintain or increase capacity, while significantly improving 

environmental performance and producing low-cost power. The coal gasification process takes place in a 

reducing atmosphere at high pressures. In the gasifier, the sulfur in the coal forms hydrogen sulfide, 

which is easily removed in a conventional amine-type acid gas removal system. The concentrated 

hydrogen sulfide stream can then be recovered as elemental sulfur or sulfuric acid, and sold as a 

commercial byproduct, eliminating the need to dispose of large amounts of combustion byproducts. The 

clean syngas is sent to the gas turbine to be burned. With the addition of nitrogen into the turbine for 

power augmentation, the combustion flame is cooled, minimizing NOx formation and eliminating the 

need for SCR. 

Many existing coal-fired plants are also affected by the NOx SIP call, and utilities are facing the 

installation of SCR on these existing units in order to comply. With changes in utility regulation, and the 

age of the units, the economics of these retrofits presents a challenge to continued operation of the units. 

Further, the possibility of stricter limitations on SO2 or other emissions in the next few years presents 

another layer of economic decisions. While the unit may still be economic to dispatch following the 

installation of SCR, the addition of FGD may not allow that to continue. In that case, the utility would 

face the stranding of its SCR assets after only a few years of operation. Repowering with IGCC would 

provide the utility with the ability to maintain or even increase capacity, meet NOx limitations, and 

prepare for stricter SO2 emission limitations. 

While the retrofit of emission controls reduces emissions, it leads to secondary environmental issues, such 

as the large amounts of land needed to dispose of the new FGD byproduct and groundwater protection. 

The SCR system raises issues regarding local exposure to risks of accidental release of ammonia and 

disposal of the SCR catalyst. 

In the gasifier, the ash in the coal melts, and is recovered as a glassy, low permeability slag which can be 

sold for use in making roofing shingles, as an aggregate, for sandblasting grit, and as an asphalt filler. 

With the sulfur also recovered as a commercial byproduct, repowering with IGCC can eliminate the solid 

waste issues that utilities might face when retrofitting conventional coal-fired plants with FGD and SCR. 

With EPA’s recent determination to regulate mercury emissions from coal-fired units, utilities will face 

additional potential requirements for the retrofit of control equipment. With the reducing atmosphere, and 

by operating a closed system at high pressures, IGCC releases of mercury are minimized. Initial 

information from EPA’s mercury-based Information Collection Request shows promising results for 

IGCC, with as much as 50% of the mercury in the coal feedstock reduced or removed, much of it bound 

in the slag and sulfur byproducts.
23

Another issue that utilities will potentially face in the near future is the need to reduce CO2 emissions. 

The existing coal-fired fleet in the U.S. is responsible for about one-third of all of the CO2 emissions. 

While automobiles and other industries make up a large portion of U.S. CO2 emissions, coal-fired power 

plants are an easier target to identify, measure, and control. Due to its high overall efficiency, repowering 

an existing coal-fired power plant with IGCC can reduce CO2 emissions by as much as 20%. 

Overall, repowering with IGCC provides a utility with significant increases in environmental 

performance. By reducing SO2 and NOx emissions, minimizing solid waste disposal issues, and 

addressing potential near-term emission limitations for mercury and CO2, repowering with IGCC allows 

the utility to move forward with the knowledge that it has addressed environmental issues effectively. 

For capacity additions and repowering over the next five years, IGCC is an option that utilities can 

seriously consider. 

IGCC Power Plant Applications

Recent History and Applications

Coal gasification technology has been used for over a hundred years. The production of town gas

worldwide is a simple form of gasification. Coupling this proven technology with efficient combined 

cycle technology was seen as a way to enjoy the advantages of using low-cost coal with the high 

efficiency of combined cycle technology. The 100-MW Cool Water IGCC project, which went in service 

in 1984, was the first commercial-scale demonstration of IGCC. That project was done in a consortium of 

EPRI, Southern California Edison, Texaco, GE, Bechtel, and others. The plant operated for more than 

four years, achieving good performance, low emissions, and developing a base of design for full-scale 

IGCC plants.

Since then, IGCC technology has improved greatly through DOE’s Clean Coal Technology program. The 

Wabash River IGCC Project and Polk Power Station IGCC Project are in operation as a part of this 

program. Installations in other countries include the Buggenum plant in the Netherlands and the 

Puertollano plant in Spain. IGCC performance and reliability continues to see significant improvements. 

In the fourth year of operation of Tampa Electric’s Polk Power Station, the gasifier had an on-stream 

factor of almost 80%, a considerable improvement over previous years. This project no longer suffers 

from the serious problems encountered over the first three years, including convective syngas cooler 

pluggage, piping erosion and corrosion, and sulfur removal problems. The on-going pluggage problems in 

the convective syngas coolers have been resolved by modifying start-up procedures to minimize sticky 

ash deposits, and by making configuration changes in the inlet to the coolers to reduce ash impingement 

at the tube inlets. In the fourth year, the coal gasification portion of the plant became so reliable that the 

leading cause of unplanned downtime was not there, but rather in the distillate oil system for the gas 

turbine (problem has been addressed).

Reliable performance has also been achieved at the Wabash River plant. During 2000, the gasification 

plant reached 92.5% availability, with the power block at 95%. In fact, the gasification technology caused 

no plant downtime at all. Other areas of the plant, such as coal handling and the air separation unit were 

available more than 98% of the time.

IGCC for New and Repowered Plants

These examples show that IGCC has met the challenges of the Clean Coal Technology program. Further, 

with almost 4,000 MW of IGCC in operation worldwide, and another 3,000 MW planned to go into 
24

operation over the next four years, this technology is commercially proven and ready for the repowering

market. 

The U.S. now has about 320,000 MW of coal-fired power plants, just over one-third of all installed 

capacity. These coal-fired power plants generate over half of all of the electricity in the U.S. Many of 

these plants are over 30 years old, with some over 50 years of age. With a growing need for additional 

capacity in many parts of the country, and rising operation and maintenance costs on existing units, many 

utilities are looking hard at repowering with technologies that can increase capacity, while decreasing 

operation and maintenance costs. 

Repowering with IGCC can meet those challenges. Repowering older, less efficient generating units with 

IGCC, results in capacity increases, lower production costs, higher efficiency, and environmental 

compliance. Since the IGCC plant uses coal as its feedstock, much of the existing coal-fired plant’s coal 

handling and steam turbine equipment and infrastructure can be utilized, lowering the overall cost of 

repowering. With greater than 95% of the sulfur emissions removed, and further improvements in 

combustion turbine low-NOx burner technology, emissions of SO2 and NOx now approach the 

performance of NGCC plants. By using low-cost and/or low-quality coals, the cost of electricity 

generated from a plant repowered with IGCC technology can meet or beat that produced by NGCC 

plants. 

One of the key efficiency advantages comes with oxygen-blown IGCC technology. In this type of 

gasification system, air is first separated into its main constituents: oxygen and nitrogen. The oxygen is 

used in the gasifier, and the nitrogen is injected into the gas turbine, where it increases the mass flow 

through the gas turbine, increasing power output, and minimizing NOx formation during combustion. 

Efficiency increases through further integration can be realized by using extraction air from the gas 

turbine in other areas of the plant. Since this extraction air leaves the gas turbine at high temperature and 

pressure, it can be used to preheat boiler feed water. After the heat is removed, the cooled air, still at high 

pressure, is used to feed the air separation unit, reducing the amount of energy expended there to 

compress air. 

A typical method of repowering an existing unit is to remove the coal-fired boiler and replace it with a 

gas turbine, re-using the steam turbine in combined cycle mode. In a combined cycle plant, the steam 

turbine usually provides about one-third of the total output. In a recent study conducted for DOE, a large 

number of plants with twin 150 MW units were identified as good candidates for repowering. There, the 

utility could repower one of the units with two 170 MW natural gas-fired gas turbines. The steam 

produced by the HRSGs for these units would power the existing 150 MW steam turbine, for a total of 

almost 400 MW. 

A typical F class gas turbine produces about 170 MW when firing natural gas. At high ambient 

temperatures, output may fall to only 150 MW. In an IGCC plant, the syngas is fired in the gas turbine 

along with the nitrogen, providing significantly higher overall mass flow over a wide range of ambient 

temperatures. When firing syngas, this same F class gas turbine produces about 20% more output, 

reaching 190 MW or more. This additional capacity from firing syngas is valuable when additional 

peaking power is needed during hot, summer days. The additional exhaust flow results in more steam 

production in the HRSG, making up for steam uses in the gasification area. By firing syngas, the overall 

capacity is increased to almost 550 MW, more than tripling the capacity of the unit. Repowering the twin 

150-MW unit could increase the overall capacity from the original 300 MW to almost 1,100 MW. 

While the typical repowering study targets coal-fired boilers, existing NGCC units also provide a 

technical and economic opportunity for repowering with IGCC. In the case of NGCC units presently 

firing natural gas, rising fuel costs have lead to increases in the cost of producing electricity. This 
25

typically results in a lower capacity factor, and the unit generates fewer MW-hours and revenues. Given 

the inherent high efficiency of the gas turbines, and the ability to utilize low-cost coal, repowering with 

IGCC can turn an NGCC unit with a high dispatch price into a unit that dispatches at a much lower cost. 

As described above, the additional 20% capacity gained from firing syngas instead of natural gas can 

have significant economic value in areas where there is insufficient peaking power capacity. 

IGCC technology has become a more attractive option for new capacity because:

o the technology has been successfully demonstrated at commercial scale in the U.S. and worldwide;

o the enhancements made by the companies operating these IGCC plants, as well as by the technology 

suppliers, have decreased the cost and complexity of IGCC, while at the same time substantially 

improving the efficiency and reliability; and

o the price differential between natural gas and coal has risen sharply over the last year.

Economics

The ability to repower units and gain the capacity increases noted in the previous section is a

major economic driver for repowering with IGCC. Another advantage of repowering with IGCC is 

the ability to reuse a significant amount of the existing infrastructure at the plant. Areas such as

buildings, coal unloading, coal handling, plant water systems, condenser cooling water,

transmission lines, and substation equipment can be incorporated into the repowered IGCC plant

This helps to minimize the time for repowering and can reduce the overall cost by about 20%. 

With uncertainty in the pace and extent of utility industry restructuring, as well as with changes in 

environmental regulations, utilities have been reluctant to make large capital expenditures for new

capacity. Almost all of the capacity installed over the last few years has been natural gas-fired gas 

turbines and NGCC. With ongoing decreases in the cost per kW for NGCC technology, along with 

forecasts of low natural gas prices, NGCC has been the choice for almost all of the new planned

baseload capacity in the U.S. Most of this new generation has been built and is being planned in

states that have completed their electric utility industry restructuring, making for easier entry into

power markets. Unfortunately, the greatest needs for new generation have been in California and

the Southeast where deregulation has either been incomplete, inconsistent, or delayed. 

With recent increases in the price of natural gas, and stability or even decreases in coal costs, the 

electric utility industry has renewed its interest in coal-based technologies. Announcements by

Tucson Electric Power and Wisconsin Electric Power to build the first coal-fired power plants in

years puts coal back in the picture for new capacity. One important result of the improved

performance of existing IGCC plants has been an overall decrease in second-generation IGCC

plant capital costs. If the current differential price between coal and natural gas continues or grows 

larger, the economics for repowering with IGCC will become even more attractive. 

In the paper “EPRI Analysis of Innovative Fossil Fuel Cycles Incorporating CO2 Removal,” 

various power generation technologies were analyzed with and without CO2 removal systems, in a 

study performed by Parsons. The allowable capital costs were analyzed to determine a break-even 

cost of electricity based on a range of gas prices. For IGCC, the break-even point with $5/mmBtu 

gas was found to be about $1,200/kW, dropping to about $1,000/kW with $4/mmBtu gas prices.

As IGCC plant costs continue to decrease, it will become an even more serious choice for

repowering. If CO2 removal is required in the future, the costs shown in the study for CO2 removal 

and the cost of producing electricity from IGCC will be competitive with NGCC at gas prices of

only $3.70-4.00/mmBtu. 
26

Reducing Regulatory Barriers

The Clean Air Act (“CAA”) imposes a number of regulatory burdens on the expansion of electric 

generating capacity. EPA’s recent interpretations of several existing laws have led to confusion 

and perhaps additional burdens. Formally proposed EPA revisions to existing CAA programs may 

impose further burdens if they are adopted. These burdens impact three activities that increase 

U.S. generating capacity: (1) the construction of new units; (2) efficiency and availability

improvements at existing units; and (3) the repowering or reactivation of existing units.

New Construction

The CAA provides two main programs to control emissions from new coal-fired sources: New 

Source Performance Standards (“NSPS”) and New Source Review (“NSR”). Both programs are 

intended to require the adoption of controls at the time it is most economical to do so – when a 

new unit is designed and built.

A utility wishing to construct a new coal-fired generating station must comply with NSPS. NSPS

require new sources to meet numerical emissions limitations based on the best technology that 

EPA determines has been “adequately demonstrated.” EPA revises these standards periodically to 

reflect advances in emissions control technology.

In areas that are in attainment with National Ambient Air Quality Standards (“NAAQS”), a new 

major source also must comply with prevention of significant deterioration (“PSD”) requirements. 

PSD rules require new sources to adopt the “best available control technology” (“BACT”) and to 

undergo extensive pre-construction permitting. This includes air quality modeling and up to one 

year of air quality monitoring to determine the impact of the new source on air quality. EPA or 

state permitting authorities determine what type of control constitutes BACT on a case-by-case 

basis. BACT may require control beyond NSPS for that source category, but may not be less 

stringent than applicable NSPS.

A company that constructs a new major source near a “Class I” attainment area must satisfy 

additional requirements. Class I areas include most national parks, and federal land managers 

(“FLMs”) are charged with protecting air quality in these areas. PSD rules require that FLMs 

receive copies of PSD permit applications that may impact air quality in Class I areas. In cases 

where the new source will not contribute to emissions increases beyond allowable levels for the 

attainment area (i.e., beyond the PSD “increment” for that area), the FLM may still object to 

issuance of the permit based on a finding that construction of the source will adversely impact “air 

quality related values” (“AQRVs”) (including visibility) for that area. The FLM bears the burden 

of making that adverse impact demonstration. If the state concurs with the determination, then a 

permit will not be issued. In cases where the new source would contribute to emissions beyond 

the PSD increment, the company must satisfy both the FLM and the permitting authority that the 

unit will not adversely impact any AQRVs, before the permit may be issued.

A company that constructs a new major source in a nonattainment area must satisfy NSR 

requirements similar to, but more stringent than, PSD requirements. Instead of adopting BACT, 

the source must adopt control as needed to meet the Lowest Achievable Emission Rate (“LAER”) 

for that source category. LAER is based on the most stringent emissions limitation found in the 

state implementation plan (“SIP”) of any state, or the most stringent emission limitation achieved 

in practice in the source category, whichever is more stringent. A new major source in a 
27

nonattainment area also must demonstrate that any new emissions caused by the source will be 

offset by greater emissions reductions elsewhere.

In July 1996, EPA proposed changes to these new source programs that would increase the 

burdens on the construction of new generating stations. EPA’s proposal would give FLMs the 

authority to require companies to perform AQRV analyses even where their new units would not 

cause exceedence of the PSD increment. A company’s PSD application would not be considered 

complete until it had completed these analyses. EPA’s proposal also would transfer authority from 

EPA to FLMs to define AQRVs and determine what qualifies as an “adverse impact” on those 

values. These changes, as a whole, would increase the ability of FLMs to control the timing and 

eventual issuance of PSD permits. EPA also would require state and federal permitting authorities 

to adopt a “top down” method for determining BACT. Under this method, a PSD applicant must 

adopt as BACT the most stringent control available for a similar source or source category, unless 

it can demonstrate that such level of control is technically or economically infeasible. The effect 

of the policy is to make BACT more similar to LAER in the stringency of control required. The 

proposed rule is now under review by the Bush EPA.

Following another recent EPA determination, new sources may be required to meet technologybased emission limitations for mercury and other air toxics. On December 20, 2000, EPA 

indicated that it would regulate emissions of mercury and possibly other air toxics from coal- and 

oil-fired utilities under the CAA’s maximum achievable control technology (“MACT”) program. 

Depending on the basis for the determination, state and federal permitting authorities may be 

required to impose unit-specific MACT limits on new coal- and oil-fired units until a categorical 

federal standard is promulgated in 2004. As its name implies, MACT would require units to meet 

a numerical emissions limitation consistent with the use of the maximum control technology 

achievable for regulated pollutants.

New source permitting is a lengthy process. The permit must be issued within one year of the 

filing of a “complete” application. Developing a “complete” application, however, can take 

another year or longer, as a source negotiates with the permitting authority, FLM, and others 

regarding modeling, monitoring, control technology, AQRVs, and other issues. If the proposed 

revisions to the NSR rules are finalized and if case-by-case MACT determinations are required, 

this permitting process for new sources will take even longer. Even without these proposed 

revisions, it will be important to consider how this permitting process can be streamlined and 

expedited.

Efficiency/Availability Improvements at Existing Units

Utilities have many opportunities to increase electrical output at existing units without increasing 

fuel burn by improving efficiency or reducing forced outages through component replacement and 

proper maintenance. In some cases, utilities do so as a reaction to unexpected component failures 

(reactive replacement). In others, utilities replace worn or aging components that are expected to 

fail in the future or whose performance is deteriorating (predictive replacement). In some cases, 

utilities replace components because more advanced designs are available and would improve 

operating characteristics at the unit. Such component replacement can restore a unit’s original 

design efficiency or, in some cases, improve efficiency beyond original design.

Babcock & Wilcox (“B&W”), industry experts on the construction, operation, and maintenance of 

coal-fired boilers, identify a number of components that electric generating stations typically 

replace or upgrade during their service lives to maintain or improve operations. These include 
28

economizers, reheaters, superheaters, furnace walls, burner headers and throats, and other assorted 

miscellaneous tubing. In their book Steam, the B&W authors identify predictable ages for the 

failure of these components and offer a variety of upgrade options to be incorporated as 

replacement parts. Other components that utilities frequently replace or upgrade include fans, 

turbine blades and rotors, feed pumps, and waterwalls.

NSR rules apply to “modifications” of existing facilities that result in new, unaccounted for 

pollution. For the first 20 years of these programs, EPA identified only a handful of 

“modifications.” In 1999, however, EPA sued several major utility companies for past availability 

and efficiency improvement projects like those described above, characterizing them as 

modifications subject to NSPS and NSR. EPA has further indicated that it will treat innovative 

component upgrades that increase efficiency or reliability without increasing a unit’s pollutionproducing capacity as modifications as well. EPA’s current approach to these projects strongly 

discourages utilities from undertaking them, due to the significant permitting delay and expense 

involved, along with the retrofit of expensive emission controls that are intended for new facilities. 

This is the greatest current barrier to increased efficiency at existing units.

NSR rules define a modification as a physical change or change in the method of operation that 

results in a significant increase in annual emissions of a regulated pollutant. However, the rules 

exclude activities associated with normal source operation from the definition of a physical or 

operational change, including both "routine maintenance, repair, and replacement" and increases in 

the production rate or hours of operation.

For more than a decade following the establishment of these programs, EPA made very few 

determinations that projects triggered NSR as “modifications.” These determinations involved 

sources that: (1) added new capacity beyond original construction, for example by adding an 

entirely new generating unit; or (2) reactivated a long-shutdown unit.

In 1988, EPA concluded that a collection of component replacements intended to extend the lives 

of five Wisconsin Electric Power (“WEPCo”) generating units that had been formally derated and 

were at the end of their useful lives triggered NSR. Pointing to the project’s “massive scope,” 

unusually high cost ($80 million spent on five 80-MW units) and “unprecedented” nature, EPA 

concluded that the project was not “routine,” and calculated an emissions increase for purposes of 

NSR.

Following the WEPCo decision, utility companies and the Department of Energy asked EPA to 

clarify the impact of its ruling for common component replacement projects in the industry. 

Through a series of communications with Congress and the General Accounting Office, EPA 

assured utilities that “WEPCo’s life extension project is not typical of the majority of utility life 

extension projects, and concerns that the agency will broadly apply the ruling it applied to 

WEPCo’s project are unfounded.”

In 1992, EPA issued regulations that confirm the historical meaning of the modification rule and 

provide special guidance on the application of the rule to electric utilities. Under the 1980 rules, 

the method used to determine an emissions increase for NSR purposes depends on whether a unit 

is deemed to have “begun normal operations.” The preamble to the 1992 rule states that units are 

deemed not to have begun normal operations only when they are “reconstructed” or replaced with 

an entirely new generating unit. Units deemed not to have begun normal operations must measure 

an emissions increase by comparing pre-change actual emissions to potential emissions after a 

change. Since few facilities operate at full capacity around the clock before a change, this test – if 

applied to existing sources -- nearly always shows an apparent emissions increase (even where 
29

emissions in fact decline after the change). Sources that have begun normal operations may 

compare actual emissions before the change to a projection of actual emissions after it. For 

utilities, the 1992 rule allows a comparison of past actual to “future representative actual 

emissions,” a term defined to allow elimination of projected increases in utilization due to demand 

growth and other independent factors (provided that post-change utilization confirms the 

projections). Other units make a more generic comparison of pre- and post-project emissions 

holding production rates and hours of operation constant.

In the decade following the WEPCo decision, utilities continued to undertake the replacements 

described above without incident. In November 1999, however, EPA commenced a major PSD 

enforcement initiative against seven utility companies and the Tennessee Valley Authority 

alleging violations of PSD provisions. In complaints and notices of violation (“NOVs”), EPA 

alleged that replacements of deteriorated components undertaken at these units over the past 20 

years were non-routine and triggered emissions increases under NSR rules. The complaints and 

NOVs target component replacements common in the industry, including economizers, 

superheaters, reheaters, air heaters, feedwater pumps, burners, turbine blades and rotors, furnace 

and water wall sections, and other components. EPA has since expanded the enforcement 

initiative to cover more than 20 companies, with plans to add more.

EPA’s claim that these projects are now non-routine has left utilities highly uncertain about the 

coverage of the modification rule. In particular, EPA now suggests that it has discretion to classify 

projects as non-routine for several new reasons, including the fact that the replacement restores 

availability, improves efficiency, or involves a major component. At the same time, EPA has 

raised the stakes for a finding that a project is non-routine by assuming an emissions increase from 

all non-routine projects. Specifically, in contrast to the NSR rule, EPA now asserts that any nonroutine change makes a unit into one that has not “begun normal operations” – necessitating use of 

an "actual to potential" emissions increase test that the unit is sure to fail. This is true even where 

such units have an extensive past operating history that would allow reliable predictions of future 

actual emissions.

A utility considering projects similar to those targeted in the complaints and NOVs must confront 

the fact that EPA has claimed broad discretion to classify availability and efficiency improvement 

projects as non-routine modifications subject to NSR. NSR requires the retrofit of BACT 

technology, which can cost hundreds of millions of dollars, and can delay projects by several years 

while permits are obtained and/or controls installed. Accordingly, EPA’s actions strongly 

discourage utilities from undertaking projects that improve efficiency, and thereby increase 

generation without any increase in pollution.

B&W’s Steam suggests the scope of projects blocked by EPA’s current approach to modification. 

In order to reach a standard 55 to 65 year operating life, B&W estimates that a typical utility will 

replace its superheaters and burners at least twice, its reheaters at least once or twice, the 

economizer and lower furnace at least once, and all other tubing at least three times. Turbine 

blades are replaced more frequently still. Industry-wide, this means thousands of major 

component replacements may be prevented or delayed by EPA’s approach, as well as other 

categories of projects EPA has not yet addressed but may find non-routine under its new 

discretion.

Moreover, EPA has extended its approach to innovative component upgrades that improve unit 

efficiency and other operating characteristics. In a letter dated May 23, 2000, EPA concluded that 

a plan by the Detroit Edison Company to replace worn turbine blades with new, improved blades 

was non-routine. Detroit Edison proposed to replace existing blading with a new, more durable 
30

blading configuration that would increase the efficiency of two turbines by 4.5% each. This would 

allow these units each to produce 70 additional megawatts of power with no increase in fuel 

consumption, or to continue producing at past energy levels while reducing fuel consumption by 

112,635 tons of coal per year, SO2 emissions by 1,826 tons per year (“tpy”), and NOx emissions by 

1,402 tpy. This would also allow an incidental 259,111 tpy reduction in CO2 emissions – a 

compound that EPA currently lacks authority to control. The company estimated that widespread 

adoption of the upgrade at compatible units would allow CO2 reductions of approximately 81 

million tpy, with correspondingly large reductions in NOx and SO2. EPA based its finding of nonroutineness in part on the fact that the project made use of new, upgraded component designs. 

EPA reached a similar conclusion in 1998, finding that a proposed blade replacement project at a 

Sunflower Corporation power plant could not be routine because it involved redesigned/ 

upgrad[ed]” components. Accordingly, utilities contemplating innovative upgrades of turbine and 

other components to improve efficiency face a known risk that EPA will classify them as nonroutine modifications based on their use of advanced technology. Although the exact numbers of 

innovative projects blocked by EPA’s approach is difficult to quantify, the example of Detroit 

Edison suggests that the losses in generation and pollution reduction from these efficiency gains is 

substantial.

In sum, EPA’s new approach to its NSR rules presents a significant regulatory barrier to projects 

at existing sources that would otherwise be undertaken to improve availability and efficiency. 

This barrier can be expected not only to prevent significant gains in generating capacity at existing 

units, but also to actively reduce availability of these units by preventing needed maintenance. As 

a related matter, this barrier also can be expected to inhibit development of more efficient 

generating technologies, reducing the amount of energy that may be produced from existing units, 

and to encourage prolonged reliance on units operating at lower efficiencies.

Repowering and Reactivation

Replacing a coal-fired boiler with a more efficient generating technology, such as fluidized bed 

combustion, or an integrated gasification combined cycle, or state-of-the-art pulverized coal 

technology, can increase generation at an existing facility. This process is commonly known as 

“repowering.” Title IV of the CAA grants special treatment to utilities that meet the acid rain 

requirements of that title through repowering. A project that qualifies as “repowering” for Title IV 

purposes also gains exemption from NSPS requirements if the project does not increase the unit’s 

maximum achievable hourly emissions. Such projects almost certainly require PSD review, but 

are granted expedited review under the Act. EPA has yet to implement these expedited review 

procedures. Additional uncertainties for permitting these facilities are created by EPA’s proposal 

to “reform” the new source permitting process discussed above.

Reactivation of shutdown existing units presents another means for utility companies to increase 

generation. A source that has been shutdown for an extended period may be subject to NSPS 

and/or NSR when it is reactivated. Early determinations on this topic are often unclear or 

inconsistent as to whether the reactivated unit is subject to NSPS or NSR because it is deemed to 

be a new unit, or because it is deemed to be an existing unit that has undergone a “modification.” 

In its most recent determination on the subject, EPA has suggested that a unit could be subject to 

NSPS/NSR for either reason – making for a stricter, two-part standard. Clarification of EPA’s 

reactivation policy, and streamlining of NSR requirements for reactivated facilities, would 

contribute capacity needed to respond to demand peaks.
31

Solutions

EPA’s proposed rule on NSR would impose significant additional burdens for new sources if it is 

finalized in its current form. EPA’s recent listing of coal- and oil-fired electric utility steam 

generating units as major sources of hazardous air pollutants could require additional, extended 

pre-construction review for new and reconstructed facilities. EPA’s recent reinterpretation of the 

modification rule with respect to routine repair and replacement, calculating emissions increases, 

and source reactivation imposes additional burdens that discourage projects that increase unit 

availability and efficiency or reactivate shutdown units, including cases where shutdown was 

never intended to be permanent. EPA should return to its historic interpretation and application of 

these rules.
32

APPENDIX A

Description of The National Coal Council

Recognizing the valuable contribution of the industry advice provided over the years to the Executive

Branch by the National Petroleum Council and the extremely critical importance of the role of coal to

America and the world’s energy mix for the future, the idea of a similar advisory group for the coal industry 

was put forward in 1984 by the White House Conference on Coal. The opportunity for the coal industry to 

have an objective window into the Executive Branch drew overwhelming support.

In the fall of 1984, The National Coal Council was chartered; and in April 1985, the Council became fully 

operational. This action was based on the conviction that such an industry advisory council could make a 

vital contribution to America’s energy security by providing information that could help shape policies

relative to the use of coal in an environmentally sound manner which, in turn, could lead to decreased

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

The National Coal Council is chartered by the Secretary of Energy under the Federal Advisory Committee 

Act. The purpose of the Council is solely to advise, inform, and make recommendations to the Secretary of 

Energy with respect to any matter relating to coal or the coal industry about which the Secretary may request 

its expertise.

Members of The National Coal Council are appointed by the Secretary of Energy ad represent all segments 

of coal interests and all geographical regions. The National Coal Council is headed by a Chairman and a 

Vice Chairman who are elected by the Council.

The Council is supported entirely by voluntary contributions from its members. It receives no funds

whatsoever from he Federal government. In reality, by conducting studies at no cost which otherwise might 

have to be conducted by the Department, it saves money for the government.

The National Coal Council does not engage in any of the usual trade association activities. It specifically 

does not engage in lobbying efforts. The Council does not represent any one segment of the coal or coalrelated industry or the views of any one particular part of the country. It is, instead, to be a broad, objective 

advisory group whose approach is national in scope.

Matters which the Secretary of Energy would like to have considered by the Council are submitted as a

request in the form of a letter outlining the nature and scope of the requested study. The first major studies 

undertaken by The National Coal Council at the request of the Secretary of Energy were presented to the 

Secretary in the summer of 1986, barely one year after the startup of the Council.
33

APPENDIX B

The National Coal Council – 2001 Membership Roster

Paul A. Agathen, Sr. Vice President, Energy Supply Services, Ameren Corporation, 1901 Chouteau 

Avenue, St. Louis, MO 63103, Ph: 314-554-2794; Fx: 314-554-3066; paagathen@ameren.com

James R. Aldrich, State Director, The Nature Conservancy, Kentucky Chapter, 642 West Main Street, 

Lexington, KY 40508, Ph: 606-259-9655, Fx: 606-259-9678, jaldrich@tnc.org

Allen B. Alexander, President & CEO, Savage Industries, Inc., 5250 South Commerce Drive, Salt Lake 

City, UT 84107, Ph: 801-263-9400; Fx: 801-261-8766; aba@savageind.com

Sy Ali, Director, Business Development, Rolls-Royce North America, Inc., P.O. Box 420, Speed Code U-5, 

Indianapolis, IN 46206-0420, Ph: 317-230-6864; Fx: 317-230-2900; sy.a.ali@rolls-royce.com

Barbara F. Altizer, Executive Director, Virginia Coal Council, 222 Sunny Hills Drive, Cedar Bluff, VA 

24609, P.O. Box 858, Richlands, VA 24641, Ph: 540-964-6363; Fx: 540-964-6342; barb@netscope.net

Gerard Anderson, President & COO, DTE Energy Company, 2000 2nd Avenue – 2409 WCB, Detroit, MI 

48226-1279, Ph: 313-235-8880; Fx: 313-235-0537; andersong@dteenergy.com

Dan E. Arvizu, Ph.D., Vice President, CH2M Hill, 6060 South Willow Drive, Greenwood Village, CO 

80111, Ph: 303-713-2436; Fx: 303-846-2231; 303-741-0902; darvizu@ch2m.com

Henri-Claude Bailly, 5115 Waukesha Road, Bethesda, MD 20816; Ph: 301-229-0166; Fx: 301-229-7997; 

hcbailly@fondelec.com

Richard Bajura, Director, National Research Center for Coal & Energy, West Virginia University, P.O. 

Box 6064, Evansdale Drive, Morgantown, WV 26506-6064, Ph: 304-293-2867 (ext. 5401); Fx: 304-293-

3749; bajura@wvu.edu

János M. Beér, Professor of Chemical & Fuel Engineering, Department of Chemical Engineering, 25 Ames 

Street, Bldg. 66-548, Cambridge, MA 02139, Ph: 617-253-6661; Fx: 617-258-5766; jmbeer@mit.edu

Klaus Bergman, 1 Essex Road, Great Neck, NY 11023, Ph: 516-487-0339 (summer residence), 7A East 

Gate Drive, Boynton Beach, FL 33436, Ph: 561-736-9760 (winter residence); Fx: Same as phone

klausbergman@aol.com (winter)

Jacqueline F. Bird, Director, Ohio Coal Development Office, Ohio Department of Development, 77 South 

High Street, 25th Floor, P.O. Box 1001, Columbus, OH 43216, Ph: 614-466-3465; Fx: 614-466-6532; 

jbird@odod.state.oh.us; www.odod.state.oh.us/tech/coal

Sandy Blackstone, Natural Resources Attorney/Economist, 8122 North Sundown Trail, Parker, CO 80134

Ph: 303-805-3717; Fx: 303-805-4342; gillesfamily@uswest.net

Charles P. Boddy, Vice President, Government Relations, Usibelli Coal Mine, Inc., 100 Cushman Street, 

Suite 210, Fairbanks, AK 99701-4659, Ph: 907-452-2625; Fx: 907-451-6543; cboddy@usibelli.com

Donald B. Brown, President & CEO, AEI Holding Company, Inc., 1500 North Big Run Road, Ashland, KY 

41102, Ph: 606-928-3438; Fx: 606-928-0450

Robert L. Brubaker, Porter, Wright, Morris & Arthur, 41 South High Street, Columbus, OH 43215, Ph: 

614-227-2033; Fx: 614-227-2100; rbrubaker@porterwright.com
34

Dr. Louis E. Buck, Jr., CFO, ConEdison Solutions, 701 Westchester Avenue, Suite 300, White Plains, NY 

10604, Ph: 914-286-7063; Fx: 914-448-2670; BuckL@condesolutions.com

Michael Carey, President, Ohio Coal Association, 50 South Young Street, Suite M102, Columbus, OH 

43215, Ph: 614-228-6336; Fx: 614-228-6349; ohiocoal@juno.com

William Carr, 200 Oak Pointe Drive, Cropwell, AL 35054, Ph: 205-525-0307

William Cavanaugh, III, Chairman, President & CEO, Progress Energy, P.O. Box 1551, Raleigh, NC 

27602, Ph: 919-546-3560; Fx: 919-546-3210; bill.cavanaugh@pgnmail.com

Maryann R. Correnti, Partner, Arthur Andersen & Company, 200 Public Square, Suite 1800, Cleveland, 

OH 44114, Ph: 216-348-2774; Fx: 216-771-7733; maryann.r.correnti@us.arthurandersen.com

Ernesto Corte, Chairman, Gamma-Metrics, 5788 Pacific Center Boulevard, San Diego, CA 92121, 

Ph: 858-882-1200; Fx: 858-452-2487; ecorte@attglobal.net

Henry A. Courtright, P.E., Vice President, Power Generation & Distributed Resources, Electric Power 

Research Institute, 3412 Hillview Avenue, Palo Alto, CA 94304, Ph: 650-855-8757; Fx: 650-855-8500; 

hcourtri@epri.com

Joseph W. Craft, III, President, Alliance Coal, LLC, 1717 South Boulder Avenue, Tulsa, OK 74119, 

Ph: 918-295-7602; Fx: 918-295-7361; josephc@arlp.com

Curtis H. Davis, Sr. Vice President – Power Generation, Duke Energy, 526 South Church Street, Charlotte, 

NC 28202-1804; Ph: 704-382-2707; Fx: 704-382-9840; cdavis@duke-energy.com

James K. Davis, Vice President, Georgia Power Company, 241 Ralph McGill Boulevard, N.E., Bin 10240, 

Atlanta, GA 30308-3374, Ph: 404-506-7777; Fx: 404-506-1767; jamkdavi@southernco.com

E. Linn Draper, Jr., Chairman, President & CEO, American Electric Power Company, One Riverside 

Plaza, Columbus, OH 43215; Ph: 614-223-1500; Fx: 614-223-1599; eldraper@aep.com

John Dwyer, President, Lignite Energy Council, 1016 East Owens Avenue, Suite 200, P.O. Box 2277, 

Bismarck, ND 58502-2277; Ph: 701-258-7117; Fx: 701-258-2755; jdwyer@lignite.com

Richard W. Eimer, Jr., Sr. Vice President, Dynegy Marketing & Trade, 2828 North Monroe Street, 

Decatur, IL 62526, Ph: 217-876-3932; Fx: 217-876-7475; Rich_Eimer@dynegy.com

Ellen Ewart, Sr. Consultant, Resource Data International, 3333 Walnut Street, Boulder, CO 80301, Ph: 

720-548-5515; Fx: 720-548-5007; eewart@ftenergy.com; eewart@resdata.com

Andrea Bear Field, Partner, Hunton & Williams, 1900 K Street, N.W., 12th Floor, Washington, D.C. 

20036, Ph: 202-955-1558; Fx: 202-778-2201; afield@hunton.com

Paul Gatzemeier, Coal Black Cattle Company, 7256 Highway 3, Billings, MT 59106, Ph: 406-245-4076; 

Fx: 406-245-0138; pgatzemeier@earthlink.net

Janet Gellici, Executive Director, Western Coal Council, 5765 Olde Wadsworth Blvd., Suite 18, Arvada, 

CO 80002, Ph: 303-431-1456; Fx: 303-431-1606; info@westcoal.org; www.westerncoalcouncil.org

Andrew Goebel, President & COO, Vectren Corporation, 20 N.W. Fourth Street, Evansville, IN 47735-

3606, Ph: 812-464-4553; Fx: 812-491-4169; agoebel@vectren.com

Gary J. Goldberg, President and CEO, Kennecott Energy Company, P.O. Box 3009, Gillette, WY 82717-

3009, Ph: 307-687-6001; Fx: 307-687-6011; goldberg@kenergy.com
35

Alex E. S. Green, University of Florida, ICAAS – Clean Combustion Tech. Lab, P.O. Box 112050, 

Gainesville, FL 32611-2050, Ph: 352-392-2001; Fx: 352-392-2027; aesgreen@ufl.edu

John Hanson, President & CEO, Harnischfeger Industries, Inc., 3600 South Lake Drive, St. Francis, WI 

53235, Ph: 414-486-6840; Fx: 414-486-6717; jnha@hii.com

Vascar G. Harris, Tuskegee University, P.O. Box 759, Tuskegee, AL 36087, Ph: 334-727-8845

Clark D. Harrison, President, CQ, Inc., 160 Quality Center Road, Homer City, PA 15748; Ph: 724-479-

3503; Fx: 724-479-4181

Gerald (Jerry) A. Hollinden, Vice President, Power Business Sector, URS Corporation, Waterfront Plaza 

Tower One, 325 West Main Street, Suite 1200, Louisville, KY 40202-4251, Ph: 502-217-1516; Fx: 502-

569-2304; Cell: 512-426-3326; jerry_hollinden@urscorp.com

Bonny Huffman, Vice President, Sands Hill Coal Company, Inc., P.O. Box 650, 38701 S.R. 160, Hamden, 

OH 45634, Ph: 740-384-4211; Fx: 740-384-3923; bhuffman@zoomnet.net

Chris Jenkins, Sr. vice President – Coal Service Group, CSX Transportation, 5000 Water Street, J120, 

Jacksonville, FL 32202; Ph: 904-366-5693; Fx: 904-359-3443

Judy A. Jones, Commissioner, Public Utilities Commission of Ohio, 180 East Broad Street, Columbus, OH 

43215-3793, Ph: 614-644-8226; Fx: 614-466-7366; judy.jones@puc.state.oh.us

William M. Kelce, President, Alabama Coal Association, Vestavia Centre, 2090 Columbiana Road, Suite 

2500, Vestavia Hills, AL 35216, Ph: 205-822-0384; Fx: 205-822-2016; aca@bellsouth.net

Valorie A. Knudsen, Vice President, Corporate Strategy & Portfolio Assessment, NRG Energy, Inc., 1221 

Nicollet Mall, Suite 700, Minneapolis, MN 55403, Ph: 612-373-8874; Fx: 612-373-5399; 

val.knudsen@nrgenergy.com

Thomas G. Kraemer, Group Vice President, Burlington Northern Santa Fe Railway Co., 2650 Lou Menk 

Drive, 2nd Floor, P.O. Box 961051 (7616-0051), Ft. Worth, TX 76131-2830, Ph: 817-352-6242; Fx: 817-

352-7940; thomas.kraemer@bnsf.com

Max L. Lake, President, Applied Sciences, Inc., 141 West Xenia Avenue, P.O. Box 579, Cedarville, OH 

45314-0579, Ph: 937-766-2020 (ext. 111); Fx: 937-766-5886; mllake@apsci.com

Steven F. Leer, President & CEO, Arch Coal Incorporated, Cityplace One, Suite 300, St. Louis, MO 

63141, Ph: 314-994-2900; Fx: 314-994-2919; sleer@archcoal.com

David A. Lester, Executive Director, Council on Energy Resource Tribes, 695 South Colorado Blvd., Suite 

10, Denver, CO 80246-8008, Ph: 303-282-7576; Fx: 303-282-7584

Peter B. Lilly, President & CEO, Triton Coal Company, LLC, 141 Market Place Drive, Suite 100, Fairview 

Heights, IL 62208, Ph: 618-394-2620, Fx: 618-394-2638; lilly@triton-coal.com

Ronald W. Lowman, Vice President – Fossil Energy, Baltimore Gas & Electric Company, 1000 Brandon 

Shores Road, Baltimore, MD 21226, Ph: 410-787-5301; Fx: 410-787-6637; 

ronald.lowman@powersrc.com

James V. Mahoney, Sr. Vice President, Asset Management, PG&E National Energy Group, 7500 Old 

Georgetown Road, Suite 1300, Bethesda, MD 20814, Ph: 301-280-6610; Fx: 301-280-6909; 

jim.mahoney@neg.pge.com

James K. Martin, Vice President, Business Development, Dominion Energy, P.O. Box 26532, Richmond, 

VA 23261, Ph: 804-819-2176; Fx: 804-819-2219; james_k_martin@dom.com
36

Christopher C. Mathewson, PhD., PE., REG, Department of Geology & Geophysics, Texas A&M 

University, MS-3115, College Station, TX 77843-3115, Ph: 409-845-2488; Fx: 409-847-9313; 

mathewson@geo.tamu.edu

Charles R. Matthews, Commissioner, Railroad Commission of Texas, P.O. Box 12967, Austin, TX 78711-

2967, Ph: 512-463-7140; Fx: 512-463-7161; charles.matthews@rrc.state.tx.us

Michael W. McLanahan, President. McLanahan Corporation, 200 Wall Street, P.O. Box 229, 

Hollidaysburg, PA 16648-0229, Ph: 814-695-9807; Fx: 814-695-6684

Emmanuel R. Merle, President, Energy Trading Corporation, 767 Fifth Avenue, New York, NY 10153

Ph: 212-421-1930; Fx: 212-421-1937; emmanuel_merle@etc.thion.com; thion@mindspring.com

Paulette Middleton, Ph.D., Director, ESPC, 2385 Panorama Avenue, Boulder, CO 80304, Ph: 303-442-

6866; Fx: 303-442-6958; paulette@rand.org; www.rand.org

Clifford R. Miercort, President & CEO, The North American Coal Corporation, 14785 Preston Road, Suite 

1100, Dallas, TX 75240-7891, Ph: 972-239-2625 (main) 972-448-5402 (direct); Fx: 972-661-9072; 

clifford.miercort@nacoal.com; lori.furbush@nacoal.com (assistant)

Janie Mitcham, Vice President, Fuel & Energy Management. Reliant Energy, P.O. Box 1700, Houston, TX 

77251-1700, Ph: 713-207-3700’ Fx: 713-207-9720; janie-mitcham@reliantenergy.com

James Mockler, Executive Director, Montana Coal Council, 2301 Colonial Drive, Helena, MT 59601,

Ph: 406-422-6223; Fx: 406-449-6628; mtcoal@aol.com

Benjamin F. Montoya, Chairman, President and Chief Executive Officer, Public Service Company of New 

Mexico, Alvarado Square MS-2824, Albuquerque, NM 87158, Ph: 505-241-2754; Fx: 505-241-2322

David J. Morris, General Manager, Pacific Coast Coal Company, 30700 Black Diamond-Ravensdale Rd.,

P.O. Box 450, Black Diamond, WA 98010, Ph: 360-886-1060; Fx: 425-432-8755; djmorris@aol.com

Patrick J. Mulchay, President, NiSource Holding , 801 East 86th Avenue, Merrillville, IN 46410, Ph: 219-

647-6027; Fx: 219-647-6061; pjmulchay@nisource.com

Robert E. Murray, Director, The American Coal Company, 29525 Chagrin Boulevard, Suite 111, Pepper 

Pike, OH 44122, Ph: 216-765-1240; Fx: 216-765-2654; bobmurray@coalsource.com

Ram G. Narula, Bechtel Fellow & Principal Vice President, Bechtel Power Corporation, 5275 Westview 

Drive, Frederick, MD 21703, Ph: 301-228-8804; Fx: 301-694-9043; RNARULA@Bechtel.Com

Georgia Ricci Nelson, President, Midwest Generation, EME, LLC, 440 South LaSalle Street, Suite 3500,

Chicago, IL 60605, Ph: 312-583-6015; Fx: 312-583-4920; gnelson@mwgen.com

George Nicolozakes, Chairman, Marietta Coal Company, 67705 Friends Church Road, St. Clairsville, OH 

43950, Ph: 740-695-2197; Fx: 740-297-8055 

Mary Eileen O’Keefe, Director, Midwest Division, KFx/Pegasus Technology, 1362 North State Parkway,

Chicago, IL 60610, Ph: 312-482-9701;, Fx: 312-482-9703; maryeileenokeefe@aol.com

Umit Ozkan, Associate Dean for Research, College of Engineering & Professor of Chemical Engineering, 

Ohio State University, 167 Hitchcock Hall, 2070 Neil Avenue, Columbus, OH 43210, Ph: 616-292-6623; 

Phone: 614-292-2986; Fx: 616-292-9615; ozkan.1@osu.edu; www.che.eng.ohiostate.edu/facultypages/ozkan.html
37

Daniel F. Packer, President, Entergy New Orleans, P.O. Box 61000, New Orleans, LA 70161, Ph: 504-

670-3622; Fx: 504-670-3605

Timothy J. Parker, Vice President , & General Manager, Metropolitan Stevedore Company, 720 East E 

Street (90744), P.O. Box 547, Wilmington, CA 90748, Ph: 310-816-6534; Fx: 310-233-3546; 

tj.parker@metsteco.com

W. Gordon Peters, President, Trapper Mining Company, P.O. Box 187, Craig, CO 81626-0187, Ph: 970-

824-4401 (extension 111); Fx: 970-824-4632; gordon@trappermine.com

Craig E. Philip, President & CEO, Ingram Barge Company, One Belle Meade Place, 4400 Harding Road, 

Nashville, TN 37205-2290; Ph: 615-298-8200; Fx: 615-298-8213

William J. Post, President & CEO, Arizona Public Service Company, P.O. Box 53999, Station 9036,

Phoenix, AZ 85072-3999, Ph: 602-250-2636; Fx: 602-250-3002

Stephen M. Powell, Sr. Vice President, IPALCO Enterprises, Inc., One Monument Circle (46204), P.O. 

Box 1595, Indianapolis, IN 46206-1595, Ph: 317-261-8369; Fx: 317-630-5718; spowell@ipalco.com

John Rednour, Sr., Chairman, Du Quoin State Bank, 15 East Main Street, P.O. Box 468, Du Quoin, IL 

62832, Ph: 618-542-2111; Fx: 618-542-5224

Bill Reid, President, EIMCO, L.L.C., P.O. Box 1100, 1712 Coal Heritage Road, Bluefield, WV 24701-

1100, Ph: 304-324-3519; Fx: 304-324-3557; Bill.reid@sandvik.com

George Richmond, President, Jim Walter Resources, Inc., P.O. Box 830079, Birmingham, AL 35283-

0079, Ph: 205-481-6100; Fx: 205-481-6011; grichmond@jwrinc.com

James F. Roberts, President & CEO, RAG American Coal Holding, Inc., 999 Corporate Boulevard, 3rd

Floor, Linthicum Heights, MD 21090; Ph: 410-689-7500; Fx: 410-689-7511 

Karen Roberts, Regional Manager, Coal Supply, Xcel Energy, P.O. Box 1261, Amarillo, TX 79170, 

Ph: 806-378-2505; Fx: 806-378-2790; karenr@swps.com; ladonnah@swps.com (assistant)

Daniel A. Roling, First Vice President, Merrill Lynch Corporate Strategy & Research, World Financial 

Center, North Tower, New York, NY 10281-1320, Ph: 212-449-1905; Fx: 212-339-0546; 

daniel_roling@ml.com

Margaret L. Ryan, Editorial Director – Nuclear/Coal Group, Platts, The McGraw-Hill Companies, Inc.; Ph: 

202-383-2160; mryan@mh.com

William B. Schafer, III, Managing Director, NexGen Coal Services, Ltd., 710 Sunshine Canyon, Boulder, 

CO 80302, Ph: 303-417-0444; Fx: 303-417-0443; bschafer@nexgen-group.com

Debbie Schumacher, Women in Mining, 915 Mayfair Drive, Booneville, IN 47601, Ph: 812-922-8524; 

Fx: 812-922-5711; wolfie66@email.msn.com

Michael J. Sierra, President & CEO, The Ventura Group, Inc., 8550 Lee Highway, Suite 450, Fairfax, VA 

22031-1515, Ph: 703-208-3303; Fx: 703-208-3305; msierra@theventuragroup.com

Anne E. Smith, Vice President, Charles River Associates, John Hancock Tower, 200 Clarendon Street, 33rd

Floor, Boston, MA 02116; Ph: 617-425-3000; Fx: 617-425-3132

Chester B. Smith, Director, RMO Associates, 5155 Wayneland, #l-7 Jackson, MS 39211; Ph: 601-952-

0734; Fx: 601-957-6121; rmoassoc@aol.com
38

Daniel D. Smith, President - NS Development, Norfolk Southern Corporation, Three Commercial Place, 

Norfolk, VA 23510-9239: Ph: 757-629-2813; Fx: 757-664-5117; dzsmith@nscorp.com

Dwain F. Spencer, Principal, SIMTECHE, 13474 Tierra Heights Road, Redding, CA 66003-8011, Ph: 530-

275-6055; Fx: 530-275-6047; BwanaDwain@aol.com

David F. Surber, Syndicated Environmental TV Producer/Journalist Producer/Host “Make Peace With 

Nature” TV Show, P.O. Box 15555, Covington, KY 41015-0555, Ph: 859-491-5000; 

Fx: 513-861-5000; surber@surber.com; surber@MakePeaceWithNature.com

Wes M. Taylor, President, Generation Business Unit, TXU, 1601 Bryan Street, 42nd Floor, Dallas, TX 

75201-3411, Ph: 214-812-4699; Fx: 214-812-4758; wtaylor1@txu.com

Malcolm R. Thomas, Vice President, Sales & Marketing, Kennecott Energy Company, 505 South Gillette 

Avenue, (82716), P.O. Box 3009, Gillette, WY 82717-3009, Ph: 307-687-6006; Fx: 307-687-6009;

thomasm@kenergy.com

Paul M. Thompson, 216 Corinthian, Austin, TX 78734, Ph: 512-608-0672; 

pmthompson23@austin.rr.com

Dianna Tickner, President, Peabody COALTRADE, Inc., 701 Market Street, St. Louis, MO 63101-1826

Ph: 314-342-7613; Fx: 314-342-7609; Dtickner@peabodygroup.com

Anthony J. Topazi, Vice President, Fuel Services, 600 North 18th Street, Bin 14N-8160, Birmingham, AL 

35202, Ph: 205-257-6100; Fx: 205-257-0334; AJTOPAZI@southernco.com

Frank L. Torbert, Jr., President, FLT Trading, Inc., 110 Roessler Road, Suite 100B, Pittsburgh, PA 

15220, Ph: 412-531-9533; Fx: 412-531-4846; flt@nb.net

Arvin Trujillo, Executive Director, Division of Natural Resources, The Navajo Nation, P.O. Box 9000

Window Rock, AR 86515-9000, Ph: 520-871-6592/3; Fx: 520-871-7040; atrujllo@keyah.navajo.org

Jane Hughes Turnbull, Principal, Peninsula Energy Partners, 64 Los Altos Square, Los Altos, CA 94022

Ph: 650-559-1766; Fx: 650-559-1763; jaturnbu@ix.netcom.com

James L. Turner, President, The Cincinnati Gas & Electric Company, Cinergy Corporation, 139 East 

Fourth Street, 29ATII, Cincinnati, OH 45202, Ph: 513-287-3232; Fx: 513-287-4031

John Turner, President & CEO, The Conservation Fund, 1800 North Kent Street, Suite 240, Arlington, VA 

22219, Ph: 703-525-6300; Fx: 703-525-4610; jturner@conservationfund.org

Richard P. Verret, Vice President, Transmission, American Electric Power, 700 Morrison Road, Gahanna, 

OH, Ph: 614-883-7007; Fx: 614-883-7440; rverret@csw.com

Kathleen A. Walton, Director, Deutsche Bank Alex Brown, 31 West 52nd Street, New York, NY 10019, 

Ph: 212-469-4602; Fx: 212-469-5225; kathleen.walton@db.com

Doris Kelley-Watkins, Vice President & Portfolio Manager, Evergreen Asset Management Corporation

1311 Mamaroneck Avenue, White Plains, NY 10605, Ph: 914-644-1340; Fx: 914-644-1341;

dkelleywatkins@evergreen-funds.com

Alan (Bud) W. Wendorf, Executive Vice President, Fossil Power Technologies Group, Sargent & Lundy, 

LLC, 55 East Monroe Street, Chicago, IL 60603, Ph: 312-269-6551; Fx: 312-269-3681; 

alan.w.wendorf@slchicago.infonet.com
39

Richard M. Whiting, President and COO, Peabody Group, 701 Market Street, Suite 900, St. Louis, MO 

63101, Ph: 314-342-76213400; Fx: 314-342-7720; rwhiting@peabodygroup.com

James F. Wood, President, Babcock & Wilcox Company, 20 South Van Buren Avenue, Barberton, OH 

44203, Ph: 330-860-6005; Fx: 330-860-1057; jfwood@pgg.mcdermott.com; powerjim@aol.com

Lillian Wu. Consultant, Corporate Technical Strategy Development, IBM Corporation, Route 100, MD 

2434, Somers, NY 10589, Ph: 914-766-2976; Fx: 914-766-7212

NCC Staff

Robert A. Beck, Executive Director, The National Coal Council, P.O. Box 17370, Arlington, VA 22216, 

Ph: 703-527-1191; Fx: 703-527-1195; RABeck@nationalcoalcouncil.org; www.nationalcoalcouncil.org

Larry B. Grimes, Esquire, 1350 Eye Street, NW, Suite 1240, Washington, D.C. 20005, Ph: 202-682-1401, 

Fx: 703-759-3557; lbgrimes@erols.com

Richard A. Hall, CPA, 1420 Beverly Road, Suite 140, McLean, VA 22101-3719, Ph: 703-821-5434; 

Fx: 703-761-4006

Pamela A. Martin, Executive Assistant, The National Coal Council, P.O. Box 17370, Arlington, VA 

22216, Ph: 703-527-1191; Fx: 703-527-1195; natcoal@erols.com; pam@nationalcoalcouncil.org; 

www.nationalcoalcouncil.org
40

APPENDIX C

The National Coal Council Coal Policy Committee Roster

Malcolm R. Thomas, Chairman, Vice President, Sales & Marketing, Kennecott Energy Company, 505 

South Gillette Avenue, Gillette, WY 82716; Ph: 307-687-6006; Fx: 307-687-6009; thomasm@kenergy.com

Dan E. Arvizu, Ph.D., Vice President, CH2M Hill, 6060 South Willow Drive, Greenwood Village, CO 

80111; Ph: 303-713-2436; Fx: 303-846-2231; 741-0902; darvizu@ch2m.com

Richard Bajura, Director, West Virginia University, P.O. Box 6064, Evansdale Drive, Morgantown, WV 

26506-6064; Ph: 304-293-2867 (ext. 5401); Fx: 304-293-3749; bajura@wvu.edu

János M. Beér, Professor of Chemical & Fuel Engineering, Department of Chemical Engineering, 

Massachusetts Institute of Technology, 25 Ames Street, Building 66-548, Cambridge, MA 02139; Ph: 617-

253-6661; Fx: 617-258-5766; jmbeer@mit.edu

Jacqueline F. Bird, Director, Ohio Coal Development Office, Ohio Department of Development, 77 South 

High Street, 25th Floor, P.O. Box 1001, Columbus, OH 43216; Ph: 614-466-3465; Fx: 614-466-6532; 

jbird@odod.state.oh.us; www.odod.state.oh.us/tech/coal

Joseph W. Craft, III, President, Alliance Coal, LLC, 1717 South Boulder Avenue, Tulsa, OK 74119; Ph: 

918-295-7602; Fx: 918-295-7361; josephc@arlp.com

Janet Gellici, Executive Director, Western Coal Council, 5765 Olde Wadsworth Boulevard, Suite 18, 

Arvada, CO 80002; Ph: 303-431-1456; Fx: 303-431-1606; info@westcoal.org; 

www.westerncoalcouncil.org

Gerald (Jerry) A. Hollinden, Vice President, Power Business Sector, URS Corporation, Waterfront Plaza 

Tower One, 325 West Main Street, Suite 1200, Louisville, KY 40202-4251; Ph: 502-217-1516; Fx: 502-

569-2304; Cell: 512-426-3326; Jerry_hollinden@urscorp.com

Judy A. Jones, Commissioner, Public Utilities Commission of Ohio, 180 East Broad Street, Columbus, OH 

43215-3793; Ph: 614-644-8226; Fx: 614-466-7366; Judy.jones@puc.state.oh.us

Thomas G. Kraemer, Group Vice President, Burlington Northern Santa Fe Railway Co., 2650 Lou Menk 

Drive, 2nd Floor, Ft. Worth, TX 76131-2830; Ph: 817-352-6242; Fx: 817-352-7940; 

Thomas.kraemer@bnsf.com

Max L. Lake, President, Applied Sciences, Inc., 141 West Xenia Avenue, P.O. Box 579, Cedarville, OH 

43214-0579; Ph: 937-766-2020 (ext. 111); Fx: 937-766-5886; mllake@apsci.com

David J. Morris, General Manager, Pacific Coast Coal Company, 30700 Black Diamond-Ravensdale Road, 

P.O. Box 450, Black Diamond, WA 98010; Ph: 360-886-1060; Fx: 425-435-8755; djmorris@aol.com

Patrick J. Mulchay, President, NiSource Holding, 801 East 86th Avenue, Merrillville, IN 46410; Ph: 219-

647-6027; Fx: 219-647-6061; pjmulchay@nisource.com

Robert E. Murray, Director, The American Coal Company, 29525 Chagrin Boulevard, Suite 111, 

Pepper Pike, OH 44122; Ph: 216-765-1240; Fx: 216-765-2654; bobmurray@coalsource.com

Ram G. Narula, Bechtel Fellow & Principal Vice President, Bechtel Power Corporation, 5275 Westview 

Drive, Frederick, MD 21703; Ph: 301-228-8804; Fx: 301-694-9043; RNARULA@Bechtel.Com
41

Georgia Ricci Nelson, President, Midwest Generation, EME, LLC, 550 South LaSalle Street, Suite 3500, 

Chicago, IL 60605; Ph: 312-583-4920; Fx: 312-583-6015; gnelson@mwgen.com

Mary Eileen O’Keefe, Director, Midwest Division, KFx/Pegasus Technology, 1362 North State Parkway; 

Chicago, IL 60610; Ph: 312-482-9701; Fx: 312-482-9703; maryeileenokeefe@aol.com

W. Gordon Peters, President, Trapper Mining Company, P.O. Box 187, Craig, CO 81626-0187; Ph: 970-

824-4401 (Ext. 111); Fx: 970-824-4632; Gordon@trappermine.com

Stephen M. Powell, Sr. Vice President, IPALCO Enterprises, Inc., One Monument Circle, Indianapolis, IN 

46204; Ph: 317-261-8369; Fx: 317-630-5718; spowell@ipalco.com

John Rednour, Sr., Chairman, Du Quoin State Bank, 15 East Main Street, P.O Box 468, Du Quoin, IL 

62832; Ph: 618-542-2111; Fx: 618-542-5224

Wes M. Taylor, President, Generation Business Unit, TXU, 1601 Bryan Street, 42nd Floor, Dallas, TX 

75201-3411; Ph: 214-812-4699; Fx: 214-812-4758; Wtaylor1@txu.com
42

APPENDIX D

The National Coal Council Electricity Availability Study Work Group

Sy Ali, Rolls-Royce North America, Ph: 317-230-6864; Fx: 317-230-2900; sy.a.ali@rolls-royce.com

Barbara F. Altizer, Virginia Coal Council, Ph: 540-964-6363; Fx: 540-964-6342; barb@netscope.net

Dan E. Arvizu, CH2M Hill , Ph: 303-713-2436; Fx: 303-846-2231; darvizu@ch2m.com

Richard Bajura, National Research Center for Coal & Energy, West Virginia University, Ph: 304-293-

2867 (ext. 5401); Fx: 304-293-3749; bajura@wvu.edu

Janos M. Beer, Department of Chemical Engineering , Massachusetts Institute of Technology, Ph: 617-

253-6661; Fx: 617-258-5766; jmbeer@mit.edu

Jacqueline F. Bird, Ohio Coal Development Office, Ohio Department of Development, Ph: 614-466-3465; 

Fx: 614-466-6532; jbird@odod.state.oh.us

Sandy Blackstone, Natural Resources Attorney/Economist, Ph: 303-805-3717; Fx: 303-805-4342; 

gillesfamily@uswest.net

Andrew Blumenfeld, Arch Coal Incorporated , Ph: 314-994-2900; Fx: 314-994-2919; 

ablumenfeld@archcoal.com

Judy Brown, Kennecott/U.S. Borax, Ph: 202-393-0266; brownju@kennecott.com

Louis E. Buck, Jr. , ConEdison Solutions, Ph: 914-286-7063; Fx: 914-448-2670; 

BuckL@condesolutions.com

Bill Brownell, Hunton & Williams, Ph: 202-955-1555; bbrownell@hunton.com

Robert L. Brubaker , Porter, Wright, Morris & Arthur, Ph: 614-227-2033; Fx: 614-227-2100; 

rbrubaker@porterwright.com

Fred Busch, Sr. Vice President – Power Generation Services, Savage Industries, Ph: 801-263-9400; Fx: 

801-261-6638; fredb@savageind.com

Tami Carpenter, Duke Energy, Ph: 704-382-2707; Fx: 704-382-9840; tscarpen@duke-energy.com

Sonny Cook, Duke Energy, Ph: 704-382-2707; Fx: 704-382-9840; dgcook@duke-energy.com

Ernesto Corte, Gamma-Metrics, Ph: 858-882-1200; Fx: 858-452-2487; ecorte@attglobal.net

Charles Crane, Tri-State, Ph: 303-452-6111; ccrane@tristategt.org

Stuart Dalton, EPRI, Ph: 650-855-2000; Fx: 650-855-2800; sdalton@epri.com

William DePriest, Sargent & Lundy, Ph: 312-269-7533; william.depriest@slchicago.infonet.com

Ellen Ewart, Resource Data International, Ph: 720-548-5515; Fx: 720-548-5007; eewart@ftenergy.com

Steve Gehl, EPRI, Ph: 650-855-2000; Fx: 650-855-2800; sgehl@epri.com
43

Janet Gellici, Western Coal Council; Ph: 303-431-1456; Fx: 303-431-1606; info@westcoal.org

Jerry L. Goodwin, NIPSCO, Ph: 219-647-5530; Fx: 219-647-5533; sjreynolds@nipsco.com

Thomas Grahame, Department of Energy, Ph: 202-586-7149; Fx: 202-586-7085;

thomas.grahame@hq.doe.gov

Manoj K. Guha, American Electric Power, Ph: 614-223-1285; Fx: 614-223-1292; mkguha@aep.com

John Hanson, Harnischfeger Industries, Inc., Ph: 414-486-6840; Fx: 414-486-6717; jnha@hii.com

Gerald A. Hollinden, URS Corporation, Ph: 502-217-1516; Fx: 502-569-2304; 

jerry_hollinden@urscorp.com

Steve Jenkins, URS Corporation, Ph: 813-387-7807; Fx: 813-874-7424; steve_jenkins@urscorp.com

Judy A. Jones, Public Utilities Commission of Ohio, Ph: 614-644-8226; Fx: 614-466-7366;

judy.jones@puc.state.oh.us

Robert Kane, Department of Energy, Ph: 202-586-4753; Fx: 202-586-1188; robert.kane@hq.doe.gov

Peter B. Lilly, Triton Coal Company, Ph: 618-394-2620; Fx: 618-394-2638; lilly@triton-coal.com

James K. Martin, Dominion Energy, Ph: 804-819-2176; Fx: 804-819-2219; james_k_martin@dom.com

Michael W. McLanahan, McLanahan Corporation, Ph: 814-695-9807; Fx: 814-695-6684

Patrick McWay, Peabody Group, Ph: 314-342-7612; pmcway@peabodygroup.com

Robert E. Murray, The American Coal Company, Ph: 216-765-1240; Fx: 216-765-2654;

bobmurray@coalsource.com

Ram G. Narula, Bechtel Power Corporation, Ph: 301-228-8804; Fx: 301-694-9043;

RNARULA@bechtel.com

Georgia Ricci Nelson (Chair), Midwest Generation, Ph: 312-583-6015; Fx: 312-583-4920; 

gnelson@mwgen.com

George Nicolozakes, Marietta Coal Company, Ph: 740-695-2197; Fx: 740-695-8055

Terry O’Connor, Arch Coal Incorporated, Ph: 314-994-2900; Fx: 314-994-2919; 

to’connor@archcoal.com

Mary Eileen O’Keefe, Director, Midwest Division, KFx/Pegasus Technology, Ph: 312-482-9701; Fx: 312-

482-9703; maryeileenokeefe@aol.com

W. Gordon Peters, Trapper Mining Company, Ph: 970-824-4401 (ext. 111); Fx: 970-824-4632;

gordon@trappermine.com

Stephen M. Powell, IPALCO Enterprises, Inc., Ph: 317-261-8369; Fx: 317-630-5718;

spowell@ipalco.com

Karen Roberts, Xcel Energy, Ph: 806-378-2505; Fx: 806-378-2790; karenr@swps.com

John Byers Rogan, Babcock & Wilcox, Ph: 330-860-2122; jbrogan@pgg.mcdermott.com
44

William B. Schafer, NexGen Coal Services, Ltd., Ph: 303-417-0444; Fx: 303-417-0443; 

bschafer@nexgen-group.com

David F. Surber, Make Peace With Nature TV Show, Ph: 859-491-5000; Fx: 513-861-5000;

surber@surber.com

Judy Tanselle, PG&E National Energy Group, Ph: 301-280-6610; Fx: 301-280-6909;

judy.tanselle@gen.pge.com

Wes M. Taylor, President, Generation Business Unit, TXU, 1601 Bryan Street, 42nd Floor, Dallas, TX 

75201-3411; Ph 214-812-4699; Fx: 214-812-4758; Wtaylor1@txu.com

Doris Kelley-Watkins, Evergreen Asset Management Corp., Ph: 914-644-1340; Fx: 914-644-1341; 

dkelleywatkins@evergreen-funds.com

Jacob Williams, Peabody COALTRADE, Inc., Ph: 314-342-7613; Fx: 314-342-7609;

jwilliam@peabodygroup.com
45

APPENDIX E

Correspondence Between U.S. Department of Energy

and the National Coal Council
46
47

APPENDIX F

Correspondence From Industry Experts 
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68

APPENDIX G

Selected Comments on the Report, Increasing Electricity

Availability From Coal-Fired Generation in the Near-Term
69
70
71
72
73
74
75
76
77
78
79
80
81
82

APPENDIX H

Acknowledgements

The members of the Working Group wish to acknowledge, with sincere thanks, the special assistance

received from the following persons in connection with various phrases of the development of this report:

Byers Rogan, Babcock & Wilcox

Bill Brownell, Hunton & Williams

Bill Schafer, NexGen

Rob Brubaker, Porter Wright Morris & Arthur

Tony Armor, EPRI

Stu Dalton, EPRI

Steve Gehl, EPRI

Janos Beér, MIT

Bill DePriest, Sargent & Lundy

Steve Jenkins, URS Corp.

Ron Litzinger, Edison Mission Energy

Cassandra Miller, NCC Staff (temporary)

Pam Martin, NCC Staff

David Surber, producer, “Make Peace With Nature” TV Show

Julie Clendenin