Opportunities to Expedite the Construction 

of New Coal-Based Power Plants 

Chair:

Thomas G. Kraemer 

Burlington Northern Santa Fe Railway Co. 

Vice Chair: 

Georgia Nelson

Midwest Generation EME, LLC 

Study Co-Chairs:

Robert Card 

U.S. Undersecretary of Energy 

Dr. E. Linn Draper, Jr. 

American Electric Power Co. 

Technical Work Group Chair: 

Michael J. Mudd 

American Electric Power Co. 

Library of Congress Catalog # 2005920127
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

2

THE NATIONAL COAL COUNCIL 

Thomas G. Kraemer, Chairman

Robert A. Beck, Executive Director 

U.S. DEPARTMENT OF ENERGY 

Spencer Abraham, Secretary of Energy 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

3

OPPORTUNITIES TO EXPEDITE

THE CONSTRUCTION OF NEW 

COAL-BASED POWER PLANTS 

Table of Contents 

Preface.............................................................................................................................................. i 

Abbreviations .................................................................................................................................ii 

Principal Contributors ................................................................................................................. iv 

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

Section 1: Introduction................................................................................................................. 7 

Section 2: Technology Choices and Economics........................................................................ 16 

Section 3: Clean Coal Power Incentives.................................................................................... 36 

Section 4: Financial Overview of Investing in New Coal-Based Generation......................... 43 

Section 5: Environmental, Permitting, and Regulatory Issues............................................... 47 

Section 6: Case Studies............................................................................................................... 57 

Section 7: Opportunities for the Future of Coal in the National Energy Mix ...................... 72 

Section 8: Conclusions................................................................................................................ 76 

References......................................................................................................................................... 

Appendix A: Description of The National Coal Council ......................................................... 79 

Appendix B: The National Coal Council Membership Roster ............................................... 80 

Appendix C: The National Coal Council Coal Policy Committee Roster.............................. 88 

Appendix D: The National Coal Council Study Work Group Roster.................................... 96 

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

 and The National Coal Council........................................................................... 98 

Appendix F: Correspondence from Industry experts............................................................ 100 

Appendix G: Acknowledgements ............................................................................................ 103 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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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 U.S. Secretary of Energy on general policy matters relating to coal. The National Coal 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. 

The 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 U.S. and a broad spectrum of diverse interests from business, industry and other groups, such 

as:

x large and small coal producers; 

x coal users such as electric utilities and industrial users; 

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

x academia; 

x research organizations; 

x industrial equipment manufacturers; 

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

commissioners; 

x consumer groups, including special women’s organizations; 

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

x attorneys; 

x state and regional special interest groups; and 

x 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. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

ii

Abbreviations

AEO Annual Energy Outlook 

AFBC Atmospheric fluidized bed combustion 

AMM Abandoned mine methane 

API American Petroleum Institute 

ABCT Best available control technology 

Bcf Billion cubic feet 

Btu British thermal units 

Btu/kWh British thermal units per kilowatt-hour 

CAA Clean Air Act 

CBM Coalbed methane 

CCS CO

2 capture and storage 

CCT Clean Coal Technology 

CDM Clean Development Mechanism 

CFB Circulating fluidized bed 

CMM Coal mine methane 

CO Carbon monoxide 

CO

2 Carbon dioxide 

COE Cost of electricity 

DOE Department of Energy 

DSM Demand side management 

EEI Edison Electric Institute 

EHE External heat exchanger 

EIA Energy Information Administration 

EIIP Emission Inventory Improvement Program 

EPA Environmental Protection Agency 

EPRI Electric Power Research Institute 

FBC Fluidized bed combustor 

FE Fossil energy 

FGD Flue gas desulfurization 

FY Fiscal year 

GCCI Global Climate Change Initiative 

GDP Gross domestic product 

GHG Greenhouse gas 

GW Gigawatts 

GWP Global warming potential H2 Hydrogen 

IGCC Integrated gasification combined cycle 

IPCC Intergovernmental Panel on Climate Change 

JI Joint implementation 

KW Kilowatt 

kWh Kilowatt-hour 

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

lb/MWh Pounds of emissions per megawatt-hour generated 

LHV Lower heating value 

LNB Low NO

x burners 

LNG Liquified natural gas 

MBtu Million Btu 

MMTCE Million metric tons carbon 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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iii

MTCO2 Million tons of carbon dioxide 

MW Megawatts 

MWh Megawatt-hour 

N2O Nitrous oxide 

NCC National Coal Council 

NETL National Energy Technology Laboratory 

NGCC Natural Gas Combined Cycle 

NMA National Mining Association 

NOx Nitrogen oxides 

NSR New Source Review 

O&M Operating and maintenance 

PC Pulverized coal 

PFBC Pressurized fluidized bed combustion 

PFBCwTC Pressurized fluidized bed combustion with topping combustor 

PPM Parts per million 

PPMV Parts per million by volume 

PSI Pounds per square inch 

R&D Research and development 

RD&D Research, Development and deployment 

SC Supercritical 

SCR Selective catalytic reduction 

SNCR Selective non-catalytic reduction 

SO2 Sulfur dioxide 

TPY Tons per year 

UNFCCC United Nations Framework Convention on Climate Change 

USC Ultra-supercritical 

VAC Ventilation air methane 

WBCSD World Business Council for Sustainable Development 

WRI World Resources Institute 
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iv

Principle Contributors

Sy Ali, Clean Energy Consulting Group 

Tom Altmeyer, Arch Coal, Inc. 

Dan Arvizu, CH2M Hill 

Eric Balles, Babcock Borsig Power, Inc. 

Janos Beer, Massachusetts Institute of Technology 

George Booras, Electric Power Research Council 

Fred Bush, Savage Industries 

Hank Courtright, Electric Power Research Council 

Stu Dalton, Electric Power Research Institute 

David Denton, Eastman Gasification Services Co. 

Bill DePriest, Sargent & Lundy 

E. Linn Draper, American Electric Power Co. 

Michael Durham, ADA Environmental Services 

Richard Eimer, Dynegy Marketing & Trade 

Joel Friedlander, The North American Coal Corporation 

Janet Gellici, American Coal Council 

Tom Grahame, Department of Energy 

Mike Gregory, The Northern American Coal Corporation 

Jerry Hollinden, URS Corporation 

Neville Holt, Electric Power Research Institute 

Steve Jenkins, URS Corporation 

Judy Jones, Public Utilities Commission of Ohio 

Jeff Knitter, WeEnergies 

Klaus Lambeck, Ohio Public Utilities Commission 

Ron Litzinger, Edison Mission Energy 

John Long, Constellation Energy 

Mike Mudd, American Electric Power Company 

Ram Narula, Bechtel Power Corporation 

Georgia Nelson, Midwest Generation 

Fredrick Palmer, Peabody Energy 

Jack Parkes, Electric Power Research Institute 

Bob Pearson, CH2M Hill 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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v

Robert Purgert, Energy Industries of Ohio 

Peter Rigby, Standard & Poor’s 

Lars Scott, Peabody Energy 

John Vella, Edison Mission Energy 

Jerry Weeden, NiSource 

Kim Wissman, Ohio Public Utilities Commission 

Mona Yee, Fitch Ratings
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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1

Executive Summary

Purpose

By letter dated December 3, 2003 (see Appendix E), U.S. Secretary of Energy Spencer Abraham 

requested that The National Coal Council prepare a study identifying “which opportunities could expedite 

the construction of new coal-fired electricity generation.” He also requested that the Council “examine 

opportunities and incentives for additional emissions reduction including evaluating and replacing the 

oldest portion of our coal-fired power plant fleet with more efficient and lower emitting coal-fired plants.” 

The Secretary expressed his belief that this report “will serve as a blueprint for industry while acting as a 

guide to promote the construction of new coal-fired facilities.” 

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

the work and prepare a report. The list of participants on this group can be found in Appendix D of this 

report.

Findings

The National Coal Council finds the following. Each finding is of equal importance. 

 Coal is the fuel of choice now, and will remain so into the future.

Coal-based power plants produce greater than 50% of all the electricity in the United States. It will 

remain the primary fuel source for electricity generation for the foreseeable future. It is secure, 

affordable and environmentally compatible. The country has about 250 years of supply in reserve at 

the present rate of consumption. Through continued research, development and deployment of new 

technologies, coal will continue to fuel low-cost electricity and to demonstrate continued 

environmental improvements. 

Natural gas has been the dominant fuel for new power plants in the last decade. 

Over the past decade, the availability of low cost natural gas and increased competition in the electric 

generation market, when combined with certain federal energy polices of the 1990s promoting the use 

of natural gas, has resulted in the choice of natural gas over coal as the fuel for most new generating 

plants. The net effect of the 1990s policies was to stimulate natural gas demand through its use to 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

2

generate electricity to the detriment of American citizens who use it for home heating purposes and 

industries which rely on natural gas for their primary feedstock or other uses. 

Coal provides a pathway for greater energy independence. 

As the demand for electricity continues to increase, the Energy Information Administration (EIA) and 

others have forecasted large increases in electricity generation using natural gas as a fuel. With the 

United States’ best prospect for increasing natural gas supplies coming from foreign sources 

including Canadian imports and liquefied natural gas (LNG), a better alternative for energy 

independence would be to build more new, domestically supplied coal-based power plants. 

There is renewed interest in using coal to fuel new power plants. 

Increases in the price and historical volatility of natural gas supplies, the long-term stability of coal 

prices, and the financial impacts from a number of financially distressed investments in natural-gas 

combined-cycle power plants have led to a renewed interest in coal-based electricity generation. 

Forecasts of natural gas supplies and prices have become more accurate. Supply difficulty and price 

volatility that have occurred since 2000 and the revised estimates of natural gas reserves by some 

companies have resulted in more realistic assessments of natural gas supplies and a more reasoned 

projection of natural gas prices. The National Petroleum Council’s 1999 and 2003 reports provide 

good examples of this increasing accuracy. The higher price forecasts and other warnings in turn 

make the economic models used to support natural gas-based power plants less attractive. 

Generators are expected to remain credit worthy. 

Experts in the financial community believe that the outlook for investor-owned electric utilities 

(IOUs), rural electric cooperative and municipal generators (gencos), and independent generation 

companies, diversified energy merchants and energy traders, is generally stable. While many IOUs 

and gencos have either maintained creditworthiness or are well on their way to financial recovery, the 

investment community believes that many in the merchant or independent power sectors will need 

time to recover. There are structural differences between the various power producers, and financial 

issues that impact decisions about whether or not to construct new coal-based facilities differ between 

the segments. 

Permitting delays have been an impediment to building new coal plants. 

The length of permitting time, as well as redundant permitting requirements, has created impediments 

to new construction. These delays are a result of an inefficient permitting process – including a 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

3

lengthy permitting appeals process – that can delay plants to the point of causing plant cancellations. 

Even with new coal-based generation meeting, and in some cases exceeding, the most stringent 

emissions control requirements and efficiency standards, the time from project initiation to start-up is 

routinely extended due to delays in the permitting process that do not result in any changes to the 

plant’s emissions control systems. These delays result in increased costs and cause uncertainty in the 

investment community (with higher perceived risks related to developing new coal-based plants). 

Environmental regulatory approaches have been an impediment to building new coal plants. 

Over the past three decades, the prevailing environmental regulatory approaches have led to the 

retrofit of high capital cost emissions control technologies at existing coal-based generating plants. In 

order to avoid the risk of stranded investments and the uncertainty of investing in new plants, power 

plant operators have taken steps to extend the lives of existing plants. This has also made it more 

difficult for new plants to enter the electricity market at a price competitive with the overall cost of 

electricity from older, coal-based plants where the capital cost component of electricity is much less. 

Uncertainty about CO2 emission reductions has been an impediment to the construction of new coalbased power plants. 

The uncertainty of future environmental regulations, especially associated with CO2, has complicated 

decisions about whether or not to repower or replace existing coal-based generation. This situation is 

exacerbated by the uncertainty surrounding the broader issue of carbon management. 

Incentives are still needed to facilitate the construction of advanced coal-based power plants. 

Past incentives have facilitated research, development and demonstration of advanced, clean and 

efficient coal-based technologies leading to significant advancements in both environmental 

performance and generation efficiency. However, these technologies require additional support for 

deployment to achieve significant market penetration. 

Lack of a regional planning approach has been an impediment to the construction of new coal-based 

power plants. 

The transitional state-by-state changes in the electric utility industry have resulted in a lack of 

regional planning. This lack of regional planning has resulted in a short-term focus with small, 

incremental capacity additions such as natural gas combined cycle plants, rather than coal-based 

plants that provide enhanced energy security, long-term sustainability and lower overall electricity 

prices for our nation. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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4

Infrastructure hurdles are impediments to the construction of new coal-based power plants. 

Opportunities to install new coal-based power plants in both the short term and in the future are 

inhibited by several factors that warrant attention on a national environmental and energy policy 

basis. These factors include the continued failure of the Federal Energy Regulatory Commission 

(FERC) and the states to deal with transmission congestion, declining engineering resources in the 

United States, limited availability of skilled construction labor to build new coal-based power plants, 

declining manufacturing infrastructure in the United States for the fabrication of steel and steel 

components required for new coal plants, and growing regulatory hurdles to permit and construct new 

coal mines. 

Recommendations

The National Coal Council makes the following recommendations: 

Streamline the permitting process. 

The Department of Energy, in concert with other appropriate agencies and stakeholders, should 

develop an integrated, flexible and streamlined approach to environmental regulations and permitting 

for new, advanced coal-based generation. Operating permits issued under this approach should 

include assurances that new regulations will not change the permit for a certain fixed period of time 

after the start-up of the new plant. The Department of Energy (DOE) should then work with the U.S. 

Environmental Protection Agency (EPA) and others to implement this approach. The goal is to 

encourage the development and deployment of a domestic, reliable, clean and affordable energy 

supply. This approach will create incentives and certainty for investments in advanced coal-based 

generation, while allowing appropriate time for capital stock turnover. 

Recognize the strategic importance of integrated gasification combined cycle (IGCC) technology. 

The Department of Energy, in concert with other agencies, should create incentives that recognize 

and reward the potential for integrated gasification combined cycle to replace the use of natural gas in 

the electricity generation market, produce synthetic gas for poly-generation, and to accelerate 

progress of the Hydrogen Initiative. This would help stabilize the price of natural gas and free more 

of it for use in the chemicals, fuels and fertilizer industries, thereby saving domestic jobs in those 

industries. Also, coal gasification could provide additional feedstock for these industries at a 

competitive cost. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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5

Recognize the importance of other coal-based technologies. 

While IGCC technology is strategically important to the future of coal, the Department of Energy 

should also support R&D for other advanced coal-based technologies, including advanced pulverized 

coal-based technology and circulating fluidized bed technology, especially in the areas of carbon 

capture and ultra-supercritical designs and other efficiency improvements, so that investors in coalbased power plants can choose from a portfolio of attractive technologies. 

Encourage regional planning. 

The Department of Energy should explore the viability of and encourage a regional planning 

approach for capacity additions. The regional approach should consider a mechanism to reward 

investment in efficient and environmentally superior coal-based plants that would have widespread 

regional benefits and transcend the individual territory of any one state or IOU. 

Continue with meaningful R&D. 

The Department of Energy should continue research and development work on advanced, efficient 

and lower-emitting coal-based technologies to ensure that technology continues to keep pace with the 

goals set forth in the DOE/CURC/EPRI Roadmap. In addition, this effort should include adequate 

funding and support for flagship programs such as FutureGen and the Hydrogen Initiative. 

Continue with technology demonstration. 

The Department of Energy should ensure that proper mechanisms and incentives are in place to allow 

not-yet-mature and first-of-a-kind technologies to be demonstrated in the marketplace so that 

promising coal-based technologies can be ready for wide-scale deployment through programs such as 

the Clean Coal Power Initiative. 

Provide meaningful incentives for the commercialization and deployment of new advanced coal-based 

technologies.

The Department of Energy should develop incentives to overcome the risk-adjusted cost differential 

between options of conventional technologies and new, more efficient, lower-emitting advanced coalbased plants so that these advanced plants can be more expeditiously deployed in the marketplace. 

The menu available for such incentives includes, but is not limited to, tax incentives, production 

incentives, public/private cost-sharing, accelerated depreciation, loan guarantees, and federal credit. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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6

Maintain a balanced portfolio of Research & Development, Demonstration and Deployment. 

The Department of Energy should recognize the importance of properly funding Research & 

Development, Demonstration and Deployment and must ensure that proper funding is allocated to all 

three elements of technology development. 

Work with state regulators for cost recovery of new advanced coal-based plants. 

The Department of Energy should facilitate the development of a clear regulatory mechanism that 

will allow investors to recover added costs of replacing some of the older, less efficient existing 

power plants with new advanced coal-based power plants. Innovative cost recovery proposals should 

address both state and regional concerns. Additional vehicles could be developed to insure recovery 

of new capital investment as well as any stranded capital from un-recovered investments associated 

with the retirement of older facilities. This mechanism would have the opportunity to provide a new 

incentive to facilitate the construction of new coal-fueled power plants with minimal impact on the 

federal deficit. 

Continue to be a champion for coal. 

The Department of Energy should continue to strongly reinforce as often as possible that coal is a 

vital resource for our country. Coal must be utilized to provide an adequate measure of energy 

security and reliability, and it has been and will continue to be the major fuel for electricity generation 

in the country. The use of coal should be encouraged as an alternative feedstock for chemicals and 

fuels (especially those that are imported), and appropriate incentives and regulatory approaches 

should be provided to encourage its use in as clean a manner as possible. The use of clean coal 

technologies should be fostered, encouraged and promoted in other countries where coal is a vital 

resource. Ever-changing environmental regulations create an impediment to new coal plants. 

Investment in new plants involves hundreds of millions of dollars and the investment community 

needs clear and stable rules as a foundation for that investment. Regulations can be and are 

reinterpreted over time. Stability can only be achieved through legislation. 
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7

Section 1: Introduction 

The nation's energy sector is facing a challenge: increasing stress is being placed on the production, 

delivery and consumption of energy, especially electricity. Throughout the 1980s and 1990s, American 

citizens were provided with, and came to expect, secure, reliable, affordable, and environmentally sound 

energy. This fueled dramatic economic growth and improved human health and welfare, even as 

environment quality steadily improved. It was assumed that energy would continue to be readily 

available at low prices, due primarily to low-cost electricity generated using inexpensive coal and nuclear 

fuels, along with relatively inexpensive natural gas and, for the most part, stable world oil supplies. 

The past four years have seen dramatic changes to this longstanding reality. The 1990s resulted in 

reduced energy investments, lack of balanced policymaking, utilization of excess generating reserves 

from low-cost nuclear plants, depletion of low-cost natural gas supplies, aggressive litigation and 

regulation toward coal-based electricity generation, increasing reliance on foreign energy sources, overreliance in scarce domestic natural gas resources, and under-investment in new coal-based generation and 

the nation’s transmission system. 

The policy and investment neglect has in turn brought about rolling energy shocks marked by sharp 

natural gas shortages and price increases, high fuel oil, heating oil and gasoline prices, electricity 

blackouts in the northeast and California, and strained energy infrastructure. There is every indication 

that these energy shocks will continue and intensify. Since 1990, for instance, reserves of inexpensive 

coal and nuclear electricity generation capacity have been cut in half. Lacking investment in new coalbased generation, the nation is most likely to rely upon scarce natural gas and other expensive fuels for 

generating electricity. Statistics show that states that choose coal for generation are rewarded by low-cost 

electricity. In the United States, the 10 states that use the highest percentage of coal enjoy electricity rates 

that are 40% lower than the 10 states that use the largest percentage of other fuels. [See Figure 1.1.] 

Figure 1.1 

Low-Cost Electricity Comes From Coal 

7.3¢ 

30%

5.9¢

62%

5.6¢

95%

5.9¢

9%

5.5¢

63%

4.7¢

96%

6.0¢

78%

6.6¢

8%

6.3¢

75%

6.7¢

88%

8.4¢

52% 11.8¢

2%

5.3¢

94%

6.4¢

42%

6.8¢

38%

6.1¢

84%

5.9¢

67%

5.6¢

64%

6.1¢

82%

7.4¢

46%

7.1¢

41%

6.2¢

69%

5.8¢

49%

6.1¢ 

26%

7.0¢

57%

5.3¢

95%

6.6¢

91%

9.2¢

3%

10.9¢

19%

6.3¢

36%

5.7¢

58%

6.3¢

66%

5.9¢ 

39%

4.3¢ 94%

6.2¢

51%

8.0¢

56%

5.1¢

98% 

6.7¢

5.7¢ 62% 60%

5.8¢

0%

10.4¢

5%

13.1¢

14%

NH 10.5¢ 27%

RI 9.2¢ 0%

CT 9.7¢ 10%

NJ 9.4¢ 16%

MA 10.0¢ 29% 

VT 10.9¢ 0%

DE 6.8¢ 59%

MD 6.5¢ 60%

¢ = average price per 

kilowatt hour for 2002

% = percent of total 

generation from coal for 

2002

<7.0¢

7.0¢ - 9.0¢

>9¢ 

Hydro
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National Coal Council Report 

8

The momentum of flawed energy policymaking and underinvestment poses enormous threats to the U.S. 

economy and its citizens. High energy prices amount to a regressive tax, most severely affecting those 

least able to gain a voice and most likely to be hurt if proper policies aren’t enacted. Consider that 60% 

of American households earn less than $32,000 per year. They average $400 per month in discretionary 

income that can quickly be consumed by rising energy costs from natural gas (which, during the winter of 

2003, more than doubled from the prior year). During the last U.S. energy crisis, middle-class Americans 

faced average energy costs equaling 4.6% of their incomes while low-income Americans were forced to 

pay 19.5% of their income on energy. 

The result of relying more heavily on natural gas to cover the growth in 

electricity demand has negatively impacted the nation's manufacturing 

sector. In June 2000, the rising cost of natural gas marked the beginning 

of a negative trend in the number of U.S.-based manufacturing jobs. 

Between July 2000 and February 2004, the number of domestic factory 

jobs decreased by over 2.8 million. Most of these jobs have been 

"outsourced" to other nations with lower energy costs. 

Against this backdrop of rolling U.S. energy shocks related to natural gas, gasoline and oil, increased use 

of vast U.S. coal resources represents the single most effective step that the United States can take to 

ensure domestic energy security, low-cost energy, reliability and sustained economic growth. 

In order to face this challenge and be responsive to the needs of our citizens, any future energy plan will 

need to balance production and consumption – both of which are tied to economic and population growth 

– in an environmentally acceptable way. Supply and demand need to be viewed in a time frame that 

looks beyond today in order to shape our research and regulatory agendas. 

Economic development will require enormous investments in all aspects of energy infrastructure and in 

all phases of the energy sector; from production to generation, storage to transmission, and distribution to 

end use efficiency. Any expansion of power supplies must recognize that no single energy source can 

meet our growing energy needs. Economic security will require a focus on the development of reliable 

power plants which can serve the growing demand for electricity at stable prices - with adequate domestic 

fuel sources.

The United States has the largest coal reserve in the world, and America 

has more coal than any nation has of any single energy resource. Coal 

makes up 85% of our nation’s fossil fuel reserves and fuels over half of 

our nation’s electricity generation. At current consumption rates, these 

coal reserves make up a 250-year supply of domestically available fuel, 

which is far greater than our nation’s reserves of natural gas and oil 

combined. Additionally, many of our natural gas and oil reserves are 

located in areas where drilling is restricted or in areas where most of the 

low-cost reserves have been substantially depleted. It has been suggested 

by many economists that liquefied natural gas (LNG) can and must be 

imported to stabilize natural gas prices. The import of LNG is clearly 

contrary to our nation’s stated goal of energy independence and security. 

The United States should encourage the utilization of domestic coal to 

help reduce our future reliance on foreign supplies of fuel.

American citizens 

need low-cost energy, 

and coal provides 

energy with low and 

stable costs. 

The United States has 

the largest coal reserves 

in the world, and 

America has more coal 

than any nation has of 

any single energy 

resource. Coal makes 

up 85% of our nation’s 

fossil fuel reserves and 

fuels over half of our 

nation’s electricity 

generation.
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From 1980 to 2000, our nation’s economy greatly benefited from the development of large coal-based 

power plants. In 1990, the average capacity utilization factor of a coal plant was 59%; by 2000, with 

increased demands for low-cost electricity, this factor had grown to 70%. Similarly, nuclear power plant 

capacity factors have increased from 66% in 1990 to 90% in 2000. The existing nuclear fleet has 

effectively reached its limit, and the existing coal fleet will soon reach its effective limit of 80-85% 

utilization. When this occurs, the nation will be short of low-cost, baseload electric generating capacity. 

Figure 1.2 

U.S. Fuel Resources 

Oil

5%

Gas

10%

Coal

85%

Figure 1.3 

World Coal Reserves 

0

50

100

150

200

250

USA Russia China India Australia Germany South Africa Ukraine Kazakhstan Poland Rest of

World

Billions of Tonnes

Anthracite & Bituminous Subbituminous & Lignite

`
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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10

Since very little new baseload capacity had been built in the 1990s, some areas of the country began to 

experience electric generation capacity shortfalls. This immediate 

need, combined with easy credit from lenders and the false 

assumption that natural gas prices would remain low for the 

foreseeable future, led to a massive overbuild of natural gas-fueled 

power plants. By default, the energy policy of the United States 

encouraged the building of natural gas-fueled power plants. From 

1998 to 2003, over 140 GW of new natural gas-fired generation 

capacity was completed. Because the price of natural gas is now at record high levels, much of this 

capacity is significantly underutilized because its cost of producing electricity is significantly higher than 

coal or nuclear power plants. If no new capacity is built to take advantage of lower-cost fuels, these new 

gas-fueled plants will eventually run, even in the face of higher gas prices, and at the added expense of 

Figure 1.4

Coal Capacity Utilization by Region 

Sources: Platts RDI/CoalDat, U.S. Department of Energy 

WECC

80%

MAPP

74%

SPP

76%

ERCOT

80%

SERC

69%

FRCC

58%

MAIN

65% ECAR

67%

NPCC

68%

MAAC

64%

% Utilization of coalfueled generating capacity

Figure 1.5

Historical and Forecasted Fuel Prices 

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

Delivered Fuel Cost ($ / MM Btu)

Coal

Natural Gas

n 00

y 00

n 01

y 01

n 02

y 02

n 03

ly 03

n 04

n 05

ly 05

n 06

y 06

y 04

n 07

y 07

n 08

y 08

n 09

y 09

Delivered cost of fossil fuel at 

steam electric utility plants. 

Source: RDI Fossil-Fuel 

Receipts at Steam-Electric 

Utility Plants through August 

2003 to 2009; U.S. Energy 

Information Administration, 

December 2003 Short Term 

Energy Outlook and Peabody 

estimates September – 

November 2003. NYMEX 

Henry Hub, September 2003 – 

2009.

Most of the natural gasfueled plants that were built 

in the past decade are in 

financial distress because of 

high gas prices.
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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11

those who rely on natural gas for home heating, manufacturing, chemicals, fertilizers and numerous other 

high-value uses. 

According to the EIA, between 1992 and 2002, the demand for natural gas increased by 2.23 billion cubic 

feet (bcf)/day. Of this increase, 93.6% was due to using natural gas for 

electricity generation. Since June 2000, when the price of natural gas 

started its climb, the nation lost over 2.7 million manufacturing jobs. 

These high paying jobs have fled the country due to the price of natural 

gas and many will not return. No amount of new import LNG facilities 

will help to change the cost differential that U.S. industry faces between 

foreign supplies of natural gas and what can be delivered to their door. What can be relied on is the 

utilization of U.S. coal for the generation of electricity. 

Building new coal-based plants and increasing the use of coal is the solution to the natural gas shortage 

and price problem. Using coal for electricity generation frees natural gas for use on higher value 

applications. A large, new 1,500 MW coal-based plant would displace 0.22 bcf/day of natural gas. If 120 

new 1,500 MW coal-based power plants were constructed over the next 30 years, coal-based electricity 

generation could displace 10 Tcf/year of natural gas demand. The capital cost of this construction would 

be less than $300 billion (2004$). Figure 1.7 shows a partial representation of the new coal-based power 

plants proposed in the United States. Announcements of new coal-based plants are occurring at a rapid 

pace. While it is unlikely that all announced power plants will be built, a reasonable percentage would 

mitigate the growth in demand for natural gas for electricity generation, and would conserve natural gas 

for industrial, chemical, and home heating demands where gas provides a premium value. 

Figure 1.6

Forecasted Growth in Fuel Demand for Electricity Production 

0

2,100

199719992001200320052007200920112013201520172019

Billion KWhrs

Renewable

(excl. Hydro)

Natural Gas

Nuclear

Coal

Source: EIA Annual Outlook 2004 

High natural gas prices 

also hurt other domestic 

industries and resulted 

in a loss of jobs.
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

12

Energy and environmental issues have become inextricably linked. This linkage is both broad and deep, 

and involves concerns about air quality, toxic wastes and global climate change. Promoting the economic 

efficiency and reliability of a competitive energy market, while advancing 

appropriate environmental policies, is a major challenge. When trying to 

balance energy needs with societal goals, sound scientific and economic 

analysis is needed. Cost-benefit and risk analyses are critical tools to be 

used when reviewing and developing environmental laws and regulations. 

Industry has made enormous improvements in the environmental 

performance of coal-based power plants. Emissions from the existing fleet 

of coal-based power plants are lower today than they were in 1970 even as 

power produced from coal plants has increased by 173%. With the 

proposed Interstate Air Quality Rule and the Utility Mercury Rulemaking, 

the reductions in emissions will accelerate. 

Figure 1.7 

New Coal-based Plants Announced Since 2000 

Number of proposed new coal-fueled generating plants and gigawatts of capacity. Source: U.S. Department of 

Energy National Energy Technology Laboratory February 24 2004

1 2.5 GW

2 0.8 GW

3 1.4 GW

1 0.5 GW

4 1.4 GW

2 1.8 GW

2 1.6 GW

3 2.7 GW

3 0.7 GW

6 2.3 GW

1 2.5 GW

1 0.5 GW

2 0.8 GW

8

5.0 GW

1

1.0 GW 2

1.4 GW

3

1.3 GW

1 1.4 GW

1

0.4 GW

1 0.6 GW

1 0.8 GW

2 1.6 GW

1 0.7 GW

3 1 2.4 GW

0.5 GW 10

8.0 GW

2 1.0 GW

4

1.4 GW 1 1.6 GW

3 1.8 GW

1 0.2 GW

5 3.0 GW

State with proposed plants

1 1.4 GW

1 0.5 GW

1 0.2 GW

1 0.4 GW

Number of proposed new coal-fueled generating plants and gigawatts of capacity. Source: U.S. Department of 

Energy National Energy Technology Laboratory February 24 2004

1 2.5 GW

2 0.8 GW

3 1.4 GW

1 0.5 GW

4 1.4 GW

2 1.8 GW

2 1.6 GW

3 2.7 GW

3 0.7 GW

6 2.3 GW

1 2.5 GW

1 0.5 GW

2 0.8 GW

8

5.0 GW

1

1.0 GW 2

1.4 GW

3

1.3 GW

1 1.4 GW

1

0.4 GW

1 0.6 GW

1 0.8 GW

2 1.6 GW

1 0.7 GW

3 1 2.4 GW

0.5 GW 10

8.0 GW

2 1.0 GW

4

1.4 GW 1 1.6 GW

3 1.8 GW

1 0.2 GW

5 3.0 GW

State with proposed plants

1 1.4 GW

1 0.5 GW

1 0.2 GW

1 0.4 GW

Emissions from the 

existing fleet of coalbased power plants 

are lower today than 

they were in 1970 

even as power 

produced from coalbased plants has 

increased by 173%.
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

13

One of the long-term, potential concerns with coal use is that it releases more carbon dioxide than other 

forms of energy production. While it is not the purpose of this report to debate whether or not global 

climate change is occurring, it is important to note three things about carbon dioxide emissions from coalbased power plants. First, improvements in power generation efficiency make it possible to reduce 

emissions, including those of carbon dioxide, by using less coal to produce the same amount of electric 

energy. Second, research and development is ongoing to find ways to economically remove and 

sequester carbon dioxide emissions from coal-based power plants. The President and the Department of 

Energy are leading the effort with the proposed FutureGen project. Third, low cost energy, when coupled 

with end-use technologies that use electricity instead of fossil fuels, allows for more productive use of 

energy. 

Figure 1.8

Changes in Coal-Based Electricity & Emissions Since 1970 

-100%

-50%

0%

50%

100%

150%

200%

1970 1975 1980 1985 1990 1995 2000 2002

Percent Increase Since 1970

+173%

-17%

-52%

-89%

Electricity from Coal

NOx

SO2

PM10

-100%

-50%

0%

50%

100%

150%

200%

1970 1975 1980 1985 1990 1995 2000 2002

Percent Increase Since 1970

+173%

-17%

-52%

-89%

Electricity from Coal

NOx

SO2

PM10

+173%

-17%

-52%

-89%

Electricity from Coal

NOx

SO2

PM10

* Estimated 

Source: EPA National Air Pollutant Emission Trends, EIA Annual Energy Review 2002 (October 2003). 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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14

Markets are not perfect, but they can be a tool for fostering energy security, public health and 

environmental protection by allocating fiscal responsibility for the public good. Initial market signals, for 

example, indicated the growing need for peaking capacity requirements (which were relatively less 

expensive and provided for more expeditious construction compared to larger, base load additions) 

leading to more acceptable and immediate returns. Now that energy market signals indicate the need for 

base load units that utilize affordable fuel, the market structure appears to present significant barriers to 

constructing new generation, especially if it is coal-based. 

Cost-effective, flexible and long-term market solutions are needed. These 

solutions must also recognize that the economy is built on the availability of 

reasonably priced energy of all forms. Expanded research programs that 

address science, economics and technology development (and the removal 

of barriers to the deployment of new technologies) are essential to the 

nation's economic health. While continuous improvement of environmental 

controls on power plants is occurring, clean coal technology is commercially 

available and should be utilized. 

While regulatory and tax policies are important tools for attracting the requisite capital investment needed 

for growth in the energy sector, the main incentive that regulators can provide is certainty. The solution is 

an integrated approach to regulation that allows an investor to recover the capital invested in a power 

plant based on existing regulations, with a moratorium on changes to existing regulations that would 

apply to that facility over an extended period of time. With that, the investment in the plant would not 

become stranded prematurely. This certainty will allow needed capital stock turnover and provide 

incentives for new investments. 

The goal is to encourage the development and deployment of domestic, reliable, affordable and 

environmentally sound energy supplies, end use technologies and energy infrastructure. Investment tax 

credits, loan guarantees and accelerated depreciation (or similar mechanisms) and patent development 

Figure 1.9 

Low Cost Electricity Leads to Lower Greenhouse Gas Intensity

Investment is required 

to support our energy 

growth; R&D, 

regulatory certainty and 

appropriate incentives 

will ensure investment 

in clean coal 

technologies.
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

15

support should be the primary market tools. Utility commission support and facilitating environmental 

permitting are the primary regulatory tools. Reliance on a properly structured marketplace for energy 

decisions regarding pricing, technology deployment, energy efficiency and fuel diversity will provide the 

needed impetus for economic growth. Investments in energy technology research and development will 

need to focus on energy sources and uses that can realistically be expected to have a significant impact on 

economic growth and environmental performance over the next 20 years. The development and 

deployment of energy infrastructure will need to include technologies that are capable of producing 

energy at progressively higher efficiency and with lower emission levels for both domestic and global 

applications. Educational programs recognizing the importance of energy infrastructure and energy 

sources, their importance to continued energy security, and the link to economic development need to be 

reemphasized. Comprehensive electric restructuring has to seek long-term improvements to the electric 

system while energy and environmental regulatory requirements must become predictable. 

Public/Private efforts are a desirable way to address the declining investments in the needed research, but 

this concept does not go far enough. The states and the federal government need to concentrate on 

allowing innovation to mature. To this end, government needs to underwrite, if not fully finance, private 

patents (applicable to all the above-mentioned sectors) without taking ownership; and continue this 

guaranteed investment to the stage of first commercial application. These guarantees, without onerous 

strings attached, will allow the freedom to pursue ideas that are currently falling by the corporate wayside because they do not add to the immediate bottom line. Financing concepts that can apply to 

regulated and unregulated states are possible. Major technological changes are needed, however, to 

accommodate the new open-market approach. This is true for all energy markets, domestic and global. 

Above all, system reliability must be assured despite vastly more complex operations including huge 

volumes of hourly and daily transactions and far more participants in the movement of energy from 

source to users. 
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Section 2: Technology Choices and Economics 

Overview 

This section of the report provides technical descriptions of the primary types of coal-based technologies 

being considered for new power plants, focusing on comparisons of their performance, efficiency, and 

cost. In addition, descriptions of emission control technologies and their impacts on unit cost and 

performance are discussed. Utilizing this information on performance and cost, the results of an economic 

case study that compares a range of power generation technologies are provided. This information can be 

used by plant developers to compare the various technologies, along with their relative capital and O&M 

costs, environmental performance, heat rate and overall cost of electricity (COE). 

Coal-Based Technology Descriptions 

Pulverized Coal (PC)

PC plants have continued to develop over the last decade. In the U.S., most have utilized standard, 

subcritical operating conditions at 2,400 psig/1,000°F superheated steam, with a single reheat to 1,000°F. 

A typical PC plant is shown in Figure 2.1. Since the early 1980s, there have been significant 

improvements in materials for boilers and steam turbines and a much better understanding of the cycle 

water chemistry. These improvements have resulted in an increased number of new plants employing 

supercritical (SC) steam cycles around the world. SC units typically operate at 3,600 psig, with 

1,050-1,100°F main steam and reheat steam temperatures. On the average, these SC units have 

efficiencies of about 3 percentage points higher than subcritical units, representing an 8% relative 

improvement in efficiency. Steam temperatures above 1,050°F are often referred to as ultra-supercritical 

(USC) conditions. 

Figure 2.1 

PC Block Flow Diagram (Subcritical, Wet Limestone Forced Oxidation FGD) 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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17

Over the past 10 years, significant improvements have also been achieved in reducing heat losses in the 

low pressure end of steam turbines, improving both efficiency and reliability of the overall generating 

units.

The choice of subcritical cycles for the coal-based power plants that have 

been built in the U.S. in the last 20 years has been mainly due to relatively 

low fuel costs. This has eliminated the cost justification for higher capital 

costs for higher efficiency cycles, such as SC. In international markets, 

where fuel cost is a higher fraction of the total COE, the higher efficiency 

cycles offer advantages which can result in favorable COE comparisons and 

lower emissions compared to subcritical plants. Of the more than 500 SC 

units in the world, 46% are in the former USSR, 12% are in Europe, and 10% are in Japan. Almost onethird of SC units are in the U.S.; and all of these U.S. units were built prior to 1991. None have been built 

since, although one has been announced for a plant in the Midwest. There is considerable activity with 

new SC units in Europe and Asia. 

The selection of SC versus a subcritical cycle is still dependent on many other site-specific factors, 

including fuel cost, emission control requirements, capital cost, load factor, local labor rates and expected 

reliability and availability. With the extensive favorable experience in Europe and Asia with SC steam 

cycles during the last decade, their superior environmental performance and the relatively small cost 

difference between SC and subcritical plants, it is becoming more difficult to justify new subcritical steam 

plants.

While improvements in boiler and turbine materials and designs have resulted in higher efficiency and 

availability, the continued addition/retrofit of emission control systems to meet progressively stringent 

emission standards has had a significant impact on unit performance and cost. Most new PC units utilize 

flue gas desulfurization (FGD) systems based on wet limestone scrubbing with forced oxidation (LSFO), 

in order to control SO2 emissions. With more than 25 years of full-scale commercial implementation of 

this technology, it has become much more reliable and far less costly. Still, only about one-third of 

existing coal-based units have FGD systems. Combustion modifications for the reduction of NOx

emissions from existing units have been widely implemented, primarily due to the acid rain provisions of 

the Clean Air Act Amendments of 1990. Low-NOx burners developed as part of the Department of 

Energy’s Clean Coal Technology demonstration program in the 1990s have been retrofitted in many units 

across the country. The retrofit of dozens of selective catalytic reduction (SCR) systems for postcombustion NOx control resulted from EPA’s State Implementation Plan call for NOx reductions to 

reduce the interstate transport of NOx, primarily in the eastern states. The performance of these emission 

control technologies has continued to improve. However, cost and performance impacts are significant. 

These impacts are discussed later in this section. 

Potential reductions in greenhouse gas emissions, particularly for CO2, have also gained significant 

attention. For coal-based technologies, one available option to reduce CO2 emissions per unit of 

electricity generated is to increase the unit’s efficiency, so that less coal is burned per MWh generated. 

Figure 2.2 shows the reduction in CO2 emissions that could be achieved with increases in efficiency. 

These increases could be accomplished by retiring an older subcritical unit and replacing it with a more 

efficient boiler (i.e., SC or USC). For example, an advanced USC plant with an efficiency of 46-48% 

(HHV basis) would emit approximately 18-22% less CO2 per MWh generated than an equivalent-sized 

subcritical PC unit. Of course, this reduction would also apply to emissions such as SO2 and NOx, since 

the more efficient plant would use less coal to produce the same energy. It is estimated that if the next 10 

GW of coal-based plants were to be built using more efficient SC technology, CO2 emissions would be 

about 100 million tons less during the lifetime of those plants, even without installing a system to remove 

the CO2 from the exhaust gases. 

PC plants have been 

the workhorse of 

America’s coalbased power plant 

fleet for decades. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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18

Figure 2.2 Carbon Dioxide Emissions vs. Net Plant Efficiency 

Fluidized-Bed Combustion (FBC)

In FBC units, coal is combusted in a hot bed of sorbent particles that are 

suspended in motion (fluidized) by combustion air that is blown in from below 

through a series of nozzles. The fluidized bed of solids provides thermal 

“inertia” which moderates upsets due to sudden changes in fuel composition. 

More than 95% of the solids consist of sorbents capable of capturing the SO2

released during the combustion of coal and inert coal ash. The coal and coal 

char constitute less than 5% of the bed solids. 

A typical FBC plant is shown in Figure 2.3. Like conventional PC units, FBC 

units operate in a Rankine steam cycle, utilizing steam produced in a boiler to 

drive a steam turbine generator. FBC boilers operate at lower temperatures 

than PC boilers, and burn crushed fuel in a fluidized bed rather then pulverized fuel in a PC unit’s 

furnace. The heat rates of FBC plants tend to be slightly higher than PC plants at the same plant size and 

steam conditions because of higher excess air and higher auxiliary power requirements. In general, FBC 

boilers burn coals with higher excess air (18-25% instead of 15-20% for PC), which results in higher flue 

gas heat loss. The higher pressure drop across the furnace requires more fan energy. However, the 

advantage of using FBC technology is that FBC boilers capitalize on the unique characteristics of 

fluidization to control the combustion process, minimize NOx formation, and capture SO2 in-situ.

In addition, FBC boilers are capable of burning a range of fuels, including bituminous and subbituminous coals, coal waste, lignite, petroleum coke, and a variety of waste fuels or “opportunity” fuels 

like biomass that cannot be accommodated by PC units. In many instances, units are designed to use 

Carbon Dioxide Emissions vs Net Plant Efficiency

0.60

0.65

0.70

0.75

0.80

0.85

0.90

37 38 39 40 41 42 43 44 45 46 47 48 49 50

Net Plant Efficiency, %

CO2 Emissions, tonne/MWh .

0

5

10

15

20

25

30

Percent CO2 Reduction

CO2 Emission, tonne/MWh Percent CO2 Reduction from 

Subcritical PC Plant

(Based on firing Pittsburgh #8 Coal)

Subcritical 

PC Plant

Ultrasupercritical 

PC Plant Range

FBC technology 

has benefited 

greatly from 

incentives in the 

1980s to assist in 

the commercialization of this 

clean coal 

technology.
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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19

several fuels, emphasizing one of this technology's major advantages: its inherent fuel flexibility. FBC 

boilers also can readily handle many fuels that are problematic in PC boilers. 

Figure 2.3 Fluidized-Bed Combustion Block Flow Diagram 

The most common FBC designs employ a large hot cyclone between the furnace and the convective heat 

transfer sections to recirculate unreacted sorbent and unburned fuel back to the bed, where the remaining 

carbon can be burned and more SO2 captured. These systems are called circulating fluidized-bed 

combustors (CFB). Due to superior mixing characteristics of CFBs compared to bubbling-bed FBCs, the 

excess air levels for CFBs are generally lower than for FBCs. Also, the higher sensible heat of the larger 

solid mass discharged and the higher pressure drop in the forced-draft fan in the FBC plants tend to make 

the heat rates for FBC inherently higher. 

CFB operates at gas velocities high enough to entrain a large portion of the solids (12-30 ft/s), which then 

is separated from the flue gas and recycled (recirculated) to the lower furnace to achieve good carbon 

burnout and SO2 sorbent utilization. Typically, an external hot cyclone is used at the furnace exit as a 

separation device. CFB recycle ratios usually exceed 40 lbs. of recycled solids per pound of feed solid, 

and may be much higher depending on the cyclone efficiency. 

Because of the high recycle rate (high residence time) of unutilized sorbent and unburned carbon, CFB 

provides better SO2 capture and better carbon burnout than bubbling bed (FBC) units. CFB also facilitates 

more effective air staging for improved NOx control and is less prone to upsets due to fuel quality 

variation. Another important advantage of CFBs is that they require significantly fewer fuel and sorbent 

feed points compared to bubbling FBCs. This provides more simplified designs, better operational 

characteristics, and easier scale up to larger size units. Consequently, CFB is the predominant type of 

FBC boiler installed worldwide in unit sizes above 200,000 lbs. per hour of steam. Currently, the largest 

CFB unit in operation is 320 MW, but designs for units up to 600 MW have been developed by three of 

the major CFB suppliers. Some of these designs are based on SC steam conditions. 

In-bed boiler tubes cannot be used in the CFB furnace because of severe tube erosion. However, an 

optional external bubbling fluidized bed can be employed as an external heat exchanger (EHE). In this 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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20

unit, boiler tubes are immersed in a bed of the hot recirculating solids from the cyclone that are lightly 

fluidized by low-velocity secondary air. The cooler solids leaving the EHE are then recycled to the lower 

furnace. An EHE can take up a large fraction of the total heat duty in a large CFB unit, and therefore 

provides a flexible alternative to the need for additional in-furnace heat transfer surface in units larger 

than 40 MW. An EHE is also advantageous in conserving the furnace height in large CFB units and in 

optimizing reduced-load operation. 

For SO2 capture, limestone is fed into the fluidized bed in addition to the coal. The limestone is converted 

to free lime, a portion of which reacts with the SO2 to form calcium sulfate. At steady-state operation, the 

bed consists of unburned fuel, limestone, free lime, calcium sulfate and ash. Because of the well-mixed 

nature of the bed and the relatively long residence time of the fuel particles (via high recycle rates in the 

CFB), efficient combustion can be maintained at temperatures as low as 1,550-1,650qF. This combustion 

temperature limits the formation of thermal NOx and is the optimum temperature range for in-situ capture 

of SO2 by the free lime. This temperature also prevents or reduces the slagging of coal ash on heat 

transfer surfaces. 

In an FBC unit, SO2 capture is a function of the limestone reactivity and Calcium-to-Sulfur (Ca/S) molar 

ratio, increasing in proportion to these parameters. As the sulfur content of the fuel increases, the Ca/S 

molar ratio required for a given percentage SO2 reduction decreases because of the increased driving 

force (partial pressure) for the sorption process. For high-sulfur coals (> 2% S), Ca/S molar ratios of 2–

2.5 are required to achieve 90% sulfur removal. For low-sulfur coals (< 1%), Ca/S molar ratios as high as 

3–6 are required to achieve the same 90% sulfur removal. Recent CFB boiler designs include dry FGD 

systems to remove additional SO2 at the back end and increase overall SO2 capture to over 98%. Due to 

the high molar ratios of limestone required to capture and remove the SO2, reagent and disposal costs are 

50–100% higher than for PC plants with FGD systems using typical bituminous coals. 

The environmental performance of FBC compared to PC boilers is enhanced by the inherently lower NOx

production due to the relatively low combustion temperatures of the FBC process. Staging the combustion 

air and decreasing the overall excess air level also reduces NOx production. Emissions are typically in the 

range of 0.05–0.20 lb/MBtu without post-combustion NOx controls, compared to 0.20–0.40 lb/MBtu for 

new PC boilers with the latest low-NOx burners and over-fire air. The use of relatively inexpensive 

selective non-catalytic reduction (SNCR) systems with FBC can reduce the flue gas NOx level an 

additional 50-90%, depending on ammonia slip and detached plume considerations. With a PC boiler, the 

more expensive SCR system would probably be required to achieve the same flue gas NOx levels as FBC 

with SNCR.

However, the low combustion temperature does have some disadvantages. CFB boilers emit higher levels 

of N2O, which forms and survives at temperatures below 2,000 qF. N2O is a greenhouse gas with a Global 

Warming Potential 296 times that of CO2. Because of its low concentration in the flue gas (typically in 

the range of 40-70 ppm at 3%O2) this N2O emission corresponds to an equivalent 15% increase in CO2

emissions. A more detailed discussion of N2O emissions from FBC has been presented in the May 2003 

NCC Report “Coal Related Greenhouse Gas Management Issues”. 

Integrated Gasification Combined Cycle (IGCC)

IGCC allows the use of coal in a power plant with the environmental benefits of a natural gas-fueled plant 

and the thermal performance of a combined cycle. A block flow diagram of a non-integrated IGCC 

system is shown in Figure 2.4. In its simplest form, coal is gasified with either oxygen or air, and the 

resulting synthesis gas (or syngas), consisting primarily of hydrogen and carbon monoxide, is cooled, 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

21

cleaned and fired in a gas turbine. The hot exhaust from the gas turbine passes through a heat recovery 

steam generator (HRSG) where it produces steam that drives a steam turbine. Power is produced from 

both the gas and steam turbine-generators. By removing the emission-forming constituents from the 

syngas under pressure prior to combustion in the power block, an IGCC power plant can meet extremely 

stringent emission standards. 

Figure 2.4 

IGCC Block Flow Diagram 

There are many variations on this basic IGCC scheme, especially in the degree of integration. It is the 

general consensus among IGCC plant designers today that the preferred design is one in which the air 

separation unit (ASU) derives part of its air supply from the gas turbine compressor and part from a 

separate air compressor. Since prior studies have generally concluded that 25-50% air integration is an 

optimum range, the case study in this section of the report has been developed on that basis. 

Three major types of gasification systems are used today: moving bed, fluidized bed, and entrained flow. 

Pressurized gasification is preferred to avoid large auxiliary power losses for compression of the syngas. 

Most gasification processes currently in use or planned for IGCC applications are oxygen-blown instead 

of air-blown technology. This results in the production a higher heating value syngas. In addition, since 

the nitrogen has been removed from the gas stream in an oxygen-blown gasifier, a lower volume of 

syngas is produced, which results in a reduction in the size of the equipment. High-pressure, oxygenblown gasification also provides advantages if CO2 capture is to be considered at a later date. 

Entrained-flow gasifiers that deliberately operate in the higher-temperature 

slagging regions have been selected for the majority of IGCC project 

applications. These include the coal/water-slurry-fed processes of General 

Electric (formerly ChevronTexaco) and ConocoPhillips (formerly 

Dow/Destec E-Gas), and the dry-coal-fed Shell process. A major advantage 

of the high-temperature entrained-flow gasifiers is that they avoid tar 

formation and its related problems. The high reaction rate also allows single gasifiers to be built with 

large gas outputs sufficient to fuel large commercial gas turbines. Recent studies have shown that a spare 

gasifier can significantly improve the availability of an IGCC plant. 

IGCC plants have 

the advantage of 

very low emissions 

and high efficiency. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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22

Most of the large components of an IGCC plant (such as the cryogenic cold box for the ASU, the gasifier, 

the syngas coolers, the gas turbine and the HRSG sections) can be shop-fabricated and transported to the 

site. The construction/installation time is estimated to be about the same (three years) as for a 

comparably-sized PC plant. 

IGCC provides several environmental benefits over PC units. Since gasification operates in a low-oxygen 

environment (unlike PC, which is oxygen-rich for combustion), the sulfur in the fuel converts to hydrogen 

sulfide (H2S), instead of SO2. The H2S can be more easily captured and removed than SO2. Removal rates 

of 99% and higher are common using technologies proven in the petrochemical industry. 

Due to its high flame temperature, combustion of the syngas in a gas turbine can result in high NOx

emissions in the exhaust gas unless controlled by other means. IGCC units can be configured to operate at 

very low NOx emissions without the need for SCR. Two main techniques are used to lower the flame 

temperature for NOx control in IGCC systems. One is to saturate the syngas with steam or hot water and 

the other is to use nitrogen from the ASU as a diluting agent in the combustor. Application of both 

methods in an optimized combination has been found to provide a significant reduction in NOx formation. 

NOx emissions typically fall in the 15 ppmv (at 15% O2) range, just above those from natural gas 

combined cycle (NGCC) units, and when converted to a 3% O2 basis, are similar to those from PC 

boilers.

An advantage of adding the extra mass from the steam, hot water or nitrogen into the gas turbine is that 

additional power is generated in the gas turbine and steam cycle. The type of gas turbine largely 

determines the electric output of an IGCC plant. The GE 7FA gas turbines used in the case study 

presented in this report have a nominal output of 197 MW in an IGCC application. 

The basic IGCC concept was first successfully demonstrated at commercial scale at the pioneer Cool 

Water Project in Southern California from 1984 to 1989. There are currently two commercially sized, 

coal-based IGCC plants in the U.S. and two in Europe. The two projects in the U.S. were supported 

initially under the Department of Energy’s Clean Coal Technology demonstration program, but are now 

operating commercially. 

The 262 MW Wabash River IGCC repowering project in Indiana started up in October 1995 and uses the 

E-Gas gasification technology (which was acquired by ConocoPhillips in 2003). The 250 MW Tampa 

Electric Company Polk Power Station IGCC project in Florida started up in September 1996 and is based 

on GE (formerly ChevronTexaco) gasification technology. The first of the European IGCC plants was the 

NUON (formerly SEP/Demkolec) project in Buggenum, the Netherlands, using Shell gasification 

technology. It began operation in early 1994. The second European project, the ELCOGAS project in 

Puertollano, Spain, uses the Prenflo (Krupp-Uhde) gasification technology and started coal-based 

operations in early 1998. In 2002, Shell and Krupp-Uhde announced that henceforth their technologies 

would be merged and marketed as the Shell gasification technology. 

The Wabash River and Polk IGCC plants represent the cleanest coal-based power technologies that exist 

today, and the current state-of-the-art facilities have even superior performance. A PC plant with 

emission controls may approach IGCC’s performance in one or two areas, but does not match IGCC’s 

lower overall environmental impact including air, water, and solids emissions. A state-of-the-art IGCC 

with enhanced sulfur removal technology can simultaneously achieve greater than 99.5% sulfur removal, 

essentially total volatile mercury removal (greater than 90-95% removal), and PM levels of <0.004 

lb/MBtu. The state-of-the art IGCC plant will also produce only 40% as many solid byproducts as PC 

units, and will use almost 40% less water. 
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Effects of Coal Quality on Coal-Based Power Generation 

Technologies

Fuel type is an important criterion that must be considered when choosing 

a given technology. Theoretically, any of the advanced coal technologies 

can use bituminous, sub-bituminous, or lignite coals. However, the coal 

characteristics of the different ranks of coals significantly impact the 

design of the different technologies and have different impacts on capital 

costs and operating efficiencies. This section discusses the significant differences. 

PC Plants

Coal properties affect PC plant heat rates and boiler size. High moisture and high ash contents reduce 

boiler efficiency. Concern over corrosion in the cold end of the air heater and downstream ductwork (due 

to condensation of SO3 as sulfuric acid) sets a minimum value on the permissible boiler outlet temperature 

when higher sulfur coals are used, and thereby reduces the achievable boiler efficiency. Each 18°F 

increase in air heater exit temperature reduces heat rate by about 14 Btu/kWh, or approximately 2%. 

Lower air heater exit temperatures can typically be achieved in plants designed for higher-quality, lower 

sulfur coals, where SO3 levels and their resulting dew points are much lower. 

Coal ash constituents can have a major impact on boiler design and operation. PC boilers are designed to 

utilize coals with either low or high ash fusion temperatures. For low ash fusion temperatures, the ash 

constituents are in molten form (slag) at furnace temperatures (“wet-bottom 

boilers”). The molten slag must be cooled, usually in a water bath, then 

crushed and sluiced to disposal or for recovery as a by-product. When ash 

fusion temperatures are high, the bottom ash exits the bottom of the boiler in 

solid form (“dry bottom boilers”), where it enters a water bath and is 

crushed and sluiced to disposal or storage. Over the past 30 years, many 

boilers designed for high sulfur, low ash fusion coals have been converted to 

lower sulfur coals to meet Clean Air Act emission reduction requirements 

for SO2. Many of these low sulfur coals also have high ash temperatures. In 

order to utilize these coals in wet bottom boilers, operators have installed fluxing systems, which add a 

small percentage of materials such as limestone and iron oxide, chemically changing the make-up of the 

ash enough to lower the ash fusion temperature and allow it to melt at furnace temperatures. Blending 

coals of various sulfur and ash contents has become commonplace in the industry as a way to optimize 

boiler performance and environmental compliance. 

Many units have been converted from high-sulfur, eastern bituminous coals to low-sulfur, sub-bituminous 

coals, primarily from the Powder River Basin (PRB) region. Due to changes in moisture and volatile 

content, power plant operators have had to make significant expenditures in coal unloading, coal 

handling, fly ash collection and fire protection systems to be able to handle these dusty coals in a safe 

manner.

CFB Plants

CFB plants have demonstrated the ability to burn high ash, high slagging/fouling fuels that would be 

problematic in a PC boiler. The cost impact of designing a CFB boiler to burn a sub-bituminous coal or 

lignite compared to lower-moisture, lower-ash, and lower-alkaline bituminous coal is less for a CFB 

boiler than for a PC boiler. This is primarily because the PC furnace heat transfer area must be increased 

Higher ash, lower 

heating value and 

higher sulfur coals 

adversely impact PC 

plant costs and 

performance. 

Coal characteristics 

can have a significant 

impact on the selection 

of the optimum 

technology. 
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in order to reduce furnace exit gas temperature as the ash softening 

temperature drops and thereby prevents slagging of the convective pass. Subbituminous fuels and lignites generally have alkaline ashes with low ash 

softening temperatures, which require large PC furnaces. On the other hand, 

CFB furnace size is strictly defined by gas velocity. CFB size would be 

increased for sub-bituminous and lignite fuels, but only due to the increase in 

fuel moisture, resulting in a much smaller increase than for a PC furnace. 

IGCC Plants

IGCC plants are proven to work very well with bituminous coal. It is 

important to recognize that different gasification technologies will likely be 

required for different types of coal such as lignite and sub-bituminous. 

The entrained-flow gasifiers of GE, Shell and ConocoPhillips all perform 

better with lower ash, lower moisture bituminous coals. Although these 

entrained-flow gasifiers can process all ranks of coal, most existing commercial gasifiers tend to show an 

increase in cost or reduction in performance with low-rank and high-ash coals. Both the Wabash River 

and Polk Power Station IGCC plants were designed for bituminous coals and most IGCC studies have 

been based on using bituminous coals. 

The relative feed rate is a function of the heating value of the feedstock, although it is exacerbated by the 

additional auxiliary power consumption due to increased oxygen usage and coal handling, preparation and 

feeding – all of these lead to higher heat rates. Gasifier efficiency decreases with decreasing coal rank and 

more of the coal’s energy is in the sensible heat from the gasifier. That leads to higher steam production; 

however, less of the feedstock energy is available to the more efficient Brayton (gas turbine) cycle and the 

overall IGCC efficiency is reduced. (The higher steam generation is more than offset by the increased 

auxiliary power consumption with lower rank coals). 

For slurry-fed gasifiers (GE and ConocoPhillips), the energy density slurries of high moisture and/or high 

ash coal is markedly reduced, which increases the oxygen consumption and reduces the gasification 

efficiency. Previous studies for E-Gas IGCC plants show a drop in performance and increase in capital 

costs as fuel quality is decreased from high quality (high carbon) feedstocks such as petroleum coke and 

Pittsburgh #8 coal to lower quality Illinois #6 and sub-bituminous coals and lignite. As the moisture 

content of the coal increases, the achievable solids concentration in the slurry becomes lower. Combined 

with the increased ash content in the lower rank coals, the energy density of the slurry deteriorates 

markedly. Accordingly, the relative oxygen requirement increases because more oxygen is required to 

evaporate the moisture. 

Research suggests that dry-coal-fed gasifiers (Shell) are more appropriate for low-rank, high-ash coals. 

While studies show there is an energy penalty (and therefore reduced steam turbine output) for drying the 

high-moisture coals to the low moisture content necessary for reliable feeding via lock hoppers and 

pneumatic conveying, less expensive coal-drying techniques are now being developed with Department 

of Energy funding. In addition, more efficient and effective technologies have shown promising results 

with low-rank coals, such as the KBR transport gasifier being demonstrated at the Power Systems 

Development Facility, which receives funding from the Department of Energy, and was recently selected 

for funding under the DOE’s Clean Coal Power Initiative. 

CFB Plants have 

more fuel flexibility 

and are well suited 

to burn low-rank 

coals such as 

lignite.

IGCC Plants are 

well suited for 

bituminous

coals.
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Although IGCC is close to being competitive with PC for bituminous coals, gaps widen for the capital 

costs and COE between slurry-fed IGCC and PC for low rank coals to about $200-300/kW for PRB coal 

and approximately $400/kW for U.S. lignites. Previous studies by EPRI and others indicate the E-Gas 

IGCC plants do not appear to compete economically with PC plants when using PRB coals and lignites. 

Figure 2.5 shows the impact of coal rank, or coal heating value, on the relative heat rates and capital costs 

of PC plants and E-Gas IGCC plants. This illustrates the challenges of lower rank coals, particularly for 

slurry-fed gasifiers. This impact would be considerably less for dry-fed gasifiers. 

Given the abundance and low cost of U.S. resources of low rank fuels such as Power River Basin subbituminous coals and Texas and North Dakota lignites, there is a great need to demonstrate and improve 

the performance of IGCC with these fuels. 

Figure 2.5 

Effect of Coal Quality on Heat Rate and Capital Cost 

Economics of Power Generation Technologies 

Figure 2.6 summarizes the results of an EPRI study which 

evaluated the performance, capital cost and COE for a range of 

500 MW plants using various power generation technologies. The 

coal technologies for PC and IGCC applications are based on the 

use of a Pittsburgh #8 bituminous coal. The CFB case is based on 

the use of Illinois #6 bituminous coal. 

The capital cost estimates shown in the figure represent average 

costs for each technology, based on EPRI’s experience. Capital 

cost estimates can vary widely depending on such factors as plant location, size, coal properties, and 

owner preference items. Labor rates can vary by more than 30%, depending on plant location. The 

resulting total plant costs could vary by as much as 20-25%. The total plant cost (TPC) shown in the 

1.00

1.05

1.10

1.15

1.20

1.25

1.30

1.35

1.40

5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000

Coal Heating Value, Btu/lb HHV

Relative Heat Rate or Capital Cost

 IGCC Capital Cost (E-Gas)

 IGCC Heat Rate (E-Gas)

 PC Capital Cost

 PC Heat Rate

TX Lignite WY PRB

Illinois #6

Pittsburgh #8

While representative 

capital costs are provided, 

capital cost estimates can 

vary widely depending on 

variable factors like

plant location, size, coal 

properties and owner 

preference items.
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table includes engineering and contingency, and is also frequently referred to as the “EPC” cost. Total 

Capital Requirement (TCR) includes TPC plus other cost items such as interest during construction, startup costs, working capital and land. Permits and other costs such as owner’s engineering, project 

management, or legal expenses are project- and/or owner-specific and are not included in the TCR. IGCC 

projects typically include additional cost items in TCR, such as licensing fees, front-end engineering 

design (FEED) costs, and could also include higher financing costs due to the perception of greater risk. 

For this EPRI study, the additional costs included in TCR are about 16% of TPC for the PC plants, and 

nearly 19% is added to the TPC for IGCC plants. 

The major components of the 500 MW PC units shown in Figure 2.6 include coal-handling equipment, 

the boiler island, turbine-generator island, FGD system, fabric filter, bottom ash and fly ash handling 

systems, and a wet stack with no flue gas reheat. The cost and design data include low-NOx burners and 

SCR to reduce NOx emissions to about 0.1 lb/MBtu for all cases. 

The boiler island includes the coal pulverizers, burners, waterwall-lined furnace, superheater, reheater, 

economizer, soot blowers, regenerative air heater, and axial-flow forced- and induced-draft fans. For the 

subcritical unit shown in Figure 2.1, the steam conditions are 2,400 psig/1,000°F superheated steam, with 

a single reheat to 1,000°F. For the SC unit, the main steam pressure is 3,600 psig, with 1,100°F main and 

reheat steam temperatures. 

The turbine-generator island includes the main, reheat and extraction steam piping, feedwater heaters, 

condenser, mechanical draft cooling towers, boiler feed pumps and auxiliary boiler. The steam turbine is a 

tandem-compound unit, designed for constant pressure operation with partial arc admission. The 

feedwater heating system uses two parallel trains of seven heaters, including the deaerator; the boiler feed 

pumps are turbine-driven. The condenser is designed to operate at 2.0 in. Hg back pressure. 

An LSFO FGD system is required for medium- to high-sulfur coals (>2%). For this study, the LSFO FGD 

system utilizes one 100% module and no spare, which has become an industry standard for new units and 

for many retrofits. The design limestone feed rate is 1.05 moles CaCO3/mole SO2 removed, achieving 

95% SO2 removal. The flue gas enters the wet stack at about 125°F. The particulate collection system is a 

reverse-gas fabric filter, located ahead of the FGD system. Two 50%-sized fabric filter modules are 

connected in parallel. 

Many assumptions go into the data used in the table on the next page. The assumptions 

used will drive the calculated COE, which drives the technology selection. In general, 

the cost of natural gas will be a primary driver on the economics of NGCC plants. The 

capital cost and capacity factor will be a primary driver on the economics of a coal plant. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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Figure 2.6 

Costs for 500 MW Power Plants Using a Range of Technologies 

PC

Subcritical

PC

Supercritical

CFB IGCC 

(E-Gas)

With

Spare

IGCC 

(E-Gas)

No Spare 

NGCC 

80%

CF

NGCC

40%

CF

Total Plant 

Cost, $/kW 1,230 1,290 1,290 1,350 1.250 440 440

Total Capital 

Requirement, 

$/kW

1,430 1,490 1,490 1,610 1,490 475 475

Fixed O&M, 

$/kW-yr 40.5 41.1 42.2 56.1 52.0 5.1 5.1

Variable

O&M,

$/MWh

1.7 1.6 4.0 0.9 0.9 2.1 2.1

Avg. Heat 

Rate,

Btu/kWh

(HHV)

9,310 8,690 9,800 8,630 8,630 7,200 7,200 

Levelized 

Fuel Cost, 

$/MBtu

(2003$) 

1.50 1.50 1.00 1.50 1.50 5.00 5.00

Capital,

$/MWh

(Levelized) 

25.0 26.1 26.1 28.1 26.0 8.4 16.9

O&M,

$/MWh

(Levelized) 

7.5 7.5 10.1 8.9 8.3 2.9 3.6

Fuel, $/MWh 

(Levelized) 14.0 13.0 9.8 12.9 12.9 36.0 36.0

Levelized 

Total COE, 

$/MWh

46.5 46.6 46.0 49.9 47.2 47.3 56.5

1st Year 

COE,

$/MWh

61.4 62.2 61.5 66.7 62.8 49.3 63.5

Other assumptions used to derive these results are as follows: 

1. Book life = 20 years 

2. Commercial Operation Date = 2010 

3. Total Plant Cost (TPC) includes Engineering and Contingencies 

4. Total Capital Requirement (TCR) includes Interest During Construction and Owner’s Costs (see text for 

details) 

5. Assumes EPRI’s TAG financial parameters 

6. All costs expressed in 2003 dollars 
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7. COE is based on Levelized Constant Dollars and is calculated using the EPRI TAG Revenue Requirement 

Methodology

8. PC plants include FGD (95% SO2 removal) and SCR (80% NOx removal) 

9. CFB plant includes 95% SO2 removal (in-bed) and SNCR for NOx reduction 

10. IGCC includes syngas moisturization/nitrogen dilution to reduce NOx to 15 ppmv 

11. NGCC includes SCR to reduce NOx to 3 ppmv 

12. Capacity factor is 80% except as noted for the NGCC plants 

Plant capacity factor has a significant impact on the COE, especially for capital-intensive coal-based 

technologies. Figure 2.7 shows the impact of capacity factor on the constant-dollar, levelized COE for 

the bituminous coal-based technologies. The NGCC case from Figure 2.6 is included for comparison. A 

spare gasifier for the IGCC case would be necessary to achieve operation at over 85% capacity factor. 

IGCC plants without a spare gasifier are projected to have equivalent availabilities in the low 80’s, 

whereas inclusion of a spare gasifier is expected to increase the IGCC plant equivalent availability to the 

low 90’s. The coal-based technologies become preferred over NGCC at capacity factors over 78-80%. 

Figure 2.7:

Impact of Capacity Factor on Levelized COE

35

40

45

50

55

60

65

60 65 70 75 80 85 90 95 100

Capacity Factor, Percent

Levelized COE, $/MWh (2003$)

PC Sub P8

PC USC P8

IGCC w/Spare

IGCC w/o Spare

NGCC 

Levelized Fuel Prices (2003$):

Pittsburgh #8 Coal = $1.50/MBtu

Natural Gas = $5.00/MBtu

Note: IGCC Capacity Factor without a Spare 

Gasifier is limited to about 82%

Another factor to consider in the trade-off of coal-based technologies 

versus NGCC is the fuel plus variable O&M cost, or dispatch cost. As 

shown in Figure 2.8, about 75% of the total levelized COE for an NGCC 

unit is due to fuel cost, whereas this drops to only about 30% for the coalbased technologies, as presented in Figure 2.9. This means that even 

though NGCC and coal may have the same total levelized COE, it is 

unlikely that the NGCC plant would dispatch before the coal plant, due to 

its higher fuel cost. Therefore it is unlikely that an NGCC plant would 

operate at anywhere close to 80% capacity factor. On that basis, coal 

would be the most cost-effective power generation technology. A recent EPRI report indicates that in 

2003 the average capacity factor for NGCC plants was only 29%. With NGCC capacity factors less than 

Once the plant is 

built, coal-based 

power plants have a 

significant

advantage in 

economic dispatch 

because coal is the 

least expensive fuel.
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half of those for coal plants, coal would be the most cost-effective choice for power generation 

technology. 

Figure 2.8 

Breakdown of Levelized COE for NGCC Plant 

Constant Dollar Levelized Cost of Electricity 

for Gas-Fired Combined Cycle

500 MW Plant Size, 2010 Startup, Gas Cost = $4.50/MBtu with 1% real escalation

0

10

20

30

40

50

60

70

2010

201120122013201420152016

2017

2018

20192020

2021

2022

2023202420252026

2027

2028

2029

Levelized Cost of Electricity, $/MWh (2004$)

 Fuel

 O&M

 Capital

Levelized COE
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Figure 2.9 Breakdown of Levelized COE for PC Unit 

Together, capacity factor and fuel cost can be analyzed to determine which fuel and technology will 

provide the lowest COE. Figure 2.10 compares PC and IGCC technologies (using Pittsburgh #8 coal at 

$1.50/MBtu) with NGCC for a range of capacity factors and fuel costs. For high capacity factor (>80%) 

base load plants, coal-based electricity is cheaper than gas-based electricity when gas prices rise above 

$4.75/mmBtu. 

Constant Dollar Levelized Cost of Electricity 

for Pulverized Coal with Pit #8 Bituminous Coal

500 MW Plant Size, 2010 Startup, Coal Cost = $1.50/MBtu with 0% real escalation

0

10

20

30

40

50

60

70

20102011

20122013

20142015

201620172018201920202021202220232024

2025

2026

2027

2028

2029

Levelized Cost of Electricity, $/MWh (2004$)

 Fuel

 O&M

 Capital

Levelized COE
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Figure 2.10 

Air Emission Issues and Cost of Mitigation for Pulverized Coal Plants 

The Clear Skies Act, the Interstate Air Quality Rule and other environmental control initiatives are being 

considered for adoption in the near future. If they go into effect, additional emission controls would need 

to be retrofitted on existing coal-based plants and would be mandatory for new units. This would result in 

lower overall efficiency and higher O&M costs. 

EPRI recently completed a study to estimate the incremental costs for more stringent emission controls 

for PC plants fired with Eastern bituminous (Pittsburgh #8) and Western sub-bituminous (PRB) coals. In 

the study, emission controls for SO2, NOx and particulate matter (PM) were included. Incremental capital 

and O&M costs were developed for each 1% change in emission control. In addition, the levelized cost 

for each additional ton removed and the impact on levelized COE was calculated. 

The study was based on a 500 MW subcritical PC plant located at a site in Wisconsin. Prior to retrofit, 

the plant had no FGD system. NOx emissions were controlled by “typical” low NOx burners and over-fire 

air, while particulates were controlled by an electrostatic precipitator. 

SO2 control technologies included a LSFO FGD system and a lime-based spray dry absorber (SDA) for 

sub-bituminous coal. For LSFO, the SO2 removal range was 90-99%. For higher removal rates with 

LSFO, the scrubber liquid to gas ratio was found to increase nonlinearly with removal percentage. More

Breakeven Capacity Factor and Fuel Cost

for Natural Gas vs Coal

0

10

20

30

40

50

60

70

80

90

100

2.00 3.00 4.00 5.00 6.00 7.00

Levelized Natural Gas Cost, $/MMBtu ('04 $)

Capacity Factor, %

 Gasification Combined Cycle

 Pulverized Coal

Natural Gas Cheapest

Coal Cheapest

(Based on 20 Year Plant Life and Pittsburgh #8 Coal at $1.50/MMBtu)
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pumping power was required and gas-side pressure drops were higher. At removal rates above 96%, 

dibasic acid also had to be added to maintain SO2 removal. 

For SDAs, the SO2 removal range was 90-97%. For higher removal rates with SDA, the Ca/S molar ratio 

was found to increase nonlinearly with removal percentage, and larger absorbent and byproduct handling 

systems were required. 

Different NOx control technologies were used to achieve higher levels of NOx removal. This differed 

from the SO2 control analysis where greater removal levels could be achieved by varying the operating 

conditions or process parameters. Rich reagent injection (RRI) was used to obtain 25% removal. RRI 

reduces NOx formation by injecting amine-based compounds into the fuel-rich region of the furnace. 

SNCR was used to obtain 30% removal. A combination of RRI plus SNCR resulted in 43% removal. 

SCR was used to obtain 80-90% removal. 

A pulse-jet fabric filter was used to control particulate matter (PM) to levels of 0.03-0.005 gr/acf (0.09-

0.015 lb/MBtu). For higher removal levels, the air-to-cloth ratio decreases, the number of compartments 

increases and the number of bags is increased. For highest removal level, the weight and thickness of bag 

is also increased. 

The results of the study indicated that the levelized COE for bituminous coals increased by $0.57/MWh 

when the SO2 removal was increased from the base value of 95% to a high level of 99%. Increasing the 

NOx removal level from the base value of 80% to a high level of 90% raised the levelized COE by 

$0.20/MWh. Finally, the higher level of particulate control increased the levelized COE by $0.13/MWh. 

Therefore, the total increase in levelized COE in going from the base 

emission control levels to the highest control levels was only 

$0.90/MWh. 

A key conclusion from this case study is that once FGD and SCR 

systems have been retrofitted, the incremental COE impact to increase 

SO2 removal from 95-99% or NOx removal from 80-90% is quite small, 

less than $1.00/MWh. Most of the additional cost is for O&M expense 

and consumables. 

Water Issues 

Water demand is increasing throughout most sectors of the U.S. economy (agricultural, residential and 

industrial). This increased demand for water coupled with recent droughts has seriously strained the 

supply of water. Aquifer levels are dropping, especially in the West. Because of the diminishing supply 

of water, many recent power plant projects have selected or have been required to install air-cooled 

condensers, which can cut the water consumption of a combined cycle power plant by about 90%. This 

trend is nationwide, even in humid regions such as the Southeast. The use of air-cooled condensers has 

significantly reduced plant efficiency. 

Disadvantages of air-cooled condensers include higher capital costs, 

loss in plant capacity and an increase in heat rate. Air-cooled 

condensers result in a higher backpressure on the steam turbine, since 

the temperature of the condensing steam must be above the dry bulb 

temperature. In a conventional water-cooled condenser, the condensing 

temperature is keyed to the wet bulb temperature, which is typically 

Even with increased 

costs for retrofitting 

emission reduction 

equipment, coal-based 

power plants are still 

expected to remain 

competitive.

Restrictions on water 

consumption in the 

future will likely result 

in a loss in efficiency for 

new power plants.
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15-20oF below the dry bulb. The performance losses are greatest in the summer, when the need for 

capacity is greatest (for air conditioning). This loss in performance and capacity is a bigger issue for PC 

plants since all of the power is produced in the steam turbine, whereas only one-third of the power is 

produced from the steam turbine for IGCC or NGCC plants. To mitigate these performance losses, 

hybrid systems have been used on some projects, where a conventional wet condenser operates in parallel 

with an air-cooled condenser. 

Market Price of Electricity from Coal-Based Plants 

In a demand-driven competitive marketplace, where the wholesale market purchases electricity from the 

plant at the incremental cost of production, an investor cannot make a profit on a power plant until the 

market price of electricity is at or above the COE of that plant shown in the table in Figure 2.6. Usually, 

older, utility-owned power plants have paid off most or all of the debt and can be dispatched to the 

electric grid at a cost that is only slightly above the fuel and O&M costs of operating the plant. However, 

older coal-based power plants are also operationally less flexible and run optimally as base load plants. 

Given that the daily load is subject to peaks and valleys, the incremental market price is driven by the 

next most dispatched unit. In most regions, this is a gas-fired plant. In comparison to an older coal-based 

power plant, a new gas-fired plant has more flexible operating characteristics allowing it to respond more 

readily to “spikes” in load. However, a gas-fired plant has a higher fuel cost than a coal-based power 

plant. All things being equal, it is the relative mix of fuel types, heat rates and generation technologies 

that drive regional market prices, with coal and nuclear plants serving the base load, and natural gas 

prices driving the market on the margin. 

Figure 2.11 provides representative average market clearing prices for various regions in the U.S. The 

graph shows that the average market price is significantly lower in regions where coal is the dominant 

source of electricity (i.e., Cinergy and Entergy) compared to regions where natural gas is the dominant 

fuel for electricity (PMJ, ERCOT and Palo Verde). This reinforces the benefit of lower electricity prices 

to the consumer where there is abundant, inexpensive coal.

Figure 2.11 

Average Wholesale Electric Market Price 

January 2003 thru April 2004

PJM West Palo Verde

ERCOT

Cinergy

Entergy

0.00

10.00

20.00

30.00

40.00

50.00

$/MWh
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Comparing the values in Figure 2.11 to the values in Figures 2.8 and 2.9 reveals the market risk of 

installing new capacity. Figure 2.8 shows that the levelized COE for a NGCC plant is approximately 

$50/MWh. Yet the average market prices shown in the four regions in Figure 2.11 are all well below that 

level. Therefore, an investor would not be able to recover the investment and cover the fuel and O&M 

costs in a NGCC plant in that region unless the price level reaches 

approximately $50/MWh by the time the unit is placed in service. If a 

coal-based plant were to be developed today, Figure 2.9 shows that the 

market price of electricity would need to be $62/MWh by the time the 

plant starts up for the investor to recover the fuel, O&M and capital 

costs in the first year. The comparison between the cost-recovery 

projections and the market prices is the key factor in developing a plant 

in a competitive marketplace. 

Before investing in a new facility, the forecasted market prices must be sufficiently high enough to cover 

the cost of operating a plant while earning a return on the capital investment. In today’s world, there are 

two fundamental views on the driving force behind the long-term forward price curve. One view is that a 

liquid, tradable energy futures market dictates pricing and the demand for investment in new power 

plants. Others argue that the future prices of electricity should be based on other fundamentals of supply, 

demand, fuel prices and infrastructure issues. This type of debate is a reason why there are many different 

projections of future electricity prices for any given region. 

Regardless of the projections that are used to justify building or not 

building a power plant, once a plant is built, the profitability (or loss) of 

that plant is determined by the ability of a plant to operate successfully. 

The operation of a plant is dependent on the reliability of the plant and 

the capacity factor of the plant. The reliability is determined by the 

ability of a plant to operate when it is called upon to run (availability). 

The capacity factor is determined by the availability and the market 

conditions. In a competitive marketplace, the capacity factor will depend upon the market price of 

electricity compared to the production cost of operating the plant. In a regulated marketplace, 

profitability (or loss) of that plant will depend on the willingness of the regulator to include the capital 

portion (capacity charge) of a plant in the rate base, coupled with the dispatch rate of the plant which is 

determined by the production cost (fuel cost plus variable O&M cost) compared to other plants. When 

one considers that the capital placed at risk for a large coal-based power plant is in the order of $1 billion, 

it becomes obvious that the technology risks and market risks associated with competition from existing 

plants and other technology options must be given careful consideration.

Conclusion

Over the past 20 years, significant improvements in performance and efficiency have been made to coalbased technologies. The use of supercritical boilers is becoming more commonplace around the world, 

and the re-introduction of this efficient technology has begun in the U.S. IGCC plants are expected to be 

competitive with conventional plants. While these improvements in coal-based technologies have 

occurred, new requirements for ever-stringent emission controls have continued to impact coal-based unit 

performance, efficiency and COE. Improvements in plant efficiencies continue to be the most costeffective means to reduce CO2 emissions from coal-based plants. The industry is meeting the challenge to 

increase the efficiency and decrease the cost for these emission control technologies, in order to minimize 

the levelized COE for coal-based generation. 

A new plant will only be 

built if the investor 

expects to recover both 

the capital investment 

and operating costs.

Once a plant is built, it 

is dispatched based on 

its operating cost, 

regardless of the capital 

investment.
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There are many technical and economic factors that go into the decisions of whether or not to build a new 

coal-based power plant and which type of coal technology to use. All of these factors are used as inputs 

to economic models to project the levelized COE and the long-term viability of these investments. As the 

price of natural gas continues to rise, the economic benefits for coal-based generation will become even 

greater.
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Section 3:

Clean Coal Power Incentives – Existing and Proposed 

In the past several years, there have been a number of clean coal power 

incentives proposed in federal energy legislation and by a variety of 

interested groups including the Coal Utilization Research Council 

(CURC), the National Association of Regulatory Utility Commissioners 

(NARUC) and Harvard University. The proposed incentives represent a 

broad spectrum of approaches including grants, interest-free loans, 

federal loan guarantees, investment tax credits, production tax credits and favorable treatment by public 

utility commissions. The targeted projects for such incentives also cover a spectrum ranging from 

demonstration projects to retrofits of existing coal or natural gas-fired plants to deployment of green field 

commercial power plants. Some of the incentives are strictly targeted at commercializing IGCC projects, 

while others apply to all advanced clean coal technologies. A summary description of these incentives 

follows.

This report does not take a position on which of the incentives would be most effective. The important 

issue is that incentives must enable the life-cycle cost of a new advanced coal-based power plant to be 

economically neutral to the investor, vis-à-vis competing alternative 

technologies. Once the cost of a new plant is economically neutral, the utility 

commission is able to justify placing the facility in the utility’s rate base in a 

regulated environment, or the investor is able to finance the plant based on the 

expectation that the revenue from the operation of the facility will be sufficient 

to justify the investment in a competitive marketplace. A key outcome of the 

incentives should be to encourage deployment of multiple new commercial-scale 

advanced coal-based plants that are based on relatively proven designs. 

Clean Coal Power Initiative (CCPI) 

The CCPI is intended to be a 10-year, $2 billion federal program to encourage the demonstration of 

advanced clean coal power technologies. The program is administered by the Department of Energy as a 

series of five solicitation rounds occurring on two-year intervals. Round 1 has been completed; and 

Round 2 solicitations/evaluations are now underway. According to proposed energy legislation, at least 

60% of the CCPI awards should be granted to IGCC or gasification-related technologies and up to 40% to 

advanced combustion and other advanced clean coal technologies. 

To meet overall program objectives, $200 million should have been appropriated in each of the authorized 

10 years. However, less than 72% of the authorized funding has been appropriated to date. (This figure 

drops to 60% if the 2005 proposed appropriations are included in the list. Proposed CCPI appropriations 

for 2005 are only $50 million, just 25% of the authorized amount.) Federal R&D funding appropriations 

for clean coal technologies have also been reduced by 40% or more in the proposed 2005 appropriations 

bill.

Under the CCPI program, up to 50% of the cost-share can come from the federal government in the form 

of interest-free loans. It is intended that these loans should be repaid from the earnings of the awarded 

project (if successful) or from the revenues resulting from additional commercialization of the clean coal 

technology (such as future licensing revenues). 

This report does 

not take a position 

on the relative 

merit of various 

incentives.

The purpose of incentives 

must be to bring the riskadjusted COE of new 

technologies to near that 

of competing alternatives.
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Federal Loan Guarantees 

Various versions of the current proposed omnibus energy bill have included authorizations for a number 

of federal loan guarantees for clean coal projects. Most of the proposed loan guarantees have been 

earmarked for specific projects, but some are more generally limited to a specific type of technology 

and/or fuel source (such as petroleum coke or coal). Such loan guarantees encourage early 

commercialization of new technologies by reducing the risk to financers, owners and ratepayers of these 

relatively expensive yet only modestly proven investments. 

Federal Tax Credits 

Proposed federal tax credits have primarily taken two forms: investment tax credits and production tax 

credits. In some cases, these incentives have appeared separately and at other times combined. These tax 

credits appeared in three main areas of proposed energy legislation: clean coal technologies 

(repowering/retrofitting applications), advanced clean coal technologies (green field applications) and 

clean air program incentives (deployment of new commercial technologies). Versions of these incentives 

appear in pending energy legislation H.R. 6 and S. 2095. These bills have not been approved by 

Congress to date. 

Investment tax credits in the range of 10-17.5% have been proposed for commercialization of new 

advanced clean coal power projects and in the range of 10-15% for clean coal repowering projects. The 

investment tax credits are applied to a limited total megawatt allocation in the range of 4,000-6,000 MW 

for new advanced clean coal projects and in the range of 0-4,000 MW for clean coal repowering projects. 

In the case of the new advanced clean coal projects, the total megawatts are further allocated across a 

defined range of advanced clean coal technologies and are sub-allocated across defined time periods. In 

general, 50% or more of the total megawatts have been allocated to IGCC projects, 25% to supercritical 

PC technologies, 12.5% to pressurized FBC technologies, and 12.5% to other advanced clean coal 

technologies. Up to 50% of these allocations are to be used for projects commercialized before 2009, and 

the remaining allocations for projects commercialized between 2009 and 2017. 

Projects that qualify for these investment tax credits must meet certain defined environmental and 

performance qualifications, such as exceeding targeted reductions of SO2 and NOx and carbon dioxide 

emissions and meeting defined heat rate targets. Coal must be used for at least 75% of the feedstock and 

at least 50% of the project’s output must be electric power. Projects are selected under criteria developed 

by either the Secretary of the Treasury and/or Secretary of Energy, focusing on those projects with the 

highest efficiency and/or best environmental performance. 

Under certain versions of the proposed energy legislation (such as S. 2095), projects that qualify for these 

investment tax credits could also qualify for production tax credits in the range of $0.0010-$0.0140 per 

kWh for up to the first 10 years of operation (adjusted for inflation for years after 2004). The amount of 

the production tax credit varies according to the efficiency of the selected project and according to the 

time period of the project commercialization. The highest production tax credits were assigned to 

projects with the highest overall efficiencies and the earliest commercialization dates. 

Repowering or retrofitting existing older PC boilers with clean coal power technologies also qualified for 

production tax credits under various versions of the proposed energy legislation. These clean coal 

technology credits were limited to a total allocation of 4,000 MW of such projects, with no more than 300 

MW of credits applied to any one project. The proposed production tax credits for such repowering 

applications were $0.0034 per kWh for up to the first 10 years of operation (adjusted annually for 

inflation after 2004). 

In addition to the above tax credits, H.R. 6 (as approved in Conference Committee) allowed five-year 

depreciation write-offs for certain IGCC plants. 
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Clean Air Coal Program 

H.R. 6 (as approved in Conference Committee) also included authorization for almost $2 billion in federal 

funding for years 2006-2012 to encourage deployment of advanced emission control systems and 

advanced clean coal technologies. The Secretary of Energy would be given considerable discretion as to 

how to utilize these funds (grants, loans, loan guarantees, etc.) within certain boundaries (no more than 

50% federal government cost-share, projects selected by competitive solicitation, priority to projects 

smaller than 600 MW, projects must meet certain environmental and heat rate requirements). 

3-Party Covenant (Harvard University) 

The 3-Party Covenant is a financing and regulatory program aimed at reducing financing costs and 

providing a risk-tolerant investment structure to stimulate initial deployment of five to 10 IGCC power 

plants during this decade. Because IGCC is a non-traditional technology for power generation and has 

more perceived risks, incentives must make IGCC more financially attractive than other options to enable 

market penetration. The 3-Party Covenant approach was developed by a group led by Bill Rosenberg of 

the Center for Business and Government, Kennedy School of Government, Harvard University. 

The 3-Party Covenant is based on a three-way arrangement among a federal agency, a state public utility 

commission (PUC) and an equity investor to lower IGCC cost-of-capital by reducing the cost of debt, 

raising the debt/equity ratio and minimizing construction financing costs. The 3-Party Covenant would 

significantly reduce the cost of capital component as well as the overall COE for new facilities, making 

new IGCC technology cost-competitive with PC and NGCC power plants. 

The three key elements of the 3-Party Covenant are: 

1. Federal Loan Guarantees: Federal legislation would authorize a federal agency (such as the 

Department of Energy) to guarantee long-term debt used to finance qualifying IGCC projects. The 

terms of the federal guarantee would include allowing for an 80/20 debt-to-equity financing structure 

and would require that a proposed project obtain from a state PUC an assured revenue stream to cover 

return of capital, cost of capital and operating costs. A government loan guarantee administrator 

would be established and be responsible for ensuring that a proposed IGCC project demonstrate 

economic feasibility and the ability to meet debt service obligations. The administrator would also 

set the financing terms and conditions of a federal guarantee for the debt financing, which include 

equity investor/owner and vendor performance guarantees to provide a measure of protection to the 

loan.

2. State PUC Approval Process: States interested in participating in the program would voluntarily 

opt-in by adopting utility regulatory provisions for implementation by their state PUCs concerning 

review, approval and recovery of the project costs, which might require legislative action to create 

appropriate enabling authority. Specifically, a state PUC (or other utility ratemaking authority in the 

case of public power), acting under state enabling authority, would agree to assure dedicated revenues 

to IGCC projects sufficient to cover return of capital, cost-of-capital and operating costs. The state 

PUC would provide this revenue certainty through adjustments to utility rates in regulated states or 

through non-bypassable wires charges in unregulated states, by certifying that the plant qualifies for 

cost recovery and establishing rate mechanisms to provide cost recovery, including cost of capital. 

The certification by the state PUC would occur up-front when the decision to proceed with the project 

was being made. Also, state PUC prudence reviews would occur as construction was ongoing, which 

would reduce construction risks borne by the developer, avoid accrual of construction financing 

expenses and protect ratepayers. It would be the responsibility of the state PUC to evaluate IGCC 

investment decisions, including a due-diligence certification process, before costs could be passed 
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along to ratepayers. After commencement of plant construction and thereafter, the state PUC would 

conduct ongoing prudence reviews that would protect ratepayers and would be the basis for 

approving recovery of costs. 

3. Equity Investor: The equity investor under the 3-Party Covenant would be either an electric 

utility or an independent power producer that secures a long-term power contract with a utility. The 

investor would contribute equity for 20% of project costs and negotiate performance guarantees to 

develop, construct and operate the IGCC plant. A fair equity return would be determined and 

approved by the state PUC before construction begins. The assured revenue stream provided by state 

PUC certification and approval enables underwriting of the federally guaranteed loan using a higher 

debt-equity ratio (80/20) than available under traditional utility financing terms. The federal 

guarantee provides the purchaser of the long-term debt with an “AAA” credit rating backed by the 

full faith and credit of the U.S. government. 

Implementation of the 3-Party Covenant would require federal legislation authorizing loan guarantees 

for qualifying IGCC projects. The primary risk to the federal loan guarantees is the regulatory risk 

that state PUC determinations regarding cost recovery would be modified or overturned at a future 

date. This regulatory risk, which could be reduced or removed through state legislation or other 

action, is much lower than the risk associated with merchant financing. Using the 3-Party Covenant 

would reduce the default risk of such loan guarantees and would allow a larger number of new plants 

to be covered by a given amount of appropriations. Current proposed federal energy policy 

legislation provides a structure that could provide these federal loan guarantees. 

There are several benefits of using the 3-Party Covenant approach. 

x First, the adjustment for cost-of-capital recovery during construction reduces the total 

required investment, making an IGCC plant only slightly more expensive to build than a 

conventional PC plant. 

x Second, due to the change in capital structure to 80/20 debt-to-equity, the equity required for 

an IGCC plant decreases to approximately half that required for a traditional plant under 

regulated utility financing. However, this high degree of leverage may not be suitable for 

investor owned utilities.

x Finally, the weighted average cost-of-capital in the 3-Party covenant case is reduced by 

several percentage points, as compared to the traditional regulated scenario. This reduces the 

effective overall capital costs of an IGCC plant by almost 40%. 

The net effect would enable IGCC plants to produce energy at lower cost than either a PC plant or an 

NGCC plant in a traditional regulated financing scenario, making it the most attractive development 

option.

NARUC Proposed Incentives 

The Department of Energy and NARUC contracted with Global-Change Associates to conduct a broad 

survey to determine barriers to commercial deployment of IGCC plants. Based on the outcome of that 

survey, a large number of recommendations were developed and listed in a March 2004 report, An

Analysis of the Institutional Challenges to Commercialization & Deployment of IGCC Technology in the 

U.S. Electric Industry: Recommended Policy, Regulatory, Executive and Legislative Initiatives.

The recommendations were organized into six key areas: 
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1. Siting and Permitting: The licensing of IGCC power plants is more complex than for 

conventional coal- or natural gas-fueled generation facilities. Currently, IGCC plants are subject to 

multiple federal and state environmental rules, and may be licensed as electric generation units, 

syngas facilities, and/or co-production plants. The White House Task Force on Energy Project 

Streamlining could establish a multi-jurisdictional group to develop uniform licensing standards for 

siting and permitting IGCC plants. The states could develop memoranda of understanding specifying 

compatible regional standards to address air shed issues associated with IGCC permitting. 

2. Project Capital and Plant Availability: If capital costs exceed a pre-determined target, there 

could be a sharing of the overruns between the developer and the federal government to partially 

protect developers without unduly weakening their incentive to hold down costs. An IGCC 

Availability Assurance Program, modeled after similar programs the federal government has 

established in other areas, could address concerns about possible limited availability of IGCC 

facilities in their early stages of operation. It would provide funding to partially defray the cost of 

possible extended outages in the first few years after a plant is put into operation. 

3. Co-Production/National Security: An IGCC facility can produce both electricity and 

transportation fuels. The value of the plant can be optimized by turning out each product when its 

price is highest (producing electricity during the day when demand and prices are high, and producing 

transportation fuels when electricity demand and wholesale electric prices are low). The production 

of transportation fuels from such a facility would provide significant national security benefits. A 

study could be initiated to analyze the ability of IGCC power plants to operate on an economic 

dispatch basis to co-produce transportation fuels as well as electricity. 

4. Strategies for Meeting Environmental Standards: The deployment of IGCC technology is 

hindered by uncertainty regarding future regulations, the piecemeal approach of the electric industry 

and regulators to meeting future environmental standards, and the absence of efficient markets in 

which the forward value of emissions reductions can be monetized. As a result, the value of 

emissions reductions cannot be recognized as an offset to the capital costs of IGCC and 

determinations regarding the choice of technology for new or repowered plants cannot be made on a 

sound economic basis. Efforts could be made to develop comprehensive plans for meeting existing 

and anticipated emissions reduction requirements. Appropriate measures could be implemented to 

monetize the value of future emissions allowances (for NOx, SO2, PM and Hg) through creation of 

forward markets, including accounting standards that allow recognition of these assets by the 

Securities and Exchange Commission and state PUCs. In addition, a study could be undertaken to 

address institutional challenges to commercialization and deployment of CO2 sequestration 

technologies. 

5. Cost of IGCC Power Plants Relative to the Cost of NGCC Plants: The NARUC survey 

indicated that the most significant challenge to the deployment of IGCC plants is their higher capital 

costs relative to NGCC plants. However, the pricing of electricity from NGCC and IGCC power 

plants does not adequately reflect several critical considerations including the importance of using 

natural gas in industrial processes and residential heating, the recent run-up in natural gas prices 

resulting from increased pressure on supplies, the accelerated depletion of the nation’s limited 

reserves of natural gas, and the need for increased reliance on gas supplies from unstable areas of the 

world as domestic supplies are used up. New policies should be developed to address this situation. 

Measures could be developed to facilitate deployment of IGCC plants and reduce undue reliance on 

NGCC plants, thereby decreasing pressure on limited natural gas supplies and freeing up natural gas 

for essential uses such as industrial processes and residential heating. Transmission Service Providers 

(TSPs), Independent System Operators (ISOs) and Regional Transmission Organizations (“RTOs”) 

could be required to establish target portfolio standards for IGCC-produced power. TSPs, ISOs and 
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RTOs could be required to provide modest credits financed through uplift charges for electricity 

produced by IGCC power plants in their early stages of operation. A study using the National Energy 

Modeling System (NEMS) could be undertaken to assess the impact of expanded IGCC deployment 

on natural gas prices and availability. 

6. Potential Federal and State Actions: Meeting requirements for reduced emissions of sulfur 

oxides, nitrogen oxides and mercury by using IGCC to repower conventional coal-fueled generating 

plants could be less costly than meeting each of the requirements separately via a piecemeal 

approach. The EPA could initiate negotiations with coal plant owners to develop a comprehensive 

approach for meeting existing and anticipated emissions reduction requirements based on repowering 

with IGCC and consider mechanisms for monetizing future reductions of emissions that are likely to 

be regulated. This could result in long-term settlements and the repowering of plants with IGCC 

technology. 

A federal greenhouse gas (GHG) registry could be created to facilitate voluntary GHG emissions 

reductions, supplemented by compatible state, regional and global registries. The registries could 

facilitate bilateral trading and allow entities to bank reduction credits. This could provide an 

important means of financing IGCC projects, particularly for repowering. Regulators could develop 

tools to take GHG reductions in registries into account in the regulatory process, such as granting 

regulatory assets in exchange for GHG credits. 

A specialized team of experts could assist in the siting and permitting processes for IGCC plants and 

in bringing new technological advances into the process. This team could also intervene in siting and 

permitting proceedings to assure that the benefits of using IGCC are fully considered in technology 

determinations. 

The project finance community has virtually no experience with IGCC projects. A targeted effort to 

assist the financial community in understanding the issues associated with IGCC deployment could 

position it as a preferred technology. Such information could also be provided to state regulators and 

developers.

The Department of Energy could establish a university center for the training and qualification of 

personnel capable of participating in the design, construction and operation of IGCC power plants.

Such a program for training and qualifying personnel is needed to rapidly deploy this technology and 

realize its benefits. 

A business case for the benefits to the U.S. of exporting IGCC technology, equipment and 

construction services could be developed. The Export-Import Bank, the Department of Treasury or 

another entity could evaluate the economic implications of exporting IGCC technology, construction 

services and equipment. 

This list of NARUC recommendations is broad and could be prioritized to form a basis for future 

federal and state actions to increase the adoption of IGCC. 

Conclusion

While many financial incentives have been proposed and implemented, their impact on the deployment of 

new clean-coal technologies has been less than expected. However, financial incentives are required to 

overcome the risk-adjusted cost differential between conventional existing options and new, more 

efficient lower-emitting advanced coal-based plants so that these advanced plants can be more 
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expeditiously deployed into the market place. The menu available for such incentives includes, but is not 

limited to, tax incentives, production incentives, public/private cost sharing, accelerated depreciation, loan 

guarantees, and federal credit. Meaningful financial incentives enable the life-cycle cost of a new 

advanced coal-based power plant to be economically neutral to the investor, vis-à-vis alternative 

conventional technologies. In addition, it is important that state, regional and federal regulators play a 

significant role in working with utilities and investors to incentivize the construction of advanced and 

efficient coal-based power plants. 
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Section 4: Financial Overview of Investing in New Coal-Based Generation 

Corporate Financial Overview and Outlook for the Electricity Generation Sector 

The outlook for IOUs and for the competitive wholesale energy sector, including independent power 

producers, diversified energy merchants and energy traders, is stable. This overall outlook is somewhat 

deceptive, however, as these two segments are in two very different places and, medium- to longer-term, 

are headed in divergent directions. While the IOUs either maintained creditworthiness or are well on 

their way to recovery, the merchant or competitive energy sector will need much more time (and 

consistent favorable developments) to recover. 

Some noted analytical firms specializing in U.S. electricity and natural gas focused on the polarization 

between the stable outlook for those utilities which did not have significant merchant energy activities, 

including public power entities, and the negative outlook for those companies that were major participants 

in competitive power and gas markets, or whose affiliates/parents had large exposures. They predicted 

that the credit gulf between “untainted” regulated utilities versus their 

unregulated wholesale peers would widen in 2003. The ensuing year 

has borne out that prediction. At the same time, they anticipated fewer 

downgrades for 2003, a prediction which has also been validated with 

53 downgrades in 2003, less than half of the figure for 2002, and offset 

by 25 upgrades against seven in 2002. 

The rating outlook for 2004 remains stable for regulated distribution and transmission utilities and 

integrated (generation, distribution and transmission) utilities. Moreover, the 2004 rating outlook is also 

stable (or, more accurately, neutral) for wholesale energy market participants, albeit at considerably lower 

credit ratings. The median rating for the diversified energy sector remains single-B, implying a one-inthree chance of default over five years. Thus while the credit ratings may be stable at this level, they are 

stable at an elevated likelihood of default for these issuers. By way of contrast, public power systems 

(municipals and electric cooperatives) remain least affected by electric industry restructuring, with debt 

ratings holding in the A category. 

Looking out over the next five years, wholesale energy market participants face adverse political, 

regulatory and competitive factors that result in a potentially more negative medium-term outlook for that 

sector. Despite an adverse external environment, some individual companies in the wholesale sector will 

improve their financial condition, reduce outstanding debt and increase their capital market access. Others 

are likely to face a renewed liquidity crunch in 2007-2009 when the companies once again face a heavy 

schedule of debt maturities. 

Near-Term Outlook

The near-term rating outlook for the regulated electric utility sector is 

stable. In fact, in many regards, the industry risk profile is the lowest it 

has been since electric industry restructuring began in the mid-1990s. 

The stability results from a number of factors, including lower-risk 

business plans, a more settled state regulatory environment, on-going benefits from cost reduction 

measures, a low interest rate environment, and less pressure from external sources (including 

counterparties and affiliates). The stable outlook also assumes that capital and banking markets will 

remain reasonably open. 

The rallying cry of “back to basics” evident in many utilities’ revised strategies contributes to this stable 

outlook. Core investment, including a swing back toward utility self-build or acquisition of power 

The outlook for regulated 

utilities is stable in the 

short term.

Structural differences 

between IOUs and other 

energy companies must 

be recognized.
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production assets and additional investment in reliability and environmental controls, is generally 

supported within the near- and long-term stable outlooks. This trend is a reaction by utilities and state 

regulators not just to the high-profile disappointments of recent non-core diversification, but also against 

weak credit fundamentals of independent power producers and fears of revocation of physical power 

supply contracts by bankrupt generators. Other incentives for utilities to buy or build new power supply, 

rather than contracting with wholesale suppliers, are utilities’ lower cost of capital and a renewed 

willingness to invest in traditional utility property as a source of future earnings growth. The associated 

increase in capital expenditures is expected to be moderate in 2004 as managements formulate plans to 

address reliability and supply issues, and to increase during 2005 and thereafter as plans are implemented. 

While in past cycles increased capital investment resulted in deteriorating credit quality due to regulatory 

lag and prudence disallowances, leading analysts to anticipate less credit stress this time around. Prudent 

managements are not likely to proceed with a major increase in utility capital spending without implicit or 

explicit regulatory support. While full recovery of new investments is still not assured, regulatory support 

lessens the likelihood of severe disallowances. Many states already have mechanisms to accelerate the 

approval and recovery of new investments. In Indiana and Missouri for example, regulators have 

approved the transfer of generating capacity from an unregulated subsidiary to a regulated affiliate, while 

Nevada and Wisconsin have approved resource plans that include new coal-based and gas-fired 

generation facilities.

Regulators’ reluctance to have a repeat of the August 2003 blackout or the 2001 California energy 

debacle also bodes well for regulatory support of new infrastructure investments. State regulators are 

loathe to repeat the mistakes of California (unhedged supply obligation) and have shown a greater 

willingness to balance the political goal of rate stability with maintaining utility credit quality and a 

reliable energy supply. New Jersey, Connecticut and Maryland have implemented or are in the process of 

implementing an auction process to serve the provider of last resort obligations and eliminate commodity 

price exposure. While the auctions also heighten counterparty credit exposure, they increasingly contain 

credit terms and collateral requirements that provide some protection to utility purchasers from counter 

party defaults. State regulators’ virtual abandonment of restructuring initiatives also contributes to a more 

stable regulatory environment. 

Enhanced liquidity as a result of improved capital market access and lower utility bond spreads also 

support a stable outlook. Unlike other sectors within the global power universe, regulated utilities have 

an incentive to maintain a reasonable capital structure and generally have maintained market access even 

in the most turbulent times. 

The currently low interest rate environment also benefits the near-term outlook. Typically, low interest 

rates are favorable for this capital intensive industry. However, the currently low interest rate 

environment is a matter of some concern for companies involved in rate reviews, as correspondingly 

lower allowed returns on equity will likely result in reduced revenues, cash flow and earnings, all else 

being equal. 

On the qualitative side, concern about counterparty credit risk and affiliate pressure has been substantially 

reduced. Over the past two years, pressure on affiliates (usually those that have been involved in 

merchant plant development or non-core businesses) has accounted for the majority of rating downgrades 

in this sector. Going forward, the impact of rating linkage is likely to be more symmetrical given the 

lowering of utility parent ratings and affiliate merchant generators as well as the potential for utility 

procurement plans to prop up the ratings of affiliates. 

Commodity price exposure will continue to be an important determinant of business risk and 

consequently credit quality. The risk is largely eliminated for pure electric distribution companies with 
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no supply obligation and substantially reduced for those companies with automatic fuel pass through 

mechanisms, although regulatory lag can still pressure liquidity. Owning sufficient generation to meet 

customer load also lessens commodity exposure, but without a fuel and/or purchased power pass-through 

mechanism, a utility is vulnerable in the case of plant outages, which can be particularly onerous for 

nuclear plant operators as recently demonstrated by the impact of Davis-Besse nuclear outage on the cash 

flow and ratings of FirstEnergy Corp. Examples of utilities with fixed tariffs and no opportunity to 

recover variable supply costs are all electric utilities in Missouri (including Ameren and Aquila) and 

Michigan electric utilities Consumers Energy and Detroit Edison (subject to fixed rates phasing out by 

Jan. 1, 2006). Commodity risk is greatest for distribution companies with fixed rates and an unhedged 

supply obligation, as was the case for California electric utilities in 2000-01, with disastrous results. 

Five Years Out

Stricter environmental compliance requirements and the elimination of 

the Public Utility Holding Company Act (PUHCA) are two significant 

issues that could affect regulated utilities in the longer term. In the case 

of the environmental issues, the impact will depend on the regulatory 

treatment of the potentially higher costs, which could include 

replacement of inefficient, older generating units. Potential losers are 

large coal-based utilities, while beneficiaries would be merchant and 

other competitive generators that rely on environmentally clean fuels 

such as nuclear power. In addition, to the extent surplus capacity is reduced, all merchant generators 

benefit.

If PUHCA is eventually repealed, mergers and acquisitions and event risk would increase. The 

elimination of PUHCA restrictions would likely attract non-traditional buyers to the utility sector. Even 

without PUHCA repeal (which does not restrict single-state utility acquisitions), there have been signs of 

increased merger and acquisition activity as 2003 draws to a close. After the attraction of the gas sector 

last year for AIG MezzVest and Macquarie Infrastructure Group, this year Texas Pacific Group, a private 

equity management firm, has formed a new, Oregon-based company to attempt to purchase Portland 

General Electric Company from Enron and Kohlberg Kravis Roberts and JP Morgan Partners have 

combined to acquire Tucson Electric Power and its parent company Unisource. Given the infinite 

permutations of possible financing plans, it is impossible to predict the implications for existing creditors. 

The Unisource acquisition appears, on first inspection, to adopt a transaction structure which avoids 

deterioration of the utility’s creditworthiness; but, generally, leveraged acquisitions result in credit 

downgrades. Potential buyers are likely to include highly rated energy firms and private equity investors 

and leveraged acquisition funds. 

Other inflection points in the longer-term are largely related to events at parent and affiliate companies. 

On the negative side would be a return to the pursuit of growth on the part of utility parent companies that 

could ultimately impair the ratings of regulated utilities as was the case in the 1999-2001 timeframe. On 

the positive side, improvement in the supply/demand environment could favorably impact affiliate 

generating companies and positively impact those companies whose ratings are currently constrained. 

Natural Gas Prices

Forecasters are predicting that relatively high gas prices (in the ranges of $4-

6 per mcf) will maintain production at around 50 billion cubic feet (bcf) per 

day level over the five-year time frame, a decline from estimated 2003 

production of 52 bcf per day. Incremental LNG capacity at the four existing 

U.S. receiving and re-gasification facilities is expected to make up for the 

Environmental 

regulations and PUCHA 

regulation are significant 

issues that could affect 

regulated utilities in the 

longer term.

Forecasters predict 

that natural gas 

prices will remain 

high and volatile.
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small decline. Analysts assume that Canadian imports will remain essentially flat. Consumption by 

power plants will increase while high prices will result in the reduced usage of natural gas as a feedstock 

for industrial processes (so-called demand destruction). U.S. demand then should average approximately 

61-63 bcf daily, depending on the level of industrial demand destruction. 

Against this back-drop, experts foresee a continuation of high volatility and relatively high price levels for 

natural gas over the five-year outlook. Volatility will result from periodic supply-demand imbalances and 

constraints on deliverability until 2008 when the first of the green field LNG projects start up. During 

this period, with industrial demand destruction keeping a lid on prices, gas prices will often be nominal 

$4-6 per mcf. 

Conclusion

New coal-based plants require a large amount of capital – in excess of $500 million for a typical plant. 

An investor can only build such a facility if it is able to raise the necessary capital to finance the project. 

This depends on the willingness of the financial community to lend money to the investor. Experts in the 

financial community believe that the outlook for IOUs – as well as wholesale generation companies, 

diversified energy merchants and energy traders – is generally stable. Therefore, if a project is 

economically viable, it is expected a power plant developer should be able to borrow the funds to build 

the plant. However, there are fundamental structural differences between the IOUs and the merchant and 

independent power producers, and those differences must be recognized in considering the financial 

issues that impact the decision whether or not to construct new coal-based facilities.
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Section 5: Environmental, Permitting and Regulatory Issues 

Permitting Issues

Obtaining an air permit for a new coal-based power plant is a critical step that must be completed before 

construction can begin. For plants located at greenfield sites (where there are no existing emissions that 

can be reduced to offset the new emissions), the new unit will be required to obtain a new source review 

(NSR) air permit. This is an important process because it provides all 

stakeholders, including the project team, EPA, state environmental 

regulators and the public an opportunity for input to the process to 

insure that the plant design incorporates state-of-the-art emission 

control equipment to minimize impact on the local, regional and 

national environment. However, the process is complicated and has 

built-in inefficiencies that can tax the resources of all of the 

stakeholders involved and can result in significant delays. 

For the criteria pollutants such as SO2 and NOx, depending upon whether the plant will be located in an 

attainment or non-attainment area, the project team must go through an analysis to define the Best 

Available Control Technology (BACT) or Lowest Achievable Emission Rate (LAER) on a case-by-case 

basis to minimize these emissions. Even though there are national standards for these emissions, this 

analysis determines whether there have been any significant advances in the control technology that need 

to be included in the equipment for the new power plant. Once this is completed, it is submitted to the 

responsible permitting agency (usually the State’s environmental regulatory authority) for review. 

Since criteria pollutants have been regulated for several years, the BACT analysis can be supported by the 

performance of emissions control equipment at existing plants. One of the resources available to the 

project team and the state is a BACT Clearinghouse that is maintained by EPA. The BACT 

Clearinghouse provides information regarding permitted emission limits at similar sources. The 

availability of these data is very important because it means that the equipment is commercially available 

and has been permitted for use on similar sources. In some cases, the emission limits will be lower than 

those currently being achieved. 

For emissions of hazardous air pollutants (HAPs) that are not subject to current federal new source review 

standards, a different analysis is performed to determine the Maximum Achievable Control Technology 

(MACT) for each potentially toxic material on a case-by-case basis. Although this case-by-case MACT 

analysis is similar to the BACT analysis, it is much more subjective and complicated because it addresses 

control of emissions that may never have been specifically controlled before. MACT analyses recently 

performed on new coal-based power plants have resulted in very aggressive limits on emissions such as 

acid gas emissions, mercury and other trace metals. 

Because there are limited operating data on which to base the case-by-case MACT analysis, the process is 

much more controversial because of the uncertainties involved. For example, the permit for the new 

MidAmerican Energy Council Bluffs Powder River Basin (PRB) coal-based plant required the BACT 

analysis to address criteria pollutants, including SO2 and particulates (PM10), and a review of the MACT 

equipment for controlling mercury emissions. The Iowa Department of Natural Resources concluded that 

the BACT equipment for PM10 and SO2 emissions was a spray dryer absorber (SDA) followed by a fabric 

filter (FF) and that MACT for mercury was activated carbon injection (ACI) equipment capable of 

feeding AC at 10 lbs/Macf. The emissions limits for the BACT analysis were based upon long-term 

performance data on SDA/FF systems on existing plants burning PRB coal. However, determining the 

MACT limit on mercury involved speculating on mercury removal based on performance measured 

Permitting a new plant is 

complicated and has 

built-in inefficiencies that 

increase costs and cause 

delays in constructing a 

new plant.
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during two one-week-long test programs; one involving a plant with similar equipment but a different 

coal type (ACI with a SDA/FF on lignite), and another involving a plant with different equipment but a 

similar coal (ACI with an ESP on PRB). The resultant air quality permit stipulates that the MACT 

equipment will obtain 83% mercury even though there has never been a test of this specific equipment 

and coal and neither of the two referenced (but different) configurations obtained mercury removal levels 

this high. 

The state then reviews the BACT and MACT analyses and negotiates with the power plant developer on 

equipment and emission limits. It should be noted that for a new power plant, these reviews are a massive 

undertaking by the state that taxes financial and personnel resources. Since there have been so few new 

coal-based power plants built since the early 1980s, state regulators have little or no experience with such 

projects. As a result, this requires a lengthy review period. 

Once the state makes their determination on equipment and limits for each pollutant, a draft permit is 

published for public review, which includes EPA and possibly Federal Land Managers (FLMs). This 

represents a very involved process because every detail is open for public comment including emission 

limits, types of control equipment, procedures for demonstrating the technology, averaging times, and test 

methods for making the measurements to demonstrate compliance. The measurement techniques 

represent a significant area for controversy – especially for newer emissions in which often there is not a 

universally accepted reference method. For example, the most common approach for measuring 

condensables is EPA Method 202, which has very well-documented problems in which related 

compounds are formed in the liquid sample collectors and are reported as emissions. 

The permit timeline can be further extended, by those opposed to the new power project beyond the 

public review period through administrative protests of the final decision by the state. Once the 

administrative processes are exhausted, opposition can create further delays by filing lawsuits and 

injunctions in the judicial system, which creates timelines outside the control of the state environmental 

regulators and the project team. 

Because of the subjectivity of the BACT and MACT analyses, it is possible that EPA or environmental 

regulators in neighboring states will disagree with the permitting authority’s conclusions. This creates the 

possibility for additional delays. In fact, neighboring states can further delay the project by filing for 

judicial relief related to the transport of emissions across state lines. In addition to EPA and neighboring 

states, delays can be created by other government entities such as the FLMs.. The FLMs may become 

involved in the permit review process if there are potential visibility issues in National Parks or other 

Class I areas. The FLMs Quality Related Values Workgroup Guidelines (FLAG) were established in late 

2000 to help determine the impacts of proposed projects on visibility in Class I areas. The FLAG method 

is being implemented in a way that threatens state authority to issue permits as FLMs exert their authority 

to protect visibility in Class I areas. As FLAG is currently being applied, it is greatly impeding the 

orderly permitting process of power plants throughout the nation. 

Once the air quality permit is obtained, the final hurdle can occur when the project team has to negotiate 

with vendors of the emission control equipment that will be purchased to meet the required emissions 

limits. This is especially true for the MACT emissions, because in many cases the vendors will be asked 

to guarantee performance of equipment for emissions that have never been controlled before or to 

maintain low emission levels that have not yet been achieved. This is further complicated by the 

controversies around the measurement techniques that will be used to define the guarantees and 

demonstrate compliance. 
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Recommendations to Eliminate Hurdles

To determine how the inefficiencies of the air permitting process can be improved, it is first necessary to 

appreciate how emissions control technology is developed for the power industry. Since the first Clean 

Air Act of 1970, the power industry has gone through several rounds of implementing emission control 

technologies for PM, SO2, and NOx. In each case, there were very similar experiences as the new 

technology was applied to this complex industry, including: 

x Unexpected reactions between flue gas constituents and the chemical reagents added to control 

the pollutants; 

x Differences in coal characteristics and plant operating conditions causing wide variation in 

performance; 

x Significant O&M problems that did not show up until after long-term operation; and 

x Secondary effects on other components of the power plants – examples include higher carbon in 

the ash from low-NOx burners, ammonia in the ash from SNCR and SCR, and changes in 

characteristics of the concrete produced when new chemicals are collected with the fly ash. 

In all of these cases, the problems that resulted from the new technology had a significant impact on the 

reliability of power generation. The plants were forced to operate at 

reduced loads and suffered many unplanned shutdowns for maintenance 

and repair. Over time solutions to these operating problems were 

developed and the technologies now operate more reliably and 

successfully. The severity of the impact of the initial problems, both in 

costs to the power consumer and in the reduction of available capacity, 

depended upon how widespread the technology was applied during the 

early adopter phase. For example, hot-side ESPs have cost the industry 

over $1 billion - after early success, the technology was quickly applied to 150 power plants before a fatal 

flaw was discovered.

One of the difficulties with implementing new emission control technology is that the equipment is so 

massive. For example, emission control equipment for a 500 MW plant must treat two million cubic feet 

of flue gas every minute. To minimize the potential detrimental impact of new emissions control 

technology on the capacity of electrical power suppliers, history has taught us that it is necessary to go 

through the following phases: 

x Laboratory testing: provides a cost-effective means to determine general feasibility and test a 

variety of parameters. 

x Pilot-scale: test under actual flue gas conditions, but at reduced scale. 

x Full-scale field tests: scale up the size of the equipment and perform tests under optimum 

operating conditions to define the capabilities and limits of the technology. 

x Full-scale field tests at multiple sites: each new site represents new operating conditions and 

new challenges.

x Long-term demonstrations at several sites: Some problems don’t show up until the first year 

or so of operation. 

x Widespread implementation: Problems will still be found at new sites, but most of the fatal 

flaws will have already been discovered and resolved. 

If an attempt is made to accelerate technology development by skipping these steps, there will be 

significant risk that operating problems could arise that will lead to untimely shutdowns of the plants 

using the technology. As a result, the process of implementing new technology in the power industry is a 

Hurdles and delays in 

permitting must be 

identified and addressed 

to facilitate the 

construction of new coalbased plants.
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10-15 year process and represents significant risk to the developer and the user at each stage. Incremental 

equipment modifications and improvements in operations can be accommodated much faster, but they 

still require three to five years for widespread implementation. 

Therefore, a significant improvement in the air permitting process can be 

made if the stakeholders acknowledge the realities that changes in 

emissions control equipment can only occur at a minimum on a 3-5 year 

timeframe. Currently, the same battles over BACT and MACT 

equipment and limits are fought for each new power plant project. This 

taxes the resources of all involved, including the project teams, the state 

environmental regulators and the environmental activists that may 

scrutinize the project. If there are 30 new power plant projects being 

reviewed, there will be 30 different debates over the permit requirements. Because different 

organizations and individuals perform the analyses, there is a significant amount of subjectivity in the 

results.

An improved process would provide a mechanism to perform the BACT and MACT analyses on a 

national level every two to three years. This process would involve all of the stakeholders, including the 

power industry, state and federal environmental administrators, citizen and environmental groups, 

emissions control experts and equipment vendors. All of these organizations could concentrate their 

resources to address the issues at a national level rather than dilute their efforts to deal with the same 

issues on a project-by-project basis. This would also eliminate subjectivity in the process. The result of 

this process would be a consensus agreement on BACT and MACT equipment and levels – possibly 

subcategorized according to boiler design and coal type – that would remain in effect for a prescribed 

time period and would apply to all new coal-fueled power plants being permitted. 

Another recommendation to accelerate the permitting is to use the BACT and MACT processes to define 

the emissions equipment for the construction permit, but delay setting the emissions limits until the 

equipment is installed, operating and optimized as part of the Title V process to define conditions for the 

operating permit. For a given type of emission, the BACT or MACT equipment can be defined, including 

its key engineering design parameters, based upon experience gained from existing equipment. The 

difficulty and uncertainties come when trying to predict the explicit performance of the equipment that 

can be obtained on a new boiler/coal combination. There are advantages to this approach, several of 

which are discussed below. 

It avoids lengthy debate on issues that have large uncertainties and minimal data to support decisions. 

Emissions control equipment can be specified and purchased with warranties without requiring guarantees 

that may be impossible to meet. 

It also provides potential environmental benefits by allowing the possibility that the emission 

limitations set during the Title V process could actually be lower than expected based upon unexpected 

favorable operating conditions or improvements in technology. As an example, the equipment defined for 

mercury control in the referenced case study for the Council Bluffs plant was an ACI system capable of 

feeding 10 lbs AC/Macf upstream of the SDA/FF. From the data available at the time of the permit, this 

offers the best opportunity by far for maximum mercury control. The same decision would be true today 

(a year later). However, what is unknown at this time is the reduction in mercury emissions that will 

occur with the coals to be burned in the future. If the construction permit only contained a definition of 

the equipment, the project could begin and the procurement of emissions control equipment would take 

place requiring only operating warranties for the equipment. Once the equipment was installed and 

operating, optimizing operation would define the emissions limits. This process could take advantage of 

any improvements in the mercury control sorbents that might have occurred during the three-to-five-year 

Changing BACT, 

MACT, and other 

emission standards 

creates uncertainty in 

the development of a 

new plant. 
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51

construction period. As a result, the final mercury emission reduction required in the permit could be 

greater than the 83% removal predicted years earlier by the permit review team. On the other hand, if the 

83% removal is not achievable, the performance of this equipment would still be by definition the 

“maximum achievable” at the specific site. 

The purpose of moving the emission limits from the construction permit to 

the operating permit is to provide flexibility in dealing with 

uncertainties associated with controlling new emissions on new power 

plants.

It should be noted that inflexible environmental regulations can impact the 

ability to obtain financing for the project. If guarantees are not obtainable 

for all emission standards, it is unlikely that capital investment could be justified. The owner/operator of 

a power plant must also confront the uncertainty of future environmental regulations which could lead to 

excessive capital costs, unforeseen O&M cost impacts, or even render the power plant uneconomical to 

operate before a reasonable rate of return could be earned for the investment. The life of a new coalbased power plant is expected to be at least 50 years, and the investment cost is expected to be on the 

order of $1 billion. Providing the investor with some assurance of the regulatory certainty concerning 

what the limits will be for the emissions from that plant – both at start-up and for a reasonable term – 

would remove an impediment to making such an investment. For example, if the ash disposed from a 

500 MW plant were to be re-classified from solid waste to a hazardous waste, the cost impact on the plant 

operation would be in the range of $3-$5 million annually. If an investor expects that regulations will be 

promulgated in the near future which would mandate removing CO2 from the exhaust of the plant, the 

investor is not likely to invest in a coal-based plant, since current technology for removing CO2 from the 

exhaust of a conventional coal-based plant is uneconomical.

Other recommendations for accelerating the process include: 

x As allowed by some states, provide an option to pay a premium on permit fees for an accelerated 

review. The state could use the increased fees to support additional resources that will be needed 

to handle a large project such as a new power plant. 

x Increase certainty with emissions regulations, such as more comprehensive and more up-to-date 

new source performance standards (NSPS). 

x More quickly establish reference measurement methods for new emissions. 

x Limit the number of opportunities to appeal (administrative and legal) or reduce the timeframe 

associated with these processes. 

x Keep the BACT Clearinghouse more current and complete. 

x Provide assurances that additional emissions reduction technology would not need to be 

retrofitted into a new plant for a certain number of years (provided that the plant is built in 

compliance with current regulations), even if the regulations mandate emission reductions from 

newer plants. 

x Withdraw the FLM’s FLAG guidelines and subject them to appropriate notice and comment 

rulemaking. This process should include an evaluation of whether or not any guidelines are 

needed for Class I areas considering already very stringent BACT/MACT emission standards and 

Class II air modeling requirements included in the Clean Air Act. 

In addition to the recommended procedural changes to accelerate the permitting and construction 

processes, there are a number a things that project teams can do to shrink the timeline. These suggestions 

relate to anticipating all possible interest groups who will have a stake in the project, and getting their 

input early in the process. The project team should get input from FLMs, neighboring states and vendors 

Uncertainty about 

environmental 

regulations can impact 

the ability to finance a 

new plant. 
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52

of emission control equipment to define current capabilities of the equipment, achievable emission limits 

and possible guarantees. 

It should be noted that recommendations requiring changes in the BACT and MACT processes could 

require modifications to the Clean Air Act for implementation. 

Mercury Regulatory Uncertainty

The federal government’s approach to regulating mercury emissions from coal-based power plants is a 

pertinent and topical example of the difficulty in anticipating environmental regulations by those who 

would invest in new generation capacity. In the Clean Air Act Amendments of 1990, EPA was charged 

with preparing a Report to Congress (RTC) within three years on the appropriateness and necessity of 

regulating emissions of hazardous air pollutants (HAPs), including mercury, from electricity generating 

units. At the time, very little was known about HAP emissions from power plants, and the methodologies 

for measuring them accurately were largely non-existent. Specifically, methods for measuring mercury at 

the exceptionally low concentrations found in coal and for making speciated mercury measurements in 

flue gas were just being developed. Therefore, much of the early effort was concentrated on making 

emission measurements from a few sources while refining the measurement methods. When the RTC 

was completed (in 1998, five years later than called for in the Act), EPA found no indication of increased 

health risk from any of the listed HAPs other than mercury, which it concluded needed more study. 

In December 2000, EPA finally made a regulatory determination that 

there was sufficient evidence to require reduction of mercury 

emissions from coal-based power plants. EPA based its conclusion, 

in part, on mercury emission data collected in 1999 under a program 

known as the Mercury Information Collection Request (ICR). Under 

a court-approved consent decree, EPA proposed a draft rule in 

December 2003. The proposed rule exemplifies the difficulty in 

anticipating and planning for the consequences of a regulatory 

determination; rather than propose a single rule, EPA proposed three separate options. One would set 

MACT floor limits (for existing sources) and NSPS limits (for new plants) to be met on a unit-by-unit 

basis. The other two rule options would implement cap-and-trade programs, but with different caps, 

allowance allocations and implementation schedules. EPA would implement one of the proposed capand-trade programs nationally, with allowance allocation procedures similar to those of the Title IV SO2

program. The other would be implemented by the individual states, under the equivalent of a State 

Implementation Plan (SIP) program. It would allow the states to “opt out” of trans-boundary trading, and 

would leave it to each state to allocate an allowance budget to individual sources. The final compliance 

dates for these options vary from as early as 2007 to as late as 2018. Questions have been raised about 

the legality of EPA’s authority to regulate under the cap-and-trade provisions, raising the likelihood of 

protracted litigation regardless of the final rule that EPA proposes. EPA is required to issue a final rule 

by March 2005. 

The emission limits (MACT, NSPS or caps) proposed in the rule introduce further uncertainty. They are 

based on little data of questionable quality. EPA based the proposed rules on mercury emission sampling 

done on 80 coal-based electricity generating units in the1999 ICR program. These samplings consisted of 

three measurements of speciated mercury emissions done using the draft “Ontario Hydro” flue-gas 

sampling method. None of the plants used mercury-specific control technology, so the mercury 

reductions achieved were the “co-benefit” of technology employed for SO2, NOx and PM. 

Research is being done on mercury-specific control technology, mostly with Department of Energy 

funding, but the technologies have yet to undergo long-term commercial demonstration in an adequate 

New proposed mercury 

reduction requirements 

add a new level of 

uncertainty in the 

construction of new coalbased power plants.
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variety of circumstances. The Department of Energy goals are to have mercury control technology 

capable of 50-70% reduction available by 2007, and to have technology capable of 90% reduction ready 

for “commercial demonstration” starting in 2010. Meeting these goals will depend on the success of the 

research, and on the continued availability of funding to conduct sufficient long-term demonstration tests. 

To illustrate the risk to a potential investor in new generating plants, consider the new source performance 

standard (mercury emission of 0.6 lb/TBtu) that EPA proposed for bituminous coal-based power plants. 

The average mercury content of bituminous coals mined in the U. S. is 8.6 lb/TBtu (as sampled in EPA’s 

1999 ICR program). Therefore, to comply with the NSPS, a plant burning the average bituminous coal 

would need to achieve 93% mercury reduction. As shown below, 55% of the coals would require a 90-

95% reduction, and 14% would require greater than 95% reduction. Given the uncertainty in achieving 

even a 90% reduction by 2010, the imposition of a standard requiring more than 90% reduction on 70% 

of U. S. bituminous coals clearly would inhibit – if not eliminate – investment in new coal-based plants 

using combustion-based technologies. The proposed NSPS limits for subbituminous and lignite coals 

would have similar results. 

Figure 5.1

Compliance with Mercury NSPS with Bituminous Coals 

Given the uncertainty about the form of the final regulation, the level of mercury control it will require, 

and the unavailability of proven commercial technology at a performance level necessary to meet the rule, 

there is an understandable reluctance among the investment community to finance new coal ventures. 

This is amply illustrated in a letter of March 30, 2004, from Lehman Brothers to Peabody Energy, Inc. 

concerning potential financing for Peabody’s Thoroughbred and Prairie State power plant projects. The 

letter was provided by Peabody as an attachment to their public comments on the mercury rule, EPA 

Docket OAR-2002-0056. In it, Lehman says that “the proposed Environmental Protection Agency (EPA) 

regulations for mercury removal create some significant uncertainty for both electric generators and the 

Compliance with Mercury NSPS: 

Bituminous Coals

0%

10%

20%

30%

40%

50%

60%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Required Hg Removal to Comply, %

Percent of ICR Part II Samples 
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financial community. . . . emissions control vendors will need to provide substantive guarantees that 

insure the required mercury emission levels can be met over the life of the plant. . . . We are unaware of 

any actual long term demonstrations at those high levels or vendors willing to provide unqualified and 

financeable guarantees for mercury removal that meet the proposed EPA standards. . . . Without 

demonstrated experience and substantive vendor guarantees for mercury emission limits, financing for 

new coal power plants will be problematic at best and perhaps not possible at all.” 

Regulatory Issues, Planning for a Robust Electricity System

In most states, electricity is still a regulated commodity. Even in “deregulated” states, there is significant 

regulation in the transmission and distribution of electricity. Therefore, the PUCs continue to play a 

significant role in establishing the criteria that determine whether a new power plant will be built and 

what technology would be used for a new plant, hence the fuel choice. The case study about We Energies 

in the subsequent chapter demonstrates that, while the PUC did not select the actual fuel type or 

technology, it had the final say on the technology and fuel choice based on a certain set of criteria. 

As noted in the discussion about the 3-Party arrangement, it is important to involve the state regulators in 

the planning process for a new power plant. The large capital investment in a new coal-based power plant 

impacts the rates that customers pay for electricity. State regulators would likely take the position that 

imposing the recovery of a new advanced (but more expensive) coal-based plant in one utility’s service 

territory may place an undue burden on those ratepayers. Therefore, absent incentives to bring the 

equivalent cost of the new advanced plant down to the level of lower-cost alternatives, it will be difficult 

to obtain approval to build a new coal-based plant in a single utility service territory. Further, where 

wholesale competition exists for electricity, the addition of new generation by Independent Power 

Producers is done based on specific wholesale market signals. These two situations have led to shortterm incremental addition of power plants without consideration to the long-term strategic needs of the 

nation.

When long-term strategic considerations are incorporated into the process, planning, system reliability, 

siting and fuel choice are interlinked and cannot be viewed in isolation. Planning for a robust electricity 

system ideally would be in the form of a nationwide integrated resource process (IRP) – taking into 

consideration load growth, supply options including generation, conservation and 

transmission/distribution network needs. A properly crafted planning effort would be able to transcend 

the electric regulatory structure on a state-by-state basis (i.e., regulated vs. deregulated) while ensuring 

that reliable electricity is available to the users of the networks. Economic considerations for the 

maintenance and expansion of the system are separate but linked issues. 

Planning has historically been done on a company-by-company 

basis, and, at most, a statewide look. While a nationwide planning 

effort, or at least on an interconnection basis, is ideal, a more 

realistic planning view and effort should concentrate on sub-regions 

of the North American continent. There are many ways to define 

these regions. One method currently being pursued would use a 

regional transmission organization (RTO) footprint to identify regions. Decisions by federal government 

agencies have considerably slowed the progress in RTO development and put in question the current 

viability of this approach for planning. In addition, the planning processes endorsed by the individual 

RTOs, as well as coordination between RTOs, is not convincingly optimal. 

It is also problematic that required planning horizons are not workable. FERC, in their Standard Market 

Design Order, did encourage regional choice and diversity as an option. However, planning horizons that 

Lack of coordinated 

regional planning is an 

impediment to the 

construction of new coalbased power plants.
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have been prevailing have been short and unreasonable for needed baseload plants in some parts of the 

country. The generation construction that has occurred to date is generally gas-fired peaking facilities. 

The planning horizon and timeframe for construction of such facilities is relatively short. If that horizon 

is found to be reasonable, the country will not be able to meet the necessary baseload growth with the 

appropriate generation mix. 

Reserve margins (which is based on the difference between the 

“peak” load at any given time and the installed capacity of a utility) 

have typically been the determinant of when new capacity is 

required in a utility service territory. As discussed at the end of 

Section 2, the type of generation required to meet a reserve margin 

typically operates at a very low capacity factor, and therefore is 

conducive to low capital-cost technology such as combustion 

turbines. However, changes in usage patterns are reducing the 

difference between average loads and peak loads. Much of the increase in electricity usage we have 

experienced in the country is due to information systems requirements and computers. This type of load is 

typically around-the-clock, thereby increasing overall consumption, but not necessarily affecting the peak 

significantly. In addition, energy efficiencies that have been gained in all aspects, industrial applications 

as well as residential and commercial uses, have resulted in a relative decrease in the peak usage 

compared to overall growth. Recognition of this paradigm shift by the regulators is expected to provide a 

more favorable view of coal-based, baseload plants rather than peaking plants such as combustion 

turbines.

Another concept is to tie load, load growth and fuel source to a geographical region. Coal basins, for 

instance, could serve as the defining area for a regional IRP effort. This would allow for tailored 

technology considerations as well as for the accompanying economic analysis for resource deployment. 

This would provide a measure for what an appropriate planning horizon might be in any given region. It 

puts some dimension on fuel mix and diversity, which can then lead to a desired planning time horizon. 

Other Infrastructure Issues

As was discussed in this report, uncertainty is an impediment to 

investment of capital. There are additional issues concerning the 

infrastructure that lead to uncertainty that warrant consideration. The 

construction of new power plants requires the availability of skilled 

construction labor to build a facility and skilled operators to safely 

operate the facility. Because not many new coal-based plants have 

been built, there has not been a strong attraction of skilled boilermakers. Many older and experienced 

workers have retired from this business and replacements are difficult to find or retain. A nearly twodecade absence of need for construction labor to erect large central generating stations has left a lack of 

experienced riggers, welders and fitters required for the construction of new power plants. Further, many 

of the experienced engineers have retired, and many well-known architect/engineer firms with long 

histories of managing complex, fixed-price turnkey projects no longer exist. 

For more than a decade, the number of high school students matriculating to engineering curricula has 

dropped. The pattern of bachelor's degrees awarded during this period has shifted significantly. 

Engineering and engineering technologies declined 4% between 1990 and 1995, with a further 7% decline 

between 1995 and 2000. Some engineering schools, in an attempt to remain viable, have "engineered" 

their curricula to deal with a less prepared student body or one marginally interested in technology, and 

then only in relation to a perceived need to evaluate technology on economic grounds, not to participate in 

creating it. Therefore, uncertainty concerning the availability of skilled labor to design, construct and 

Planning for new coalbased power plants on a 

regional basis such as 

geographical areas or 

coal basins can lead to a 

superior planning 

process.

Building new coal-based 

power plants will require 

a skilled workforce of 

engineers, construction 

labor and operators. 
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operate new coal-based power plants must be considered to ensure that new coal-based power plants can 

be built and operated properly.

Other factors also create uncertainty to an investor in new coal-based power plants. FERC and states 

have failed to adequately deal with transmission congestion that must be addressed in siting a new plant. 

Availability of affordable coal is critical to the long-term operation of a power plant, yet there are 

growing regulatory hurdles to the development of new mines that will be required to fuel new plants. 

Finally, domestic manufacturing capability has declined, requiring that many components used in a new 

coal plant must be fabricated overseas, which can place added risk of delivery and stable prices. 

Conclusion

Environmental and regulatory issues transcend the financial issues discussed in the previous sections of 

this report. If an investor believes that a plant cannot be permitted, the plant will not proceed even if there 

are other financial incentives. Further, uncertainty of the permitting process may result in the selection of 

a gas-fired plant over a coal-based plant, all other considerations being equal or close. The length of 

permitting time, as well as redundant permitting requirements, has created impediments to new 

construction. Even with new coal-based generation meeting, and in some cases exceeding, the most 

stringent emission control requirements and efficiency standards, time from project initiation to start up is 

routinely extended due to delays in the permitting process that do not result in any changes to the plant’s 

emission control systems. This causes uncertainty in the investment community, with higher perceived 

risks in developing new coal-based plants. 

Over the past three decades, the prevailing regulatory approaches have led to the retrofit of high capital 

cost emissions control technologies at existing coal-based generating plants. In order to avoid the risk of 

stranded investments and the uncertainty of investing in new plants, power plant operators have taken 

steps to extend the life of existing plants. This has also made it more difficult for new plants to enter the 

electricity market at a price competitive with older, less expensive coal-based plants. 

The uncertainty of future environmental regulations has complicated the decision as to whether or not to 

repower or replace existing coal-based generation. This situation is exacerbated by the uncertainty 

surrounding the issue of carbon management. Past incentives have facilitated research, development and 

demonstration of advanced, clean and efficient coal-based technologies leading to significant 

advancements in both environmental performance and generation efficiency. However, these 

technologies require additional support for deployment to achieve significant market penetration.
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Section 6: Case Studies 

The preceding sections of this report provide discussions and analyses of issues which impact the 

construction of new coal-based power plants. This section provides case studies to highlight those issues 

as they relate to actual experiences with permitting, construction and operation of new coal-based electric 

generation facilities. 

CASE STUDY #1 

Elm Road Generating Station 

Milwaukee County, Wisconsin

We Energies 

Overview and Current Status of Project

We Energies’1 proposed Elm Road Generating Station (ERGS) 

consists of two 615 MW SC PC generating units located adjacent to 

the Oak Creek Power Plant in Milwaukee County, Wisconsin. In 

November 2003, the Public Service Commission of Wisconsin 

(PSCW) issued a Certificate of Public Convenience and Necessity 

(CPCN) allowing construction of ERGS Units 1 and 2 to be inservice in May 2009 and May 2010, respectively. The PSCW denied the CPCN for a 600 MW coalbased IGCC unit proposed for 2011. 

As of March 30, 2004, ERGS has received an air permit but still needs several water, wetlands and other 

site-related permits. Numerous lawsuits involving the PSCW and the Wisconsin Department of Natural 

Resources (WDNR) brought by parties opposing the project are pending. Construction is expected to 

start in the second half of 2004. 

Project Chronology

Wisconsin is an electrical island with only four frequently constrained high-voltage transmission 

connections to Minnesota and Illinois. Unlike the region in general, Wisconsin does not have a surplus of 

generation of any type. No baseload power plants have been built in the state since the mid-1980s. Load 

growth has been met exclusively with new gas-based units. Retail access has not been pursued in 

Wisconsin although the state’s utilities have divested their transmission assets and joined the independent 

American Transmission Company. 

ERGS was proposed in 2000 as part of a broader Power the Future initiative that committed Wisconsin 

Energy Corporation (the parent company of We Energies) to invest $7 billion in “a comprehensive 

approach to address electricity supply and reliability issues for We Energies' customers in a way that 

considers both the economy and the environment,” according to www.powerthefuture.com. The web site 

explains that “Power the Future expands power production to meet growing demand, improves existing 

power plants for increased efficiency and reduced emissions, and upgrades power delivery to help keep 

the lights on.” 

1

 Wisconsin Energy Corporation is the parent holding company of two utilities: Wisconsin 

Electric Power Company and Wisconsin Gas Company which jointly do business under the brand name 

We Energies. 

We Energies received 

regulatory approval to 

construct two 615-MW 

PC plants, but was denied 

approval for a 600-MW 

IGCC Plant.
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A large coalition supporting all or parts of the Power the Future project took shape in 2000 and 2001, 

eventually encompassing industrial energy customers, residential customers, some environmental groups, 

labor unions, other Wisconsin utilities, Wisconsin municipal utilities and cooperatives, and some 

renewable energy advocacy groups. This broad coalition remained roughly intact throughout the PSCW 

CPCN process and remains a valuable supporter of the project as it moves forward. 

Several potential obstacles were avoided early in the project because We Energies was willing to 

compromise on the structure, timing and size of the project as it worked to form a broad-based coalition 

supporting the project. The core components of the plan remained unchanged: invest in new gas and coal 

generation to meet future needs. The company approached the addition of new generating capacity as 

part of an overall transition towards expanding and improving its generation portfolio, including retiring 

older generation and investing in emission upgrades to intermediate-aged coal units. 

The initial Power the Future proposal, which was not well received by customer groups, was structured as 

an IPP-type power purchase agreement that would fall under the jurisdiction of the FERC. In subsequent 

negotiations, a broad coalition supported a non-utility affiliate (We Power) owning and building new 

power plants with the regulated utility (We Energies) leasing and operating the plants for the term of the 

lease. Wisconsin Energy Corporation is also the parent company for We Power. The unifying goal of the 

coalition’s effort was to keep power plant regulation at the state rather than the federal level, while 

allowing utilities financial certainty through a long-term, PSCW-approved lease. Legislation allowing 

such transactions was proposed and debated in 2001 and, with strong support from the customer coalition, 

the Leased Generation Law was passed and signed into law in September 2001. The key risk-mitigating 

feature of the Lease Generation Law is that PSCW approval of a lease ensures full recovery of lease costs 

in utility rates. 

In early 2001, Wisconsin Energy Corporation earned valuable labor union support for the projects with 

the signing of a project labor agreement with the Milwaukee Building and Construction Trades Council 

that ensured all Power the Future construction projects would be staffed by union labor. Union labor 

support for the ERGS project was critical in the battle for headlines and as a strong and vocal 

counterpoint to the opposition at numerous public forums and hearings. 

One of the primary opponents of the project was a large Racine manufacturing company and its 

billionaire owner who ensured a well-funded legal defense team and significant public media exposure. 

Their primary issues were the local environmental impacts of the ERGS project, particularly mercury and 

fine particulate emissions, compared to gas-fueled generation. The high profile opposition probably 

neutralized some portion of the local business community that otherwise might have supported the local 

utility. 

Early in the project, ERGS gained two prospective co-owners, Wisconsin Public Power, Inc. and Madison 

Gas and Electric. Each prospective co-owner has an option to own a 50 MW share of each unit being 

built at Oak Creek. In addition, ERGS gained support from Wisconsin’s municipal and cooperative 

entities by making up to a total of 50 MW of the We Energies system energy per coal unit available for 

purchase through an open season offering. 

In 2001, We Energies committed to serving 5% of its Wisconsin retail load from renewable energy 

sources by 2011, far exceeding the state’s renewable portfolio standard. We Energies also earmarked $20 

million to encourage and support customer-based energy efficiency activities over 10 years. The 

renewable and energy efficiency commitments were valuable complements to the power plant additions 

and provided the necessary counterpoint to base-load generation. 
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On February 1, 2002, Wisconsin Energy Corp. filed its Certificate of Public Convenience and Necessity 

(CPCN) application and associated affiliated interest agreements to build the 1,830 MW ERGS (1,230 

MW of SC PC and 600 MW of IGCC) and 1,090 MW Port Washington (Wis.) Generating Station gas 

combined cycle plant (PWGS). The PSCW decided to process the gas and coal applications separately. 

The gas-fueled PWGS application was deemed complete in April 2002. In December 2002, the PSCW 

issued the CPCN order approving the PWGS plant and associated lease. The 20-year lease includes a 

fixed price guarantee and allowed a 12.7% return on investment assuming a 53/47 equity-debt ratio. It 

also includes a current return on construction work in progress, recovery of pre-certification expenses, 

and liquidated damages if the project is late or performs below guarantee. In approving the PWGS lease, 

the PSCW acknowledged that We Energies contention “...that We Energies will not be allowed sufficient 

return on a traditional rate base investment to compensate investors for the risks associated with the plant. 

Although the rate-based option is clearly one feasible alternative based on the evidence presented in this 

case, the Commission concludes that leased generation financing is in the public interest.” PWGS 

construction began in mid-2003 for the first unit with a July 2005 targeted in-service date. The second 

unit will be in service by summer 2008. 

The coal-based ERGS application needed several rounds of additional information before the PSCW 

deemed its application complete in November 2002. In Wisconsin, the CPCN process must be finished 

within one year of the date the application is deemed complete. Given the various Environmental Impact 

Statement (EIS) and regulatory review and notice requirements, the one-year clock is a strong motivator 

for the parties and the PSCW to move through the regulatory process expeditiously. 

The joint PSCW-WDNR Draft EIS was published in April 2003. The PSCW received comments from 

about 300 parties or individuals. The 800-page Final EIS was issued in August 2003. Two weeks of 

technical hearings and three days of public hearings were held in August and September 2003. 

The PSCW issued the ERGS CPCN and lease approval order on November 10, 2003. The CPCN was 

conditioned on receiving the necessary environmental permits, planning for 55 MW of new energy 

efficiency programs, and an updated needs assessment for the second unit. The PSCW-approved 30-year 

ERGS lease allows a 12.7% return on investment assuming a 55/45 equity-debt ratio and a 5% cap on 

cost overruns. The ERGS lease also includes a current return on construction work in progress, recovery 

of pre-certification expenses, and liquidated damages if the project is late or performs below guarantee. 

At the end of the initial 30-year lease term, We Energies has the option to renew the lease at a substantial 

discount, terminate the lease, or buy the facility, subject to certain tax limitations. 

Construction activities at the site will begin in late 2004 or early 2005 to meet the May 2009 and May 

2010 in-service dates. 

Major Issues for the ERGS Project

1. Need for new power plants 

The first hurdle turned out to be the easiest for We Energies and ERGS. The last baseload power plant 

built in Wisconsin went into service in 1985 while load has been growing 2-3% per year. As a result, 

there was strong agreement among almost all parties – including our primary opposition – that there was a 

need for one or more new baseload power plants. 
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Gas vs. Coal 

One of the fundamental issues for new generation was fuel choice. The Power the Future initiative 

included plans to retire an old coal-based plant and replace it with new gas-fueled or new coal-based 

generation. The opposition argued primarily for gas-fueled plants instead of using coal. The main issues 

were the economics, reliability and environmental impacts of each fuel. 

From We Energies' standpoint, the economic advantages of building coal-based capacity were 

overwhelming. Long-range planning models run by the PSCW showed a $1.9 billion net present value 

advantage to building coal-based units compared to an all-gas/no-coal scenario. Detailed analyses of 

dozens of planning scenarios resulted in the near consensus opinion that there are economic benefits to 

adding two new coal-based plants in the 2008-2012 timeframe. In the ERGS Order, the PSCW 

recognized the need for coal-based capacity and compromised on the timing by ordering 2009 and 2010 

in-service dates. In their deliberations, the PSCW considered that given the long and arduous application 

and approval process for a new coal-based plant, rejecting new coal-based units in 2003 would have 

represented a serious setback and may have delayed future attempts to build coal-based capacity. 

Several IPPs were unsuccessful in opposing the PWGS combined cycle plant in 2002 and dropped out of 

the Power the Future opposition group, leaving Calpine as the only IPP proposing to build gas-fueled 

plants in place of or before new coal-based units. Calpine submitted its confidential bid directly to the 

PSCW, but later provided copies to We Energies. The most economic Calpine alternative was a 500 MW 

NGCC plant built in 2007, which delayed new coal-based units a few years. The PSCW rejected the 

proposal, noting the high proportion of IPP gas generation in Wisconsin already owned by Calpine and 

the relative financial stability of Wisconsin Energy compared to Calpine. 

The underlying coal and gas price forecasts provided by We Energies were closely scrutinized by 

opposing parties but were ultimately used without modification by the PSCW. The 20-year gas forecast 

was provided and ably defended by Energy and Environmental Analysis, Inc. 

The late-2000 and early-2003 gas price run-ups and the overall high price volatility of the natural gas 

market were important issues. Consumer groups, particularly industrial customer groups, were supportive 

of more coal and less gas generation in large part to ensure more stable and predictable electric rates. 

Maintaining fuel diversity was also a key issue. After the Power the Future additions in 2010, We 

Energies’ generating capacity mix by fuel will be roughly the same as it is today (about 60% coal, 25% 

nuclear, 10% gas, 5% hydro/other). If new coal-based units were not built, the fuel mix would have 

become increasingly gas-based. The huge advantage in proven reserves of coal vs. gas was also an 

important point in favor of coal. 

2. Plant Siting 

We Energies’ Oak Creek site is the best site for a new power plant in the state because it has access to 

Lake Michigan cooling water, existing rail and coal handling facilities and extensive and underutilized 

transmission infrastructure. Ever since four old Oak Creek units (600 MW) were retired in 1988-89, the 

site has topped any list of possible locations for new generation. The large extent of We Energies’ 

property surrounding the Oak Creek Power Plant allowed for the development of several different 

alternate siting options for the ERGS units. 

3. Environmental Issues 

The ERGS faced a substantial challenge that needed to be overcome in terms of the environmental 

perception of new coal generation, particularly as compared to the emission characteristics of natural gas 

peaking units. The ERGS units, however, include several direct and indirect environmental 

improvements. The differential between emission controls that are required for new units versus the 
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existence and characteristics of emission controls for older coal-based units is significant. In addition, 

greater plant efficiency achieved by new coal-based plant designs means less fuel burned per unit of 

electrical output, lower emissions and less coal combustion by-products.. 

As noted previously, the Power the Future initiative included a financial commitment to invest in air 

quality improvements at existing power plants. When these emission reductions are combined with the air 

quality improvements associated with the addition of the ERGS units, system-wide emissions of SO2 and 

NOx will be reduced by more than 65% and mercury by more than 50% by 2013 compared with year 

2000 levels. These reductions come from a combination of coal plant retirements, addition of emission 

controls at existing plants, and the addition of new, lower-emitting coal and gas units. System-wide 

emissions of SO2 and NOx will be reduced by more than 100,000 tons per year by the time the full Power

the Future initiative is implemented, and mercury will be reduced by more than 500 pounds per year. 

In Wisconsin, the power plant approval processes (CPCN, air permit, water permit, EIS, etc.) at the 

PSCW and WDNR and other agencies is a complex web of interconnected filings, reviews, comment 

periods and decision dates. The CPCN approval by the PSCW is one of the first approvals received and 

is usually conditioned on the applicant receiving subsequent approval from other agencies. A summary of 

the major environmental areas follows. 

Air – The ERGS project (including the IGCC unit) received an air permit in January 2004. (The main 

permit conditions are shown in Attachments 1 and 2.) All criteria air pollutants were a significant issue 

and were examined. The air permit process took 25 months and included 46 formal submittals, 16 faceto-face meetings with the WDNR, seven consultants, and $380,000 in permit fees. The opposition spent 

most of their time addressing mercury and fine particulates. 

Water – ERGS will use Lake Michigan’s cold water in its once-through cooling system to improve unit 

efficiency and lower emissions, compared to plants with cooling towers. The project includes building a 

new intake tunnel bored under the lake extending about 1-1/2 miles out from the shore. Cylindrical 

wedge-wire screens will be installed at the lake bottom to keep fish from entering the intake structure. 

The EPA has recently issued federal standards under Section 316(b) of the Clean Water Act that impose 

technology-based performance requirements for the location, design, construction and capacity of cooling 

water intake structures. To comply with the new standards, the current onshore open-channel intake 

structure currently serving the Oak Creek Power Plant will be modified to share the ERGS offshore intake 

tunnel. The principal advantage to the offshore intake is to locate the water withdrawal point in an area of 

the lake that has less biological activity than the current onshore location. The addition of the new ERGS 

units at the site of existing generating units optimizes the environmental improvements associated with 

implementing the new federal rules for the entire generating facility. 

Wetlands – The site is large enough to accommodate the new units and their associated rail and yard 

modifications without disturbing significant amounts of wetland habitat. The company has proposed a 

mitigation plan to compensate for impacts on specific wetland communities which includes a mix of onsite and off-site wetland enhancements and restoration projects. 

Coal Combustion By-products – The primary coal combustion by-products produced at the ERGS units 

are fly ash, bottom ash, and synthetic FGD gypsum. We Energies’ goal is to use 100% of these byproducts (We Energies coal combustion by-product utilization rate from its existing coal-based generation 

is 98% and growing). Based on past experience and recent discussions with firms that use and market 

these materials, the company expects to increase utilization from zero at the start of ERGS commercial 
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operation to 100% over 10 years. An initial need for landfill space will be provided through existing 

landfill capacity.

4. Jobs

The very positive local economic impact of coal-based power plant construction and operation was 

important not only to the city of Oak Creek and the area’s union labor force, but also to state and local 

businesses, equipment suppliers, politicians and citizens. The coal plant enjoyed tremendous support 

from a very broad coalition rallying around the new jobs and economic development benefits as well as 

reduced air emissions of the ERGS project. Their attendance, testimony and support at public hearings 

and other forums was instrumental to securing approval from the PSCW. 

The planned but denied IGCC Unit in 2011

In the February 2002 Power the Future filing, We Energies proposed a third coal-based unit utilizing 

IGCC technology at the ERGS site to be in-service in 2011. This third coal-based unit was denied a 

CPCN by the PSCW for two reasons: 1) it was too expensive, and 2) it was not needed in 2011. We 

Energies and We Power used cost and performance assumptions based on firm quotes, estimates and 

recent contract experience (see Attachment 3). In the long-range least cost planning models used by the 

PSCW and We Energies, both SC PC and IGCC units were available options but only SC PC units were 

selected, both in the base case and in all scenarios (high gas prices, high coal prices, etc.). 

We Energies argued that the environmental advantages and promising technology made IGCC 

appropriate as the third coal-based unit at the site, despite some apparent economic disadvantages. In the 

end, the PSCW decided only two coal-based units were needed at this time. We Energies remains 

optimistic that the IGCC technology will continue to mature and will consider using the technology in 

future generation plans. 
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FIGURE 6.1 

Supercritical Unit Air Permit Limits 

ERGS Supercritical Units 1 and 2 Air Permit 

Control Technologies and Emission limits for each Boiler

POLLUTANT CONTROL 

TECHNOLOGY EMISSION LIMIT Averaging Time 

Carbon Monoxide (CO) Good Combustion 

Practices

0.12 lb/MBtu , 

742 lb/hr, 

3,250 tpy 

24-hour rolling average, 

excluding SU/SD 

12-month rolling average 

including SU/SD 

Nitrogen Oxides (NOx)

Low NOx Burners and 

Selective Catalytic 

Reduction 

0.07 lb/MBtu 

< 5 ppmdv ammonia 

30-day rolling average 

excluding SU/SD 

12-month rolling average 

including SU/SD 

Particulate Matter (PM) 

Fabric Filter Baghouse, 

Flue Gas Desulfurization, 

Wet ESP 

0.018 lb/MBtu 

20% opacity 

Based on a 3-hour block 

average limit. 

Particulate matter < 10 

microns (PM10)

Fabric Filter Baghouse, 

Flue Gas Desulfurization, 

Wet ESP 

0.018 lb/MBtu 

20% opacity 

Based on a 3-hour block 

average limit. 

Sulfur Dioxide (SO2) Washed Coal and Wet 

Flue Gas Desulfurization 

0.15 lb/MBtu 

4.0 lb/MBtu 

30-day rolling average 

including SU/SD 

Uncontrolled – 30-day 

rolling average 

Volatile Organic 

Compounds (VOC) 

Low NOx Burners and 

Good Combustion 

Practices

0.0035 lb/MBtu 

21.6 lb/hr, 

95 tpy 

24-hour rolling average, 

excluding SU/SD 

12-month rolling average 

including SU/SD 

Lead (Pb) Fabric Filter Baghouse and 

Flue Gas Desulfurization 7.9 lb/TBtu Based on a 3-hour block 

average limit. 

Mercury (Hg) Fabric Filter Baghouse and 

Flue Gas Desulfurization 

1.12 lb/TBtu 

(based on 90% 

Removal, Final Limit is 

operational permit) 

Stack Testing 

Coal Sampling & Analysis 

Beryllium (Be) Fabric Filter Baghouse and 

Flue Gas Desulfurization 0.35 lb/TBtu Stack Testing 

Coal Sampling & Analysis 

Fluorides (F) Fabric Filter Baghouse and 

Flue Gas Desulfurization 0.00088 lb/MBtu Stack Testing 

Coal Sampling & Analysis 

Hydrogen Chloride (HCl) Flue Gas Desulfurization 16.2 lb/hr 

Stack Testing 

Based on a 24-hour rolling 

average 

Sulfuric Acid Mist (H2SO4) Flue Gas Desulfurization 

and Wet ESP 0.01 lb/MBtu 

Stack Testing 

Based on a 24-hour rolling 

average 
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CASE STUDY #1 

Attachment 2 – IGCC Air Permit Limits 

ERGS IGCC Unit Air Permit (but CPCN was denied by PSCW) 

Control Technologies and Emission limits for each IGCC Gas Turbine

POLLUTANT CONTROL 

TECHNOLOGY EMISSION LIMIT Averaging Time 

Carbon Monoxide (CO) Good Combustion 

Practices

0.030 lb/MBtu 

624 lbs 

282 tons 

24-hour rolling average, 

excluding SU/SD 

1 hour period including 

SU/SD 

12-month rolling average 

including SU/SD 

Nitrogen Oxides (NOx) Diluent Injection System 

15 ppm 

15 ppm 

30-day rolling average 

excluding SU/SD 

12-month rolling average 

including SU/SD 

Particulate Matter (PM) Good Combustion 

Practices, Syngas Fuel 

0.011 lb/MBtu, 

Including SU/SD 

Stack Testing , based on a 

3-hour block average 

limit. 

Particulate matter < 10 

microns (PM10)

Good Combustion 

Practices, Syngas Fuel 

0.011 lb/MBtu, 

Including SU/SD 

Stack Testing , based on a 

3-hour block average 

limit. 

Sulfur Dioxide (SO2)

IGCC Process 

Gas Cleanup System 

0.030 lb/MBtu 

40 ppm sulfur in syngas 

278 tons 

24-day rolling average 

including SU/SD 

12-month rolling average 

including SU/SD 

Volatile Organic 

Compounds (VOC) 

Good Combustion 

Practices

0.0017 lb/MBtu 

3.64 lbs 

16.93 tons 

24-hour rolling average, 

excluding SU/SD 

24-day rolling average 

excluding SU/SD 

12-month rolling average 

including SU/SD 

Lead (Pb) Good Combustion 

Practices 0.0000257 lb/MBtu Stack Test, based on a 3-hour 

block average limit. 

Mercury (Hg) IGCC Process 

Gas Cleanup System 

0.56 lb/Tbtu 

95% Removal 

12-month rolling average 

including SU/SD 

Stack Testing 

Coal Sampling & Analysis 

Sulfuric Acid Mist (H2SO4)

IGCC Process 

Gas Cleanup System 0.0005 lb/MBtu 

Based on a 3-hour rolling 

average including SU/SD 

Stack Testing 
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Control Technologies and Emission 

Limits for Each Sulfuric Acid Plant 

POLLUTANT CONTROL 

TECHNOLOGY EMISSION LIMIT Averaging Time 

Sulfur Dioxide (SO2) Dual Absorption with mist 

eliminators

4.0 lbs per ton of 

Sulfuric Acid Produced Stack Testing 

Sulfuric Acid Mist (H2SO4) Dual Absorption with mist 

eliminators

0.128 lbs per ton of 

Sulfuric Acid Produced Stack Testing 

Visible Emissions 10% Method 9 

Control Technologies and Emission 

Limits for Gasifier Flare 

POLLUTANT CONTROL 

TECHNOLOGY EMISSION LIMIT Averaging Time 

Particulate Matter 

(PM/PM10) Good Flare Design 35 lb/MBtu SU/SD 12-month rolling average 

Visible Emissions 

0%

NTE 5 minutes during 

any 2 hr period 

Method 9 
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CASE STUDY #1 

Attachment 3 –Generation Planning Alternatives 

ERGS CPCN Docket, Exhibit JEK-1, Table 1-8 (excerpts) 

 Size Overnight 

Construction Cost

Var.

O&M

Fixed

O&M

Average

Heat Rate 

Generic Units (MW) (2003 $/kW) ($/MWh) ($/kW-yr) (Btu/kWh) 

Biomass 100 $1,804 $3.13 $48.49 8,911 

Coal (bituminous) 515 $1,400 $2.07 $20.90 8,700 

NGCC 545 $545 $2.35 $4.28 6,983 

Combustion Turbine 150 $400 $2.02 $5.21 10,555 

Wind 200 $0 (confidential) 

IGCC 500 $1,437 $0.85 $34.75 8,300 

Notes:

1- A firm gas transport charge is assigned to combined cycle units at a rate of $3.45 per kilowatt of capacity, and to combustion

turbine units at a rate of $6.08 per kilowatt of capacity. 

2- Wind is given no capacity credit toward reserves. 

3- A $2.09 / MWh charge is added to wind generation to cover costs of additional spinning reserve margin due to wind resource 

variability (per Electrotek study). 

CASE STUDY #2 

Springerville Units 3 and 4 

Springerville, Arizona 

Tucson Electric Power 

Tucson Electric Power is adding two 400 MW coal-based units to its existing two-unit (800 MW) 

Springerville plant. The units will be equipped with SCR for NOx control, spray dryers for SO2 control 

and baghouses for particulate control. The power will be used to serve the growing electric load in the 

southwest. Air permitting was conducted in the spring of 2001 and 

a permit application was filed with the Arizona Department of 

Environmental Quality in March of the same year. 

The air permitting identified two concerns. First, the proposed 

plant is close to two nearby Class I air quality areas (Petrified 

Forest National Park and the Mt. Baldly Wilderness Area). To 

reduce potential impacts on these areas, Tucson Electric agreed to net the SO2 and NOx emissions from 

Springerville Units 1 and 2 to offset new emissions from operating Units 3 and 4. This resulted in a PSD 

permit being applied for only PM10 and the other non-sulfur PSD pollutants. On this basis, long-range 

transport modeling of the plant’s impact on the Class I areas showed no concerns. 

The second concern was a legacy issue related to EPA’s original permitting of Units 1 and 2. Because 

construction of Unit 2 began long after its original PSD permit was issued, EPA required a revised best 

available control technology analysis be done; and the analysis resulted in more stringent controls on Unit 

2. After months of negotiations, EPA, Arizona DEQ and Tucson Electric Power agreed to lower the SO2

Tucson Electric Power is 

adding two 400 MW coalbased units to its existing 

two-unit (800 MW) 

Springerville plant.
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and NOx effective emission rates for Unit 2. These emission reductions enabled the netted emissions 

from all four units to comply with PSD regulations and the permit was issued. 

Litigation brought by a conservation organization raised essentially these same issues by challenging the 

original issuance of an air permit for Unit 2. A court has decided the litigation in favor of Tucson 

Electric.

The air permit was issued by the Arizona DEQ and approved by EPA. Unit 3 has been purchased by TriState Generation and Transmission Association of Denver and is now under construction. Construction 

has not yet begun on Unit 4. 

CASE STUDY #3 

Intermountain Power Project Unit 3 

Delta, Utah,

Intermountain Power Agency 

Intermountain Power Agency is adding a 950 MW coal-based unit 

to its existing Intermountain Power Project, which has two other 

950 MW units. Unit 3 will be equipped with SCR for NOx control, 

a FF for particulate control and wet limestone FGD systems for 

SO2 control. The power will be used by customers of Los Angeles 

Department of Water and Power in California and Utah Associated 

Municipal Power Systems. 

The air permit application was submitted to the Utah Division of Air Quality (UDAQ) in December 2002. 

Several analyses have been performed to determine the impact of the plant on five nearby Class I areas in 

southern and eastern Utah as well as a non-attainment area in Utah County at Provo. The Class I area 

analyses were conducted pursuant to the federal land manager guidance (FLAG) document. The result is a 

demonstration of no significant impact. In addition, a cumulative SO2 increment consumption analysis 

was conducted showing that the Class I increment has only been one third consumed in the nearby 

national parks. A draft permit has been prepared and is being readied for public comment by UDAQ. A 

public hearing will be held this spring with the final permit issuance to follow this summer. 

CASE STUDY #4 

Marion Station Units 1-3 

Southern Illinois Power Cooperative 

Southern Illinois Power Cooperative (SIPC) is a generation and 

transmission cooperative serving three distribution cooperatives. 

Organized in 1948, SIPC operates four units at the Marion 

Station, with the most recent addition being the 173 MW Unit 4 

placed in service in 1978. Units 1-3 were commissioned in 1963 and are rated at 33 MW each. All of 

SIPC’s units burn high-sulfur coal and coal mining wastes mined locally in southern Illinois. 

Reduced reliability on the three small units and the requirement for costly NOx emission reductions from 

these cyclone boilers led SIPC to investigate the most cost-effective and environmentally acceptable 

approach to meeting the current and future power needs of their member cooperatives. Refurbishment of 

the existing boilers to improve reliability would have required major modifications and/or replacements to 

Intermountain Power 

Agency is adding a 950MW 

coal plant to its 

Intermountain Power 

Project.

SIPC repowered three 33 

MW units with a CFB 

boiler.
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virtually all major components of the plant, including: cyclones, furnace walls, superheater, draft system, 

boiler feed water pumps, coal conveyors, water treatment, and controls. On top of these major 

improvements to the steam generator, SIPC would also need to add costly SCR system(s) to reduce NOx

emissions. 

These staggering capital requirements with no significant increase in capacity led SIPC to investigate 29 

different alternatives, including refurbishment of the existing facilities, a variety of coal- and gas-based 

technologies, as well as power purchase agreements. Considering a 30-year evaluation period, the most 

favorable alternative for the SIPC’s member cooperatives was a four-fold approach: 

1. Retirement of the three steam generators on Units 1-3; 

2. Repowering of Units 1-3 steam turbines with a single CFB boiler; 

3. Adding SCR for NOx control on Unit 4; and 

4. Adding various gas-fired peaking combustion tubines (CTs). 

The heart of the SIPC program is the coal-based CFB repowering of Units 1-3. This coal-based 

repowering provided SIPC with a 22% increase in capacity over the existing output from the three units. 

The repowering also led to a 12% increase in the plant’s energy conversion efficiency and a related 12% 

reduction in CO2 emissions per MWhr of generation. 

Air permitting for the proposed Marion Station modifications and additions used the PSD emission 

“netting” process, which considered both emission reductsions (e.g. retired cyclone boilers, SCR system 

for NOx control) and emission additions (e.g. CFB boiler, two CTs). The result was a significant net 

decrease in NOx, SO2, and H2SO4 emissions and only minor (well below the PSD threshold for major 

modifications) increases in other emissions (i.e. VOC, TSP, PM10 and lead) with the exception of CO. 

The net increase in CO emissions exceeded the PSD threshold, and CO therefore was subject to a BACT 

analysis and (PSD) emission modeling. 

This successful project was placed in service in 2003 with significant benefits to SIPC's member 

cooperatives, the local communities of Southern Illinois and the air shed of the region. This SIPC 

program has facilitated the continued use of local high sulfur coals and coal mining wastes to more 

efficiently increase the production of electricity while significantly reducing air emissions. 

CASE STUDY #5 

Council Bluffs Energy Center Unit 4 

Council Bluffs, Iowa 

MidAmerican Energy 

Council Bluffs Energy Center Unit 4 is a 750 MW SC PC unit being added to an existing MidAmerican 

Energy facility in Council Bluffs, Iowa. The power will be used in the MidAmerican system. 

Air permitting for this facility was relatively straight forward and the review of the permit application by 

the Iowa Bureau of Air Quality was completed in nine months. The closest Class I area to this plant is in 

southern Missouri (about 600 km away). Some concern was expressed about current air quality levels for 

PM10 and SO2 in the area, but no public comments were offered on the draft permit and the permit was 

issued. The unit is under construction. Pre-operation air quality data are being collected. 
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CASE STUDY #6 

Hunter Unit 4 

Castle Dale, Utah 

PacifiCorp

Hunter Unit 4 is a 550 MW coal-based unit being added to the existing Hunter Power Plant in Castle 

Dale, Utah, and is owned by PacifiCorp. The power generated by Unit 4 will be used in the PacifiCorp 

system. PacifiCorp has chosen to reduce the SO2 and NOx levels from Hunter’s existing Units 1, 2, and 3 

to offset the new emissions from Unit 4. The netting of SO2 and NOx across the plant resulted in a PSD 

permit being applied for PM10 and other non-SO2 PSD emissions. Air quality data analysis from nearby 

Class I areas has shown no significant impact from the proposed unit. The permit application is currently 

being reviewed by UDAQ. 

CASE STUDY #7 

Comanche Unit 3 

Pueblo, Colorado

Xcel Energy 

or

Pawnee Unit 2 

Brush, Colorado 

Xcel Energy 

Xcel Energy is planning to build a new 750 MW SC PC unit at either its Comanche Plant in Pueblo, 

Colorado, or its Pawnee Plant in Brush, Colorado. Regardless of the site, this unit will be added to an 

existing facility. The power will be used in the Xcel system. Xcel is currently evaluating both sites and 

will select one for the construction of the new unit. Preparation of the permit application has not yet 

begun.

CASE STUDY #8 

New Plant 

NE Iowa 

Dairyland Power 

Dairyland Power is planning to construct a new 400 MW coal-based unit in northeast Iowa. A site 

selection study has located two sites that are being evaluated for the plant. The EIS process has been 

initiated for this project, but the preparation of the air quality permit application has not yet begun. 

Conclusion

These case studies provide an indication of the uncertainties and difficulties encountered in the 

development of new coal-based plants. The significant common theme is that even after the decision is 

made to build a new plant, significant risks emerge during the complicated regulatory and permitting 

processes. Figure 5.1 provides a summary of the significant aspects of each of the eight case studies 

reviewed.
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FIGURE 6.2 

Case Studies Summary Table (Units Added at Existing Plants) 

Power Plant 

(plant, utility, 

location)

Configuration (power

output, fuel type, steam 

conditions, AQS, emission 

requirements)

Key Project Dates 

(initial announcement, 

permits, construction, 

commercial operation)

Issues 

During

Project

Development 

Status & 

Remaining

Actions

Council Bluffs 

Energy Center 

– Unit 4

MidAmerican 

Energy 

Council Bluffs, 

Iowa

790 MW; PRB Coal 

SC PC, SCR + SDA 

+ Baghouse 

NOX 0.07 lb/MBtu 

SOX 0.1 lb/MBtu 

PM10 0.025 lb/MBtu 

Hg 1.7x10-6

lb/MBtu

Site announced: 1/02 

AQ Permit issued: 

Construction started: 

9/03

Commercial op: mid2007 

SO2; PM10 Pre-operational

AQ data being 

collected.

Regulatory

approval needed 

for transmission 

line upgrade. 

ERGS, Elm 

Road

Adj. To Oak 

Creek Plant 

Milwaukee,

Wisconsin

2 units; 615 MW 

each;

SC PC 

Proposed: 2000 

CPCN filed: 2/02 

Approved: 11/02 

EIS: 9/02 

Air permit: 1/04 

Construction: 2nd half 

‘04

In-service (Unit 1): 5/09 

In-service (Unit 2): 5/10 

600 MW 

IGCC denied; 

System-wide 

reduction:

NOX, SOX 

>65%; Hg 

50%; 

Wetlands

permit in 

progress

100% use of coal 

combustion 

products by 

WeEnergy; NPV 

advantage: Coal 

$1.9 B over Gas; 

Additional

controls: CO; Pb; 

PM10; VOC; F; 

HCl; H2SO4

Springville

Units 3 & 4 

Tucson Electric 

Power

Tucson,

Arizona

2 units; 400 MW 

each; Coal-based 

Unit 3 in construction; 

Unit 4 not yet started 

Proximity to 

Class 1 AQ 

areas; Revised 

BACT for No. 

2 SCR, PM10,

NOx, SOx,

PSD permit for 

PM10 & Non-S 

pollutants.

Reduce NOX, SOX

on Units 1 & 2. 

Court ruling in 

favor of company.

Intermountain

Project, Unit 3 

Intermountain 

Power Agency 

Delta, Utah 

950 MW; Coal-based Draft permit for public 

comments; Air permit 

applied 12/02; Draft 

permit in preparation 

Class 1 & 

nonattainment; no 

significant

impact. 

SOX increment 

1/3 consumed. 

LADWP

customer. 

Permit expected 

by Summer ‘04 
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CASE STUDIES SUMMARY CHART 

(Units Added at Existing Plants) 

Continued

Power Plant 

(plant, utility, 

location)

Configuration

(power output, fuel 

type, steam 

conditions, AQS, 

emission 

requirements)

Key Project Dates (initial 

announcement, permits, 

construction, commercial 

operation)

Issues During 

Project

Development 

Status & 

Remaining

Actions

Hunter, Unit 4 

PacifiCorp

Castle Dale, 

Utah

550 MW Coalbased; added to 

existing 1,2 & 

3; NOX, SOX

from 1,2 & 3 to 

offset Unit 4 

emissions 

 Impact on 

Class 1

Areas; PSD in 

process for PM10,

non-S PSD 

emissions 

PSD Permit being 

applied for PM10

&

Non S PSD 

Pollutants

Comanche,

Unit 3 or 

Pawnee Unit 2 

Xcel Energy 

Pueblo or Brush, 

Colorado

750 MW; SC 

PC

Site selection initiated; 

AQ permit preparation to 

start

 USER Xcel 

Energy. Selection 

of one site to be 

made soon. 

New Plant in 

Notheast Iowa 

Dairyland 

Power

NE Iowa 

400 MW; Coalbased2 sites being evaluated Environmental 

Impact Study 

started; AQ 

permit not yet 

started

Prepare AQ 

permit. Complete 

site selection. 

Marion Station 

Units 1-3 

Southern Illinois 

Power

Cooperative

Southern Illinois 

Repower

existing units; 

coal-based

CFB; 22% 

power increase; 

12% efficiency 

increase; 12% 

CO2 reduction 

Repowering started:

2003

Decreases in NOX,

SOX; minor 

increases in 

VOM, TSP, PM10,

Pb

Continued use of 

local high-sulfur 

coal. CO subject 

to BACT. 
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Section 7: Opportunities for the Future of Coal in the National Energy Mix

Historical Perspective

(1985 – 2003) 

The historical and projected capacity additions for electricity in 

the U.S. from 1985 to 2003 effectively depict the condition of the 

power industry during that period. From 1985 to 1998, the range 

of capacity additions per year varied from 1,600 MW to 7,900 

MW, with an average of about 4,000 MW. This growth pattern of approximately 0.5%/yr (of a total 

800,000 MW installed capacity) was significantly less than the increase in the electrical demand during 

the same period. Reserve margins across the U.S. dramatically dropped below the industry-wide standard 

of 15%. 

The effect of these significant reductions in the reserve margins, along with the introduction of 

deregulation, spurred the most significant capacity expansion in the history of the U.S. In 1999, almost 

9,000 MW of new capacity came on line – most of these were simple-cycle gas turbines burning natural 

gas, providing peaking capacity. It wasn’t rocket science. Simple cycle plants were quick and easy to 

install, with low capital cost, negligible environmental impacts and gas prices less than $3.0/MBtu. New 

independent power producers and merchant plants led the way. Moreover, the financial institutions were 

more than happy to finance the boom. Coal-based generation was not designed to provide this component 

(peaking) of the overall need for additional generation. In addition, coal was perceived to be at a 

disadvantage from an environmental standpoint when compared to natural gas. This perception found its 

way into the policies and positions of some regulatory agencies. 

In 2000, nearly 27,000 MW of new capacity came on-line, 

including both gas-fired simple-cycle (peaking) and NGCC 

(baseload) units. With low-cost natural gas available, and NGCC 

installed costs of $500-600/kW, they were the choice for 

baseload capacity. However, for future baseload capacity, new 

coal-based plants were being considered (24 coal-based facilities were announced according to the 2001 

Power Plant Construction Magazine) most notably because of a significant increase in gas prices during 

that specific period of time. 

At the peak of power plant development, over 300,000 MW of new generation was announced, planned 

or in construction. The net result was the projected addition of 5%/yr of new generating capacity. EIA 

had projected a range of 2.3-3.6% increases in electrical demand for 2001. Thus, about 50% of the new 

capacity being built at that time addressed increase in demand while the other 50% addressed the need for 

enhanced reserve margins. Such projections were consistent with Vice President Cheney’s Energy Task 

Force that recommended that 1,300-1,800 new power plants be built during a 20-year period. 

Some analysts, including Salomon-Smith Barney considered these projections overly optimistic and 

predicted that as many as 50% of the projects would never be constructed. However, the main reason for 

this pessimism was not the obvious as we understand today but rather the concern of inadequate supply of 

natural gas, the fuel for at least 95% of these new projects. 

Beginning in late 2000 and continuing into 2001 and 2002, several major events changed the future of 

this historical growth pattern. First, gas prices significantly increased (>160%). Second, the recession set 

in and the annual demand electricity forecasts began to fall off. Third, significant financial problems 

occurred at most of the major IPPs and merchant energy companies, resulting in financial institutions 

cutting off funding to power plant developers. Fourth, questionable market practices by some merchant 

Only 52 GW of new plants 

came on line from 1985 to 

2003.

36GW of new plants came 

on line in 1999 and 2000. 

Most of that capacity was 

fueled by natural gas. 
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and trading companies lead to their being forced out of the marketplace. While the extent of such 

practices can be debated, the public perception that IPPs were responsible for increased prices and 

shortages in areas such as California was very real. This further exacerbated the financial problems and 

led to many states retracting their moves towards deregulation. 

This removed an incentive from the marketplace. The overall 

impact of these factors was that new plant construction was 

significantly curtailed, especially for the most capital intensive 

projects, which at that time (2002) meant most of the newly 

announced coal-based plants.

Because of high natural gas prices, EIA Annual Energy Outlook (AEO) 2004 continued to forecast 

significant new coal-based generation, although most are noted as “Unplanned.” Approximately 52,000 

MW were forecast in the 2004 report. 

x 2000-2005: 0 MW 

x 2006-2010: 6,800 MW 

x 2011-2015: 11,800 MW 

x 2015-2020: 33,200 MW 

In its June 2003 issue, Power Magazine was more bullish, predicting 11,500 MW of new coal-based 

capacity by 2007. (This is only a quarter of what was originally announced.) 

Overall, most of the coal-based capacity announced in the 2000-2002 timeframe will not be built. While 

the need for additional generation may still exist, the demise of many IPPs and the lack of funding make 

these projects highly unlikely. For the future, the need will be there and the competitive advantage of 

coal prices compared with higher gas prices will exist, but the capital cost of coal-based generation will 

continue to be problematic, not just for regulated utilities, but especially for IPPs and merchant plant 

developers.

Longer Term Opportunities

(2004-2025) 

The major long-term opportunities/challenges for coal are: (1) 

price stability, (2) cost competitiveness, (3) environmental 

controls and (4) energy security. 

Price Stability. EIA’s AEO 2004 report projects fuel prices 

(2002 $/MBtu) delivered to electricity generators for natural gas, 

oil, coal and nuclear. Coal prices are expected to be stable during 

this entire 20+ year period at $1.25/MBtu. Gas prices are projected to drop to $4.00/MBtu in 2004 and 

then gradually increase to $4.75/MBtu by 2025. However, natural gas price forecasts vary considerably 

depending on trends in domestic exploration and production, as well as the future role of imports of LNG. 

Cost Competitiveness. DOE report #DE-AC-01-94FE62747, April 2001, projected marginal 

competitive pricing for gas- and coal-based power plants. In this study, an NGCC power plant with a 

capital cost of $500-600/kW and a gas price of $3.50/MBtu was basically equivalent to a coal-based plant 

with a capital cost of $1,000-1,200/kW and a fuel cost of $1.00-1.25/MBtu. With everything else being 

equal, an equivalent natural gas price of $4.50/MBtu would amount to increasing the cost of electricity for 

an NGCC plant by about 25%. 

Market changes and high 

natural gas prices have 

curtailed the construction of 

new plants since 2002.

Planning for coal-based 

plants must address price 

stability, cost 

competitiveness, 

environmental controls and 

energy security.
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In the most recent National Coal Council report, Increasing Coal-Fired Generation Through 2010: 

Challenges and Opportunities, May 2002, costs were presented for advanced combustion technologies by 

2010. This study showed that NGCC technology with an “H” model gas turbine would cost $460/kW, 

somewhat negating the effect of the higher gas cost. Advanced supercritical PC and Advanced IGCC (air 

or oxygen blown) units could be installed for essentially $1,000/kW, the lower range of the price quoted 

above.

From a cost competitiveness position, coal is expected to be able to maintain an advantage over gas for 

both the short and long term. 

Environmental Controls. Perception and reality concerning environmental issues for coal-based power 

plants are still major concerns for the power industry. The following are facts, not myths. 

 According to the latest findings on national air quality published in 2002 Status and USEPA 

Trends, emissions of the six principal air pollutants have been cut 48% since 1970, despite a 42% 

increase in energy consumption;

y SO2 emissions are 41% lower than in 1980 

y Power plant NOx emissions are 33% lower than in 1990 

 The Annapolis Center for Science-Based Public Policy has found that since the 1960s, ambient 

concentrations of SO2 have dropped by over 90% and concentrations of NOx have dropped by 

more than half. (A Critique of the Campaign Against Coal-Fired Power Plants, 2002)

 EPA and Department of Energy data show that between 1970 and 1999 CO, VOC, PM10 and lead 

levels in the environment decreased 28%, 42%, 75% and 98% respectively. 

 The popular impression that older coal plants are “grandfathered,” which many interpret to being 

uncontrolled, is fiction – 

y Every power plant is regulated under the NAAQS and the acid rain Title IV programs for SO2

and NOx; many are regulated under the NOx SIP call for eastern state ozone. 

 Utilities that are currently installing SO2 controls (i.e., TVA, Duke, Progress Energy, Cinergy, 

AEP and Southern Company) are requiring more stringent SO2 control than would be required by 

NSPS. In other words, existing plants would be as clean (or cleaner) than new plants. 

In addition, new/proposed regulations for existing coal-based plants would reduce emissions even further. 

x Clear Skies and/or the Interstate Air Quality Rule (IAQR) would double the amount of FGD 

systems installed in the U.S. by 2010. SO2 emissions would be cut by 70% beyond current levels 

of emissions. 

x Clear Skies legislation would double the amount of SCR capacity in the U.S. The IAQR would 

increase SCR capacity by 50% in 2010 with continued growth in SCR thereafter. 

x Significant amounts of mercury would be captured with the addition of FGD and SCR systems. 

The IAQR would reduce power plant mercury emissions to 15 tons in 2018 (a 70% reduction 

from current levels). 

The result of these rules and regulations would make existing coal-based plants cleaner than at any time 

in our nation’s history. In many instances, there would be basically no difference in environmental 

emissions from a new plant versus an existing coal-based plant. 
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Energy Security. Coal remains an affordable and reliable domestic energy source. As such, coal was 

recognized as an essential component of our domestic energy supply in the May 2001 National Energy 

Policy. Coal reserves, which are distributed geographically throughout the U.S., comprise the greatest 

share of the nation’s energy resource base. Of the nation’s more than 500 billion tons of demonstrated 

coal reserves, 275 billion tons are economically recoverable using existing technologies. The U.S. has 

sufficient coal reserves to meet growing demand for well over 200 years, according to National Energy 

Security Post 9/11.

America already relies heavily on domestic coal to meet its energy needs. Coal accounts for 

approximately one-third of the nation’s primary energy production and for about 23% of U.S. energy 

consumption. Coal is principally used to generate electricity; over 50% of power generated in the U.S. 

comes from coal-based power plants. According to EIA’s Annual Energy Outlook 2002, coal production 

is expected to increase by some 200 million tons, or by just over 19%, by the end of the next decade. In 

2010, production is forecast to reach 1.284 billion tons. This entire increase will be used to generate 

electricity, but coal’s share of total electrical generation will decline slightly from its current share of 

51%. 

Unlike some forms of energy, coal poses few security issues during the production, distribution or storage 

stages. Nearly all the coal used in the U.S. (99%) is mined domestically and shipped by either rail or 

through our inland waterway system to power plants, steel mills, cement processing facilities and other 

industrial users. Because coal is a solid, it poses little risk to the surrounding public and would not likely 

be a target for terrorists. In the event of an emergency, the coal industry could increase production fairly 

quickly to meet increased demand for fuel for electricity and would only be hampered by possible 

transportation constraints. 

Conclusion

Despite the market fundamentals over the past 20 years that have led to an onslaught of natural gas-fired 

plants, coal remains the fuel of choice to provide a stable and secure source of energy for the nation. The 

major long-term opportunities/challenges for coal – price stability, cost competitiveness, environmental 

controls and energy security – must be recognized and understood in order to address the importance of 

coal to the economy. 
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Section 8: Conclusions

During the past decade, the availability of low-cost natural gas and increasing deregulation essentially 

halted the construction of coal-based power plants. However, the rapid deployment of NGCC plants, 

coupled with more rapid depletion of existing natural gas basins, caused demand for natural gas to 

significantly exceed supply. The result was overcapacity of electric power generation in a number of 

markets, a significant and sustained increase in the market price and price volatility of natural gas and 

very low capacity factors for NGCC plants (average of 29% for 2003). This has let to the return to coal as 

a favored feedstock for power generation. 

But even though coal is now favored for power generation, market 

overcapacity has created impediments to new construction. A significant 

impediment to the construction of new coal-based power plants is that the 

total cost of a new plant (which includes capital recovery, fuel and operating 

costs) must compete in an open marketplace with the cost of electricity from 

existing power plants, where the capital cost is no longer a significant portion 

of the cost of electricity. The lower COE from existing plants usually results 

in the lowest overall electric price to the customers, but it creates a significant 

economic hurdle to the construction of new coal-based power plants. 

Further, the regulatory system which has led to the retrofit of expensive 

emission control systems onto existing plants, coupled with the uncertainty of 

recovery of capital investment due to the structural changes in the electricity sector are underlying 

obstacles to wide-spread construction of new coal-based power plants. The uncertainty of future 

environmental regulations also complicates the decision between retrofitting existing older coal-based 

plants or retiring them and constructing new coal-based plants. 

As discussed in Section 3, numerous incentives to facilitate the construction of new advanced coal-based 

power plants either exist or have been proposed. While past incentives, based primarily on demonstration 

of new advanced technologies, have facilitated the construction of some new coal-based power plants, 

they have proved inadequate to attract investment in a significant number of new plants. This report has 

examined in considerable detail the structural issues that have inhibited the construction of new plants and 

offer recommendations that should help drive commercial-scale deployment and market penetration of 

new advanced clean coal power plants. 

The National Coal Council recommends that the Department of Energy 

develop federal incentives to reduce the risk-adjusted cost of new advanced 

coal-based plants that are not competitive with alternative technologies. 

The Council has not taken a position on which incentives (i.e., capital cost 

sharing, production tax credits, accelerated depreciation) would be most 

effective. The important issue is that whatever incentives are provided 

must enable the life-cycle cost of a new advanced coal-based power plant 

to be economically neutral to the investor, vis-à-vis alternative 

conventional technologies. A key outcome of the incentives should be to 

encourage deployment of multiple new commercial-scale advanced coalbased plants that are based on relatively proven designs. Special emphasis should be provided to promote 

those advanced clean coal technologies that best support Department of Energy and Administration goals 

of moving toward near-zero emissions power plants, a hydrogen-based energy economy, and carbon 

sequestration.

A significant 

impediment to the 

construction of new 

coal-based power 

plants is that the total 

cost of a new plant 

must compete in an 

open marketplace with 

the cost of electricity 

from existing power 

plants.

Incentives are required 

to enable the life-cycle 

cost of a new advanced 

coal-based power plant 

to be economically 

neutral to the investor 

vis-à-vis alternative 

conventional

technologies.
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Tying those incentives to the retirement of older, less efficient power plants in such a way that the owners 

of the existing facilities are able to recover the difference between the incremental cost of generating 

electricity at the existing facility and the new facility (i.e., recovery of the new capital investment and any 

stranded capital from the retirement of the older facility). Improved financial and regulatory models are 

also needed to appropriately account for and assess the overall risks and life-cycle costs associated with 

keeping and retrofitting older facilities versus retiring them and constructing new advanced coal-based 

plants.

A clear regulatory mechanism is also needed that will allow the investor to 

recover the added costs of the new facility though charges in the electricity 

marketplace. Because the benefit of new coal-based generation is on a 

national level, and the environmental benefits of advanced coal-based 

generation are on both regional and national levels, this regulatory 

mechanism for rate recovery must transcend state borders. Therefore, 

mechanisms are needed that will allow the recovery of the capital investment 

of the plants through capacity charges on a regional basis such as geographic 

coal basins or regional transmission organizations. The federal government 

must also work with state PUCs to ensure that utilities are able to recover 

those capacity charges through electricity rates. 

Incentives should recognize and reward IGCC’s potential to replace the use of natural gas in multiple 

markets – power, chemicals, fuels and fertilizers. Incentives should treat poly-generation options 

favorably and special incentives should be developed for repowering of distressed natural gas combined 

cycle plants with coal-based syngas. 

As discussed in Section 6, there is a need for an environmental regulatory 

approach that provides more certainty to the investor in coal-based power 

plants and eliminate several of the roadblocks to an expeditious permitting 

process that have arisen over the years 

Because of the rapid increase in natural gas prices and the view that gas 

prices may remain at these levels in the long term, many operating and 

partially constructed NGCC plants have become distressed assets that are 

not being dispatched. As a means of preserving the asset value in these 

plants, initial assessments indicate that it may be economical to convert 

some of these natural gas plants to coal-based plants using IGCC. The 

syngas produced by coal gasification can be combusted in these gas turbines with minor modifications. It 

may also be possible to build one or more coal gasification facilities to feed a closely clustered group of 

NGCC plants. Many factors must be considered including the need for power, access to coal 

transportation, plant location, etc. It is recommended that a program be implemented to address IGCC 

repowering of distressed NGCC plants. This would involve performing a detailed assessment of the 

economics of repowering, prioritizing and categorizing NGCC assets and devising an incentive program 

to initiate the conversion process. 

Continued public education is also essential to strongly reinforce that coal is a 

vital resource for our country, that it must be utilized to provide an adequate 

measure of energy security and reliability, that it has been and will continue 

to be the major fuel for electricity generation in the country, that it should be 

encouraged as an alternative feedstock for chemicals and fuels, that 

appropriate incentives and regulatory approaches should be provided to 

encourage its use in as clean a manner as possible, and that the use of such 

A clear regulatory 

mechanism is needed 

that will allow the 

investor to recover the 

added costs of the new 

facility though charges 

in the electric 

marketplace. 

There is a need for an 

environmental 

regulatory approach 

that provides more 

certainty to the 

investor in order to 

eliminate several of the 

roadblocks to an 

expeditious permitting 

process.

Coal is a vital national 

resource, provides 

energy security, and 

has been and will 

continue to be used for 

electric power 

generation.
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clean coal technologies should be fostered, encouraged and promoted in other countries where coal is a 

vital resource.

It is critical that the coal producers, transporters, users, equipment suppliers and users, the federal 

government and the state regulatory agencies recognize the strategic importance of clean coal 

technologies to the United States and the world, and cooperate to ensure that advanced coal-based plants 

are constructed in the near term. 
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APPENDIX A 

Description of The National Coal Council 

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 could, in turn, lead to decreased 

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

The Council is chartered by the Secretary of Energy under the Federal Advisory Committee Act. The 

purpose of The National Coal 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 that he may request. 

Members of The National Coal Council are appointed by the Secretary of Energy and represent all 

segments of coal interests and geographical disbursement. The National Coal Council is headed by a 

Chairman and Vice-Chairman who are elected by the Council. The Council is supported entirely by 

voluntary contributions from its members. To wit, it receives no funds whatsoever from the Federal 

Government. In reality, by conducting studies at no cost, which might otherwise have to be done 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 nor the views or 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 start-up of the Council. 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

80

APPENDIX B 

The National Coal Council 2004 Member Roster 

Robert O. Agbede, President & CEO 

ATS Chester Engineers 

639 Alpha Drive 

Pittsburgh, PA 15238 

Ph: 412-967-1900 Ext. 203 

ragbede@atschester.com

James R. Aldrich, State Director 

The Nature Conservancy 

642 West Main Street 

Lexington, KY 40508 

Ph: 606-259-9655 

Fx: 606-259-9678 

jaldrich@tnc.org

Allen B. Alexander, President & CEO 

Savage Companies 

6340 South 3000 East #600 

Salt Lake City, UT 84121 

Ph: 801-944-6600 

Fx: 801-261-8766 

AllenA@SavageCompanies.com

Sy Ali, President 

Clean Energy Consulting Corp. 

7971 Black Oak Drive 

Plainfield, IN 46168 

Ph: 317-839-6617 

Syali1225@aol.com

Barbara Farmer-Altizer, Executive Director 

Eastern Coal Council 

P.O. Box 858 

Richlands, VA 24641 

Ph: 276-964-6363 

Fx: 276-964-6342 

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. 

Sr Vice President & CTO 

Energy, Environment & Systems Businesses 

CH2M Hill 

9191 South Jamaica Street 

Englewood, CO 80112 

Ph: 720-286-2436 

Fx: 720-286-9214 

darvizu@ch2m.com

Kathie A. Baardson

CEO & Managing Member 

Nordic Energy, LLC 

9013 NE Highway 99, Suite S 

Vancouver, WA 98665 

Richard Bajura, Director 

National Research Center for Coal & Energy 

West Virginia University 

P.O. Box 6064, Evansdale Dr. 

Morgantown, WV 26506-6064 

Ph: 304-293-2867 (ext. 5401) 

Fx: 304-293-3749 

bajura@wvu.edu

Janos M. Beer 

Professor of Chemical & Fuel Engineering 

Dept. of Chemical Engineering 

Massachusetts Institute of Technology 

25 Ames St., Bldg. 66-548 

Cambridge, MA 02139 

Ph: 617-253-6661 

Fx: 617-258-5766 

jmbeer@mit.edu

Richard Benson, President 

Caterpillar Global Mining 

300 Hamilton Blvd., Ste. 300 

Peoria, IL 61629-3810 

Ph: 309-675-5127 

Fx: 309-675-4777 

Benson_Richard_a@cat.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

81

Jacqueline F. Bird, Director 

OH Coal Development Office 

OH Air Quality Development Authority 

50 W. Broad St., Suite 1718 

Columbus, OH 43215 

Ph: 614-466-3465 

Fx: 614-752-9188 

jbird@aqda.state.oh.us

www.ohioairquality.org

Sandy Blackstone 

Natural Resources Attorney/Economist 

8122 North Sundown Trail 

Parker, CO 80134 

Ph: 303-805-3717 

Fx: 303-805-4342 

sblackstone@ssbg.net

Robert L. Brubaker, Partner 

Porter, Wright, Morris & Arthur 

41 South High St. 

Columbus, OH 43215 

Ph: 614-227-2033 

Fx: 614-227-2100 

rbrubaker@porterwright.com

Michael Carey, President 

Ohio Coal Association 

17 S. High Street, Suite 215 

Columbus, OH 43215-3413 

Ph: 614-228-6336 

Fx: 614-228-6349 

info@ohiocoal.com

www.ohiocoal.com

Henry J. Cialone, Sr. Vice President 

& General Manager/Energy Products 

Battelle Labs 

4606 Burbank Drive 

Columbus, OH 43220 

Ph: 614-457-7948 

cialoneh@battelle.org

William Connors, Esquire 

Centennial Power, Inc. 

400 North 4th Street 

Bismarck, ND 58501 

Ph: 701-222-7965 

Cell: 701-426-2913 

Fx: 701-222-7877 

bill.connors@mduresources

www.centennialenergy.com

www.mduresources.com

Steve Corwell

Sr. Vice President, Corporate Affairs 

Indianapolis Power & Light 

One Monument Circle 

Indianapolis, IN 46204 

Ph: 317-261-8240 

Steve.corwell@aes.com

Kelly A. Cosgrove 

Vice President, Marketing & Sales 

Kennecott Energy Company 

PO Box 3009 

505 South Gillette Avenue 

Gillette, WY 82716 

Ph: 307-687-6053 

Fx: 307-687-6009 

cosgrovk@kenergy.com

Henry A. Courtright, Vice President 

Power Generation & Distributed Resources 

Electric Power Research Institute 

3412 Hillview Ave. 

Palo Alto, CA 94304 

Ph: 650-855-8757 

Fx: 650-855-8500 

hcourtri@epri.com

Joseph W. Craft, III, President 

Alliance Coal 

1717 S. Boulder Ave. 

Tulsa, OK 74119 

Ph: 981-295-7602 

Fx: 981-295-7361 

josephc@arlp.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

Michael D. Durham, President 

ADA Environmental Solutions 

8100 SouthPark Way, Unit B2 

Littleton, CO 80120 

Ph: 303-737-1727 

Fx: 303-734-0330 

miked@adaes.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

82

John Dwyer, President 

Lignite Energy Council 

1016 E. Owens Ave., Ste. 200 

PO 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, Inc. 

2828 North Monroe St. 

Decatur, IL 62526 

Ph: 217-876-3932 

Fx: 217-876-3913 

rich_eimer@dynegy.com

Irl F. Engelhardt, Chairman & CEO 

Peabody Energy 

701 Market Street 

St. Louis, MO 63101 

Ph: 314-342-3400 

Fx:

Email: 

Andrea Bear Field, Partner 

Hunton & Williams 

1900 K St., NW, 12th Fl. 

Washington, DC 20036 

Ph: 202-955-1558 

Fx: 202-778-2201 

afield@hunton.com

Lance Fritz, Vice President & 

General Manager/Energy 

Union Pacific Railroad 

1416 Dodge Street 

Omaha, NE 68179 

Ph: 402-271-5678 

Fx: 402-271-3378 

lfritz@up.com

Paul Gatzemeier 

Vice President & General Manager 

Centennial Energy Resources, LLC 

122 East Broadway 

Bismarck, ND 58501 

Ph: 701-222-7985 

Fx: 701-222-7877 

paul.gatzemeier@mduresources.com

Janet Gellici, Executive Director 

American Coal Council 

2890 E. Northern Ave., Ste. B4 

Phoenix, AZ 85028 

Ph: 602-485-4737 

Fx: 602-485-4847 

jgellici@americancoalcouncil.org

www.americancoalcouncil.org

Patrick Graney, President 

Petroleum Products, Inc. 

500 Rivereast Dr. 

Belle, WV 25015 

Ph: 304-926-3000, ext. 113 

Fx: 304-926-3009 

pgraney@petroleumproductsinc.com

Alex E. S. Green 

Graduate Research Professor Emeritus 

University of Florida 

Gainesville, FL 32611-6550 

Ph: 352-392-2001 

Fx: 352-392-2001 (call before sending) 

aesgreen@ufl.edu

John Nils Hanson, President & CEO 

Joy Global, Inc. 

100 E. Wisconsin Ave., Ste. 2780 

Milwaukee, WI 53202 

Ph: 414-319-8500 

Fx: 414-319-8510 

jnha@hii.com

Clark D. Harrison, President 

CQ, Inc. 

160 Quality Ctr. Rd. 

Homer City, PA 15748 

Ph: 724-479-3503 

Fx: 724-479-4181 

clarkh@cq-inc.com

www.cq-inc.com

J. Brett Harvey, President & CEO 

CONSOL Energy, Inc. 

1800 Washington Rd. 

Pittsburgh, PA 15241 

Ph: 412-854-6671 

Fx: 412-854-6613 

brettharvey@consolenergy.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

83

William Hoback, Bureau Chief 

Office of Coal Development, State of Illinois 

607 East Adams Street, CIPS-4 

Springfield, IL 62701 

Ph: 217-785-2001 

Fx: 217-558-2647 

bill_hoback@commerce.state.il.us

Warren J. Hoffman, Esquire 

Frost Brown Todd LLC 

250 W. Main St., Ste. 2700 

Lexington, KY 40507-1749 

Ph: 859-244-3320 

Fx: 859-231-0011 

whoffman@fbtlaw.com

Gerald (Jerry) A. Hollinden 

Vice President, Power Sector Manager 

URS Corporation 

Waterfront Plaza Tower One 

325 W. Main St., Ste. 1200 

Louisville, KY 40202-4251 

Ph: 502-217-1516 

Fx: 502-569-3326 

jerry_hollinden@urscorp.com

Christopher P. Jenkins 

Sr. Vice President, Coal Service Group 

CSX Transportation 

500 Water Street 

Jacksonville, FL 32202 

Ph: 904-366-5693 

Fx: 904-359-3443 

chris_jenkins@csx.com

William Dean Johnson 

Executive Vice President, General 

 Counsel and Secretary 

Progress Energy, Inc. 

411 Fayetteville St. Mall 

Raleigh, NC 27602 

Ph: 919-546-6463 

bill.johnson@pgnmail.com

Judy A. Jones, Commissioner 

Public Utilities Commission of OH 

180 East Broad St. 

Columbus, OH 43215-3793 

Ph: 614-644-8226 

Fx: 614-466-7366 

judy.jones@puc.state.oh.us

www.puc.state.oh.us

Dick Kimbler 

PO Box 186 

Danville, WV 25053 

Ph: 304-369-3347 

James R. Klauser 

Sr. Vice President 

Wisconsin Energy Corporation 

231 West Michigan Street 

Milwaukee, WI 53203 

Ph: 414-221-4740 

Fx: 414-221-3550 

james.klauser@we-energies.com

Thomas G. Kraemer, Group Vice President 

Burlington Northern Santa Fe Railway Co. 

2650 Lou Menk Dr. 

Ft. Worth, TX 76131-2830 

Ph: 817-867-6242 

Fx: 817-352-7940 

thomas.kraemer@bnsf.com

Max L. Lake, President 

Applied Sciences, Inc. 

141 W. Xenia Ave, PO 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 Inc. 

One City Place, Ste. 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 S. Colorado Blvd., Ste. 10 

Denver, CO 80246-8008 

Ph: 303-282-7576 

Fx: 303-282-7584 

ad@qwest.net

John T. Long, Sr. Vice President

Power Generation 

Constellation Energy 

111 Market Place, Suite 200 

Baltimore, MD 21202 

Ph: 410-230-4910 

Fx: 410-230-4669 

john.long@constellation.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

84

Jason Makansi, President 

Pearl Street, Inc. 

801 North Second Street, Suite 403 

St. Louis, MO 63102 

Ph: 314-621-0403 

jmakansi@pearlstreetinc.com

James K. Martin 

Vice President, Business Development 

Dominion Energy 

PO Box 26532 

Richmond, VA 23261 

Ph: 804-819-2176 

Fx: 804-819-2219 

james_k_martin@dom.com

Christopher C. Mathewson 

Dept. 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

Kevin McGowan

(awaiting contact info) 

Michael W. McLanahan, President & CEO 

McLanahan Corporation 

200 Wall Street 

Hollidaysburg, PA 16648-0229 

Ph: 814-695-9807 

Fx: 814-695-6684 

mmclanahan@mclanahan.com

Emmanuel R. Merle, President 

Energy Trading Company 

15 East Putnam Ave., #3210 

Greenwich, CT 06830 

Ph: 203-618-0161 

Fx: 203-618-0454 

thion@mindspring.com

Clifford R. Miercort, President & CEO 

The North American Coal Corporation 

14785 Preston Rd, Ste. 1100 

Dallas, TX 75240-7891 

Ph: 972-448-5402 

Fx: 972-661-9072 

clifford.miercort@nacoal.com

Jeffrey Miller, Managing Editor 

Definitive Solutions Company, Inc. 

8180 Corporate Park Dr., Ste 220 

Cincinnati, OH 45242 

Ph: 513-719-9150 

Cell: 513-678-5456 

Fx: 513-719-9130 

jeff_miller@dsc-online.com

Michael G. Mueller, Vice President 

Ameren Energy Fuels & Services Co. 

PO Box 66149, Mail Code 611 

St. Louis, MO 63166-6149 

Ph: 314-554-4174 

Fx: 314-206-1250 

mmueller@ameren.com

Robert E. Murray, President & CEO 

Murray Energy Corporation 

29325 Chagrin Blvd., Ste. 300 

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 Dr. 

Frederick , MD 21703 

Ph: 301-228-8804 

Fx: 301-694-9043 

rnarula@bechtel.com

Georgia Ricci Nelson, President 

Midwest Generation EME, LLC 

440 S. LaSalle St., Ste. 3500 

Chicago, IL 60605 

Ph: 312-583-6050 

Fx: 312-583-4920 

gnelson@mwgen.com

Mary Eileen O’Keefe, Director 

KFx, Inc. 

1362 North State Parkway 

Chicago, IL 60610 

Ph: 312-482-9701 

Fx: 312-482-9703 

maryeileenokeefe@aol.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

85

Umit Ozkan, Associate Dean for Research 

College of Engineering & Professor of Chemical 

Engineering 

Ohio State University 

167 Hitchcock Hall, 2070 Neil Ave. 

Columbus, OH 43210-1275 

Ph: 614-292-6623 (Dept) 

Ph: 614-292-2986 (College) 

Fx: 614-292-9615 

ozkan.1@osu.edu

www.che.eng.ohio-state.edu/facultypages/ozkan.html

Daniel F. Packer, President 

Entergy New Orleans 

PO Box 61000 

New Orleans, LA 70161 

Ph: 504-670-3622 

Fx: 504-670-3605 

dpacker@entergy.com

Thomas Pajonas, Managing Director 

ALSTOM USA 

2000 Day Hill Road 

Windsor, CT 06095 

Ph: 860-285-5035 

Fx: 860-285-5425 

Fredrick D. Palmer, Exec. Vice President 

Peabody Energy 

701 Market St. 

St. Louis, MO 63101-1826 

Ph: 314-342-7624 

Fx: 314-342-7614 

fpalmer@peabodyenergy.com

Earl B. Parsons, III, Vice President-Fuels 

Southern Company 

600 N. 18th St., 14N-8160, PO Box 2641 

Birmingham, AL 35291 

Ph: 205-257-6100 

Fx: 205-257-0334 

eabparso@southernco.com

Craig E. Philip, President & CEO 

Ingram Barge Company 

One Belle Meade Place 4400 Harding Rd 

Nashville, TN 37205-2290 

Ph: 615-298-8200 

Fx: 615-298-8213 

philipc@ingrambarge.com

Robert M. Purgert, President 

Energy Industries of Ohio 

Park Center Plaza, Suite 200 

6100 Oak Tree Blvd. 

Independence OH 44131 

Ph: 216-643-2952 

Fx: 216-643-2901 

purgert@energyinohio.com

William Raney, President 

West Virginia Coal Association 

PO Box 3923 

Charleston, WV 25339 

Ph: 304-342-4153 

Bill Reid, Managing Editor 

Coal News 

106 Tamarack St. 

Bluefield, WV 24701-4573 

Ph: 304-327-6777 

Fx: 304-327-6777 

billreid007@comcast.net

John W. Rich, Jr., President 

Gilberton Coal Company 

Main Street 

Gilberton, PA 17934 

George Richmond, President 

Jim Walter Resources, Inc. 

PO Box 830079 

Birmingham, AL 35283-0079 

Ph: 205-481-6100 

Fx: 205-481-6011 

grichmond@jwrinc.com

James F. Roberts, President & CEO 

Foundation Coal Company 

999 Corporate Blvd, 3rd Fl. 

Linthicum Heights, MD 21090 

Ph: 410-689-7500 (7512) 

Fx: 410-689-7511 

jroberts@rag-american.com

Karen Roberts 

Regional Manager, Coal Supply 

Xcel Energy 

PO Box 1261 

Amarillo, TX 79105 

Ph: 806-378-2505 

Fx: 806-378-2790 

karen.roberts@xcelenergy.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

86

James E. Rogers, Chairman, President, CEO 

Cinergy Corporation 

P.O. Box 960 

Cincinnati, OH 45201 

Ph:

Fx:

Daniel A. Roling, First Vice President 

Merrill Lynch 

Four World Finance Ctr., 19th Fl. 

New York, NY 10080 

Ph: 212-449-1905 

Fx: 212-449-0546 

daniel_roling@ml.com

William B. Schafer, III, Managing Director 

NexGen Coal Services 

710 Sunshine Canyon 

Boulder, CO 80302 

Ph: 303-417-417-0444 

Fx: 303-417-0443 

bschafer@nexgen-group.com

Debbie Schumacher 

Women in Mining 

915 Mayfair Dr. 

Booneville, IN 47601-2319 

Ph: 812-749-0040 

wolfie66@msn.com

Michael J. Sierra, President & CEO 

The Ventura Group 

8550 Lee Highway, Ste 450 

Fairfax, VA 22031-1515 

Ph: 703-208-3303 

Fx: 703-208-3305 

msierra@theventuragroup.com

Ann E. Smith, Vice President 

Charles River Associates 

1201 F St. NW, Ste 700 

Washington DC 20004 

Ph: 202-662-3872 

Fx: 202-662-3910 

asmith@crai.com

Chester B. Smith, CEO 

The Medford Group 

5250 Galaxie Dr, Ste 8A 

Jackson, MS 39206 

Ph: 601-368-4583 

Fx: 601-368-4541 

chestervision@aol.com

Daniel D. Smith, President 

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 Rd. 

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 

PO Box 15555 

Covington, KY 41015-0555 

Ph: 859-491-5000 

Fx: 859-291-5000 

surber@surber.com

surber@makepeacewithnature.com

Wes M. Taylor, President 

Generation Business Unit 

TXU Energy 

1601 Bryan St., 42nd Fl. 

Dallas, TX 75201-3411 

Ph: 214-812-4699 

Fx: 214-812-4758

wtaylor1@txu.com

Malcolm R. Thomas, Exec. Vice President 

Charah Environmental, Inc. 

Unit M, Suite 100 

307 Townepark Circle 

Louisville, KY 40243 

Ph: 502-245-1353 

Fx: 502-245-7398 

thomasms@bellsouth.net

www.charah.com

Arvin Trujillo, Executive Director 

Division of Natural Resources 

The Navajo Nation 

PO Box 9000 

Window Rock, AZ 86515-9000 

Ph: 928-871-6592/6593 

Fx: 928-871-7040 

dirdnr@email.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

87

Raja P. Upadhyay, President & 

Principal Mine Engineer 

Pincock, Allen & Holt 

274 Union Boulevard, Suite 200 

Lakewood, CO 80228 

Ph: 303-986-6950 

Fx: 303-987-8907 

rpu@pincock.com

Kathy Walker, President 

Elm Street Resources, Inc. 

228 Main St., Suite 209 

P.O. Box 1718 

Paintsville, KY 41240 

Ph: 606-789-4036 ext. 14 

Fx: 606-789-4059 

kwelmst@bellsouth.net

Steve Walker, President 

Walker Machinery 

PO Box 2427 

Charleston, WV 25329 

Ph: 304-949-6400 

swalker@walker-cat.com

John L. Waltman, Vice President 

DM&E Railroad 

140 North Phillips Av, PO Box 1260 

Sioux Falls, SD 57101 

Ph: 605-782-1222 

Fx: 605-782-1299 

Cell: 605-321-8445 

jwaltman@dmerail.com

Kathleen A. Walton 

Soleil Securities 

1230 Avenue of the Americas 

Floor Two 

New York, NY 10020 

Ph: 212-632-5370 

kwalton@soleilgroup.com

Jerome B. Weeden 

Vice President, Generation 

NIPSCO 

801 East 86th Avenue 

Merrillville, IN 46410 

Ph: 219-647-5730 

Fx: 219-647-5533 

jbweeden@nisource.com

Alan W. Wendorf, Exec. Vice President 

Fossil Power Technologies Group 

Sargent & Lundy 

55 E. Monroe St 

Chicago, IL 60603 

Ph: 312-269-6551 

Fx: 312-269-3681 

alan.w.wendorf@sargentlundy.com

James F. Wood, President & CEO 

Babcock Power Inc. 

One Corporate Place 

55 Ferncroft Road, Suite 210 

Danvers, MA 01923 

Ph: 798-777- 

Cell: 303-351-0766 

Fx: 781-993-2499 

powerjim@aol.com

NCC Staff 

Robert A. Beck, Exec Vice President 

robertabeck@natcoal.org

Larry B. Grimes, General Counsel 

larrygrimes@cox.net

Richard A. Hall, CPA 

rhall@natcoal.org

Pamela A. Martin, Executive Assistant 

pmartin@natcoal.org

1730 M St NW, Ste 907 

Washington DC 20036 

Ph: 202-223-1191 

Fx: 202-223-9031 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

88

APPENDIX C 

The National Coal Council

2004 Coal Policy Committee Roster 

(Georgia Nelson, Chair) 

Robert O. Agbede, President & CEO 

ATS Chester Engineers 

639 Alpha Drive 

Pittsburgh, PA 15238 

Ph: 412-967-1900 Ext. 203 

ragbede@atschester.com

James R. Aldrich, State Director 

The Nature Conservancy 

642 West Main Street 

Lexington, KY 40508 

Ph: 606-259-9655 

Fx: 606-259-9678 

jaldrich@tnc.org

Allen B. Alexander, President & CEO 

Savage Companies 

6340 South 3000 East #600 

Salt Lake City, UT 84121 

Ph: 801-944-6600 

Fx: 801-261-8766 

AllenA@SavageCompanies.com

Sy Ali, President 

Clean Energy Consulting Corp. 

7971 Black Oak Drive 

Plainfield, IN 46168 

Ph: 317-839-6617 

Syali1225@aol.com

Barbara Farmer-Altizer, Executive 

Director 

Eastern Coal Council 

P.O. Box 858 

Richlands, VA 24641 

Ph: 276-964-6363 

Fx: 276-964-6342 

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. 

Sr Vice President & CTO 

Energy, Environment & Systems Businesses 

CH2M Hill 

9191 South Jamaica Street 

Englewood, CO 80112 

Ph: 720-286-2436 

Fx: 720-286-9214 

darvizu@ch2m.com

Richard Bajura, Director 

National Research Center for Coal & Energy 

West Virginia University 

P.O. Box 6064, Evansdale Dr. 

Morgantown, WV 26506-6064 

Ph: 304-293-2867 (ext. 5401) 

Fx: 304-293-3749 

bajura@wvu.edu

Janos M. Beer 

Professor of Chemical & Fuel Engineering 

Dept. of Chemical Engineering 

Massachusetts Institute of Technology 

25 Ames St., Bldg. 66-548 

Cambridge, MA 02139 

Ph: 617-253-6661 

Fx: 617-258-5766 

jmbeer@mit.edu

Richard Benson, President 

Caterpillar Global Mining 

300 Hamilton Blvd., Ste. 300 

Peoria, IL 61629-3810 

Ph: 309-675-5127 

Fx: 309-675-4777 

Benson_Richard_a@cat.com

Jacqueline F. Bird, Director 

OH Coal Development Ofc. 

OH Air Quality Development Authority 

50 W. Broad St., Suite 1718 

Columbus, OH 43215 

Ph: 614-466-3465 

Fx: 614-752-9188 

jbird@aqda.state.oh.us

www.ohioairquality.org
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

89

Sandy Blackstone 

Natural Resources Attorney/Economist 

8122 North Sundown Trail 

Parker, CO 80134 

Ph: 303-805-3717 

Fx: 303-805-4342 

sblackstone@ssbg.net

Robert L. Brubaker, Partner 

Porter, Wright, Morris & Arthur 

41 South High St. 

Columbus, OH 43215 

Ph: 614-227-2033 

Fx: 614-227-2100 

rbrubaker@porterwright.com

Michael Carey, President 

Ohio Coal Association 

17 S. High Street, Suite 215 

Columbus, OH 43215-3413 

Ph: 614-228-6336 

Fx: 614-228-6349 

info@ohiocoal.com

www.ohiocoal.com

Henry J. Cialone, Sr. Vice President 

& General Manager/Energy Products 

Battelle Labs 

4606 Burbank Drive 

Columbus, OH 43220 

Ph: 614-457-7948 

cialoneh@battelle.org

William Connors, Esquire 

Centennial Power, Inc. 

400 North 4th Street 

Bismarck, ND 58501 

Ph: 701-222-7965 

Cell: 701-426-2913 

Fx: 701-222-7877 

bill.connors@mduresources

www.centennialenergy.com

www.mduresources.com

Steve Corwell

Sr. Vice President, Corporate Affairs 

Indianapolis Power & Light 

One Monument Circle 

Indianapolis, IN 46204 

Ph: 317-261-8240 

Steve.corwell@aes.com

Kelly A. Cosgrove 

Vice President, Marketing & Sales 

Kennecott Energy Company 

PO Box 3009 

505 South Gillette Avenue 

Gillette, WY 82716 

Ph: 307-687-6053 

Fx: 307-687-6009 

cosgrovk@kenergy.com

Henry A. Courtright, Vice President 

Power Generation & Distributed Resources 

Electric Power Research Institute 

3412 Hillview Ave. 

Palo Alto, CA 94304 

Ph: 650-855-8757 

Fx: 650-855-8500 

hcourtri@epri.com

Joseph W. Craft, III, President 

Alliance Coal 

1717 S. Boulder Ave. 

Tulsa, OK 74119 

Ph: 981-295-7602 

Fx: 981-295-7361 

josephc@arlp.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

Michael D. Durham, President 

ADA Environmental Solutions 

8100 SouthPark Way, Unit B2 

Littleton, CO 80120 

Ph: 303-737-1727 

Fx: 303-734-0330 

miked@adaes.com

John Dwyer, President 

Lignite Energy Council 

1016 E. Owens Ave., Ste. 200 

PO Box 2277 

Bismarck, ND 58502-2277 

Ph: 701-258-7117 

Fx: 701-258-2755 

jdwyer@lignite.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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Richard W. Eimer, Jr., Sr. Vice President 

Dynegy, Inc. 

2828 North Monroe St. 

Decatur, IL 62526 

Ph: 217-876-3932 

Fx: 217-876-3913 

rich_eimer@dynegy.com

Irl F. Engelhardt, Chairman & CEO 

Peabody Energy 

701 Market Street 

St. Louis, MO 63101 

Ph: 314-342-3400 

Fx:

Email: 

Andrea Bear Field, Partner 

Hunton & Williams 

1900 K St., NW, 12th Fl. 

Washington, DC 20036 

Ph: 202-955-1558 

Fx: 202-778-2201 

afield@hunton.com

Lance Fritz, Vice President & 

General Manager/Energy 

Union Pacific Railroad 

1416 Dodge Street 

Omaha, NE 68179 

Ph: 402-271-5678 

Fx: 402-271-3378 

lfritz@up.com

Paul Gatzemeier 

Vice President & General Manager 

Centennial Energy Resources, LLC 

122 East Broadway 

Bismarck, ND 58501 

Ph: 701-222-7985 

Fx: 701-222-7877 

paul.gatzemeier@mduresources.com

Janet Gellici, Executive Director 

American Coal Council 

2890 E. Northern Ave., Ste. B4 

Phoenix, AZ 85028 

Ph: 602-485-4737 

Fx: 602-485-4847 

jgellici@americancoalcouncil.org

www.americancoalcouncil.org

Patrick Graney, President 

Petroleum Products, Inc. 

500 Rivereast Dr. 

Belle, WV 25015 

Ph: 304-926-3000, ext. 113 

Fx: 304-926-3009 

pgraney@petroleumproductsinc.com

Alex E. S. Green 

Graduate Research Professor Emeritus 

University of Florida 

Gainesville, FL 32611-6550 

Ph: 352-392-2001 

Fx: 352-392-2001 (call before sending) 

aesgreen@ufl.edu

John Nils Hanson, President & CEO 

Joy Global, Inc. 

100 E. Wisconsin Ave., Ste. 2780 

Milwaukee, WI 53202 

Ph: 414-319-8500 

Fx: 414-319-8510 

jnha@hii.com

Clark D. Harrison, President 

CQ, Inc. 

160 Quality Ctr. Rd. 

Homer City, PA 15748 

Ph: 724-479-3503 

Fx: 724-479-4181 

clarkh@cq-inc.com

www.cq-inc.com

J. Brett Harvey, President & CEO 

CONSOL Energy, Inc. 

1800 Washington Rd. 

Pittsburgh, PA 15241 

Ph: 412-854-6671 

Fx: 412-854-6613 

brettharvey@consolenergy.com

William Hoback, Bureau Chief 

Office of Coal Development, State of Illinois 

607 East Adams Street, CIPS-4 

Springfield, IL 62701 

Ph: 217-785-2001 

Fx: 217-558-2647 

bill_hoback@commerce.state.il.us
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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Warren J. Hoffman, Esquire 

Frost Brown Todd LLC 

250 W. Main St., Ste. 2700 

Lexington, KY 40507-1749 

Ph: 859-244-3320 

Fx: 859-231-0011 

whoffman@fbtlaw.com

Gerald (Jerry) A. Hollinden 

Vice President, Power Sector Manager 

URS Corporation 

Waterfront Plaza Tower One 

325 W. Main St., Ste. 1200 

Louisville, KY 40202-4251 

Ph: 502-217-1516 

Fx: 502-569-3326 

jerry_hollinden@urscorp.com

Christopher P. Jenkins 

Sr. Vice President, Coal Service Group 

CSX Transportation 

500 Water Street 

Jacksonville, FL 32202 

Ph: 904-366-5693 

Fx: 904-359-3443 

chris_jenkins@csx.com

William Dean Johnson 

Executive Vice President, General 

 Counsel and Secretary 

Progress Energy, Inc. 

411 Fayetteville St. Mall 

Raleigh, NC 27602 

Ph: 919-546-6463 

bill.johnson@pgnmail.com

Judy A. Jones, Commissioner 

Public Utilities Commission of OH 

180 East Broad St. 

Columbus, OH 43215-3793 

Ph: 614-644-8226 

Fx: 614-466-7366 

judy.jones@puc.state.oh.us

www.puc.state.oh.us

Dick Kimbler 

PO Box 186 

Danville, WV 25053 

Ph: 304-369-3347 

James R. Klauser 

Sr. Vice President 

Wisconsin Energy Corporation 

231 West Michigan Street 

Milwaukee, WI 53203 

Ph: 414-221-4740 

Fx: 414-221-3550 

james.klauser@we-energies.com

Thomas G. Kraemer, Group Vice President 

Burlington Northern Santa Fe Railway Co. 

2650 Lou Menk Dr. 

Ft. Worth, TX 76131-2830 

Ph: 817-867-6242 

Fx: 817-352-7940 

thomas.kraemer@bnsf.com

Max L. Lake, President 

Applied Sciences, Inc. 

141 W. Xenia Ave, PO 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 Inc. 

One City Place, Ste. 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 S. Colorado Blvd., Ste. 10 

Denver, CO 80246-8008 

Ph: 303-282-7576 

Fx: 303-282-7584 

ad@qwest.net

John T. Long, Sr. Vice President

Power Generation 

Constellation Energy 

111 Market Place, Suite 200 

Baltimore, MD 21202 

Ph: 410-230-4910 

Fx: 410-230-4669 

john.long@constellation.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

92

Jason Makansi, President 

Pearl Street, Inc. 

801 North Second Street, Suite 403 

St. Louis, MO 63102 

Ph: 314-621-0403 

jmakansi@pearlstreetinc.com

James K. Martin 

Vice President, Business Development 

Dominion Energy 

PO Box 26532 

Richmond, VA 23261 

Ph: 804-819-2176 

Fx: 804-819-2219 

james_k_martin@dom.com

Christopher C. Mathewson 

Dept. 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

Kevin McGowan

(awaiting contact info) 

Michael W. McLanahan, President & CEO 

McLanahan Corporation 

200 Wall Street 

Hollidaysburg, PA 16648-0229 

Ph: 814-695-9807 

Fx: 814-695-6684 

mmclanahan@mclanahan.com

Emmanuel R. Merle, President 

Energy Trading Company 

15 East Putnam Ave., #3210 

Greenwich, CT 06830 

Ph: 203-618-0161 

Fx: 203-618-0454 

thion@mindspring.com

Clifford R. Miercort, President & CEO 

The North American Coal Corporation 

14785 Preston Rd, Ste. 1100 

Dallas, TX 75240-7891 

Ph: 972-448-5402 

Fx: 972-661-9072 

clifford.miercort@nacoal.com

Jeffrey Miller, Managing Editor 

Definitive Solutions Company, Inc. 

8180 Corporate Park Dr., Ste 220 

Cincinnati, OH 45242 

Ph: 513-719-9150 

Cell: 513-678-5456 

Fx: 513-719-9130 

jeff_miller@dsc-online.com

Michael G. Mueller, Vice President 

Ameren Energy Fuels & Services Co. 

PO Box 66149, Mail Code 611 

St. Louis, MO 63166-6149 

Ph: 314-554-4174 

Fx: 314-206-1250 

mmueller@ameren.com

Robert E. Murray, President & CEO 

Murray Energy Corporation 

29325 Chagrin Blvd., Ste. 300 

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 Dr. 

Frederick , MD 21703 

Ph: 301-228-8804 

Fx: 301-694-9043 

rnarula@bechtel.com

Georgia Ricci Nelson, President 

Midwest Generation EME, LLC 

440 S. LaSalle St., Ste. 3500 

Chicago, IL 60605 

Ph: 312-583-6050 

Fx: 312-583-4920 

gnelson@mwgen.com

Mary Eileen O’Keefe, Director 

KFx, Inc. 

1362 North State Parkway 

Chicago, IL 60610 

Ph: 312-482-9701 

Fx: 312-482-9703 

maryeileenokeefe@aol.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

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Umit Ozkan, Associate Dean for Research 

College of Engineering & Professor of Chemical 

Engineering 

Ohio State University 

167 Hitchcock Hall, 2070 Neil Ave. 

Columbus, OH 43210-1275 

Ph: 614-292-6623 (Dept) 

Ph: 614-292-2986 (College) 

Fx: 614-292-9615 

ozkan.1@osu.edu

www.che.eng.ohio-state.edu/facultypages/ozkan.html

Daniel F. Packer, President 

Entergy New Orleans 

PO Box 61000 

New Orleans, LA 70161 

Ph: 504-670-3622 

Fx: 504-670-3605 

dpacker@entergy.com

Thomas Pajonas, Managing Director 

ALSTOM USA 

2000 Day Hill Road 

Windsor, CT 06095 

Ph: 860-285-5035 

Fx: 860-285-5425 

Fredrick D. Palmer, Exec. Vice President 

Peabody Energy 

701 Market St. 

St. Louis, MO 63101-1826 

Ph: 314-342-7624 

Fx: 314-342-7614 

fpalmer@peabodyenergy.com

Earl B. Parsons, III, Vice President-Fuels 

Southern Company 

600 N. 18th St., 14N-8160, PO Box 2641 

Birmingham, AL 35291 

Ph: 205-257-6100 

Fx: 205-257-0334 

eabparso@southernco.com

Craig E. Philip, President & CEO 

Ingram Barge Company 

One Belle Meade Place 4400 Harding Rd 

Nashville, TN 37205-2290 

Ph: 615-298-8200 

Fx: 615-298-8213 

philipc@ingrambarge.com

Robert M. Purgert, President 

Energy Industries of Ohio 

Park Center Plaza, Suite 200 

6100 Oak Tree Blvd. 

Independence OH 44131 

Ph: 216-643-2952 

Fx: 216-643-2901 

purgert@energyinohio.com

William Raney, President 

West Virginia Coal Association 

PO Box 3923 

Charleston, WV 25339 

Ph: 304-342-4153 

Bill Reid, Managing Editor 

Coal News 

106 Tamarack St. 

Bluefield, WV 24701-4573 

Ph: 304-327-6777 

Fx: 304-327-6777 

billreid007@comcast.net

John W. Rich, Jr., President 

Gilberton Coal Company 

Main Street 

Gilberton, PA 17934 

Ph:

Fx:

Email: 

George Richmond, President 

Jim Walter Resources, Inc. 

PO Box 830079 

Birmingham, AL 35283-0079 

Ph: 205-481-6100 

Fx: 205-481-6011 

grichmond@jwrinc.com

James F. Roberts, President & CEO 

Foundation Coal Company 

999 Corporate Blvd, 3rd Fl. 

Linthicum Heights, MD 21090 

Ph: 410-689-7500 (7512) 

Fx: 410-689-7511 

jroberts@rag-american.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

94

Karen Roberts 

Regional Manager, Coal Supply 

Xcel Energy 

PO Box 1261 

Amarillo, TX 79105 

Ph: 806-378-2505 

Fx: 806-378-2790 

karen.roberts@xcelenergy.com

James E. Rogers, Chairman, President, CEO 

Cinergy Corporation 

P.O. Box 960 

Cincinnati, OH 45201 

Ph:

Fx:

Daniel A. Roling, First Vice President 

Merrill Lynch 

Four World Finance Ctr., 19th Fl. 

New York, NY 10080 

Ph: 212-449-1905 

Fx: 212-449-0546 

daniel_roling@ml.com

William B. Schafer, III, Managing Director 

NexGen Coal Services 

710 Sunshine Canyon 

Boulder, CO 80302 

Ph: 303-417-417-0444 

Fx: 303-417-0443 

bschafer@nexgen-group.com

Debbie Schumacher 

Women in Mining 

915 Mayfair Dr. 

Booneville, IN 47601-2319 

Ph: 812-749-0040 

wolfie66@msn.com

Michael J. Sierra, President & CEO 

The Ventura Group 

8550 Lee Highway, Ste 450 

Fairfax, VA 22031-1515 

Ph: 703-208-3303 

Fx: 703-208-3305 

msierra@theventuragroup.com

Ann E. Smith, Vice President 

Charles River Associates 

1201 F St. NW, Ste 700 

Washington DC 20004 

Ph: 202-662-3872 

Fx: 202-662-3910 

asmith@crai.com

Chester B. Smith, CEO 

The Medford Group 

5250 Galaxie Dr, Ste 8A 

Jackson, MS 39206 

Ph: 601-368-4583 

Fx: 601-368-4541 

chestervision@aol.com

Daniel D. Smith, President 

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 Rd. 

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 

PO Box 15555 

Covington, KY 41015-0555 

Ph: 859-491-5000 

Fx: 859-291-5000 

surber@surber.com

surber@makepeacewithnature.com

Wes M. Taylor, President 

Generation Business Unit 

TXU Energy 

1601 Bryan St., 42nd Fl. 

Dallas, TX 75201-3411 

Ph: 214-812-4699 

Fx: 214-812-4758

wtaylor1@txu.com

Malcolm R. Thomas, Exec. Vice President 

Charah Environmental, Inc. 

Unit M, Suite 100 

307 Townepark Circle 

Louisville, KY 40243 

Ph: 502-245-1353 

Fx: 502-245-7398 

thomasms@bellsouth.net

www.charah.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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Arvin Trujillo, Executive Director 

Division of Natural Resources 

The Navajo Nation 

PO Box 9000 

Window Rock, AZ 86515-9000 

Ph: 928-871-6592/6593 

Fx: 928-871-7040 

dirdnr@email.com

Raja P. Upadhyay, President & 

Principal Mine Engineer 

Pincock, Allen & Holt 

274 Union Boulevard, Suite 200 

Lakewood, CO 80228 

Ph: 303-986-6950 

Fx: 303-987-8907 

rpu@pincock.com

Kathy Walker, President 

Elm Street Resources, Inc. 

228 Main St., Suite 209 

P.O. Box 1718 

Paintsville, KY 41240 

Ph: 606-789-4036 ext. 14 

Fx: 606-789-4059 

kwelmst@bellsouth.net

Steve Walker, President 

Walker Machinery 

PO Box 2427 

Charleston, WV 25329 

Ph: 304-949-6400 

swalker@walker-cat.com

John L. Waltman, Vice President 

DM&E Railroad 

140 North Phillips Av, PO Box 1260 

Sioux Falls, SD 57101 

Ph: 605-782-1222 

Fx: 605-782-1299 

Cell: 605-321-8445 

jwaltman@dmerail.com

Kathleen A. Walton 

Soleil Securities 

1230 Avenue of the Americas 

Floor Two 

New York, NY 10020 

Ph: 212-632-5370 

kwalton@soleilgroup.com

Jerome B. Weeden 

Vice President, Generation 

NIPSCO 

801 East 86th Avenue 

Merrillville, IN 46410 

Ph: 219-647-5730 

Fx: 219-647-5533 

jbweeden@nisource.com

Alan W. Wendorf, Exec. Vice President 

Fossil Power Technologies Group 

Sargent & Lundy 

55 E. Monroe St 

Chicago, IL 60603 

Ph: 312-269-6551 

Fx: 312-269-3681 

alan.w.wendorf@sargentlundy.com

James F. Wood, President & CEO 

Babcock Power Inc. 

One Corporate Place 

55 Ferncroft Road, Suite 210 

Danvers, MA 01923 

Ph: 798-777- 

Cell: 303-351-0766 

Fx: 781-993-2499 

powerjim@aol.com

NCC Staff 

Robert A. Beck, Exec Vice President 

robertabeck@natcoal.org

Larry B. Grimes, General Counsel 

larrygrimes@cox.net

Richard A. Hall, CPA 

rhall@natcoal.org

Pamela A. Martin, Executive Assistant 

pmartin@natcoal.org

1730 M St NW, Ste 907 

Washington DC 20036 

Ph: 202-223-1191 

Fx: 202-223-9031 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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APPENDIX D 

The National Coal Council 2004 Study Work Group 

Sy Ali, Clean Energy Consulting Corporation; Ph: 317-839-6617; syali1335@aol.com

Tom Altmeyer, Arch Coal, Inc.; Ph: 202-333-5265; taltmeyer@archcoal.com

Dan Arvizu, CH2M Hill; Ph: 270-286-2436; darvizu@ch2m.com

Eric Balles, Babcock Borsig Power, Inc.; Ph: 508-854-4004; eballes@babcockpower.com

Janos Beer, MIT; ph: 617-253-6661; jmbeer@mit.edu

George Booras, EPRI; ph: 650-855-2471; gbooras@epri.com

Rob Brubaker, Porter, Wright, Morris & Arthur; Ph; 614-227-2033; 

rbrubaker@porterwright.com

Frank Burke, CONSOL R&D; Ph: 412-854-6676; frankburke@consolenergy.com

Fred Bush, Savage Companies; Ph: 801-263-9400; fredb@savagecompanies.com

Hank Courtright, EPRI; Ph: 650-855-8757; hcourtri@epri.com

Stu Dalton, EPRI; Ph: 650-855-2000; sdalton@epri.com

David Denton, Eastman Gasification Services Company; Ph: 423-229-6559; 

dldenton@eastman.com

Bill DePriest, Sargent & Lundy; Ph: 312-269-6678; William.depriest@sargentlundy.com

E Linn Draper, Jr., AEP; Ph: 614-223-1500; eldraper@aep.com

Richard Eimer, Dynegy Marketing & Trade; Ph: 217-876-3932; rich_eimer@dynegy.com

Joel Friedlander, The North American Coal Corporation; joel.friedlander@nacoal.com

Janet Gellici, American Coal Council; Ph: 602-485-4737; jgellici@americancooalcouncil.org

Tom Grahame, DOE; 202-586-7149; Thomas.graham@hq.doe.gov

Mike Gregory, The North American Coal Corporation; Ph: 972-448-5443; 

mike.gregory@nacoal.com
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97

Larry Grimes, The National Coal Council; Ph: 202-223-1191; larrygrimes@cox.net

Jerry Hollinden, URS Corporation; Ph: 502-217-1516; jerry_hollinden@urscorp.com

Neville Holt, EPRI; Ph: 650-855-2503; nholt@epri.com

Klaus Lambeck, Public Utilities Commission of Ohio; ph: 614-644-8244; 

klaus.lambeck@puc.state.oh.us

Steve Jenkins, URS Corporation; Ph: 813-397-7807; steve_Jenkins@urscorp.com

Judy Jones, Public Utilities Commission of Ohio; Ph: 614-644-8226; judy.jones@puc.state.oh.us

Bob Kane, DOE; Ph: 202-586-4753; Robert.kane@hq.doe.gov

Jeff Knitter, WeEnergies; Jeff.knitter@we-energies.com

Ron Litzinger, Edison Mission Energy; Ph: 949-798-7912; rlitzinger@edisonmission.com

John Long, Constellation Energy; Ph: 410-230-4910; john.long@constellation.com

Mike Mudd, AEP; Ph 614-716-1585; mjmudd@aep.com

Ram Narula, Bechtel Power Corporation; Ph: 301-228-8804; rnarula@bechtel.com

Georgia Nelson, Midwest Generation; Ph: 312-583-6015; gnelson@mwgen.com

Fredrick Palmer, Peabody Energy; Ph: 314-342-7624; fpalmer@peabodyenergy.com

Jack Parkes, EPRI; ph: 650-855-2128; jparkes@epri.com

Bob Pearson, CH2M Hill; Ph: 720-286-5056; rpearson@ch2m.com

Robert Purgert, Energy Industries of Ohio; Ph: 216-643-2952; purgert@energyinohio.com

Peter Rigby, Standard & Poor’s; Ph: 212-438-2085; peter_rigby@standardandpoors.com

Lars Scott, Peabody Energy; Ph: 314-342-7594; lscott@peabodyenergy.com

John Vella, Edison Mission Energy; Ph: 949-798-7935; jvella@edisonmission.com

Jerry Weeden, NiSource; Ph: 219-647-5730; jbweeden@nisource.com

Kim Wissman, Public Utilities Commission of Ohio; ph: 614-644-6692; 

kim.wissman@puc.state.oh.us

Mona Yee , Fitch Ratings; ph: 202-908-0557; mona.yee@fitchratings.com
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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APPENDIX E 

Correspondence Between The National Coal Council 

and the U.S. Department of Energy 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

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Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

100

APPENDIX F 

Correspondence from Industry Experts 
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

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Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

102
Opportunities to Expedite the Construction of New Coal-Based Power Plants 

National Coal Council Report 

103

APPENDIX G 

Acknowledgements 

The members of the Council wish to acknowledge, with sincere thanks, the special assistance received 

from the following persons in connection with various phases of the development of this report: 

Julie Clendenin, Editor

Pam Martin, NCC Staff