EPA-600/R-02/073 

October 2002 

Final Report

ENGINEERING AND

ECONOMIC FACTORS

AFFECTING THE

INSTALLATION OF CONTROL

TECHNOLOGIES FOR

MULTIPOLLUTANT 

STRATEGIES

The information presented here reflects EPA's modeling of the Clear Skies Act of 2002. The Agency is in the 

process of updating this information to reflect modifications included in the Clear Skies Act of 2003. The 

revised information will be posted on the Agency's Clear Skies Web site (www.epa.gov/clearskies) as soon 

as possible.
clobtloa

The U. S. Environmental Protection Agency is charged by Congress with protecting the Nation's 

land, air, and water resources. Under a mandate of national environmental laws, the Agency 

strives to formulate and implement actions leading to a compatible balance between human 

activities and the ability of natural systems to support and nurture life. To meet this mandate, 

EPA's research program is providing data and technical support for solving environmental 

problems today and building a science knowledge base necessary to manage our ecological 

resources wisely, understand how pollutants affect our health, and prevent or reduce 

environmental risks in the future. 

The National Risk Management Research Laboratory is the Agency's center for investigation of 

technological and management approaches for reducing risks from threats to human health and 

the environment. The focus of the Laboratory's research program is on methods for the 

prevention and control of pollution to air, land, water, and subsurface resources, protection of 

water quality in public water systems; remediation of contaminated sites and groundwater; and 

prevention and control of indoor air pollution. The goal of this research effort is to catalyze 

development and implementation of innovative, cost-effective environmental technologies; 

develop scientific and engineering information needed by EPA to support regulatory and policy 

decisions; and provide technical support and information transfer to ensure effective 

implementation of environmental regulations and strategies. 

This publication has been produced as part of the Laboratory's strategic long-term research plan. 

It is published and made available by EPA's Office of Research and Development to assist the 

user community and to link researchers with their clients. 

E. Timothy Oppelt, Director

National Risk Management Research Laboratory

EPA REVIEW NOTICE 

This report has been peer and administratively reviewed by the U.S. Environmental 

Protection Agency, and approved for publication. Mention of trade names or 

commercial products does not constitute endorsement or recommendation for use. 

This document is available to the public through the National Technical Information 

Service, Springfield, Virginia 22161. 

ii 
EPA-600/R-02/073 

October 2002 

Engineering and Economic Factors Affecting the 

Installation of Control Technologies for 

Multipollutant Strategies 

Prepared by:

ARCADIS Geraghty & Miller

4915 Prospectus Drive, Suite F

Durham, NC 27713

EPA Contract No. 68-C-99-201

Work Assignment 3-034

U.S. EPA Project Officer: Ravi K. Srivastava

National Risk Management Laboratory

Research Triangle Park, NC 27711

Prepared for:

U.S. Environmental Protection Agency

Office of Research and Development

Washington, DC 20460

iii 
^ÅâåçïäÉÇÖÉãÉåíë

ARCADIS would like to acknowledge the many contributors to this document, without whose 

efforts this report would not be complete. In particular, we wish to acknowledge the advice of 

Chad Whiteman of Clean Air Markets Division, Office of Air and Radiation, U.S. Environmental 

Protection Agency. Helpful suggestions were received from Kevin Culligan and Mary Jo 

Krolewski, both of Clean Air Markets Division. Technical guidance was received from Dr. Ravi 

Srivastava of the National Risk Management Research Laboratory, Office of Research and 

Development, U.S. Environmental Protection Agency. 

ARCADIS would also like to acknowledge other organizations, which provided research that was 

incorporated into the report. These organizations include ESI International and Andover 

Technology Partners. 

iv 
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This report evaluates the engineering and economic factors of installing air pollution control 

technologies to meet the requirements of multipollutant control strategies. The implementation 

timing and reduction stringency of such strategies affect the quantity of resources required to 

complete the control technology installations and the ability of markets to adjust and to provide 

more resources where needed. Using the Integrated Planning Model (IPM), the U.S. 

Environmental Protection Agency (EPA) estimated the number and size of facilities that need to 

install new emissions control equipment to meet the implementation dates and emission 

reductions set forth in the Clear Skies Act. 

This study provides an estimate of the resources required for the installation of control 

technologies to obtain emission reductions of sulfur dioxide (SO2), nitrogen oxides (NOx), and 

mercury under the Clear Skies Act. More innovative control technologies and compliance 

alternatives requiring fewer resources than those considered for this study are likely to be 

developed with the implementation of the Clear Skies Act. Market based approaches reward 

firms for finding cost-effective measures that exceed emission reduction targets. For example, 

improved scrubber performance and the ability of some firms to switch to lower sulfur fuels 

under the Acid Rain Program were reasons the cost of that program were less than projected. 

The development of control technology alternatives to selective catalytic reduction (SCR) under 

the NOX State Implementation Plan (SIP) Call is another example of how alternative solutions 

may require fewer resources than the projected approach. In addition to innovative technologies, 

the time allowed for installation of significant numbers of control technologies is an important 

factor to consider, especially for the near future. While it is expected that markets for the 

materials and labor used in the construction and operation of the control technologies will 

respond to increased demand, this response will not be instantaneous. It is likely that the 

strength of this market response will increase as time progresses. It is expected that the market 

would have sufficient time to respond to phase II of the program as the more stringent emission 

targets for phase II are set for 2018. Even though this analysis looks at the resource availability 

beyond 2010, these projections are of limited value as they do not take into account this market 

response. However, it is projected that there are sufficient resources available to complete the 

projected control technology installations for phase I by 2010. It should also be noted that 

decreasing the amount of time provided to install control technologies to meet a given strategy 

has the potential to affect the cost of compliance as this will accelerate their installation. 

The control technologies considered by this report as candidates to be used for multipollutant 

control strategies include: limestone forced oxidation (LSFO) flue gas desulfurization (FGD) for 

the control of SO2, SCR for the control of NOX, and activated carbon injection (ACI) for the 

control of mercury. 

Installation of LSFO presents a conservatively high estimate of anticipated resources and time to 

provide additional control of SO2 emission, since LSFO systems commonly are more resource 

intensive than many other FGD technologies. Conservatively high assumptions were made for 

the time, labor, reagents, and steel needed to install FGD systems. For LSFO installation timing, 

it is expected that one system requires about 27 months of total effort for planning, engineering, 

installation, and startup, with connections occurring during normally scheduled outages. 

Multiple retrofits at one plant would take longer to install (e.g., approximately 36 months for the 

v 
retrofit of three absorbers for six boilers). Limestone is the reagent used in LSFO to remove SO2 

from the flue gas stream. Steel is the major hardware component for FGD systems and is used 

primarily for the absorber, ductwork, and supports. 

Other elements of FGD installations, such as construction equipment requirements, are typically 

modest, particularly given that systems are installed at the back end of the facility and close to 

the ground. More recently, improvements in technology have been implemented where space 

requirements were an issue for construction and accommodating the FGD system, including 

fewer and smaller absorbers and more efficient on-site use and treatment of wastes and 

byproducts. 

SCR is currently the predominant technology to be used for NOX control and is also the most 

demanding in terms of resources and time to install when compared to other NOx control 

technologies. It is expected that one SCR system requires about 21 months of total effort for 

planning, engineering, installation, and startup. Multiple SCR systems at one facility would take 

longer to install (e.g., approximately 35 months for seven SCRs). Ammonia and urea are the 

reagents used along with a catalyst to remove NOX from the flue gas stream. Experience in 

installing SCRs for the NOX SIP Call has shown that the SCR equipment can be installed on the 

facilities in the space provided. In some cases, some moving of equipment has been necessary. 

One of the primary pieces of specialized construction equipment that can be useful for SCR 

installations are tall, heavy-lift cranes, and these appear to be in adequate supply. 

ACI was presumed to be the technology that would be used to reduce mercury where dedicated 

mercury controls were needed. Planning, engineering, installation, and start up of one ACI 

system is only about 15 months. Multiple ACI systems at any one facility are assumed to take 

longer to install (e.g., approximately 16 months for two ACI). ACI hardware is comprised of 

relatively common mechanical components and is largely made of steel. An ACI system requires 

much less in terms of steel, labor, or other resources to install than either FGD or SCR 

technology. Therefore, the impact of ACI hardware on resource demand is much less than that of 

FGD or SCR technologies for SO2 or NOX control, respectively. 

The resources required for the installation of control technologies to achieve the emission 

reductions under the Clear Skies Act were estimated and compared to their current market 

availability. For the Clear Skies Act, control technology installations have been looked at for the 

periods between now and 2005, 2005 and 2010, 2010 and 2015, and 2015 and 2020. For the first 

period, it is assumed that all controls need to be installed in a 31-month period. This will provide 

a conservatively high estimate of the required resources because many of the necessary control 

installations have already begun. For the other five year-periods, it is conservatively estimated 

that all installations will be completed within three years. However, the estimates indicate that 

there is ample steel and general construction labor to support the installation of these 

technologies over these time periods. As noted above, projections beyond 2010 are of limited 

value as market conditions could change significantly between now and 2010 in response both to 

demand for resources for a multipollutant program and because of other market factors. Skilled 

labor requirements, specifically for boilermakers, were estimated and have the potential to be the 

more limiting resource requirement in phase I of the program. The demand for boilermaker labor 

due to the NOX SIP Call over the next few years is likely to be limiting, but through the 

implementation of the Clear Skies Act, additional recruiting and training of new boilermakers 

would create a stronger market for skilled labor, ultimately increasing the supply. 

vi 
With regards to reagents and other consumables, it is projected that there is sufficient supply of 

limestone for additional FGD systems. It is estimated that there is also enough SCR catalyst 

capacity to supply this market. Ammonia and urea supply is also plentiful, although it is 

expected that NOX reduction will cause a moderate increase in U.S. demand. Bolstered by the 

fact that there is currently a worldwide excess capacity problem for suppliers of these globally 

traded commodity chemicals, it is projected that there will be an ample supply of ammonia and 

urea. U.S. demand for activated carbon is expected to slightly increase as a result of the Clear 

Skies Act. Activated carbon is traded on a global basis and there is currently substantial excess 

capacity that can readily provide for this increase in demand. 

vii 
viii
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Acknowledgements .........................................................................................................................iv

Executive Summary..........................................................................................................................v

List of Figures .................................................................................................................................xi

List of Tables................................................................................................................................. xii

List of Acronyms.......................................................................................................................... xiii

Chapter 1 Background ............................................................................................................1

Chapter 2 SO2 Control Technology Retrofits .........................................................................3

2.1 System Hardware................................................................................3

2.2 Reagents..............................................................................................6

2.3 Construction Equipment .....................................................................7

2.4 Installation Time.................................................................................7

2.5 Labor.................................................................................................11

2.6 Space Requirements..........................................................................12

Chapter 3 NOX Control Technology Retrofits ......................................................................15

3.1 System Hardware..............................................................................15

3.2 Catalyst and Reagents.......................................................................18

3.3 Construction Equipment ...................................................................19

3.4 Installation Time...............................................................................20

3.5 Labor.................................................................................................22

3.6 Space Requirements..........................................................................24

Chapter 4 Mercury Control Technology Retrofits................................................................26

4.1 System Hardware..............................................................................26

4.2 Reagent .............................................................................................29

4.3 Construction Equipment ...................................................................30

4.4 Installation Time...............................................................................30

4.5 Labor.................................................................................................32

4.6 Space Requirements..........................................................................34

Chapter 5 Synergies of Combinations of Control Retrofits on a Single Unit.......................35

5.1 SCR and FGD (Scrubber) Installations ............................................35

5.2 Mercury Control Technology and Scrubber Installations.................35

5.3 Mercury Control Technology and SCR Installation .........................36

ix 
Chapter 6 System Resource Availability ..............................................................................37

6.1 System Hardware..............................................................................40

6.2 Labor.................................................................................................41

6.3 Construction Equipment ...................................................................46

6.4 Reagents............................................................................................47

6.5 Creation of Jobs under Clear Skies Act due to Control Technology

Installations.......................................................................................53

Chapter 7 Conclusions ..........................................................................................................54

Chapter 8 References ..........................................................................................................58

Appendix A Implementation Schedules for Control Technology Installations ..................... A-1

x 
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2-1. Gas path for coal-fired boiler with FGD ..................................................................................4

2-2. Major components of Wet FGD ..............................................................................................5

3-1. Gas path for coal-fired boiler with SCR, ESP, and FGD.......................................................15

3-2. SCR installation at 675 MWe AES Somerset Station ............................................................16

3-3. Plate and honeycomb catalyst ................................................................................................17

4-1. Gas path for coal-fired boiler with SCR, ACI, and ESP ........................................................27

4-2. Gas path for coal-fired boiler with SCR, ACI, ESP, and FF..................................................27

4-3. Simplified schematic of ACI system......................................................................................28

6-1. U.S. construction employment and unemployment ...............................................................42

6-2. Boilermaker Demand Under Clear Skies Act (32 GWe of FGD Installations) ......................44

6.3. Boilermaker Demand Under Clear Skies Act (10 GWe of FGD Installations) ......................45

6.4. Cumulative SCR Catalyst Demand Compared To Cumulative Production Capacity............50

6-5. SCR installations on coal-fired plants in Germany................................................................51

xi 
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2-1. Estimated Resources Needed for Single and Multiple FGD Retrofits...................................13

3-1. Estimated Resources Needed for Single and Multiple SCR Retrofits ...................................24

4-1. Estimated Steel Requirement for 500 MWe ACI System.......................................................29

4-2. Estimated AC Injection Rates for a 500 MWe Boiler ............................................................30

4-3. Estimated Man-hours for Supply of an ACI System for a 500 MWe 0.6 % Bituminous

Coal Boiler Coal with ESP (Example 1 from Table 4-4)33...................................................32

4-4. Estimated Performance and Resources Needed for Single ACI Retrofit ...............................33

4-5. Estimated Performance and Resources Needed for Single and Multiple ACI Retrofits........34

6-1. a) FGD Retrofits, b) SCR Retrofits, c) ACI Retrofits............................................................38

6-2. Estimated Steel Required for Multipollutant Initiative ..........................................................40

6-3. Estimated Annual Construction and Boilermaker Labor Required for Clear Skies Act........41

6-4. Estimated Annual Boilermaker Demand Created by the Clear Skies Act .............................46

6-5. Crushed Limestone Sold or Used By U.S. Producers............................................................47

6-6. Estimated FGD Limestone Consumption and U.S. Production .............................................48

6-7. SCR Catalyst Capacity for Coal-fired Boilers .......................................................................48

6-8. Estimated Annual SCR Catalyst Demand Resulting from Clear Skies Act

and NOX SIP Call .................................................................................................................49

6-9. Projected AC Demand Due to Multipollutant Initiative .......................................................52

7-1. Estimated Resources Needed for Installation and Operation of Technologies ......................57

xii 
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AC Activated carbon

ACI Activated carbon injection

CAAA Clean Air Act Amendments

DCS Distributed control system

ESP Electrostatic precipitator

FF Fabric filter

FGD Flue gas desulfurization

GWe Gigawatt (electric)

IPM Integrated Planning Model

LSD Lime spray dryer

LSFO Limestone forced oxidation

MEL Magnesium enhanced lime

MWe Megawatt (electric)

NAAQS National Ambient Air Quality Standards

PJFF Pulsejet fabric filter

PLC Programmable logic controller

SCR Selective catalytic reduction

SIP State Implementation Plan

TVA Tennessee Valley Authority

xiii 
xiv
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In response to continuing concerns about emissions from electric generating units, further reductions of 

emissions of multiple pollutants from electric power sector are being considered. Because the largest 

portion of emission reductions are expected to come from the coal-fired electricity-generating segment of 

the electric power sector, this report considers environmental improvement for coal-fired electricity 

generating power plants. Strategies enabling the control of multiple pollutants (multipollutant control 

strategies) from these plants have recently been receiving increased attention. 

Currently, power plants are required to reduce emissions of nitrogen oxides (NOX) and sulfur dioxide 

(SO2). The revisions of the National Ambient Air Quality Standards (NAAQS) aimed at reducing haze 

may require electric utility sources to adopt additional control measures. In addition, the U.S. 

Environmental Protection Agency (EPA) has determined that the regulation of mercury emissions from 

coal-fired power plants is appropriate and necessary. Concurrently, legislation has been proposed in 

previous and current Congresses that would require simultaneous reductions of multiple emissions, and 

the Administration’s National Energy Policy recommends the establishment of “mandatory reduction 

targets for emissions of three main pollutants: sulfur dioxide, nitrogen oxides, and mercury.” 

The administration’s multipollutant proposal, a far reaching effort to decrease power plant emissions, 

was introduced as the Clear Skies Act in the U.S. House of Representatives on July 26, 2002 and in the 

U.S. Senate on July 28, 2002. This legislation is intended to reduce air pollution from electricity 

generators and improve air quality throughout the country. The Clear Skies Act is designed to decrease 

air pollution by 70 percent through an emission cap-and-trade program, using a proven, market-based 

approach that could save consumers millions of dollars. The Clear Skies Act calls for: 

Ŷ Decreasing SO2 emissions by 73 percent, from current emissions of 11 million tons to a cap of 4.5 

million tons in 2010, and 3 million tons in 2018, 

Ŷ Decreasing NOx emissions by 67 percent, from current emissions of 5 million tons to a cap of 2.1 

million tons in 2008, and to 1.7 million tons in 2018, and 

Ŷ Decreasing mercury emissions by 69 percent by implementing the first-ever national cap on mercury 

emissions. Emissions will be cut from current emissions of 48 tons to a cap of 26 tons in 2010, and 

15 tons in 2018. 

Therefore, it is timely to review the engineering and resource requirements of installing control 

technologies for multipollutant control strategies. 

This report analyzes the resources required for installing and operating retrofit control technologies for 

achieving reductions in multiple pollutants from coal-fired power plants in the United States. It examines 

the control technology’s hardware, reagents, availability of the needed construction equipment, time 

required to implement at plants with single and multiple installation requirements, and the availability of 

labor needed for installation. The control technologies considered in this report include limestone forced 

oxidation (LSFO) wet flue gas desulfurization (FGD), selective catalytic reduction (SCR), and activated 

carbon injection (ACI) for the control of SO2, NOX, and mercury, respectively. 

The report is organized into eight chapters and one appendix. Chapter 1 provides general background 

information on emission control technologies. Chapter 2 analyzes the SO2 control technology resource 

1
requirements by providing information on control technology’s hardware and reagents, the construction 

equipment necessary to install a control technology, time required to implement this control technology 

at plants with single and multiple installation requirements, and the amount of labor needed to install the 

control technology. Chapters 3 and 4 review, in the same fashion, the resource requirements of 

installing NOX and mercury control technology, respectively. Chapter 5 focuses on synergistic 

combinations of control retrofits on a single unit. Chapter 6 examines the availability of resources 

necessary for the installation of SO2, NOX, and mercury control retrofit technologies for the timing and 

emission reductions proposed under the Clear Skies Act. Conclusions are presented in Chapter 7 and 

references in Chapter 8. Appendix A is located at the end of this report. It provides implementation 

schedules for single and multiple control technology installations. 

2
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In this chapter, the resource requirements to retrofit FGD systems to remove SO2 are examined for 

existing coal-fired electric utility boilers. The FGD technology most commonly installed in the U.S. and 

worldwide is LSFO. Material, labor, and construction equipment resource estimates presented in this 

chapter are for LSFO systems and are a conservative estimate compared to less resource intensive 

magnesium enhanced lime (MEL) or lime spray dryer (LSD) technologies. Typically, MEL and LSD 

technologies rely upon increased reactivity of reagents with flue gas and require fewer resources for 

installation. Advances in FGD technology, design, materials, and expertise available for retrofit 

installations made over the last decade form a sharp contrast to earlier retrofit systems. Technology to 

remove SO2 is anticipated to continue along current trends and rely heavily on wet FGD and other 

advanced technologies. This chapter examines the experience and issues for the retrofit installation of 

LSFO technology. 

The chapter focuses on the resources needed for typical or normally constrained wet FGD, specifically 

LSFO, retrofit installations. Wet FGD retrofit technology generally provides a conservatively high 

estimate of most resources. However, it is likely that other SO2 removal technologies, as well as 

upgrades or enhancements to existing FGD systems, will compete in the market under a multipollutant 

strategy. Upgrades to existing FGD systems would include a case-by-case examination of the absorber 

tower, flue gas inlet, absorber gas velocity, reagent preparation, upgrade pumps, and potential changes to 

some internals, the type of reagent, and to the chemical processes to increase performance. Scrubber 

upgrades were not considered in this analysis in order to provide a conservative estimate of the resource 

demand for a multipollutant strategy. This is because upgrades to existing retrofits will generally 

consume fewer resources than full retrofits regardless of the technology. 

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The wet FGD process operates by reacting SO2 in the flue gas with a reagent in an absorber. FGD 

systems are typically positioned after the particulate control device. FGD retrofits are positioned 

downstream, typically at the back end of the facility, and are not intrusive to the boiler. Typical 

configuration is shown in Figure 2-1. At the typical unit, hot corrosive flue gases leaving the particulate 

control device (149– 182 oC) are cooled, or quenched, before entering the main absorber device. 

Quenching cools and saturates the flue gas with absorber slurry. Quenching can occur in a prescrub area 

or more commonly an area integral to the absorber. After quenching, the less corrosive flue gases 

entering the absorber decrease to temperatures of 49 – 66 oC with pH values between 5 and 6.5. Some 

higher efficiency boilers may have increased flue gas velocities and can result in corrosive flue gas “blow 

through” to the absorber. The chemical reactions that occur with the limestone reagent form a corrosive 

environment requiring many of the system components to be corrosion and abrasion resistant. The 

quenching area is typically a highly corrosive environment and the reagent slurries are highly abrasive. 

The handling and processing of the reagent, commonly limestone, is often done onsite, as is the treatment 

of the effluent as waste or processing into a saleable product (e.g., gypsum handling facility). 

3
exhaust 

FGD 

Boiler SCR 

ESP 

Combustion Air 

Coal 

Byproduct/Waste 

Stack 

Disposal 

Figure 2-1. Gas path for coal-fired boiler with FGD. 

The major systems and components of a wet FGD limestone reagent system include:

Reagent Feed

Ŷ Limestone conveying and crushing (e.g., ball mills) equipment

Ŷ Slurry preparation tank and reagent feed equipment

SO2 Removal

Ŷ Absorber tower or reactor (tray optional)

Ŷ Absorber slurry recirculation/reaction tank and optional air sparger (forced oxidation operation)

Ŷ Mist eliminator wash system

Ŷ Slurry bleed

Ŷ Pipes, pumps, and valves

Ŷ Gas reheaters

Flue Gas Handling

Ŷ Ductwork

Ŷ Support steel

Ŷ Fans, blowers, and dampers

Waste/By-Product

Ŷ Dewatering system (settling tanks/vessels, hydrocyclones, and/or vacuum filters)

Ŷ Stacking equipment

Major wet FGD system components are shown in Figure 2-2. The hardware and equipment to support 

wet FGD technology involves five major systems. Two systems are primarily responsible for the direct 

scrubbing and handling of flue gases, and three systems are involved with delivery of reagents, 

processing of wastes (air, solids, and water), and the processing of wastes into saleable by-products. 

Typically, the greatest hardware requirements involve the systems for SO2 removal, primarily the 

absorber vessel, and flue gas handling, particularly ductwork and support steel. Much of the equipment 

for these systems will be unique to the site and project requirements, although the equipment 

4
specifications may be repeated if multiple absorbers are involved. Typically an FGD retrofit can use an 

existing chimney or stack. 

Figure 2-2. Major components of wet FGD. 

The material used in the largest quantity for an FGD retrofit, aside from reagent, is steel. In general, the 

amount of structural steel for a typical FGD retrofit system is equal to or less than the steel requirements 

for a SCR retrofit of the same size.1 The reduced requirement for structural steel is due to the FGD 

absorber usually being self-supporting, weighing less, and being installed closer to the ground. In 

contrast, a typical SCR installation is heavier, elevated, and adjacent to the boiler. The majority of 

structural steel in modern FGD installations is dedicated to ductwork and supports. Other steel may be 

needed to reinforce existing steel at a facility. In addition to structural steel, additional light, or gallery, 

steel may be used in the limestone preparation area and for the processing of waste or byproducts (e.g., 

buildings). Modern FGD systems are more attuned to the corrosive SO2 scrubbing environment and 

therefore increasingly utilize fiberglass, rubber lined steel, and alloys in construction. In addition, 

because of existence of corrosive zones, preference is often given to the use of large-sized sheets that 

minimize welding.2 Large-sized sheets are used to fabricate the absorber vessel, the ductwork, and 

supports. Particularly over the past decade, there has been greater availability of plate steel for FGD 

projects due to the global sourcing of carbon steel. 

5
Total steel requirements for retrofitting a typical 500 mega Watt, electric (MWe) FGD system are in the 

range of 1000 to 1125 tons of steel, or between 2.0 and 2.25 tons of steel per MWe. This range assumes 

approximately 80 percent of the structural steel is for ductwork and supports and 20 percent is required 

for miscellaneous steel such as reagent conveying equipment, buildings, and solids handling systems. An 

assumption of 1125 tons of steel is a conservatively high estimate since 500 MWe FGD retrofit 

installations have been completed with as little as 250 to 375 tons of steel, or 0.5 tons of steel per 

MWe..1,3 Often a single absorber will serve multiple boilers and reduce much of the steel that would be 

required if absorbers had been fed by individual boilers. Currently, the installed maximum single 

absorber capacity in the U.S. is 890 MWe being fed by 2 boilers at Tampa Electric’s Big Bend Station. It 

is likely that two 450 MWe boiler units will use a common single absorber with commensurate reduction 

in required steel from efficiencies gained by common areas. For example, a 900 MWe system is 

estimated to use approximately 2000 tons of steel, or about 2.2 tons of steel per MWe, rather than a 

combined maximum of 2025 tons for a situation in which the boilers required separate absorbers. 

In general, a better understanding of the chemical processes in an FGD system allows designers to 

maximize mass transfer in a minimum amount of space.4 More efficient designs can also reduce the 

amount of steel needed for the absorber and ductwork. Other advanced design factors reduce steel 

requirements, including the virtual elimination of redundant absorbers, the ability to down-size absorbers 

without sacrificing performance (e.g., by increasing flue gas velocity, advanced placement of spray 

nozzles, enhancing limestone characteristics), and material changes including wallpapering with alloys 

and utilizing fiberglass.5 A new generation of wet FGD systems, pioneered in the mid to late 1990’s, 

improved mass transfer, which resulted in the usage of more compact absorbers that are estimated to 

require 50 percent less material, compared to an older generation of wet FGD systems.5 In addition, 

typical MEL absorber units need less steel due to the use of smaller absorbers enabled by shorter 

residence time requirements than for LFSO systems.==In this report, the estimate of typical LFSO FGD 

system hardware requirements provides a conservatively high estimate of installation resources compared 

to other SO2 control technologies. 

The majority of hardware required for FGD systems is commonly available. Storage tanks, nozzles, and 

piping for the reagent storage and delivery system are also common and therefore widely available. The 

major hardware for an FGD system includes the flue gas duct system, limestone storage (including 

loading and conveyer equipment), gypsum dewatering and wastewater treatment, gypsum storage, piping, 

valves, pumps and tanks, electricity supply, controls, instrumentation, pipe bridges and cable channels, 

and foundations and buildings as needed. FGD systems also include hardware such as inlet fans, 

dampers, absorber internals, recirculation pumps, and oxidation blowers that are commonly used in other 

large industries. Because this hardware is used extensively throughout industry, availability should not 

be an issue, except that supply of this type of equipment needs to be integrated into the overall project 

schedule so it does not cause bottlenecks. Early FGD systems were designed with separate quenching, or 

prescrubber, systems to cool the flue gas coming off the particulate control device. Modern systems take 

the hot flue gas directly into the absorber, where quenching occurs. Limestone and gypsum handling also 

includes milling, conveying, and wastewater treatment systems. 

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Wet FGD systems require a continuous feed of reagent to remove SO2. Generally, if pH of scrubbing 

liquor falls below a range of 5.0 to 6.0, additional reagent is required to maintain the reactivity of the 

absorbent. Limestone is the most commonly used reagent, with the quantity of its consumption 

depending primarily on coal sulfur levels. For example, even in the range of 3 percent to 4 percent coal 

6
sulfur levels, a 4 percent sulfur coal can increase consumption by about one-third.6 It is not uncommon 

for modern FGD systems to achieve 97 percent utilization of limestone.7 Generally, higher percent 

utilization equates to higher reactivity of the reagent, and, therefore, less reagent is needed to achieve a 

given level of SO2 removal. The production of gypsum requires a minimum of 92 percent limestone 

utilization. 

A 500 MWe plant uses roughly 25-32 tons per hour of limestone. A coal with 4 percent sulfur, 

conservatively, will require 32 tons*

 of limestone per hour, or 0.064 tons per MWe per hour. This 

estimate is based on an 85 percent load factor, 10,500 Btu/kWh, stoichiometry of 1.1 for limestone, SO2 

removal rate of 95 percent, and a minimum purity of 95 percent for CaCO3. Any enhancement of the 

reagent (i.e., magnesium or buffering agents) will reduce the amount of limestone needed. MEL sorbent 

consumption for a 4 percent sulfur coal is approximately 17-18 tons per hour.6 These estimates are 

conservatively high given that recent FGD systems are operating at near stoichiometric levels8

 and 

additives are commonly used to achieve higher SO2 removal, particularly to enhance the performance of 

existing retrofits. Limestone stoichiometry is the number of moles of Ca added per mole of SO2 

removed. Typically the required stoichiometry of a wet FGD limestone system is in the range of 1.01 to 

1.1, with 1.01 to 1.05 typical for modern wet FGD systems.8 A stoichiometry of 1.03 is typical when the 

FGD process is producing gypsum by-product, while a stoichiometry of 1.05 is needed to produce waste 

suitable for a landfill. Grinding limestone to an ultrafine particle size improves dissolution rate of 

limestone in the slurry and can decrease the size requirement of the reaction tank.8 

OKP `çåëíêìÅíáçå=bèìáéãÉåí

The construction equipment required for typical FGD installations is standard construction equipment – 

welders, excavation equipment, concrete pouring equipment, cranes, etc. Crane requirements for FGD 

technology retrofits are generally site specific, although these requirements are generally less demanding 

than requirements for SCR retrofits. Generally, FGD systems tend to be constructed closer to the ground 

compared to SCR technology retrofits. Lift at a site rarely exceeds 30 meters (100 feet) and 100 tons. 

The use of modular and fabricated absorbers shifts much of the construction off-site, reducing the need 

for specialized cranes and equipment. The usefulness and appropriateness of using cranes in an FGD 

installation is dependent on several factors, including the ability to physically place a crane on site or 

adjacent to the site (e.g., on a barge) and the use of modular construction of major FGD technology 

components. Prefabrication has been used since the early 1990’s, notably on two large retrofit projects: 

the 1300 MWe Zimmer Station and the 2600 MWe Gavin station. Both facilities had limited lay-down 

area to perform the retrofit installation. In these two retrofits, the absorber modules were fabricated in 

two pieces, shipped by barge, and assembled on site. Often modular units can be transported via barges 

or trucks to the site for assembly. Component modularization and prefabrication off-site can reduce the 

amount of time cranes are needed on a site, as well as provide opportunities to reduce project schedules 

and construction costs and to concentrate jobs locally at the prefabrication facility. 

OKQ fåëí~ää~íáçå=qáãÉ

Implementation of an SO2 control technology at a plant involves several activities contingent upon each 

other. These activities may be grouped under the following phases of an implementation project: (1) 

*

 EPA cost modeling for wet scrubber installations estimate 29 tons of limestone required to achieve 95 percent SO2 

removal while burning a 4 percent sulfur coal. 

7
conducting an engineering review of the facility and awarding a procurement contract; (2) obtaining a 

construction permit; (3) installing the control technology; and (4) obtaining an operating permit. 

Modular construction can minimize field labor and construction time on a site by prefabricating at a shop 

and then transporting large sections, such as ductwork or absorber modules, by barge or truck. For 

example, the 550 MWe boiler at Kansas City Power & Light Company’s Hawthorne Generating Station 

required rebuild and NOX, SO2, and PM simultaneous control retrofits. To expedite placing the facility 

back into use, large sections were fabricated off site and transported by barge to the site. Shop 

fabrication has also been used outside of the U.S. For example, ten absorber modules handling a 

combined capacities of 2000 MWe and 3000 MWe at two facilities were installed during December 1995 

(order placed) through March 2000. The ten absorbers were mostly installed sequentially with startup of 

the units staggered over 22 months. The 2000 MWe FGD systems at the Taean facility in South Korea 

were fabricated off-site in three modules, shipped by barge, and then assembled on-site. 

FGD installation plans and experience have been extensive in the U.S. and abroad. To date, there have 

been approximately 94 GWe of scrubber capacity built on coal-fired power plants in the US. Over 200 

GWe of capacity has been built worldwide. 

Exhibits A-1 and A-2 in Appendix A depict the timelines typical to complete a single absorber module 

and a three absorber-module installation of FGD, respectively. The three absorber-module installation 

assumes each absorber module can treat up to 900 MWe of boiler capacity. Currently, approximately 900 

MWe of single absorber capacity has been successfully installed in the U.S. However, greater absorber 

capacities are being offered outside of the U.S.9 While the sum of the time estimated to complete 

individual tasks generally exceeds the overall estimated installation time, the overall installation schedule 

accounts for overlap in these tasks. These timelines also indicate that completion of some of the 

activities is contingent upon completion of some other activities. In general, the FGD implementation 

schedule appears to be driven primarily by the pre-hookup construction activities. Multiple absorber 

installations will typically add a few months to the implementation schedule, particularly to connect 

additional absorbers during scheduled outages. Prefabrication of absorber modules can reduce the overall 

construction schedule. The major phases of the implementation schedule are discussed below. 

båÖáåÉÉêáåÖ=oÉîáÉï

As shown in Exhibits A-1 and A-2 in Appendix A, in the first phase of technology implementation, an 

engineering review and assessment of the combustion unit is conducted to determine the preferred 

compliance alternative. During this phase, the specifications of the control technology are determined, 

and bids are requested from the vendors. After negotiating the bids, a contract for implementing the SO2 

control technology is awarded. The time necessary to complete this phase is approximately four months. 

`çåëíêìÅíáçå=mÉêãáí

Before the actual construction to install the technology can commence, the facility must receive a 

construction permit from the applicable State or local regulatory authority. The construction permit 

process requires that the facility prepare and submit the permit application to the applicable State or local 

regulatory agency. The State or local regulatory agency then reviews the application and issues a draft 

approval. This review and approval process is estimated to take about six months. The draft 

construction permit is then made available for public comment. After any necessary revisions, a final 

construction permit is issued. The estimated time to obtain the construction permit is approximately=nine 

months10 but can vary with State and local permitting procedures as well as other interests in the project. 

8
`çåíêçä=qÉÅÜåçäçÖó=fåëí~ää~íáçå

In the second phase, the control technology is installed. This installation includes designing, fabricating, 

and installing the control technology. In addition, compliance testing of the control technology is 

completed in this phase. Since FGD technology is not invasive to the boiler, most of the construction 

activities, such as earthwork, foundations, process electrical, and control tie-ins to existing items, can 

occur while the boiler is in operation. The time needed to complete this phase of an implementation 

project is about 23 months. 

An important element of the overall control technology implementation is the time needed to connect, or 

hook up, the control technology equipment, particularly in relationship to the planned outage time for the 

unit. On average, it takes about four to seven weeks to connect FGD.1, 3 For example, the Homer City 

and Centralia facility FGD retrofit connections were performed during the scheduled outages in 

approximately five weeks. Based on experience in Germany in response to a compliance directive, a 

significant quantity of SO2 and NOX control installations were performed within outage periods 

consisting of less than four weeks.11 Electricity generating facilities often plan the connection to occur 

during planned outages to avoid additional downtime. Additional downtime leading to loss of a unit’s 

availability to supply electricity is atypical for FGD technology installations.3,12 Because peak electricity 

demand generally occurs during the summer months (May through September), typically control 

connections occur during months of other seasons, notably the spring or fall.10 For example, FGD 

connections to the two Centralia units were performed outside of the peak electricity demand period. 

Sources located where peak demand does not occur during the summer months may be less timeconstrained to connect the FGD controls. However, FGD connections for single and multiple systems 

can typically be performed during planned outage times. Multiple systems normally are installed in 

sequence and overlapping to maintain a high level of activity at the site. Installation of the control device 

hookup on a sequential basis usually involves an overlap of compliance testing of FGD system on one 

unit with hookup of an FGD system with the next unit. The total implementation time for sequential 

hookup for multiple systems is estimated at between 32 months for two absorber modules and 36 months 

for three absorber modules. Although not as common, multiple systems installed at a single facility can 

be performed simultaneously. Generally, scheduled outages will govern which method can be used for 

multiple FGD system installations. 

léÉê~íáåÖ=mÉêãáí

Facilities will also need to modify their Title V operating permit to incorporate the added control devices 

and the associated reduced emission limits. In some States, an interim air-operating permit may need to 

be obtained until the Title V permit is modified. The operating permit modification process consists of 

preparation and submission of the application to the applicable State or local regulatory agency. This 

process can occur simultaneously with the processing of the construction permit application.10 The 

process of transitioning from the construction permit to the operating permit varies among States, but the 

application review process is estimated to take between 9 – 11 months. The Title V operating permit 

must also be made available for public comment. The Title V operating permit is then not made final 

until compliance testing on the control device is completed. Therefore, the total estimated time to 

modify the Title V operating permit is about 17 months, plus the additional time to complete compliance 

testing. 

Based on the estimated time periods needed to complete each of the four phases described above, the 

estimated time period to complete the implementation of a single FGD installation is conservatively 27 

months. For the Clear Skies Act, EPA’s projections reflect that the majority of FGD installations will 

involve a single absorber unit installation per plant; however, the maximum projected number of 

scrubbers retrofitted at any facility is three absorber modules serving six boilers with a maximum of 2400 

9
MWe of boiler capacity. Changes in FGD technology and reliability have resulted in planning for smaller 

and fewer absorbers per retrofit installation. For example, the Zimmer and Gavin station FGD retrofits 

performed in the early 1990’s both involve three absorbers on each 1300 MWe unit. If these retrofits 

were being planned today, these stations’ two 1300 MWe units would likely require only two absorbers 

per unit rather than three.6 

Average FGD installation times have commonly been within 24-27 months. For example, recent FGD 

retrofit systems installed at Homer City (September 2001) and Centralia (July 2001) were both completed 

within approximately 24 months.13 Although these FGD system installations are considered typical, the 

Homer City FGD retrofit installation was performed during the same time frame as the installation of 

three SCR units. Both of these units provide more recent insight into the ability and scheduling to install 

FGD systems during a period of high demand for SCR installations. 

One factor that can increase the time to install a scrubber is competition for resources with other 

emission control projects. During the first time period analyzed (through the end of 2005), EPA projects 

that a large number of SCR’s will be installed to meet the requirements of the NOX SIP Call. However, 

SCR installations designed to comply with the NOX SIP Call are generally already into the installation 

process or, at a minimum, into the engineering phase of the project.13 Furthermore, construction has 

already begun or been completed for 4 GWe of the scrubbers that EPA projects will be built by 2005 

under current regulatory requirements. Typically the overall engineering, fabrication, and construction 

resources would remain the same as the scenario analyzed above, with the exception that these resources 

are reallocated over an extended schedule. One estimate is that, as demand for installation resources 

increase for FGD and other air pollution control installations, planned FGD retrofit installations could be 

between 30 and 42 months1

 while another source estimates FGD installations at 36 months.14 It should 

be noted, however, that some recent contracts have been signed to install scrubbers between now and 

2005 that would be installed in less than 36 months. For instance, a contract to install a scrubber on a 

500 MWe unit at the Coleman Station in Kentucky is scheduled to be completed in early 2004 

(approximately 24 months after the contract was announced, which is several months shorter than the 

installation schedule set forth in Exhibit A-1). This suggests that labor demands to install SCR’s for the 

NOX SIP Call may not lead to increased installation time for scrubbers. 

Single-unit FGD installations have occurred in as little as 20-21 months9

, and multiple FGD systems have 

been installed within 36 months. In addition, owners of new, or “greenfield,” power generation facilities 

often request 24 months for completion of these projects, including installation of the boiler, FGD 

system, and SCR. Primarily as a cost cutting option, more relaxed installation schedules of up to 36 

months for a single FGD retrofit installation may be planned, but are not common. Despite changes in 

overall installation schedules, efficient utilization of labor and sequencing the installation during planned 

outages will continue to be planning issues. In summary, the total time needed to complete the design, 

installation, and testing at a typical 500 MWe facility with one FGD unit is 27 months, 32 months at a 

facility with two boilers being served by a single absorber module, and approximately 36 months at a 

facility with three absorber modules (six boiler units). For the multiple installation of three absorber 

modules at one plant (six boiler units), an additional four months may be needed to schedule the outage 

for the FGD hookup outside of the high electricity demand months. Typically, multiple absorbers will be 

installed sequentially with some overlap to conserve and schedule continuous use of labor, as well as 

keep associated installation costs down. 

10
OKR i~Äçê

The installation of an FGD system requires a significant amount of labor. Approximately 80 percent of 

the labor is for construction of the system, and 20 - 25 percent of the labor is for engineering and project 

management. The installation of the FGD control technologies may require the following types of labor: 

Ŷ general construction workers for site preparation and storage facility installation; 

Ŷ skilled metal workers for specialized hardware and/or other material assembly and construction; 

Ŷ other skilled workers such as electricians, pipe fitters, millwrights, painters, and truck drivers; and 

Ŷ unskilled labor to assist with hauling of materials and cleanup. 

A typical turnkey 500 MWe unit FGD system retrofit requires 380,000=man-hours, or approximately 200 

person-years, of which 20 percent, or 72,000 man-hours, are dedicated to engineering and project 

management,3

 and roughly 40 percent of man-hours are for boilermakers.14 The labor required to install 

an absorber vessel and ductwork is a major portion of the system installation man-hours. Generally, 

construction labor is proportional to the amount of steel used in the system. The greatest labor 

requirement occurs for FGD on a single unit (i.e., 500 MWe), and additional efficiencies in incremental 

labor occur when scheduling multiple units at one facility, particularly when combining multiple boilers 

into a single absorber. In general, large numbers of boilermakers have been used in this industry; 

however, it is not expected that this demand will impact other industries. A more thorough discussion of 

boilermaker labor demand is given in Chapter 6. 

There are some efficiencies that result when multiple systems are installed at one site. In engineering 

alone, there is a 10-15 percent savings in engineering and project management labor commonly realized 

when installing multiple units of similar design. In addition, other increases in project management and 

labor productivity and efficiencies in using resources and equipment can occur with multiple system 

installations on one site. While multiple systems on one site are common, the number of required systems 

to serve large MWe of capacity has been decreasing. For example, in the past FGD systems for 2,600 

MWe stations included six absorbers; however, today these systems would likely be designed for four 

absorber systems, or approximately 650 MWe of boiler capacity per absorber.6 Using the methodology 

described for 900 MWe of capacity, today a six-absorber system could serve as much as 5,400 MWe of 

capacity, or more than double the capacity served in installations in the early 1990’s. 

A reasonable estimate of multiple FGD installations at one site includes 380,000 man-hours for the initial 

500 MWe of capacity (or 760 man-hours/MWe) and an additional 500 man-hours per MWe, up to a total 

of 900 MWe, for any combination into a single common absorber. Therefore, a 900 MWe system 

requires the initial 500 MWe at 380,000 man-hours, and the second 400 MWe at about 273,200, for a 

combined labor requirement of 653,200 man-hours, or approximately 300 person-years, or the equivalent 

of about 725 man-hours per MWe. As another example, a 1400 MWe system retrofit using 2 (700 MWe) 

turnkey systems requires 700,000 man-hours, or only 500 man-hours per MWe.

6 Generally, extending 

FGD installation schedules may reduce the number of persons on a job at one time but will not reduce the 

overall labor requirement. 

While, it is likely that installation of multiple systems will benefit from economies of scale to reduce 

labor requirements, the range for man-hours per MWe for multiple systems is bounded by 500 and 725 

man-hours per MWe. It is also clear that boiler capacities of at least 900 MWe can be served by a 

common absorber, and a minimum 10 percent reduction in engineering and project management labor 

will result from multiple absorbers being installed at a single site. For example, procurement contracts 

only need to be negotiated once, and common site issues need only be addressed once. Therefore, 

11
653,200 man-hours is a conservative estimate of labor required to install FGD at a 900 MWe facility. 

Because no additional efficiencies in engineering and project management are assumed for larger 

installations, multiple 900 MWe absorber systems each add another 653,200 man-hours. A 2,700 MWe 

facility requires approximately 1,960,000 man-hours for the retrofit installation. This produces a 

conservatively high estimate bounding the uncertainties of labor and how many boilers or units will be 

combined into a single absorber. 

The above estimates of labor are conservative particularly given efficiencies realized in recent retrofit 

installations. In many cases, portions of retrofit construction can be performed off-site, particularly with 

modular designs. For example, at the Gavin scrubber retrofit installation the absorber modules were 

fabricated at the vendor’s shop and then shipped by barge to the site for hookup. To take advantage of 

off-site fabrication requires that a shop and facility are available and collocated with an adequate 

shipping and transport facilities (i.e. water accessible facility and a barge). When the requirements are 

met the fabrication has the potential to employ and retain a skilled work force as well as opportunity to 

save time and reduce field labor requirements. 

Based upon the discussion from sections 2.1 through 2.5, the total resources needed for a single 500 

MWe FGD retrofit and multiple FGD retrofits are shown in Table 2-1. 

OKS pé~ÅÉ=oÉèìáêÉãÉåíë

Generally 1-acre on-site will allow the installation of an FGD retrofit.1 The need for additional space for 

support systems ranges from no additional space needed to 2.5 acres typical for up-front reagent 

processing and 1 acre for dewatering when reagent processing and dewatering operations are selected as 

part of the FGD system design. Space issues also include the positioning of the FGD after the particulate 

control device and before the stack. This area of the power unit is generally referred to as the “back end” 

– an area where there is typically ample space for retrofit installations. 

The FGD retrofit on the Cinergy’s Gibson Unit 4 is an example of an extremely space limited retrofit.1 

Gibson Unit 4 is a 668 MWe inhibited oxidation limestone FGD retrofit designed for 92 percent SO2 

removal and completed in late 1994. In the case of this scrubber retrofit, the congestion at the site did 

not allow for a clean pick by a standard sized crane. With up-front planning, one module was raised by 

less conventional means (jacking construction), allowing for the second module to be constructed using 

more conventional methods. Because of the difficulty due to congestion of the site, this retrofit required 

additional time and labor, but worked within space constraints. This method of jacking construction has 

been used in other retrofits. The wet FGD retrofit at the Bailly Generating Station, Units 7 & 8, is an 

example where a full service system (single limestone absorber for combined 528 MWe capacity, 2-4.5 

percent sulfur coal, >95 percent SO2 removal) was able to significantly reduce space requirements while 

also decreasing cost by about one-half and creating no new waste streams. Much of the success of this 

public/private project (DOE/operator and vendors) was due to a more compact and multi-functional (prequenching, absorption, and oxidation) absorber vessel that used a co-current flow design. As a result, the 

FGD system required only modest space requirements.15 In most locations connection space is not a 

problem since there is usually adequate space behind the flue gas stack to perform the scrubber retrofit. If 

connection space is limited, additional ductwork may be necessary. 

12
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Often absorbers can be designed to accommodate site-specific requirements. Smaller absorbers, use of 

common absorbers for multiple boilers, and technology advances that supplant the need for redundant 

absorbers, have decreased the footprint needed for a modern FGD retrofit installation. Where space for 

the FGD installation is an issue, reducing the overall absorber size can be accomplished by using 

multiple absorber trays (within one absorber) and improving mass transfer with the use of a fan.16 

Improved absorption at higher velocities has contributed to smaller, more compact absorbers. For 

example, designers are continually improving absorber efficiencies by increasing absorber gas velocities 

in the range of 5 m/s (15 feet/s) and greater. Velocities of 6.1 m/s (20 feet/s) have been demonstrated.8 

By contrast, earlier systems’ design capacities were based on absorber flue gas velocities of 3 m/s (10 

13
feet/s). In addition to smaller absorbers, single absorbers commonly serve multiple boilers, reducing the 

overall footprint of the FGD retrofit. To date, a single absorber has been successfully installed to serve 

up to 900 MWe of capacity in the U.S. while even larger absorber modules (i.e. 1000 MWe and greater) 

are now being offered for purchase overseas. 

Space for an FGD installation may also include areas for reagent processing and treatment of the waste or 

byproduct. Complete limestone processing (delivery, crushing, slurry preparation, reagent feed 

equipment, etc.) requires as much as 2 to 3 acres; however, this space is a one-time requirement and does 

not increase with increasing FGD capacity being served. Conservatively, when on-site reagent 

processing is selected, an additional 2.5 acres for an entire facility will be sufficient. While limestone 

processing can be performed at the facility, purchased powdered limestone is an option that also reduces 

or eliminates the requirement for on-site reagent preparation and other equipment, as well as the space 

these processes would occupy. Ultra-fine limestone has been demonstrated as an optional enhancement 

over typical limestone reagent feed.17 In areas where the ability to deliver limestone on a continuous 

basis during winter months may be limited, storage of limestone may be needed. For example, a 30-day 

supply of limestone to feed a 500 MWe FGD system (95 percent control efficiency, 85 percent capacity, 

4 percent sulfur coal) will require approximately 40 by 40 m (120 by 120 foot) storage area to handle 

approximately 23,000 tons of limestone. 

Traditionally, FGD systems have produced a solid waste product that can be sent to a landfill, or an 

increasingly attractive alternative is to treat the byproduct for the manufacture and sale of gypsum. If 

dewatering is required, typically 1-acre will be needed for an entire facility regardless of the amount of 

FGD capacity being served. One approach to improving sorbent utilization is recycling the spent sorbent 

for multiple exposure to the SO2 in the flue gas. The result is less unreacted sorbent and smaller 

quantities of end product.18 Improved performance and alternative reagents are becoming common. By 

the mid-1990’s, at least one FGD vendor was supplying a system that took advantage of a water 

treatment system’s precipitated calcium and magnesium carbonates that produced a high quality, fine 

calcium and magnesium carbonate FGD reagent. In addition to reducing the facility’s dependence on 

limestone, this process also reduced equipment required for limestone handling and milling.4 

More efficient use of water in modern systems has almost completely removed the need for dewatering 

and containment ponds. Typically, purge streams are used if the wastewater contains high levels of 

chlorides. However, usually water is either evaporated from the system or remains in the by-product or 

waste. Techniques for wastewater minimization or elimination are commonly available. For example, 

many FGD systems repeatedly cycle the cooling tower blow-down before being treated in the wastewater 

system. As a result, the wastewater has a high solids content as well as high alkalinity for improved 

performance. Since large amounts of water are evaporated during this cycling, this method also benefits 

from reduced effluent that requires treatment by a wastewater system.16 

While water treatment of FGD effluent was once a concern, contemporary FGD systems are much more 

effective in limiting production of waste water and can achieve zero, or near-zero, wastewater discharge.9 

Many of the wastewater advances being used outside of the U.S., including conserving blowdown in the 

absorber vessel primarily for chloride control, are now being used or considered in the U.S. For 

example, the 446 MWe Hunter Unit 3 (operated by PacifiCorp) installed a wet FGD limestone reagent 

system in 1983; and, by use of mechanical draft cooling towers, the plant is zero-discharge for waste 

water. The FGD system operates at 0.12 lb SO2/MMBtu and is designed for 90 percent SO2 removal. An 

additional example of zero wastewater discharge is the 446 MWe Craig Units 1 & 2 (installed 1980) that 

are designed for 85 percent SO2 removal and also employ limestone reagent and mechanical draft cooling 

towers. 

14
`Ü~éíÉê=P 

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In this chapter, retrofit of SCR will be assessed for coal-fired electric utility boilers that would be 

affected by a multipollutant regulation. SCR is the NOX control technology that is expected to have the 

greatest impact on future utility boiler NOX emissions and is the most difficult NOX control technology to 

install. It is, therefore, the most important NOX control technology to understand from both a NOX 

reduction and resource requirement perspective. 

PKN póëíÉã=e~êÇï~êÉ

The SCR process operates by reacting ammonia with NOX in the exhaust gas in the presence of a catalyst 

at temperatures of around 315 to 370 oC. For most applications, this temperature range makes it 

necessary to locate the SCR reactor adjacent to the boiler – immediately after the boiler and before the 

air preheater as shown in Figure 3-1. An infrequently used alternative approach is to locate the SCR 

after the FGD. This approach, however, increases operating costs, as it requires additional heating of the 

gas. By locating the SCR reactor as in Figure 3-1, it is often necessary to install the catalyst reactor in an 

elevated location, which may result in a structure hundreds of feet tall. Figure 3-2 shows the 

configuration of the SCR that was retrofit onto AES Somerset Station, a 675 MWe boiler already 

equipped with an electrostatic precipitator (ESP) and wet FGD system. In this common installation, the 

SCR reactor is installed on structural steel that elevates it above existing ductwork and the ESP 

(designated “precipitator” in the Figure 3-2). In the lower right corner of Figure 3-2, an image of a person 

provides a perspective of the size of the SCR installation. 

Boiler SCR 

Air Preheater 

ESP 

FGD 

Stack 

exhaust 

Combustion Air 

Coal 

Figure 3-1. Gas path for coal-fired boiler with SCR, ESP, and FGD. 

15
Figure 3-2. SCR installation at 675 MWe AES Somerset Station.19 

The SCR system reduces NOX through a reaction of ammonia and NOX in the presence of oxygen and a

catalyst at temperatures around 315 to 370 °C (600 to 700 oF). The products of this reaction are water

vapor and nitrogen. The catalyst is mounted inside an expanded section of ductwork and is configured

for the gas to pass through it as in Figure 3-2.

The major components of an SCR system include:

Ŷ Ammonia or urea storage

Ŷ Ammonia vaporization system (if aqueous ammonia is used)

Ŷ Urea to ammonia converter (if urea is used)

Ŷ Ammonia or urea metering and controls

Ŷ Dilution air blowers

Ŷ Ammonia injection grid

Ŷ Catalyst

Ŷ Catalyst reactor, ductwork and support steel

Ŷ Catalyst cleaning devices (soot blowers, sonic horns, etc)

Ŷ Instrumentation

16
Except for the catalyst, most of the material/equipment used to assemble an SCR system is either 

standard mechanical and electrical components (pumps, blowers, valves, piping, heaters, pressure 

vessels, temperature and pressure sensors, etc.) or is largely manufactured for other power plant 

applications and has been adopted for use in SCR systems (cleaning devices such as soot blowers or 

sonic horns, gas analyzers, etc.). The catalyst, however, is a specialized product designed specifically for 

this purpose. 

The catalyst is typically a ceramic material that, in most cases, is either extruded into a ceramic 

honeycomb structure or is coated onto plates, as shown in Figure 3-3. The catalyst is assembled into 

modules at the factory. The modules are shipped to the site and installed into the SCR reactor in layers. 

Each layer of catalyst is comprised of several individual modules that are installed side-by-side. 

Figure 3-3. Plate and honeycomb catalyst.20 

The material used in the largest quantity, aside from a catalyst or reagent, is steel. The amount of steel 

required for an SCR in the range of 300-500 MWe is about 800 to 1200 tons,20 or about 2.4 to 2.6 tons per 

MWe. About 4,000 tons of steel is necessary for retrofit of two 900 MWe units (1,800 MWe total),20 or 

about 2.2 tons per MWe. The steel used for an SCR includes large structural members, plates, and sheets. 

These steel pieces are used to fabricate the catalyst reactor, the ductwork, and the support steel. There is 

typically less of a requirement for corrosive resistant alloys for an SCR installation when compared to a 

scrubber installation. Steel is also needed for boiler modifications. In this case, large pieces of steam 

piping or other large steel boiler components may need to be replaced. The catalyst reactor is often 

fabricated on-site. Sections of the catalyst reactor and ductwork may be fabricated off-site and shipped 

in pieces to the site for final assembly, or they may be fabricated on-site into subassemblies and lifted 

into place during erection. 

If more than one boiler at a facility is to be retrofit with SCR, then some, but not all, equipment can be 

made common. For example, it may be possible, and is probably preferable, to have a common ammonia 

17
or urea storage facility. Reagent storage is probably the only major equipment item that lends itself to 

sharing between adjacent boilers. Therefore, there is some gained efficiency in the use of equipment at a 

site with multiple units. However, this gain in efficiency is generally small compared to the total project. 

The major synergy will be in construction equipment and in labor, as will be discussed in Sections 3.3 

and 3.5, respectively. 

PKO `~í~äóëí=~åÇ=oÉ~ÖÉåíë

An SCR system requires an initial and ongoing supply of catalyst. It also requires reagent. The reagent 

can be ammonia or urea. Most facilities to date have used ammonia; however, urea is becoming an 

increasingly popular reagent due to its inherent safety and the recent availability of systems to convert 

urea to ammonia on-site. 

`~í~äóëí

The amount of catalyst required for an SCR system is directly proportional to the capacity (or gas 

flowrate) of the facility, if all other variables are equal. The actual amount of catalyst for any specific 

plant depends upon several parameters; in particular, the amount per MWe (measured in m3

 per MWe) for 

a given level of reduction and lifetime will fall within a general range. Therefore, it is possible to make 

an estimate of how much catalyst would be necessary to retrofit a particular facility or a large number of 

facilities if the total capacity is known. It is assumed that most SCR systems to be retrofit onto electric 

utility boilers will be designed for about 90 percent reduction. For most boilers, this level of reduction 

may initially require about 0.90 to 1.3 m3

 of catalyst for each MWe of coal-fired boiler capacity.18,21,22 

For example, a 500 MWe plant would be expected to have about 450 to 650 m3 of catalyst. The amount 

of catalyst for a particular situation will vary somewhat depending on the catalyst supplier and the 

difficulty of the application. At the 675 MWe AES Somerset Boiler, 90 percent NOX reduction was 

achieved with SCR using 897 m3

 of plate catalyst,19 or about 1.33 m3 per MWe. This unit fires 2.5 

percent sulfur coal. At each of the 745 and 755 MWe Montour Units 1&2, 671 m3

 of ceramic catalyst 

were used,22 or about 0.89 m3

 per MWe. This unit fires 1.5 percent sulfur coal that can have arsenic 

levels as high as 100 ppm (limestone injection is used to reduce gaseous arsenic concentration in the 

furnace). The amount of catalyst will tend to be lower in situations that are less challenging, such as with 

lower sulfur coals or situations expected to have lower gaseous arsenic concentration (gaseous arsenic is a 

catalyst poison that originates in the coal; it will reduce the lifetime of the SCR catalyst). Hence, less 

than 0.90 m3

 per MWe may be sufficient in some cases. 

The catalyst is typically loaded in three or more layers. This permits replacement of sections of the 

catalyst as activity is reduced. The advantage of this approach is that it permits lower overall catalyst 

usage over the economic lifetime of the plant. Normally, room for an extra layer is provided, so a fourth 

layer can be added, if necessary. At the first catalyst addition (typically, after about 24,000 operating 

hours), the fourth layer will be filled or half filled. Once the SCR reactor is full, layers of catalyst are 

replaced after catalyst activity drops to a minimum level. At the first catalyst replacement, new catalyst 

will replace the original first layer; at the next catalyst replacement, new catalyst will replace the original 

second layer, and so on. EPA modeling projections conservatively assumed that one layer of catalyst is 

replaced for every 15,000 – 20,000 hours of operation for coal-fired units. Therefore, after the initial 

installation, there is a need to replace roughly one fourth of the total catalyst reactor volume every 24- 32 

months or so – or conservatively about 1

/8 of the installed volume should be replaced each year for the 

coal-fired installations. 

18
The catalyst may also be regenerated rather than replaced.23 This will reduce the amount of new catalyst 

that must be purchased. However, due to the limited experience with this method, it will be assumed that 

the catalyst is replaced according to the catalyst management plan. 

oÉ~ÖÉåíë

The amount of reagent consumed in the SCR process is directly proportional to the amount of NOX 

reduced. Although ammonia is the chemical that actually participates in the chemical reaction, some 

suppliers have developed equipment to convert urea to ammonia on-site. According to one supplier of 

urea-to-ammonia converters, each mole of urea within the conversion system is converted to two moles 

of ammonia.24 For example, reducing one pound of NOX will require roughly 0.176 kg of ammonia or 

about 0.312 kg of urea. This includes a 1⁄2 percent increase in reagent demand due to ammonia slip and a 

five percent increase to account for a small amount of nitrogen dioxide (NO2) in the flue gas. 

Therefore, for any given plant size, the amount of catalyst and reagent consumption can be estimated. 

For a 500 MWe plant reducing NOX from 0.50 lb/MMBtu to 0.05 lb/MMBtu and 85 percent capacity 

factor (this is conservatively high for most coal boilers), approximately 3,400 tons/yr of ammonia 

(anhydrous equivalent) or about 6,100 tons/yr of urea (as 100 percent urea) would be needed. The same 

500 MWe plant would have around 450-650 m3

 of catalyst with roughly 120-160 m3 replaced about every 

three years. This is, if a third of the initial catalyst loading must be replaced, on average, every 15,000 to 

20,000 operating hours, then 0.015 to 0.0289 cubic meters per MWe per 1000 hours must be replaced. 

PKP `çåëíêìÅíáçå=bèìáéãÉåí

Construction equipment needed for installation of an SCR includes standard construction equipment – 

welders, excavation equipment, concrete pouring equipment, cranes, etc. In some cases, installers may 

use tall-span heavy-lift cranes. These cranes are capable of lifting heavy loads, as much as 100 tons or 

more, several hundred feet. The advantage of this crane type is realized when lifting assembled sections 

of catalyst reactor or other large pieces high off the ground. If lower capacity cranes are used, smaller 

pieces must be lifted, which means that less pre-fabrication is possible and more assembly must be done 

in place. Less pre-fabrication could lengthen the necessary boiler outage somewhat. Although the 

availability of the largest cranes is reported to about 60 or more, about 12 new cranes can be supplied 

every six months.25 It has been reported that, in some cases, it has been necessary to go further away 

from the plant to source cranes with adequate lift and reach capacity. In other cases, engineers found that 

by changing the design/fabrication method to meet the available crane, the project could be managed 

with lower capacity cranes (lifting smaller pieces).26,27 If more than one boiler is retrofit at one facility, 

then the crane can be used for both boilers, saving cost and time when compared to boilers retrofit 

separately. It is important to note that in many cases the erection method is not limited by the available 

crane, but is limited by the access to the plant (For example, can large sections be delivered by barge, 

rail, or roadway?) and by the available lay-down area for material and construction equipment on site. At 

many facilities, there is inadequate area to prefabricate large sections. In some instances, transportation 

routes to the facility do not permit transporting large, pre-assembled equipment to the site. In such cases, 

it will not be possible to do much pre-assembly, and a smaller, less expensive crane may be adequate. 

As a result, the type of crane that is best for a particular SCR installation frequently is not the largest 

crane available. The crane selected for a project will be determined as part of an overall construction 

plan developed to optimize all of the available resources – labor, material, and equipment - for a 

particular project. 

19
The need to lift material to high elevations is a result of the location of the SCR – often above existing 

ductwork and adjacent to existing equipment. Figure 3-2 provided one good example of this. It may be 

necessary to move existing equipment, such as the air preheater, in order to accommodate the addition of 

the SCR reactor. As a result, every retrofit is a custom fit. However, engineers have been very 

innovative when installing these systems, even on facilities that apparently had little room available for 

the SCR. Hence, the physical size of the technology has not been limiting. 

PKQ fåëí~ää~íáçå=qáãÉ

Implementation of a NOX control technology at a plant involves several activities contingent upon each 

other. These activities may be grouped under the following phases of an implementation project: (1) 

conducting an engineering review of the facility and awarding a procurement contract; (2) obtaining a 

construction permit; (3) installing the control technology; and (4) obtaining an operating permit. 

Exhibit A-3 in Appendix A depicts the timeline expected for completing a single unit installation of SCR. 

Completion of some of the activities is contingent upon completion of some other activities. For 

example, construction activities cannot commence until a construction permit is obtained. In general, the 

SCR implementation timeline appears to be driven primarily by the engineering activities (i.e., design, 

fabrication, and construction). 

båÖáåÉÉêáåÖ=oÉîáÉï

As shown in Exhibit A-3 in Appendix A, an engineering review and assessment of the combustion unit is 

conducted in the first phase of technology implementation to determine the preferred compliance 

alternative. During this phase, the specifications of the control technology are determined, and bids are 

requested from the vendors. After negotiating the bids, a contract for implementing the NOX control 

technology is awarded. The time necessary to complete this phase is approximately four months for 

SCR. 

`çåëíêìÅíáçå=mÉêãáí

Before the actual construction to install the technology can commence, the facility must receive a 

construction permit from the applicable state or local regulatory authority. The construction permit 

process requires that the facility prepare and submit the permit application to the applicable state or local 

regulatory agency. The state or local regulatory agency then reviews the application and issues a draft 

approval. This review and approval process is estimated to take about six months. The draft 

construction permit is then made available for public comment. After any necessary revisions, a final 

construction permit is issued. The actual time needed will depend on the size and complexity of the 

project and the local procedures for issuing a permit. Exhibit A-3 in Appendix A shows that nine months 

are allowed for the construction permit. This is expected to be ample time. In one case, only about 4-5 

months were needed for obtaining the construction permit,26 and only six months were needed to obtain 

the construction permit for retrofit of two 900 MWe boilers in another case.21 Shorter periods for 

construction permit authorization would allow earlier commencement of construction activities and could 

potentially shorten the overall schedule. 

`çåíêçä=qÉÅÜåçäçÖó=fåëí~ää~íáçå

In the second phase, the control technology is installed. This installation includes designing, fabricating, 

and installing the control technology. In addition, compliance testing of the control technology is also 

completed in this phase. Most of the construction activities, such as earthwork, foundations, process 

20
electrical and control tie-ins to existing items, can occur while the boiler is in operation. The time 

needed to complete this phase of an implementation project is about 17 months for SCR. 

An important element of the overall control technology implementation is the time needed to connect, or 

hook up, the control technology equipment to the combustion unit because the boiler typically must be 

shut down for this period. SCR connection can occur in a three to five week outage period.28 In some 

cases longer outages are needed. When Babcock & Wilcox retrofitted the 675 MWe AES Somerset 

boiler, the outage began on May 14, and the boiler was returned to service on June 26 – about a six-week 

outage.19 One major SCR system supplier in the U.S. stated that they would want in the range of one to 

two months of boiler down time and have never required more than two months.27 Difficulty is increased 

as the extent of boiler modifications necessary to fit the SCR into the facility is increased. A German 

SCR system supplier installed SCR on a significant portion of the German capacity within outage periods 

consisting of less than four weeks.11 Based upon outages in this time range for SCR connection, 

electricity-generating facilities would normally be able to plan the SCR connection to occur during 

planned outages to avoid additional downtime. Some facility owners have been innovative in their 

construction plans to minimize down time. At the Tennessee Valley Authority’s (TVA’s) 700 MWe 

Paradise Unit 2, it was necessary to demolish the existing ESP with the unit on line. TVA installed a 

construction bypass to send gas from the air preheater outlet directly to the FGD, while the ESP was 

being demolished and the SCR reactor erected in its place.11 However, in more difficult retrofits, down 

time might be impacted in a significant way. In some cases it may be desirable to plan a brief outage in 

advance of the hook-up to install structural steel through sleeves placed in existing equipment, such as 

the ESP, or to relocate existing equipment that would otherwise interfere with erection of the SCR. This 

permits erection of the catalyst reactor above existing equipment while the unit is on line.26 However, 

because an SCR project is expected to extend close to two years (see Exhibits A-3 and A-4 in Appendix 

A), it should be possible to incorporate this work into planned outages, which would have occurred 

regardless of whether an SCR was to be installed. 

léÉê~íáåÖ=mÉêãáí

Facilities will also need to modify their Title V operating permit to incorporate the added control devices 

and the associated reduced emission limits. In some states, an interim air-operating permit may need to 

be obtained until the Title V permit is modified. The operating permit modification process consists of 

preparation and submission of the application to the applicable state or local regulatory agency. As 

shown in Exhibit A-3 in Appendix A, this process can occur simultaneously with the processing of the 

construction permit application. The process of transitioning from the construction permit to the 

operating permit varies among states and appears to be somewhat unclear due to the infancy of the Title 

V operating permit process. Nonetheless, based on discussions with several states, the application 

review process is estimated to take approximately 9-11 months. The Title V operating permit must also 

be made available for public comment. Following public comment, the Title V operating permit is not 

made final until compliance testing on the control device is completed. Therefore, the total estimated 

time to modify the Title V operating permit is about 17 months, plus the additional time to complete 

compliance testing.10 

Based on the estimated time periods needed to complete each of the four phases described above, the 

estimated time period to complete the implementation of SCR on one combustion unit is about 21 

months. This time period is shown in Exhibit A-3 in Appendix A. However, depending upon the 

specifics of the project, the time needed could vary by a couple of months. For example, at AES 

Somerset station, the time to complete the retrofit from the point of contract award was nine months.19 

Assuming four months of work prior to contract award, a total elapsed time of 13 months would have 

been necessary to retrofit this 675 MWe boiler. Another facility, Reliant Energy’s Keystone plant, has 

21
two 900 MWe, 8-corner, T-fired combustion engineering units that burn approx 1.5 percent sulfur 

bituminous coal. Reliant intends to reduce the NOX from a baseline of 0.40 lb/MMBtu to 0.04 

lb/MMBtu. The permit to construct was received in approximately six months. The time from placing 

the order to completion of commissioning activities is 46 weeks for both units. However, preliminary 

engineering was accomplished earlier. Even if preliminary engineering and contract negotiation took as 

long as six to eight months, the total time for completing two 900 MWe units would be about 17 to 19 

months.21 For the New Madrid plant, units 1 & 2 (600 MWe each), the specifications were released to 

turnkey contractors in February 1998, the project specification was released in March 1998, the contract 

was awarded on June 26, 1998, and the first unit was in operation by February 2000. In this project, an 

option for a second unit was available (and was exercised), and air preheaters were replaced.29 

Therefore, 21 months should be a reasonable, and in some cases a conservative estimate of the total time 

necessary to retrofit a single utility boiler. 

Under the Clear Skies Act, EPA does not expect that SCR will be implemented at every facility. For 

those plants where EPA projects SCR retrofits will occur, EPA’s projections reflect that these facilities 

will typically have 1 to 4 boilers retrofit per site. However, for one facility, seven SCR retrofits are 

projected to be installed by 2020. Exhibit A-4 in Appendix A examines a schedule for retrofitting a 

facility with multiple (seven) SCR retrofits. This examines the installation of the control device hook-up 

on a sequential basis. Installation is staggered by two to three months between sequential units to enable 

more efficient utilization of manpower and project management than if multiple units were connected at 

one time. This approach also assures that at least about 83 percent of the plant capacity is available at 

any given time (only one boiler is shut down), and during most of the time there is no impact to the plant 

availability at all. This approach requires a total time of 35 months for seven SCR retrofits. An 

alternative approach might be to schedule outages to avoid any outage during high electricity demand 

periods. This might extend the total elapsed time by about four months. However, because there is a 

substantial amount of work that can be accomplished with the boiler on line, the additional time would be 

much less than the number of high electricity demand months that are accommodated by this approach. 

Another alternative approach would involve retrofit of more than one unit at a time during low-demand 

periods and avoiding any outage during high demand periods. This alternative could result in a faster 

project completion, but would have less even labor utilization, which is an important cost-benefit 

tradeoff.30 

In summary, the total time needed to complete the design, installation, and testing at a facility with one 

SCR unit is about 21 months; at a facility with multiple SCR (seven) units, total time is approximately 35 

months. Based on these timelines, it is estimated, in principal, that the NOX controls needed to comply 

with a multipollutant strategy can be met provided that: (1) an adequate supply of materials and labor is 

available, and (2) the control technology implementation process begins at least about 35 months prior to 

the date controls must be in place. However, ideally, longer than 35 months would allow for all of the 

retrofits to occur over a period of several years so that facility owners can properly plan outages and 

suppliers can properly plan for resource availability. 

PKR i~Äçê

The installation of an SCR system requires a significant amount of labor. Most of the labor is necessary 

for the construction of the facility. However, engineering and project management labor are also needed 

for the project. The total construction labor for an SCR system of 500 MWe is in the range of 333,000 to 

350,000 man-hours.22,27 Typically, approximately 40-50 percent of the labor is for boilermakers.31 

However, the percent of labor for boilermakers will vary from one project to another, with 40-50 percent 

22
being an average for several projects.32 Some projects require a higher degree of boiler integration and 

less erected steel and, therefore, have a higher percentage of boilermaker labor. Other projects require 

extensive steel erection with less boiler integration and will, therefore, have a lower percentage of 

boilermakers versus other trades. For a 500 MWe plant, the construction labor would be about 340,000 

man-hours, of this roughly 136,000-170,000 man-hours would be boilermaker activity. Engineering and 

project management are about 5 percent of the total cost, while construction is about 50 percent of the 

total cost.19 If labor rates for engineering and project management is 50 - 100 percent greater than 

construction labor, then about 17,000 to about 28,000 man-hours of engineering and project management 

are needed for the project. Total labor man-hours of construction and engineering labor are then about 

365,000 man-hours for a single 500 MWe unit. 

Construction man-hours are approximately proportional to the tons of steel fabricated. As noted earlier, 

the material needed for multiple boiler installations is generally not reduced significantly over the 

projects if they were installed separately. However, if more than one system is installed at a site, some 

significant efficiencies result. 

When there are multiple units retrofit at one site only, one mobilization is needed for all of the boilers, 

only one construction supervisor is required, and equipment is more efficiently used. As a result, 15-20 

percent efficiencies can be realized from these activities and can be planned into the project.22 Longterm projects, such as retrofits of more than one unit at one site, also lend themselves to additional 

efficiencies from learning curves. Learning curves result from productivity improvements over the 

duration of the project. Productivity measures the actual man-hours used versus those planned. A 

productivity value over 100 indicates that fewer man-hours are needed to accomplish the goal than 

expected. A labor productivity value of 110 means that 10 percent more work was accomplished for the 

level of labor expended than if a productivity value of 100 was achieved. There are examples of 

productivity improvements of 9 to 19 percent during the project due to additional efficiencies gained 

from learning curves.30 If only 10 percent or less improved efficiency results from planned reduced labor 

and from productivity improvements that occur after the project commences, the labor for each additional 

500 MWe plant might be reduced from 340,000 man-hours to about 310,000 man-hours, or about 

2,170,000 construction man-hours for seven 500 MWe units at one plant. 

For a site with multiple units, the total engineering and project management man-hours are likely to be 

significantly less than the total if each unit were addressed separately. This is because there will be many 

common site issues that need to be addressed and engineered only once. Procurement contracts need to 

be negotiated only once, and only one project management team is needed over the duration of the 

contract. However, it is difficult to say how much engineering will be reduced, because adjacent units 

may be very similar or very different. One approximation is to make total engineering, project 

management, and testing proportional to the project duration. Thus, a seven-unit facility would require 

about 42,000 man-hours of engineering and project management. 

Based upon the discussion from sections 3.1 through 3.5, the total resources needed for a single 500 

MWe plant and a site with seven 500 MWe plants is shown on Table 3-1. 

23
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PKS pé~ÅÉ=oÉèìáêÉãÉåíë

An SCR system for a coal-fired boiler may have a negligible impact on the footprint of the boiler. This 

is because the SCR is frequently installed in an elevated position near the boiler and well off of the 

ground. The choice of installing the SCR reactor near the ground level or elevated well above ground 

level depends upon which configuration is viewed as most cost effective while considering installation 

cost and operating cost. Locating the SCR in an elevated location near the boiler economizer and air 

preheater is frequently done to minimize the length of ductwork (with the associated pressure loss) and 

because no additional real estate is necessary for the SCR reactor. When this type of installation is 

performed, the SCR reactor is installed atop a steel structure that must be erected above existing 

equipment, such as the electrostatic precipitator. This is an approach that is frequently used because 

engineers have developed cost effective methods to install the SCR reactor while addressing potential 

interferences from existing equipment. Section 3.4 of this document discussed how brief outages, in 

advance of the outage to connect the SCR, were taken to address interferences and permit SCR reactor 

24
construction with the unit on line. In some cases, however, the preferred approach has been to locate the 

SCR reactor on the ground near the boiler and to route the ductwork to and from the SCR reactor. This is 

the approach that was taken on the retrofit of PSNH Merrimack Unit 2, the first retrofit of a coal-fired 

boiler in the United States. In this case there was a large amount of space near the boiler to permit this 

approach. Regardless of where the SCR reactor is located, ductwork from the economizer outlet to the 

SCR reactor and back to the air preheater inlet must be accommodated. In cases where space for this 

ductwork was extremely limited, the air preheater was relocated. However, relocation of the air 

preheater(s) usually is not necessary. Only a few installations have required the relocation of the air 

preheater. 

The other item that must be located is the reagent storage system. This usually does not take up as much 

room as the SCR reactor itself. However, the storage and unloading system must be located near rail or 

truck access to permit delivery of reagent. In some cases, long piping is run from the storage and 

unloading area to the SCR reactor. In these cases, the piping may be insulated and heat traced to prevent 

condensation of the ammonia vapor. 

25
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Under a multipollutant control scenario, mercury emissions would be controlled from coal-fired power 

plants by equipment that reduces emissions of other pollutants (e.g., scrubbers and SCR) and the use of 

sorbent injection. Other methods are being investigated (such as oxidation and scrubbing technologies), 

which utilize ozone, barrier discharge, and catalyst and/or chemical additives in combination with 

existing technologies. To the extent that other technologies are developed, these would provide more 

options for compliance, so their introduction would serve to reduce issues related to resource 

requirements of installing controls. Similarly, with regard to sorbent injection, sorbents other than 

activated carbon (AC) may ultimately prove to be superior for this application in terms of cost or 

collection efficiency performance and may reduce the likely demand for ACI from what is projected 

here. Nevertheless, all of the sorbent-based approaches use similar hardware to inject sorbent as ACI. 

Therefore, the assumption of ACI as a control method will provide a fairly representative indication of 

the demand for hardware and construction resources regardless of which sorbents are used in the market. 

The assumption of ACI as a mercury control method will be more conservative with regard to sorbent 

consumption since it will assume that all of the facilities installing sorbent injection for mercury control 

require AC. 

QKN póëíÉã=e~êÇï~êÉ

The AC is typically injected at the lowest temperature available that is upstream of a particle-collecting

device because experience has found that mercury collection is most efficient at lower temperatures. On

a boiler equipped with an ESP or a fabric filter (FF) for particle collection, the configuration would look

as in Figure 4-1. Collection of mercury is somewhat more efficient when a FF is used for particle

collection because of the higher gas-sorbent contact in the filter cake. Another approach is to have

injection downstream of an ESP, which would collect most of the coal fly ash, and upstream of a fabric

filter (FF), which would mostly capture sorbent. This approach is shown in Figure 4-2. The advantages

of this approach are that greater mercury capture occurs because of the additional mercury capture that

can occur on the FF filter cake; and, because the ash is largely separated from the sorbent, more efficient

sorbent utilization is possible through sorbent recycling. This approach could be implemented through

addition of a Pulse Jet Fabric Filter (PJFF) when ACI is installed.

The ACI System consists of the following components, as shown in the simplified schematic of Figure

4-3:

Ŷ A silo for storing the sorbent

Ŷ A metering system for metering the amount of sorbent injected into the ductwork – typically a rotary

metering valve 

Ŷ A pneumatic or mechanical conveying system for moving the sorbent to the injection location 

Ŷ An injection system for dispersing and distributing the sorbent in the boiler ductwork. For many 

facilities, injection of sorbent will occur after the air preheater and upstream of the ESP or FF. This 

injection system is principally made from piping that may split off to manifolds for injecting in 

multiple locations. Special nozzles or other hardware are generally not required. 

26
Ŷ A blower to provide a carrying medium 

Ŷ Associated piping for the blower and the distribution system 

Ŷ A humidification system may be used in some cases to reduce temperature and improve mercury 

capture. The humidification system will typically consist of water spray injectors (possibly air 

atomized) located upstream of the ACI injectors, a grid for the spray injectors, and a water supply 

system that will include pumping and metering systems. 

Ŷ A control system that may utilize a programmable logic controller (PLC) or may be accommodated 

by the plant distributed control system (DCS) 

Boiler SCR 

(if installed) 

Air Preheater 

ESP or 

FF 

Combustion Air 

Coal 

Sorbent and fly ash 

are collected here 

Activated Carbon Injection 

exhaust 

Stack 

Figure 4-1. Gas path for coal-fired boiler with SCR, ACI, and ESP. 

exhaust 

Air 

Boiler SCR 

(if installed) 

Air Preheater 

ESP 

Stack 

exhaust 

Combustion 

Air 

Coal 

Fabric 

Filter 

Fly ash is collected here 

Sorbent is collected here 

Activated Carbon Injection 

Figure 4-2. Gas path for coal-fired boiler with SCR, ACI, ESP, and FF. 

27
Activated Carbon 

Sorbent Storage Silo 

Blower 

Rotary 

Metering 

Valve 

Optional 

water spray From air 

preheater 

Exhaust 

Gas Duct 

To ESP 

Or FF 

Figure 4-3. Simplified schematic of ACI system. 

Regardless of boiler size, an ACI system will require the same equipment. The principal differences will 

be the size of the sorbent storage silo, the size of the metering and conveying system, and the size and 

number of injectors for the sorbent injection system. 

There are also several other combinations that may be used, including combinations of ACI with spray 

dryer and FF and combinations of ACI with FGD.32 The various combinations will be discussed further 

in Section 4.2. In each of these combinations, the actual equipment associated with the ACI system is 

similar. The particular combination of equipment chosen for mercury reduction at a particular facility is 

largely determined by the existing equipment and conditions at the facility. However, most facilities are 

currently equipped with ESPs, and some are equipped with FFs. Thus, the most likely scenario for 

application of ACI is in a configuration with ESP or FF. 

Most existing facilities have ESPs for particle emission control and do not have any SO2 removal 

technology. Therefore, injection of sorbent, and possibly water for humidification, will most often be 

performed downstream of the air preheater and upstream of the electrostatic precipitator, where the gas 

temperature is typically in the range of 280-300 oF. In this part of the boiler ductwork, there are no water 

wall tubes. Therefore, the mechanical interface between the ACI system and the boiler is through the 

duct walls, and high-pressure boiler tubing will not be affected by the retrofit of ACI. 

Some companies offer other sorbent-based methods for reduction of mercury emissions; however, the 

equipment used is very similar in scope to the equipment used for ACI.32 

28
The majority of the equipment used for an ACI system is produced from standard mechanical or 

electrical hardware that is sold for a wide range of purposes. The total amount of steel is relatively small 

in comparison to an SCR or an FGD for a 500 MWe plant.27 The estimated steel requirement for a 500 

MWe ACI system is indicated in Table 4-1.33 Since the largest item contributing to the steel requirement 

is the storage silo, it will be assumed that the total steel requirement is proportional to the capacity of the 

unit, as the storage requirement would be proportional to the capacity. For multiple units at one site, all 

but the silo would certainly need to be duplicated. It is possible that there might be one large silo serving 

several units with more than one feed off of it, or, that individual silos may be needed. In any event, the 

synergies in reducing total steel requirement over what would be needed for individual units is expected 

to be small. 

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AC is assumed to be the principal reagent used to absorb the mercury in the exhaust gases. Most of the 

information on the AC injection requirements for a coal-fired power plant is from pilot studies and 

demonstrations of ACI technology. Table 4-2 shows AC injection rates estimated from the data provided 

a comprehensive assessment of ACI under a range of scenarios.34 For example, to achieve 80 percent 

mercury reduction from a low sulfur bituminous coal using an ACI system with humidification will 

require a treatment rate of about 8 lb/million acf (MMacf).34 If a pulsejet FF (PJFF) is used downstream, 

the sorbent injection rate can be reduced to about 4.6 lb/MMacf. If the facility fires high sulfur coal and 

is equipped with FGD, then the estimated sorbent rate is between 6.1 lb/MMacf to 2.0 lb/MMacf, without 

and with a PJFF, respectively. For a high sulfur coal application, humidification would not be performed 

due to risk of acid condensation. Table 4-2 summarizes estimated injection rates for a 500 MWe boiler 

under various scenarios.34 As shown, the injection rates vary substantially based upon the circumstances. 

Because combination of SCR and FGD are expected to have high mercury removal due to the SCR and 

FGD systems, those facilities that are so equipped are not expected to add ACI systems. 

There are really no synergies in consumption if multiple ACI units are installed at one site. Therefore, 

the total AC consumption at a plant will be roughly proportional to the total plant capacity equipped with 

ACI. 

29
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Construction equipment needed for installation of an ACI system includes standard construction 

equipment – welders, excavation equipment, concrete pouring equipment, cranes, etc. Since an ACI 

system is much smaller and uses substantially less steel than an SCR or FGD system, cranes and other 

lifting equipment can be of low to moderate lifting capacity. Blowers, the sorbent storage silo, and other 

equipment will be mounted on concrete pads or foundations. In most cases, the sorbent storage silo will 

be field erected; however, for some facilities that require less sorbent, a smaller, prefabricated silo may 

be installed. Steel erection and minor excavation and concrete work is necessary for an ACI system, and 

this work should not require any more than very common construction equipment. Piping for sorbent 

transport will typically be welded steel and can be erected in the field in many cases. It should not be 

necessary to relocate any existing boiler equipment to install an ACI system. Therefore, the construction 

effort and need for equipment is relatively modest compared to the more involved SCR and FGD 

projects. 

QKQ fåëí~ää~íáçå=qáãÉ

Implementation of a control technology at a plant involves several activities contingent upon each other. 

These activities may be grouped under the following phases of an implementation project: (1) conducting 

an engineering review of the facility and awarding a procurement contract; (2) obtaining a construction 

permit; (3) installing the control technology; and (4) obtaining an operating permit. 

Exhibit A-5 in Appendix A depicts the timeline expected for completing a single unit installation of ACI. 

Completion of some of the activities is contingent upon completion of other activities. For example, 

construction activities cannot commence until a construction permit is obtained. In general, the ACI 

implementation timeline appears to be driven primarily by the engineering activities (i.e., design, 

fabrication, and construction). 

30
båÖáåÉÉêáåÖ=oÉîáÉï

As shown in Exhibit A-5 in Appendix A, in the first phase of technology implementation, an engineering 

review and assessment of the combustion unit, is conducted to determine the preferred compliance 

alternative. During this phase, the specifications of the control technology are determined and bids are 

requested from the vendors. After negotiating the bids, a contract for implementing the control 

technology is awarded. The time necessary to complete this phase is approximately four months. 

`çåíêçä=qÉÅÜåçäçÖó=fåëí~ää~íáçå

In the second phase, the control technology is installed. This installation includes designing, fabricating, 

and installing the control technology. In addition, compliance testing of the control technology is also 

completed in this phase. Most of the construction activities, such as earthwork, foundations, process 

electrical and control tie-ins to existing items, can occur while the boiler is in operation. The time 

needed to complete this phase of an implementation project is expected to be less than three months.33 

An important element of the overall control technology implementation is the time needed to connect, or 

hook up, the control technology equipment to the combustion unit. As a result of the minimal 

mechanical interface between the sorbent injection system and the boiler, retrofit of an ACI system will 

typically require a fairly short outage - one week or less.33,34 This brief outage is necessary to install 

injection hardware and to make any control system connections that may be necessary between the ACI 

control and the boiler control. Other equipment associated with the ACI system can be installed with the 

boiler on line, as it does not require any interfacing with the boiler and should not require moving any 

essential boiler equipment. 

It should be possible to complete a project in less than 4 months from receipt of order.34 If construction 

and operating permits are included in the analysis, the project is likely to take longer than would be 

necessary only for engineering, supply, installation, and startup of the ACI system. This is because the 

permitting activities might become the time-limiting steps. In some localities, it is possible that the 

permitting activities will not be the limiting steps. In this case, a faster execution is possible than shown 

on Exhibit A-5 in Appendix A. 

léÉê~íáåÖ=mÉêãáí

Facilities will also need to modify their Title V operating permit to incorporate the added control devices 

and the associated reduced emission limits. In some states, an interim air-operating permit may need to 

be obtained until the Title V permit is modified. The operating permit modification process consists of 

preparation and submission of the application to the appropriate state or local regulatory agency. As 

shown in Exhibit A-5 in Appendix A, this process can occur simultaneously with the processing of the 

construction permit application. The process of transitioning from the construction permit to the 

operating permit varies among states and appears to be somewhat unclear due to the infancy of the Title 

V operating permit process. Nonetheless, based on discussions with several states, the application 

review process is estimated to take approximately 38 weeks (9-10 months). The Title V operating permit 

must also be made available for public comment and is not made final until compliance testing on the 

control device is completed. Therefore, the total estimated time to modify the Title V operating permit is 

about 12 months, plus the additional time to complete compliance testing.10 

Based on the estimated time periods needed to complete each of the four phases described above, the 

estimated time period to complete the implementation of ACI on one combustion unit is about 15 

months, as shown in Exhibit A-5 in Appendix A. Since the permitting process limits the timeline, a 

faster permitting process will shorten the time necessary to install ACI on a single unit. 

31
Under the Clear Skies Act, EPA does not expect that ACI will be implemented at many facilities due to 

the co-benefit of mercury removal from other control technologies. For those plants where EPA projects 

ACI retrofits will occur, EPA’s projections reflect that these facilities will either have 1 to 2 boilers 

retrofit per site. Exhibit A-6 in Appendix A examines a schedule for retrofitting a facility with multiple 

(two) ACI retrofits. This examines the installation of the control device hook-up on a sequential basis. 

Installation is staggered by one month between sequential units to enable more efficient utilization of 

manpower and project management than if multiple units were connected at one time. This approach 

requires a total time of 16 months. 

In summary, the total time needed to complete the design, installation, and testing at a facility with one 

ACI unit is about 15 months, at a facility with two ACI units is approximately 16 months. Based on 

these timelines, it is estimated that, in principle, the mercury controls needed to comply with a 

multipollutant strategy can be met provided that (1) an adequate supply of materials and labor is 

available and (2) the control technology implementation process begins at least 16 months prior to the 

date controls must be in place. However, ideally, longer than 16 months would allow retrofits to occur 

over a period of several years so that facility owners can properly plan outages and suppliers can properly 

plan for resource availability. Erection of a PJFF would typically take 16 to 20 months from award of 

contract to start up.35 If 4 months is added for pre-contract effort and 1-2 months is provided for start up 

and commissioning, the total project duration would be anywhere from about 21 months to 26 months. 

However, EPA’s modeling under the Clear Skies Act projects that the units installing ACI will not be 

installing PJFFs.36 

QKR i~Äçê

The man-hours of labor estimated to be required for supply of an ACI system are listed in Table 4-3, 

which includes a breakdown of man-hours by task.33 Craft labor for installation is also indicated. 

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In summary, a 500 MWe boiler firing eastern bituminous coal with 0.6 percent sulfur, an ESP, and no 

SCR or FGD, is estimated to provide the performance and require the resources listed in the first column 

of Table 4-4, and estimates of performance and resources needed for other types of fuels and boiler 

configurations are shown in the other columns. A boiler firing subbituminous coal and with only an ESP 

for particle collection and pollution control will require the most activated carbon consumption and the 

most steel for the ACI system. Table 4-5 shows the estimated performance and resources needed for a 

single and multiple (two) ACI retrofit on a 500 MWe boiler firing subbituminous coal and equipped with 

an ESP. As shown, as long as at least 16 months are provided for installation of ACI control technology, 

32
then there should be sufficient time for the technology to be installed. If a facility owner chose to install 

a Pulse-Jet Fabric Filter (PJFF) in addition to the ACI system for the purpose of improving sorbent 

utilization, the project time would necessarily be lengthened beyond this 16-month period to allow for 

the installation of the PJFF. As stated in section 4.4, the total duration for a PJFF retrofit is estimated to 

be anywhere from about 21 months to 26 months, including pre-contract effort and start up and 

commissioning. Since the Clear Skies Act provides much more than 26 months of notice for any 

mercury control regulation, there should be adequate time for compliance even if some facilities install 

PJFFs. 

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33
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Most of the equipment and piping associated with a sorbent injection system is fairly small and can be 

easily accommodated on any facility. The only piece of equipment that could potentially be a challenge 

to locate on site is the sorbent storage silo, the other equipment largely being piping and a blower. The 

storage silo is, by far, the largest part of the ACI system. It is estimated that a storage silo that is sized 

for 15 days of AC storage at full load for a 500 MWe plant firing bituminous coal and with only an ESP 

would be about 10.7 m in diameter and about 26.7 m high.33 This sized piece of equipment, while large, 

should be readily accommodated on most sites large enough for a 500 MWe boiler. For boilers with 

fabric filters, the size of the silo would be less because of the lower sorbent injection rate. Some facility 

operators may choose to install a PJFF in order to reduce sorbent consumption and to segregate carbon 

from the ash. In this case, more space would be needed for the PJFF. The dimensions for a PJFF on a 

500 MWe plant would be roughly 62 feet wide x 92 feet long x 90 feet high.35 

34
`Ü~éíÉê=R

póåÉêÖáÉë=çÑ=`çãÄáå~íáçåë=çÑ=`çåíêçä=oÉíêçÑáíë=çå=~=páåÖäÉ=råáí

This chapter will explore the combination of these technologies and how deployment of more than one 

technology at a unit could potentially result in improved resource utilization. It is assumed that the ACI, 

FGD, and SCR would not be necessary at a single unit because of the high mercury removal efficiencies 

expected through combination of FGD and SCR. Hence, the synergies of combining all three 

technologies were not explored. 

RKN p`o=~åÇ=cda=EpÅêìÄÄÉêF=fåëí~ää~íáçåë

In some cases, facility owners may choose to retrofit their plants with both SCR and FGD technology to 

achieve both NOX and SO2 reduction. Combination of SCR and FGD will also result in significant 

reduction of mercury emissions, thereby mitigating the need for the addition of ACI. However, both 

SCR and FGD are very capital-intensive projects, which require a substantial level of material and 

construction. Therefore, it is worthwhile to consider if both SCR and FGD installations can be combined 

efficiently. 

An SCR project involves retrofitting in the boiler and its immediate area. Therefore, an SCR retrofit 

project may require relocation of equipment in the boiler area. An FGD system is installed farther 

downstream in the plant, after the ESP. Occasionally, it is necessary to install a new smoke stack, and it 

may be necessary to add more fan capacity. However, an additional smoke stack is normally 

unnecessary. The FGD connection with the facility is generally less difficult than with SCR because it 

does not require modification of the boiler, just connection to ductwork in the vicinity of the stack. As a 

result, the construction activities would normally be in different locations at the plant, reducing the 

interference between the two projects. The SCR might be the limiting item on the boiler outage because 

of its more complex connection. In any event, the tie-in of the SCR and the FGD systems could be done 

in the same outage, and it has been confirmed that the installation of SCR and scrubber could be 

performed simultaneously without interference.37 Therefore, installing these at the same time on a boiler 

is preferable to doing them separately as they may be able to use the same outage, and project 

efficiencies result from a single mobilization, a single construction manager, and sharing of large 

construction equipment for the two projects. At Kansas City Power and Light’s Hawthorn Power 

Station, Unit 5 was replaced (excluding turbine) in under 22 months. This included the boiler, an SCR, 

and an LSD/FF.38 Although, in this case the equipment did not have to be erected adjacent to an 

operating boiler, the erection included demolishing and erecting a complete boiler island and 

demolishing the existing electrostatic precipitator. Hence, this was a very complex project that was 

completed approximately within the time frame estimated and shown in Exhibit A-7 in Appendix A. 

RKO jÉêÅìêó=`çåíêçä=qÉÅÜåçäçÖó=~åÇ=pÅêìÄÄÉê=fåëí~ää~íáçåë

As noted in Chapter 4, ACI entails a much smaller construction project than either an FGD or an SCR. 

Moreover, the ACI is located in a different part of the plant than FGD or SCR and activated carbon 

injection occurrs in the ductwork between the air preheater and the ESP or FF. One benefit of combining 

35
these two projects is that the ACI hookup can be completed during the outage for the scrubber hookup, 

since the installation effort necessary for the FGD will far outweigh that of the ACI system. A second 

benefit is better planning of material storage and handling equipment. Both FGD and ACI require a 

substantial amount of material (limestone and AC, respectively) and associated storage and handling 

facilities. Installing both technologies at the same time will permit better planning of material storage 

and equipment locations, thereby avoiding interference. Other benefits, such as a single mobilization, a 

single construction manager, and sharing of large construction equipment for the two projects exist, but 

they are not expected to make a significant difference due to the difference in size between the portions 

of the combined FGD and ACI project. Therefore, as shown in Exhibit A-8 in Appendix A, the schedule 

for a combined FGD and ACI project is expected to be the same as the schedule of an FGD project. 

RKP jÉêÅìêó=`çåíêçä=qÉÅÜåçäçÖó=~åÇ=p`o=fåëí~ää~íáçå

As noted in Chapter 4, ACI entails a much smaller construction project than either an FGD or an SCR. 

The primary benefit of combining these two projects is that the ACI hookup can be completed during the 

outage for the SCR hookup, since the installation effort necessary for the SCR will far outweigh the ACI 

system. Other benefits, such as a single mobilization, a single construction manager, and sharing of large 

construction equipment for the two projects exist, but they are not expected to make a significant 

difference due to the difference in size between the SCR and ACI portions of the combined project. 

Therefore, as shown in Exhibit A-9 in Appendix A, the schedule for a combined SCR and ACI project is 

expected to be the same as the schedule of an SCR project. 

36
`Ü~éíÉê=S

póëíÉã=oÉëçìêÅÉ=^î~áä~Äáäáíó

Having assessed the resource requirements for individual or multiple retrofits of control technologies, 

this chapter will assess the resource availability in the United States for retrofit of control technologies 

for the Clear Skies Act. This analysis considers the current availability of resources for the construction 

of control technologies and does not consider any potential increase in production of resources due to the 

demand created by the Clear Skies Act. Because this effect will be more pronounced in the period 

following 2010 and because other market factors may also change over time, the longer term projections 

are of less value than those out to 2010. EPA has made preliminary estimates of the retrofits of each 

technology that would result from the Clear Skies Act. Tables 6-1a, b, and c list the expected total MWe 

of facilities that would be equipped with SCR, FGD, or ACI after response to a multipollutant rule. It is 

important to note that the “Current Air Quality Rule Retrofit MWe” row of the table includes only the 

projected retrofits under the current air quality rules. The control technology retrofits estimated to result 

from the Clear Skies Act, including the retrofits from current air quality rules, is listed in the 

“Multipollutant & Current Retrofits MWe” row of the tables. The “Cumulative Total” MWe shown in 

Table 6-1 includes facilities that currently are equipped with the technology or are expected to be 

equipped with the technology as a result of current air quality rules, such as SCRs resulting from the NOX 

SIP Call as well as the projected retrofits under the Clear Skies Act. EPA estimated that up to 72 GWe of 

SCR would result from the NOX SIP Call and an additional 13 GWe from individual state multipollutant 

rules with approximately 14 GWe currently installed. However, facilities are responding to the NOX SIP 

Call at this time and it is uncertain exactly how many facilities will ultimately be equipped with SCR in 

2004 when the NOX SIP Call deadline arrives. 

EPA projections estimate that it would be cost effective for 32,000 MWe of FGD retrofits to be installed 

under the Clear Skies Act by 2005 even though the first phase of the SO2 cap is not in effect until 2010. 

These retrofits would be early installations that sources initiate due to the economic benefits of banking 

SO2 allowances. It is estimated that there are about 4,000 MWe of FGD capacity being constructed or 

just recently completed. Based on availability of resources, particularly labor, it is projected that an 

additional 6,000 MWe of FGD capacity could be built for a total of 10,000 MWe by 2005. Because the 

FGD estimate based on availability of resources is much less than the amount of FGD capacity that 

would be cost effective to build, EPA ran model sensitivities constraining the amount of scrubber 

capacity that could be installed by 2005 at 10,000 MWe. This estimate for the potential number of FGD 

retrofits considers the resource and labor requirements of the simultaneous installation of SCRs, which is 

further discussed under the labor section (6.2) of this chapter. The 22,000 MWe difference, between the 

number of FGDs which would be cost effective to build and the estimated number based on resources, 

would be pushed back a few years to be completed by 2010. Therefore, the 53,000 MWe of FGD 

retrofits projected to be built by 2010 for Clear Skies and current requirements remains the same under 

both scenarios. It is likely that additional FGD retrofits could be completed by 2005, but there would be 

the potential for an increase in the cost of construction due to decreased implementation time. 

A typical unit size of 500 MWe was selected for each technology. In previous sections, capacity factors 

of 85 percent were assumed. In reality, coal-fired facilities, on average, have lower capacity factors. For 

example, in 1999, 39.8 percent of 786 GWe of generating capacity in the U.S., or 313 MWe, was coal 

fueled. In that same year, coal-fired U.S. plants produced about 51 percent of 3,691 billion kWh, or 

37
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1,882 billion kWh.39 This corresponds to a capacity factor of 68.7 percent (Data is from Energy 

Information Administration Web Site; Capacity Factor is total MWe-h produced divided by the total 

MWe-h that would be produced if the plant were run at full capacity for 8,760 h in the year). As a result, 

assuming a capacity factor of 85 percent will result in a much more conservative (high) estimate of 

resources needed than is likely to be the case. 

In estimating the resources necessary to put new control technology capacity in place (labor, steel, etc.), 

the “Multipollutant & Current Rule Retrofits MWe” values of Tables 6-1a, b and c are of greatest 

interest. For estimating the consumables necessary for the technologies, such as limestone, ammonia, 

catalyst, or activated carbon, the “Cumulative Total MWe” value is most important. The multipollutant 

and total MWe of control technology retrofits are given for 2005, 2010, 2015, and 2020. To provide a 

conservative estimate of required resources, the following analysis looks at implementing the retrofits for 

2005 in 31 months prior to 2005 and retrofits for 2010, 2015, and 2020 three years prior to each five-year 

period. For example, it estimates the resource requirements from the period between 2005 and 2010 over 

three years prior to 2010 instead of five years. Thirty-one months was used for 2005, because the 

analysis for 2005 was based on the projected number of retrofits needed by 2005, less the amount of 

capacity installed by May 2002. It should also be noted that most of the retrofits needed by 2005 are 

being installed to meet existing requirements under the NOX SIP Call or other regulatory requirements as 

opposed to the requirements of a multipollutant program such as the Clear Skies Act. 

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38
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39
íä ê í

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SKN póëíÉã=e~êÇï~êÉ

The hardware items such as steel, piping, nozzles, pumps, soot blowers, fans, tower packing, and related 

equipment required for a typical SCR, FGD, or ACI systems installation are used in large industries such 

as construction, chemical production, auto production, and power production. Consequently, installation 

of these technologies on many coal-fired utility boilers is not expected to result in severe changes in 

demand for the hardware items listed. 

From Chapter 2, roughly 1,125 tons of steel is needed for a 500 MWe FGD system, which is about 2.25 

tons per MWe. This is conservatively high since there are some significant synergies possible when there 

are multiple units on site. In particular, two boilers with 900 MWe of capacity require approximately 2.1 

tons per MWe. From Chapter 3, an SCR for a coal-fired utility boiler requires roughly 2.5 tons of steel 

per MWe for the typical size. From Chapter 4, a 500 MWe facility will need about 175 tons of steel to 

install an ACI system, or about 0.35 tons per MWe. Estimated steel requirements for the projected 

retrofit MWe are shown in Table 6-2 assuming that the retrofits occur over 31 months prior to 2005 and 

over three years prior to 2010, 2015, and 2020. For retrofits starting in 2005 facility owners are likely to 

have more than three years to complete this work as many of these retrofits have already begun. These 

time periods were chosen to show that even under short periods of time, no significant impact to U.S. 

steel supply is expected. 

Census Bureau data on=U.S. steel shipments in 2000 was approximately 108,703,000 tons, and imported 

steel was 30,993,000 tons for a total demand of about 140 million tons. An assumed growth rate of US 

steel demand was chosen at 3 percent, a typical number for growth in GDP. For each increment of time, 

the impact to US steel demand was less than one tenth of one percent. Even if there were no growth in 

the US steel production and imports from 2000 out to 2020, the amount of steel needed to complete the 

retrofits for the Clear Skies Act would still be less than one tenth of one percent of US production 

including imports. 

Similarly, available supplies of piping, nozzles, pumps, soot blowers, fans, and other related standard 

component necessary for SCR, FGD or ACI installations are not expected to present constraints on the 

ability of facilities to install the technology. SCR catalyst is the only specialized piece of equipment that 

is needed. Catalyst is discussed in Section 6.4. 

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40
SKO i~Äçê

The installation of the SCR, FGD, and ACI control technologies will require the following types of labor: 

x general construction workers for site preparation and storage facility installation; 

x skilled metal workers for specialized metal and/or other material assembly and construction; 

x other skilled workers such as boilermakers, electricians, pipe fitters, painters, and truck drivers; and 

x unskilled labor to assist with hauling of materials, placing of catalyst elements, and clean up. 

From Chapter 2, it takes roughly 760 man-hours of labor per MWe of FGD built. Chapter 3 showed that 

about 700 man-hours of labor per MWe are required for an SCR system on a coal-fired boiler, and 

Chapter 4 showed that roughly 10 man-hours of labor are needed per MWe for an ACI system. Using 

these factors and the expected retrofits, the labor requirement for SCR, FGD, and ACI retrofits can be 

determined and are shown in Table 6-3. These estimates do not take into account any synergies or 

efficiencies realized from retrofitting multiple units on a site, as are described in Section 2.5 and 3.5, or 

from a combination of technologies, as described in Chapter 5. Roughly 50 percent of an SCR project 

man-hours and 40 percent of an FGD project man-hours are for boilermakers.40 There is little data on 

ACI breakdown of labor; however, a conservative level of 50 percent is assumed. Using these rates and 

assuming the above mentioned construction periods, it is possible to estimate the number of fully 

employed laborers and boilermakers. The results are shown in Table 6-3. The actual annual requirement 

for labor would be less if the estimated number of retrofit installations were evenly distributed over the 

full five-year increment of time instead of the conservative three-year increment. 

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Figure 6-1 shows a summary of construction worker labor available in the United States. The data shows 

steady growth in construction industry employment at the national level during the 1992 to 2000 period. 

Employment in the construction sector grew by 49.1 percent (4.1 percent annualized) over the period 

compared to 21.7 percent (2.0 percent annualized) for the economy as a whole. The unemployment rate 

of 6.4 percent in 2000 compares to 4.0 percent for the whole economy.41 

41
Figure 6-1. U.S. construction employment and unemployment (Source: Bureau of Labor Statistics). 

The available construction labor in the United States, about 6.7 million, will provide a large labor pool 

for the trades that are not unique to the power industry, such as iron and steel workers, pipe fitters, and 

electricians. In other words, that the estimated demand of under 20,000 full-time workers represents only 

about 0.3 percent of the current total labor pool. 

Boilermakers are a skilled labor source that is fairly unique to utility work. Sixty percent of the demand 

for boilermakers in the construction division is from the utility industry.31 Other industries requiring 

boilermaker labor include refinery (13 percent), chemical (6 percent), paper (7 percent), and metals (6 

percent). These are the industries where boilers and high-energy vessels are most likely to be found. 

Retrofit of equipment on utility boilers often requires a significant number of boilermakers due to the 

integration that is needed with the boiler that often requires modification of steam piping or other boiler 

equipment. Also, in response to the increase in demand for boilermakers over the last few years, their 

ranks have increased from 15,444 active members in 1998 to 17,587* members in 2000 - an annualized 

growth rate of 6.7 percent.31 Employment level also increased during this time from 69.8 percent to 81.8 

percent (employment level is equal to the total man-hours worked in the year divided by total active 

members time 2080 h/yr). During much of the 1990’s the number of active boilermakers had been 

declining due to very low employment levels resulting from very low activity in the utility power plant 

construction business.30 Therefore, the increased activity of the last few years has been a welcome 

change to boilermakers. 

Several sources have mentioned that the availability of boilermakers has been tight for the SCR projects 

underway for the NOX SIP Call.42, 43 However, where shortages have been experienced in manning SCR 

construction projects with adequate numbers of boilermakers, manpower planning had been done with 

short notice.44 Many boilermakers travel to work sites that are out of their local area. A large project 

may require mobilization of several hundred boilermakers to a site, which will frequently require pulling 

*

 It is assumed that this number is for journeyman boilermakers and does not include persons in apprenticeship 

programs. 

42
members from other parts of the country. In the current, competitive environment for utilities, power 

plant owners are reluctant to provide much advance notice of when outages will occur. Therefore, in 

some cases contractors must find manpower on very short notice. The boilermaker's union (The 

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

attempts to provide the necessary manpower to the contractors. However, with very short notice, it is 

sometimes difficult to move the manpower to the site in the short time desired. Nevertheless, the union 

has been successful in providing sufficient manpower to the project sites where they have had adequate 

advance notice.44 Therefore, although there is little slack in the availability of boilermakers, better 

coordination may have avoided the labor shortage problems. 

It is worthwhile to consider the expected future state of the supply of boilermakers. The total number of 

members in the boilermaker's construction division is currently about 24,000 journeymen and 

apprentices.44 The union has about 4000 members in Canada. These numbers are up from the 1990's 

when a severe drought of work for boilermakers caused many boilermakers to seek other lines of work. 

Due to the current workload, the boilermaker ranks are growing. However, the average age of the work 

force is about 48. Because of the aging workforce and because of the anticipated demand for work at 

power plants, the union has made it an objective to have at least 28,000 members in the construction 

division by 2005, or at least a 5.3 percent annual growth rate. The boilermaker's union is working to 

recruit new members into their apprenticeship programs, which takes four years to complete. Also, 

skilled workers from other trades may choose to work as a boilermaker, so a shorter apprenticeship may 

be possible, depending upon the experience and skill level of the individual. For example, iron and 

steelworkers who had been boilermakers in the past could move back into boilermaker work very 

quickly. Since, boilermakers earn somewhat more than ironworkers,42 it is reasonable to expect that with 

increased job stability in the boilermaker trade, some ironworkers might choose to move to the 

boilermaker trade for the higher pay, especially if they had worked as boilermakers in the past. The iron 

and steelworkers union has 150,000 members.45 Even without prior boilermaker experience, some of 

these iron and steelworkers could choose to move to boilermakers with much less than a full four-year 

training requirement because of their knowledge and skill level. In addition, the boilermaker's 

shipbuilding division has about 30,000 members45 who, depending upon industry conditions, could move 

over to the construction division quickly. 

As noted earlier, the number of boilermakers dropped quickly during the 1990s when little work was 

available. Conversely, increasing demand for boilermakers that would result from a multipollutant rule 

should stimulate more workers to enter the trade. The overall employment outlook for boilermakers 

should be quite good, considering the work created by a multipollutant initiative and the work on new 

power plants that is projected over the next 20 years. As stated in the National Energy Policy (May 

2001): 

Over the next 20 years, the United States will need 1300 to 1900 new power plants. 

Electricity demand is expected to increase at a rate of 1.8 percent per year over the next 20 

years, creating the need for 393,000 MWe of generating capacity. At a 1.5 percent growth 

rate that number is reduced by between 60,000 to 66,000 MWe to about 330,000 MWe of new 

generating capacity. 

A large quantity of new generating capacity, consisting mostly of gas combined cycle units, has been 

built within the last several years. Since 1998, close to 200 GWe of new capacity have been built or is 

currently under construction with an even larger quantity being proposed. This excess in capacity is 

projected to create an overall reserve margin greater than 25 percent in the US over the next few years. 

By comparison, this is a significant increase in the reserve margin since it dipped below 10 percent in the 

late 1990's. As the demand in electricity grows, the need for new generating capacity will not be felt 

43
until the excess capacity is worked off. Assuming new capacity will be needed when the reserve margin 

approaches 15 percent, it is expected to push back the need for additional capacity beyond 2005 and in 

some regions as late as 2010. 

Due to the installation of SCR units for the NOX SIP Call, a significant percentage of the boilermakers 

who are currently working in the utility industry would be needed to complete those retrofits by 2004. 

Integrated Planning Model (IPM) projections indicate that it would be cost effective to install 32 GWe of 

scrubbers by 2005 in addition to the projected SCR installations; however, boilermaker labor is not 

expected to be sufficient to meet this demand even if their numbers grow at the projected 5.3 percent 

annual growth rate. Figure 6.2 shows the boilermaker labor requirements out to 2010 assuming 32 GWe 

of scrubbers and 85 GWe of SCR installations are installed by 2005 and compares the demand to the 

supply of labor. 

Boilermaker Supply vs. Clear Skies Demand 

(32 GWe Scrubber Installations by 2005) 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 

Boilermaker Labor 

(1000 man-hrs) 

Other Utility Demand Clear Skies Demand Utility Boilermaker Supply 

Figure 6-2. Boilermaker demand under Clear Skies Act (32 GWe of FGD installations). 

Assuming that the boilermaker membership grows at a 5.3 percent growth rate out to 2005, it is estimated 

that there will be sufficient new boilermaker labor to complete approximately 10 GWe of scrubber 

retrofits by 2005. Considering that 4 GWe of scrubber capacity is either being built or recently 

constructed, it is conservatively assumed than an additional 6 GWe could be completed by 2005. This 

estimate of 10 GWe of scrubber retrofits by 2005 was determined from the difference between the 

boilermaker labor hours available from the boilermaker membership working in the electric utility 

industry and the labor hours needed to complete control technology retrofits and other electric utility 

projects. This estimate is supported by the number of orders of FGDs for 2001 and projected orders 

through 2002 by the electric utility industry, which totals over 11 GWe

46, and over 13 GWe of announced 

scrubbers which are scheduled to start up by 2005. Orders for scrubbers, such as the recent order for the 

Coleman Station in Kentucky, are continuing to be received in spite of the concerns raised about the 

availability of boilermaker labor during the simultaneous installation of SCRs for the NOX SIP Call. The 

other electric utility projects that boilermakers work on include such projects as routine maintenance at 

operating plants and new plant construction, which account for approximately 13,500,000 man-hours of 

44
boilermaker labor per year.30 Figure 6-3 compares the available boilermaker labor to the demand from 

the electric utility industry which includes the retrofits from the Clear Skies Act. 

Boilermaker Supply vs. Clear Skies Demand 

(10 GWe Scrubber Installations by 2005) 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 

Boilermaker Labor 

(1000 man-hrs) 

Other Utility Demand Clear Skies Demand Utility Boilermaker Supply 

Figure 6-3. Boilermaker demand under Clear Skies Act (10 GWe of FGD installations). 

Since boilermakers earn more money than most other craft trades42 and the demand for boilermakers 

should be steady and increasing, it is reasonable to expect that the growth in boilermaker numbers 

experienced these last few years should continue for many more years. To assess the impact of this, it 

was assumed that the boilermakers in the U.S. continued to grow at the 5.3 percent pace that the 

International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers, and Helpers has set 

as a minimum growth target. Based upon the estimates of Table 6-3 and the assumed growth rates, the 

annual boilermaker demand created by the Clean Skies Act can be estimated and is shown in Table 6-4. 

Table 6-4 was derived considering that 14 GWe of SCRs have already been installed for the NOX SIP 

Call, so the remaining 71 GWe of SCR and 10 GWe of scrubber installations were considered for 2005. 

According to Table 6-4, if the retrofit of the FGD, SCR, and ACI systems for 2005 occur over thirty-one 

months prior to 2005 and over a three-year period for each five-year increment after 2005 to 2020, the 

maximum demand would be about 23 percent of the journeyman boilermakers or about 19 percent for 

journeymen and apprentices combined. 

Considering only the boilermakers who are currently in demand by the utility industry, the demand would 

be about 38 percent of the journeyman boilermakers or about 31 percent for journeymen and apprentices 

combined. These percentages of demand are expected to be experienced prior to 2010, but with growth 

in the boilermaker numbers out to 2010, the percent of boilermakers affected drops off. The number of 

boilermakers in demand for retrofit installations under the Clear Skies Act is spread fairly evenly out to 

2010 when the demand begins to decrease. However, there may still be significant demand for 

boilermakers after 2010 from other power plant construction programs. 

45
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vÉ~ê OMMM OMMR OMNM OMNR OMOM

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The actual impact on the demand for boilermakers could be lower for several reasons. Due to the longer 

increments of time that the Clear Skies Act provides facility owners to comply than was assumed in this 

analysis, installation of these technologies will extend over more than three years, spreading out the 

demand. As stated earlier, this analysis does not consider any of the synergies or efficiencies that have 

been demonstrated to occur on multiple unit retrofits or multiple-technology retrofits. The boilermaker 

population has been growing at a faster rate– 6.7 percent annually – in recent years than the union’s 

minimum target of 5.3 percent that was assumed. Therefore, the number of boilermakers may actually 

grow more quickly than what was assumed. This analysis also neglects overtime, which would reduce 

the demand for workers somewhat. 

SKP `çåëíêìÅíáçå=bèìáéãÉåí

Most of the construction equipment necessary for the installation of SCR, FGD, and ACI technology is 

standard construction equipment that is used for most construction activities. The piece of equipment 

that is not standard that may be needed for SCRs and possibly for FGD systems is a tall-span heavy-lift 

crane. These cranes are necessary to lift heavy pieces (sometimes over 100 tons) several hundred feet 

and are not needed for all projects. When the largest piece to be lifted is determined from the 

construction plan, the necessary crane can be determined. In some cases, the available crane or the crane 

pricing may limit the largest piece to be lifted, and the construction plan may be modified to 

accommodate a smaller crane by lifting smaller pieces. In many instances, the best crane for the job is 

46
not the largest because the large cranes are very expensive to rent (one size up could double or triple the 

monthly charges for renting the crane30). As a result, it may be more cost effective overall to use a 

smaller crane and lift smaller pieces. This may lengthen the installation time slightly, but it will reduce 

crane rental fees. Therefore, an economic trade off must be assessed for each project. 

As discussed in Section 3.3, utility engineers reported that while installing SCRs for the NOX SIP Call, 

crane availability has been an issue that can be accommodated with proper planning. The construction 

plan could be modified to employ the available or most cost-effective crane. Therefore, sufficient supply 

of construction equipment is expected to be available for installing air pollution control equipment. 

SKQ oÉ~ÖÉåíë

The major groups of reagents considered in this Section include limestone for FGD systems, SCR 

catalyst, Ammonia/Urea, and AC for ACI systems. 

iáãÉëíçåÉ=Ñçê=cda=póëíÉãë

Limestone is used for a wide range of purposes in the United States. Overall limestone usage increased 

22 percent over the four years from 1995 to 1999 (annualized growth of 5.1 percent). Table 6-5 shows 

the production of crushed limestone sold or used by U.S. producers. 

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NVVU NIMRMIMMM

NVVT NIMNMIMMM

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NVVR UUQIMMM

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As noted in Chapter Two, 500 MWe plant firing 4.0 percent sulfur coal and equipped with LSFO FGD 

technology will use about 32 tons per hour of limestone, or about 240,000 tons/yr (about 0.064 

tons/MWh), and limestone consumption for MEL technology would be less.6 Using an LSFO 

consumption rate is conservatively high, and Table 6-6 shows expected consumption rates if all projected 

FGD retrofits were LSFO technology and operated at 85 percent capacity factor. The row 

“Multipollutant & Current Rule FGD Limestone Consumption (tons)” provides an estimate of the 

limestone consumption for the projected retrofits due to the multipollutant strategy and current air quality 

rules. The row “Cumulative FGD Limestone Consumption (tons)” provides an estimate of the limestone 

consumption for the cumulative total number of FGD installations, which includes 94 GWe of current 

installations. As shown, the impact to total U.S. production for the multipollutant strategy remains less 

than 2 percent out to 2020 while the overall demand from all installed FGD remains less than 4 percent 

out to 2020. 

47
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p`o=`~í~äóëí

SCR catalyst is a critical part of the SCR system that is manufactured on a worldwide basis by some of 

the largest companies in the world. Manufacturing is largely in the United States, Europe, and Japan, and 

the worldwide capacity is used to support worldwide sales. The current and planned capacity of SCR 

catalyst supply available to the U.S. market for coal-fired boilers is nearly 90,000 m3

/yr. Table 6-7 

shows the results of a survey of major suppliers of SCR catalyst to coal-fired boilers. The suppliers 

provided EPA their current capacity and the capacity that will be on line in the year 2002. The estimated 

capacity of other suppliers of catalyst to coal-fired boilers that could not be reached in time for this study 

is listed also. Suppliers that have offered catalyst for coal applications in the past but currently focus 

strictly on gas and oil -fired applications were not included. However, it is recognized that these 

companies could shift their product mix if the market conditions justified it, so the capacity value shown 

could be quickly increased if manufacturers simply changed product focus. 

The current capacity was originally built overseas to meet overseas demand or was subsequently built to 

meet U.S. demand for catalyst spurred by the NOX SIP Call and the build up of gas turbine power plants 

in the U.S. Except for a moderate demand for replacement catalyst, much of this capacity will be 

available after 2004 because these large demand peaks will have mostly passed. Because most of the 

companies that supply catalyst are divisions of very large companies with the resources to rapidly expand 

their manufacturing capacity to meet increases in market demand, it is reasonable to assume that this 

manufacturing capacity could be expanded if the market demand justified it. In fact, recent capacity 

expansions provide strong evidence of this. 

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48
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Currently, the equivalent of approximately 100 GWe of coal, oil, and gas-fired capacity worldwide 

utilizes SCR technology. At these worldwide installations, the volume of SCR catalyst in use is 

estimated to be approximately 55,000 to 95,000 m3

.

10 Assuming that one-twelfth of the current catalyst is 

replaced each year on average, the annual demand for replacement SCR catalyst is approximately 5,000 

to 8,000 m3/yr. Note that the estimate for the current annual demand is quite conservative since the 

catalyst replacement rate on oil- and gas-fired combustion units is likely to be less frequent than onetwelfth of the catalyst per year. By 2005, an additional 85 GWe of coal-fired SCR capacity is expected to 

be on line in response to the NOX SIP Call and recently promulgated State rules (this includes anticipated 

SCR retrofits under the state rules for Missouri, Connecticut, and Texas). Assuming conservatively that 

one-eighth of the catalyst is replaced each year on average for coal-fired units, the annual demand for 

replacement SCR catalyst would increase by 12,600 m3

/yr by 2005. Adding the current annual 

replacement demand from worldwide installations to the projected annual replacement demand under the 

Clear Skies Act would yield a total of 17,600 - 20,600 m3

/yr demand for replacement catalyst by 2005.10 

The estimated annual demand for catalyst from the Clear Skies Act, which consists of the demand due to 

new installations and annual replacement is shown in Table 6-8. The highest catalyst demand will occur 

by 2010. From Table 6-7, the estimated capacity of catalyst supply is 87,300 m3

/yr. Considering the 

initial fill demand of 26,000 m3

/yr from 65 GWe of SCR installations and replacement demand of 22,300 

m3

/yr from 150 GWe of cumulative SCR installations plus the worldwide catalyst replacement demand 

of between 5,000 and 8,000 m3

/yr, the annual excess capacity is estimated to be 31,000 to 34,000 m3/yr. 

A more conservative approach to determining if there is sufficient catalyst supply to meet the demand 

from the Clear Skies Act is demonstrated in Figure 6-4. It compares the current cumulative production 

capacity for SCR catalyst to the cumulative annual demand for SCR catalyst from the total SCR 

installations in 2005 and 2010. This approach assumes that the annual production of catalyst continues at 

the current level of 87,300 m3

/yr and starts accumulating in May 2002. If all SCR systems were loaded 

with catalyst in just a one year period prior to 2005 and 2010 instead of spreading out the loading over 

several years, there would be sufficient accumulated supply to meet the increased demand. 

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49
Cumulative SCR Catalyst Production Capacity 

vs Cumulative Clear Skies Demand 

0 

100 

200 

300 

400 

500 

600 

700 

800 

2002 2003 2004 2005 2006 2007 2008 2009 2010 

Catalyst (1000 m3/yr) 

Clear Skies Cumulative Initial Fill Demand Clear Skies Cumulative Replacement Demand 

Cumulative Production Capacity 

Figure 6-4. Cumulative SCR catalyst demand compared to cumulative production capacity. 

Utility power plants are already installing SCR catalyst for the purpose of NOX SIP Call compliance in 

2004. As shown in Figure 6-4, the cumulative demand from the Clear Skies Act plus the worldwide 

demand can be met with the total cumulative confirmed capacity. Consequently, adequate capacity of 

SCR catalyst supply is available to satisfy the demand that may result from the projected installations. 

Of course, as demonstrated by the catalyst suppliers, if more capacity was desirable to satisfy the market, 

it could be added given sufficient lead time for the construction of the catalyst production facility. 

The ability to retrofit a large number of SCR systems over a short period of time was exemplified in 

Germany during the late 1980s. Figure 6-5 shows the number of systems installed over an eight-year 

period, with most of these systems (97 of 137) installed during two consecutive years (1989-1990). This 

pattern of installations exhibits that the catalyst market demonstrated the ability to respond to the surge in 

demand resulting from a dramatic increase in SCR installations. 

^ããçåá~=~åÇ=rêÉ~

The installation and operation of SCR systems is not expected to be constrained by the future availability 

of ammonia or urea. The production of anhydrous ammonia in the U.S. in 2000 was approximately 

17,400,000 tons (equivalent anhydrous) with apparent consumption of 22,000,000 tons and about 

4,600,000 met through net imports, as shown in a 2001 edition of U.S. Geological Survey Minerals 

Commodity Summaries. Ammonia demand is directly proportional to the tons of NOX reduced. The 

increased ammonia demand from a multipollutant rule is estimated to increase to about 1,040,000 tons 

per year by 2020. This 4 percent increase in demand over a nearly 20-year period can easily be met. 

Moreover, the U.S. and worldwide ammonia business is struggling because of slumping domestic 

demand and increased global capacity for the product and other nitrogen fertilizers derived from it, such 

as urea. Nevertheless, more capacity is scheduled to come on in the U.S. during the near future. In 

addition, 1.2 million tons of capacity is being built in Trinidad and Venezuela. Algeria and the former 

Soviet Union have also added significant capacity. Another problem is the withdrawal of China as an 

importer of ammonia. China traditionally bought 3 to 6 million tons of urea annually (which is produced 

50
from ammonia), but in 1996, the country launched a drive to become self-sufficient in urea, a move that 

has displaced 1.9 to 3.7 million tons of ammonia.47 Based on these estimates, the ability to supply of 

ammonia will continue to exceed its demand, even with the additional demand from newly installed SCR 

systems. 

SCR systems can also use urea as a reagent, and it is becoming preferred to ammonia in many cases 

because of its safety. Urea is a commonly available chemical with approximately 11,760,000 tons of 

domestic annual production capacity.48 For SCR purposes, this adds effectively another 6.7 million tons 

of ammonia annually available as SCR reagent.* Additionally, U.S. urea manufacturers and distributors 

routinely trade within a 130,000,000 tons worldwide annual production capacity.10 Based on total world 

urea trade, increased demand due to a multipollutant regulation would be well under 2 percent of world 

trade if all SCRs used urea rather than ammonia. And, like ammonia, the urea market is currently 

experiencing an oversupply situation. Urea prices have fallen precipitously since China, formerly a 

major buyer, decided to strive for self-sufficiency. From 1994 to 1997, China opened nine new urea 

plants and raised its domestic production by 50 percent. U.S. producers knew China would bring on the 

new, more-efficient plants, but they did not expect that country to continue running its smaller, lessefficient ones.48 Thus, it is expected that this worldwide supply will provide additional flexibility in 

meeting any significant increases in demand. Since urea production is performed on a worldwide basis, 

plants producing urea would be able to expand their capacity if needed. Based on these considerations, 

adequate urea supply is expected to be available for the SCR systems. 

60 

50 

40 

30 

20 

10 

2 

5 

7 

17 

51 

46 

6 

3 

0 

1985 1986 1987 1988 1989 1990 1991 1992 

Year 

Figure 6-5. SCR Installations on coal-fired plants in Germany. 11 # of Installations Per Year 

*

 It takes about 1.76 lbs of urea to make one lb of ammonia reagent in a urea to ammonia conversion. 

51
í íá

^`=Ñçê=^`f=póëíÉãë

AC is produced in the United States and abroad for filtration and other manufacturing purposes. Total 

AC usage in the United States was 182,887 tons/yr in 2000, as given in the U.S. Census Bureau Summary 

Current Industrial Reports for the Inorganic Chemical Industry. Capacity in the U.S. is equal to 465 

million pounds/yr, or 233,000 tons.49 Both of these numbers include both granular and powdered carbon, 

powdered being preferable to granular for ACI applications. U.S. demand is projected to grow to 454 

million pounds, or about 227,000 tons, in 2004.49 However, large underutilized capacity overseas will 

provide a ready supply of potential imports, which will tend to limit price increases for most grades.49 

The competition from Chinese and South-East Asian producers remains strong.50 Chinese exports 

quadrupled from 53,230 tons in 1995 to 224,331 tons in 1997, with the average product cost dropping by 

16 percent to 660/ton. Therefore, growth in demand experienced in the 1990’s has not been reflected in 

the value of the market due to over-capacity and the continued rise in Asian exports. AC producers are 

concentrating increasingly on the Asia-Pacific region to exploit growing markets and take advantage of 

lower production costs; reported capacity expansions of over 15,000 tons/yr are all planned for AsiaPacific and Russia.50 

According to Norit, the largest supplier of AC for air pollution control purposes, there is currently 

adequate excess capacity to accommodate significant growth in the demand (tens of millions of 

pounds/yr, or roughly tens of thousands of tons/yr).51 However, depending upon how much growth 

occurs as a result of regulation, additional capacity may be necessary. It would take 2-3 years to add a 

plant; and this would only be done after a regulation was put in place, the technical advantages of ACI 

for mercury removal were proven relative to other approaches, and a clear time-line for compliance was 

mandated.51 Therefore, even if a multipollutant strategy implementation causes a large increase in 

demand for AC, provided that the timing of compliance was clear and far enough in the future, adequate 

supply of AC should be assured. 

EPA estimated that, of the total 1,300 MWe to be retrofit by 2020 with ACI, all of that capacity would 

have existing fabric filters. 36 As mentioned before, EPA’s modeling indicates that none of the total MWe 

of ACI retrofits will include a PJFF.36 AC usage nationally for mercury control from power plants 

should be roughly proportional to the total MWe of coal-fired facilities that are equipped with the 

technology (this assumes an average capacity factor of 85 percent and other assumptions of Tables 4-4 

and 4-5). Table 6-9 shows the results of this analysis. Based upon this analysis, it is possible that 

existing excess capacity in AC production could adequately address the increased demand for AC. And, 

even if ACI is more broadly used than anticipated by EPA (more than 1,300 MWe), it is clear that with at 

least 2-3 years of preparation time to build more production capacity the AC industry can accommodate 

any additional demand. 

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52
SKR `êÉ~íáçå=çÑ=gçÄë=ìåÇÉê=`äÉ~ê=pâáÉë=^Åí=ÇìÉ=íç=`çåíêçä=qÉÅÜåçäçÖó

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The Clear Skies Act is expected to create jobs for those directly involved in the retrofit of facilities. 

These have been estimated in Section 6.2 of this document. In addition to the jobs that are directly 

created by this activity, jobs will be created indirectly as a result of the economic activity that is 

stimulated by additional discretionary income workers will have. Workers that are directly employed on 

these clean air projects will purchase consumer goods and services, which will stimulate additional 

economic activity. To account for these indirect effects of economic activity, economists use economic 

multipliers that are related to worker’s marginal propensity to consume. Economic multipliers of 2 to 3 

are often used.52 Using the lower multiplier of 2 and the total labor estimates of Table 6-3, 25,000 

additional jobs may be created through indirect economic activity (2 times the peak direct labor level of 

12,500 workers indicated in Table 6-3). This effect does not consider the additional job-gain potential 

from U.S.-based equipment suppliers that export to other countries the clean-air technology know-how 

they will gain from these clean-air programs. 

53
`Ü~éíÉê=T

`çåÅäìëáçåë

This report evaluated the resources necessary to comply with the Clear Skies Act for which EPA 

estimated, by using the IPM, the number, and size of facilities that will have to install new hardware. 

The control technologies considered by this report as candidates to be used for this multipollutant control 

strategy include: 

Ŷ LSFO for the control of SO2; 

Ŷ SCR for the control of NOX; and 

Ŷ ACI for the control of mercury. 

Based upon the IPM-generated information from EPA and the characteristics of the technologies listed 

above, the total resources needed to comply with the multipollutant control strategy were estimated and 

compared to the available resources. The availability of resources was based on their current market 

demand and does not reflect the increased production capacity that a multipollutant strategy may create. 

It is likely that the market for materials, labor, construction equipment, and other resources used in the 

construction and operation of air pollution control technologies would respond by increasing production 

to meet demand where needed. 

Installation of wet FGD, specifically LSFO, presents a conservatively high estimate of anticipated 

resources and time to provide additional control of SO2 emissions. LSFO systems commonly are more 

resource intensive than many other FGD technologies. Conservatively high assumptions were made for 

the time, labor, reagents, and steel needed to install FGD systems. Although FGD installations are time 

and labor intensive, they are typically planned and installed within normally scheduled outages. It is 

expected that one FGD system requires about 27 months of total effort for planning, engineering, 

installation and startup. Modern FGD systems typically use fewer and smaller absorbers and 

increasingly control greater amounts of generating capacity using common absorbers fed by multiple 

boilers. Under the Clear Skies Act, three absorber systems for six boilers are anticipated to handle 2,400 

MWe of capacity. The estimate of labor includes planning and engineering, general labor, and skilled 

boilermakers. Construction of absorbers off-site is one way that projects can control project resources, 

schedules, and labor. 

Steel is the major hardware component for FGD systems. Structural steel is used primarily for the 

absorber, ductwork, and supports, and secondarily in miscellaneous components including reinforcement 

of existing structures at a facility. FGD systems are installed on the back end of a facility, are usually 

built close to the ground, and do not require the amounts of structural steel generally associated with 

elevated installations such as SCR. By comparison, the conservative estimate of the amount of steel 

required for a full FGD system is less than or equal to that required for an SCR retrofit. Corrosion and 

abrasion resistant materials are increasingly being applied with success in modern FGD systems to 

improve reliability and long-term performance. The total demand for additional FGD installations will 

be modest and is expected to be well within the anticipated steel capacity, even with demands from other 

applications. 

54
Construction equipment requirements for FGD installations are typically modest, particularly given that 

systems are installed at the back end of the facility and close to the ground. However, experience has 

indicated that project planning can surmount even difficult situations (e.g., prefabrication and jacking up 

components). Experience has also shown that specific site issues, while often a planning challenge, have 

not prevented installations of FGD systems. More recently, space requirements for construction and 

accommodating the FGD system have been addressed with the implementation of improvements in 

technology, including fewer and smaller absorbers and more efficient on-site use and treatment of wastes 

and byproducts. 

Limestone was used as an estimate of reagent for FGD systems. Experience indicates that the quantity of 

limestone is conservatively high compared to other enhanced reagents such as fine-ground limestone and 

MEL. Even with the assumption that all new FGD capacity will require limestone, the amount of 

limestone needed as a reagent is projected to be within availability of supply. 

SCR is the technology that will primarily be used for NOX control. Since it is also the most demanding 

in terms of resources needed for installation, it was assumed to be the only technology used for NOX 

control. SCR systems are primarily made from steel, standard mechanical hardware, and catalyst. 

Conservatively high assumptions were made for steel, catalyst, reagents, and the labor and equipment 

necessary to install the systems projected by the IPM that result from a multipollutant control strategy. 

The amount of ammonia or urea reagent needed can be estimated with good confidence as constituting a 

small portion of available supply. 

Experience in installing SCRs for the NOX SIP Call has shown that the SCR equipment can be installed 

on the facilities in the space provided. In some cases, moving of equipment has been necessary, but this 

has not proved to be limiting. The only specialized construction equipment that can be useful for SCR 

installations are tall, heavy-lift cranes. These appear to be in adequate supply and are not essential, since 

the erection plan can be modified to accommodate the use of smaller cranes, which are frequently more 

economical. The only specialized labor necessary for SCR installations are members of the boilermakers 

trade, and estimates of boilermaker demand were made. It is expected that one SCR system requires 

about 21 months of total effort for planning, engineering, installation, and start-up. Experience has 

shown that many installations have been completed in much shorter times. Therefore, 21 months appears 

to be somewhat conservative. 

ACI was presumed to be the technology that would be used to reduce mercury where dedicated mercury 

controls were needed because the hardware is representative of most sorbent injection technologies. 

Also, other sorbent-based approaches in development may prove in time to be preferable to ACI, making 

the use of ACI only a conservative assumption. ACI hardware is comprised of relatively common 

mechanical components and is largely made of steel. An ACI system requires much less in terms of 

steel, labor, or other resources to install than either FGD or SCR technology. Therefore, the impact of 

ACI hardware on resource demand is much less than that of FGD or SCR technologies for SO2 or NOX 

control, respectively. The only piece of equipment of any consequence in terms of size is the storage 

silo, and this piece of equipment is not so large as to pose a problem with regard to location for most 

facilities. Planning, engineering, installation, and start-up of an ACI system is only about 15 months and 

could be done in much less time if administrative matters, such as permitting, occur more quickly than 

assumed. Figures for consumption of AC were based on prior, peer-reviewed EPA work, and 

conservative operating conditions were assumed. 

In summary, this study found that the expected demand for resources resulting from a multipollutant 

control strategy could be met. However, the market is expected to adjust to changes in both the demand 

for resources under a multipollutant program and other market factors. For this reason, the longer term 

55
projections are of less value than those for the 2005 and 2010 time period. Table 7-1 shows a summary 

of resource demand and its effect on current supply. In Table 7-1 the Supply Basis may be current U.S. 

demand, capacity available to U.S. users, or other basis as appropriate and described in the table notes. 

For all resources needed for installation, it is assumed that these resources are required over a 31-month 

period prior to 2005 and a three-year period prior to 2010, 2015, and 2020. This is a very conservative 

assumption because the most complex FGD installations will require three years while the actual 

available time to complete the projected retrofits for each period, except prior to 2005, is five years. 

As shown in Table 7-1, there is ample steel and general construction labor to support the installation of 

these technologies, assuming a 31-month period of installation prior to 2005 and a three-year installation 

prior to 2010, 2015, and 2020. Moreover, the demand assumptions do not consider any efficiencies that 

can be achieved at multiple unit installations or installations of multiple technologies at a site. As 

discussed in this document, these efficiencies can reduce steel requirement somewhat and labor needs 

substantially. Demand for boilermaker labor is significant when compared to the boilermaker labor 

supply basis. However, most boilermakers (60 percent) work in the electric power industry, so it should 

not be surprising that the percentage is high. It should also be considered that the value in this table 

assumes conservatively high proportion of boilermaker labor and that the boilermaker trade grows at its 

minimum target rate of 5.3 percent. In fact, the boilermaker trade has been growing at about 6.7 percent 

annually in recent years due to the improving employment prospects for boilermakers. 

There is also ample SCR catalyst capacity to supply this market. SCR catalyst manufacturing is almost 

entirely dedicated to power generating applications. Thus, it should not be surprising that demand for 

initial fill and periodic replacement catalyst should account for a significant portion of the supply basis. 

Moreover, the U.S. market for catalyst is currently larger than all of the other national markets combined. 

With regard to reagents and other consumables, clearly there is ample supply of limestone for additional 

FGD systems, especially in light of conservatively high assumptions that were used to make these 

estimates. Ammonia and urea supply is also plentiful, although it is expected that NOX reduction will 

cause a modest increase in U.S. demand. In fact, there is currently a worldwide excess capacity problem 

for suppliers of these commodity chemicals that are traded globally. Although U.S. demand for activated 

carbon is expected to increase by a small amount as a result of a multipollutant strategy, activated carbon 

is traded on a global basis, and there is currently substantial excess capacity that can readily provide for 

this increase in demand. Suppliers have also indicated that new plants could be brought on line within 3 

years, if needed, to satisfy increased demand. Additionally, there are other technologies under 

development that potentially could reduce activated carbon demand from what is estimated here. 

56
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57
`Ü~éíÉê=U

oÉÑÉêÉåÅÉë

1. Personal Communication with R. Telez, Babcock & Wilcox, August 2001. 

2. DOE/EPRI: Materials & Components Newsletter, No. 141, August 1, 1999. 

3. Personal Communication with P. Croteau, Babcock Borsig Power, August 2001. 

4. Feeney, S., Gohara, W.F., Telez, R.W., “Beyond 2000: Wet FGD in the Next Century,” ASME 

International Joint Power Generation Conference, October 1995. 

5. Fukasawa, K., “Low Cost, Retrofit FGD Systems,” IEA Coal Research, London England, 

September 1997. 

6. Personal Communication with D. Foerter, Institute of Clean Air Companies, August 28-29, 2001. 

7. Wu, Z., “Materials for FGD Systems,” IEA Coal Research, London England, January 2000. 

8. Srivastava, R. K., Jozewicz, W., "Controlling SO2 Emissions: A Review of Technologies,” EPA600/R-00-093 (NTIS PB2002-101224), Research Triangle Park, NC, December 2000. 

9. Personal Communication with S.Kumar, FLS miljo, September 2001. 

10. U.S. Environmental Protection Agency, “Feasibility of Installing NOX Control Technologies by 

May 2003,” September 1998. 

11. Bultmann, A., Watzold, F., “The Implementation of National and European Legislation 

Concerning Air Emissions from Large Combustion Plants in Germany,” UFZ-Centre for 

Environmental Research Leipzig-Halle, August 2000. 

12. North American Electric Reliability Council (NERC), “Impact of FGD Systems: Availability 

Losses Experienced by Flue Gas Desulfurization Systems,” NERC Generating Availability Trend 

Evaluations Working Group, July 1991. 

13. Personal Communication with J. Bushman, Alstom Power, February 19, 2002. 

14. Klingspor, J.S., Brown, G.N., “Techniques for Improving FGD System Performance to Achieve 

Ultra-High SO2 Removal Efficiencies,” In the Proceedings of the U.S. EPA-DOE-EPRI 

Combined Power Plant Air Pollutant Control Symposium: The Mega Symposium and The 

A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, 

August 20-23, 2001. 

15. Advanced Flue Gas Desulfurization Demonstration Project, DOE/NETL project fact sheet, 

http://www.lanl.gov/projects/cctc/factsheets/puair/adflugasdemo.html 

16. Feeney, S., Gohara, W.F., Telez, R.W., “Beyond 2000: Wet FGD in the Next Century,” Presented 

at the ASME International Joint Power Generation Conference, October 1995. 

58
17. CT-121 Chiyoda Thoroughbred 121 Flue Gas Desulfurization Process, http://www.chiyodacorp.com/select business, environmental preservation, Chiyoda Thoroughbred 121 (CT-121) 

FGD process 

18. Claussen, R. L., Martin, C. E., Smith, P. V., Oberjohn, W. J., Weber, G. F., “Engineering and 

Design Guidelines for Duct Injection Retrofits,” In the Proceedings of the 1993 SO2 Control 

Symposium, Boston, MA, 1993. 

19. Nischt, W., Woolridge, B., Hines, J., Robison, K., “Selective Catalytic Reduction Retrofit of a 

675 MWe Boiler at AES Somerset,” Presented at the ICAC Forum 2000, Washington, DC, March 

23-24, 2000. 

20. Siemens, Kat Treff ’97, Washington, D.C. June 3-5, 1997. 

21. Personal Communication with J. Urbas, Reliant Energy, August 13, 2001. 

22. Glaser, R., Licata, A., Robinson, T., “The SCR Retrofit at the Montour Steam Electric Station,” 

Electric Power Generation Association Meeting, Hershey, PA, October 24-25, 2000. 

23. Hartenstein, H., Servatius, P., Schluttig, A., "Lifetime Extension of SCR De-NOx Catalysts Using 

SCR-Tech's High Efficiency Ultrasonic Regeneration Process," Presented at the Coal-Gen 

Conference, Chicago, IL, July 25-27, 2001. 

24. Personal Communication with M. Gialanella, Hamon Research Cottrell, August 7, 2001. 

25. Air Daily, “For Now, Labor Capable of Meeting SCR Demand,” Clear Air Regulations and 

Markets, Vol. 8, No. 138, July 18, 2001. 

26. Personal Communication with a utility engineer that asked to remain anonymous, August 6, 

2001. 

27. Personal Communication with J. Bushman of Alstom, August 8, 2001. 

28. Babb, B., Angelini, E., Pritchard, S., “Implementation of SCR System at TVA Paradise Unit 2,” 

Presented at the ICAC Forum 2000, Washington DC, March 23-24, 2000. 

29. Cochran, J., Hellard, D., Rummenhohl, V., “Design and Initial Startup Results from the New 

Madrid SCR Retrofit Project,” Presented at the ICAC Forum 2000, Washington DC, March 23-

24, 2000. 

30. Hines, J., Kokkinos, A., Fedock, D., “Design for Constructability – A Method for Reducing SCR 

Project Costs,” In the Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air 

Pollutant Control Symposium: The Mega Symposium and The A&WMA Specialty Conference 

on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, August 20-23, 2001. 

31. Personal Communication with T. Licata, Babcock Borsig Power, February 20, 2002. 

32. Personal Communication with T. Licata, Babcock Borsig Power, August 3, 2001. 

33. Personal Communication with C. Martin of ADA Environmental Solutions, August 14, 2001. 

34. Personal Communication with M. Durham, ADA Environmental Solutions, August 3, 2001. 

35. E-mail from Rich Miller, Hamon Research-Cottrell, March 19, 2002. 

59
36. Personal Communication with Chad Whiteman, U.S. Environmental Protection Agency, February 

22, 2002. 

37. Personal Communication with John Bushman, Alstom, July 10, 2001. 

38. Burnett, G., Tonn, D., Redinger, K., Snyder, R., Varner, M., “Integrated Environmental Control 

On the 21st Century’s First New Coal-Fired Boiler,” In the Proceedings of the U.S. EPA-DOEEPRI Combined Power Plant Air Pollutant Control Symposium: The Mega Symposium and The 

A&WMA Specialty Conference on Mercury Emissions: Fate, Effects, and Control, Chicago, IL, 

August 20-23, 2001. 

39. Electricity production, Energy Information Administration web site 

http://www.eia.doe.gov/cneaf/electricity/epav1/elecprod.html . 

40. Personal Communication with Tony Licata, Babcock Borsig Power, February 20, 2002. 

41. Bureau of Labor Statistics Website, Industry at a Glance, Construction, http://www.bls.gov/iag/ 

iag.construction.htm. 

42. “Market Gyrations Make Hitting Targets for Skilled Crafts an Art”, Power Magazine, vol. 146, 

no. 1, January/February 2002, pp. 28-32. 

43. Hines, J., Jones, W., Wasilewski, K., “Reliant Energy SCR Construction Implementation Plan”, 

presented at ICAC Forum 2002, Houston, February 12-13, 2002. 

44. Personal Communication with Ande Abbot, International Brotherhood of Boilermakers, Iron Ship 

Builders, Blacksmiths, Forgers and Helpers, February 5, 2002. 

45. Personal Communication (2) with Ande Abbot, International Brotherhood of Boilermakers, Iron 

Ship Builders, Blacksmiths, Forgers and Helpers, February 22, 2002. 

46. Institute of Clear Air Companies, “Equipment Market Forecasts,” Issue Number 20, September 

2001. 

47. Chemexpo.com web site, November 29, 1999, http://www.chemexpo.com/news/newsframe.cfm? 

framebody=/news/profile.cfm. 

48. Chemexpo.com web site, December 13, 1999, http://www.chemexpo.com/news/newsframe.cfm? 

framebody=/news/profile.cfm. 

49. Chemexpo.com web site, April 23, 2001, 

http://www.chemexpo.com/news/PROFILE010423.cfm. 

50. Roskill Information Services Website, http://www.roskill.co.uk/acarbon.html 

51. Personal Communication with Bob Thomas, Norit Americas, September 6, 2001. 

52. Institute of Clean Air Companies, White Paper, November 2001. 

60
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Exhibit A-1: Single FGD

Exhibit A-2: Three FGD Modules on Six Units

Exhibit A-3: Single SCR

Exhibit A-4: Seven SCRs

Exhibit A-5: Single ACI

Exhibit A-6: Two ACIs

Exhibit A-7: Single FGD and SCR

Exhibit A-8: Single FGD and ACI

Exhibit A-9: Single SCR and ACI

iÉÖÉåÇW

Major Task – Dark Gray

Subtask – Light Gray

Key Completion Point – Black

A-1
A-2

Exhibit A-1: Single FGD Months 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies Develop and Send Request for Bids Receive, Review and Negotiate Bids Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery Construction: Pre Hookup Construction: Control Device Hookup (Eqmt outage) Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission Construction Permit - State Review and Draft Proposal Construction Permit - Public Comment Construction Permit - Approval (final) 

Title V Operating Permit Modification 

Title V Permit Application Preparation and Submission Title V Permit Application - State Review Title V Permit Application - Public Comment Initial Compliance Stack Testing Receipt of Title V Operating Permit 
A-3

Exhibit A-2: Three FGD Modules on Six Units Months 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies Develop and Send Request for Bids Receive, Review and Negotiate Bids Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery Module #1: Construction: Pre Hookup Module #1: Construction: Control Device Hookup (Eqmt outage) 

Module #1: Control Technology Testing 

Module #2: Construction: Pre Hookup 

Module #2: Construction: Control Device Hookup (Eqmt outage) 

Module #2: Control Technology Testing 

Module #3: Construction: Pre Hookup 

Module #3: Construction: Control Device Hookup (Eqmt outage) 

Module #3: Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission State Review and Draft Proposal Public Comment Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission State Review 

Public Comment Module #1: Initial Compliance Stack Testing Module #1: Receipt of Title V Operating Permit Module #2: Initial Compliance Stack Testing Module #2: Receipt of Title V Operating Permit Module #3: Initial Compliance Stack Testing Module #3: Receipt of Title V Operating Permit 
A-4

Exhibit A-3: Single SCR Months 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies 

Develop and Send Request for Bids Receive, Review and Negotiate Bids Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery 

Construction: Pre Hookup 

Construction: Control Device Hookup (Eqmt outage) Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission State Review and Draft Proposal Public Comment Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission State Review Public Comment 

Initial Compliance Stack Testing 

Receipt of Title V Operating Permit 
A-5

Exhibit A-4: Seven SCRs (pg 1 of 2) Months 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies 

Develop and Send Request for Bids 

Receive, Review and Negotiate Bids 

Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery Unit #1: Construction: Pre Hookup Unit #1: Construction: Control Device Hookup (Eqmt outage) Unit #1: Control Technology Testing Unit #2: Construction: Pre Hookup Unit #2: Construction: Control Device Hookup (Eqmt outage) Unit #2: Control Technology Testing Unit #3: Construction: Pre Hookup Unit #3: Construction: Control Device Hookup (Eqmt outage) Unit #3: Control Technology Testing Unit #4: Construction: Pre Hookup Unit #4: Construction: Control Device Hookup (Eqmt outage) Unit #4: Control Technology Testing Unit #5: Construction: Pre Hookup Unit #5: Construction: Control Device Hookup (Eqmt outage) Unit #5: Control Technology Testing Unit #6: Construction: Pre Hookup Unit #6: Construction: Control Device Hookup (Eqmt outage) Unit #6: Control Technology Testing Unit #7: Construction: Pre Hookup Unit #7: Construction: Control Device Hookup (Eqmt outage) Unit #7: Control Technology Testing 
A-6

Exhibit A-4: Seven SCRs (pg 2 of 2) 

123456789 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 

Construction Permit 

Permit Application - Preparation and Submission 

State Review and Draft Proposal Public Comment Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission 

State Review 

Public Comment 

Unit #1 Initial Compliance Stack Testing 

Unit #1 Receipt of Title V Operating Permit 

Unit #2 Initial Compliance Stack Testing 

Unit #2 Receipt of Title V Operating Permit 

Unit #3 Initial Compliance Stack Testing 

Unit #3 Receipt of Title V Operating Permit 

Unit #4 Initial Compliance Stack Testing 

Unit #4 Receipt of Title V Operating Permit 

Unit #5 Initial Compliance Stack Testing 

Unit #5 Receipt of Title V Operating Permit 

Unit #6 Initial Compliance Stack Testing 

Unit #6 Receipt of Title V Operating Permit 

Unit #7 Initial Compliance Stack Testing 

Unit #7 Receipt of Title V Operating Permit 

Months 
A-7

Exhibit A-5: Single ACI Months 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies Develop and Send Request for Bids 

Receive, Review and Negotiate Bids Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery Construction: Pre Hookup Construction: Control Device Hookup (Eqmt outage) Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission State Review and Draft Proposal Public Comment Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission State Review Public Comment 

Initial Compliance Stack Testing 

Receipt of Title V Operating Permit 
A-8

Exhibit A-6: Two ACIs Months 

123456789 10 11 12 13 14 15 16 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies Develop and Send Request for Bids Receive, Review and Negotiate Bids Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery Unit #1: Construction: Pre Hookup Unit #1: Construction: Control Device Hookup (Eqmt outage) Unit #1: Control Technology Testing Unit #2: Construction: Pre Hookup Unit #2: Construction: Control Device Hookup (Eqmt outage) Unit #2: Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission State Review and Draft Proposal Public Comment 

Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission 

State Review Public Comment 

Unit #1 Initial Compliance Stack Testing 

Unit #1 Receipt of Title V Operating Permit 

Unit #2 Initial Compliance Stack Testing 

Unit #2 Receipt of Title V Operating Permit 
A-9

Exhibit A-7: Single FGD and SCR Months 

123 4567 89 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies 

Develop and Send Request for Bids 

Receive, Review and Negotiate Bids 

Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery 

Construction: Pre Hookup 

Construction: Control Device Hookup (Eqmt outage) 

Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission 

State Review and Draft Proposal 

Public Comment 

Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission 

State Review 

Public Comment Initial Compliance Stack Testing 

Receipt of Title V Operating Permit 
A-10

Exhibit A-8: Single FGD and ACI Months 

12345 6789 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies 

Develop and Send Request for Bids 

Receive, Review and Negotiate Bids 

Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery 

Construction: Pre Hookup 

Construction: Control Device Hookup (Eqmt outage) 

Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission State Review and Draft Proposal Public Comment Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission State Review Public Comment Initial Compliance Stack Testing Receipt of Title V Operating Permit 
A-11

Exhibit A-9: Single SCR and ACI Months 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 

Facility Engineering Review and Award of Contract 

Engineering Assessment of Technologies 

Develop and Send Request for Bids Receive, Review and Negotiate Bids Award Contract to Technology Provider 

Control Technology Installation 

Engineering Fabrication Delivery Construction: Pre Hookup 

Construction: Control Device Hookup (Eqmt outage) Control Technology Testing 

Construction Permit 

Permit Application - Preparation and Submission State Review and Draft Proposal Public Comment Approval (final) 

Title V Operating Permit Modification 

Preparation and Submission State Review Public Comment Initial Compliance Stack Testing Receipt of Title V Operating Permit