CURRENT CAPITAL COST AND COST-EFFECTIVENESS

OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES

Prepared by

J. Edward Cichanowicz

Prepared for

Utility Air Regulatory Group

July 2013
TABLE OF CONTENTS

SECTION 1 OVERVIEW AND SUMMARY 1-1

SECTION 2 BACKGROUND 2-1

2.1 Introduction 2-1

2.2 Environmental Mandates 2-1

2.3 FGD and SCR Inventory 2-2

2.3 New Generating Stations 2-6

SECTION 3 FACTORS AFFECTING REPORTED CAPITAL COST 3-1

3.1 Capital Cost Reporting Methodology 3-1

3.2 Capital Cost Escalation 3-2

3.3 Site and Design Factors 3-2

SECTION 4 MATERIAL AND LABOR ESCALATION 4-1

4.1 Basic Materials 4-1

4.2 Construction Labor 4-4

SECTION 5 FLUE GAS DESULFURIZATION COSTS 5-1

5.1 FGD Capital Costs 5-1

5.1.1 Wet FGD 5-1

5.1.2 Dry FGD 5-3

5.2 FGD Operating Cost 5-4

5.2.1 Wet FGD 5-5

5.2.2 Dry FGD 5-5

5.3 Levelized Removal Cost Per Ton 5-6

SECTION 6 SELECTIVE CATALYTIC REDUCTION COST 6-1

6.1 SCR Capital Cost 6-1

6.2 Operating Cost 6-4

6.2.1 SCR Catalyst 6-5

6.2.2 Reagent 6-6

6.2.3 Example Operating Cost 6-7

6.2.4 Levelized Removal Cost Per Ton 6-8
SECTION 7 FABRIC FILTER CONTROL TECHNOLOGY COSTS 7-1

7.1 Fabric Filter Capital Cost 7-2

7.1.1 Good Site Access 7-3

7.1.2 Limited Site Access 7-4

7.2 Example Operating Cost 7-6

7.2.1 Fixed O&M 7-6

7.2.2. Variable O&M. 7-6

7.3 Levelized Cost 7-7

SECTION 8 COST COMPETITIVENESS 8-1

8.1 Power Market Reference 8-1

8.2 SCR, FGD Reference Unit Cost 8-3

8.3 Role of Fabric Filter 8-4

APPENDIX A EXAMPLE WET FGD CAPITAL COST DATA A-1

APPENDIX B EXAMPLE SCR CAPITAL COST DATA B-1
LIST OF FIGURES

Figure 2-1. Historical and Projected Wet, Dry FGD Capacity: Installed MW 

per Year....................................................................................................... 2-3

Figure 2-2. Historical and Projected Wet, Dry FGD Capacity: Cumulative MW 

per Year....................................................................................................... 2-3

Figure 2-3. Historical and Projected SCR Capacity: Annual Installed Capacity 

(MW)........................................................................................................... 2-4

Figure 2-4. Historical and Projected SCR Capacity: Cumulative Installed SCR 

Capacity (MW) ........................................................................................... 2-5

Figure 2-5. Historical, Projected FGD and SCR Annual Capacity (MW)...................... 2-5

Figure 2-6. Historical, Projected FGD and SCR Cumulative Capacity (MW)............... 2-6

Figure 3-1. Bureau of Economic Analysis (BEA) Implicit GDP Deflator..................... 3-3

Figure 3-2. First Energy Sammis Station: Constrained Site .......................................... 3-6

Figure 3-3. Confined Site at PNM San Juan Station: Retrofit Fabric Filters, Upgraded 

FGD, Candidate SCR Locations................................................................. 3-8

Figure 4-1. Steel Mill Products Cost History ................................................................. 4-2

Figure 4-2. Iron Ore Cost Escalation .............................................................................. 4-2

Figure 4-3. Price History Escalation: Nickel, Molybdenum, and Copper..................... 4-3

Figure 4-4. U.S. Bureau of Economic Analysis Finished Goods Capital Price Index ... 4-4

Figure 4-5. U.S. Bureau of Economic Analysis Private Industry Construction Worker 

Labor Rate Index......................................................................................... 4-5

Figure 5-1. Wet FGD Process Equipment Cost: Four Periods of Deployment ............. 5-2

Figure 5-2. Dry FGD Process Equipment Cost: Various Sources................................. 5-4

Figure 5-3. Calculated SO2 Removal Cost per Ton: Wet FGD Retrofit to 500 MW 

Reference Unit ............................................................................................ 5-7

Figure 6-1. Capital Cost of SCR Process Equipment vs. Generating Capacity: ............ 6-2

Figure 6-2. Increase in SCR Capital Cost Based on Four Time Periods (Three 

Increments) ................................................................................................. 6-3

Figure 7-1. Fabric Filter Particulate Control Device and Detail of Filter Material ........ 7-1

Figure 7-2. Fabric Filter Capital Cost (2011 $ Basis) vs. Generating Capacity ............. 7-2

Figure 7-3. Dairyland Power Madgett Unit 1: Fabric Filter Installation ....................... 7-3

Figure 7-4. Dynegy Vermilion Units 1 and 2: Fabric Filter Installation ....................... 7-4

Figure 7-5. Arizona Public Service’s Cholla Units 3 and 4: Fabric Filter Retrofit 

(Moderate Difficulty).................................................................................. 7-5

Figure 7-6. Alliant Lansing Unit 4: Fabric Filter Retrofit (Moderate Difficulty........... 7-5

Figure 8-1. Competitive Power Landscape: Wholesale (Peak) Power Prices, and Fuel 

Cost for Generating Options....................................................................... 8-2

Figure 8-2. FGD and SCR Incremental and Total Carrying Costs Compared to Fuel 

Costs for NG/CC and Steam Boilers .......................................................... 8-3

Figure 8-3. Fabric Filter Total Cost vs. NG/CC Fuel Charge: 300 and 500 MW 

Units............................................................................................................ 8-5

Figure A-1. Individual Cost Data for Wet FGD: Phase 1 CAAA Applications (Curve A 

of Figure 5-1)............................................................................................. A-1
Figure A-2. Individual Cost Data for Wet FGD: 2003-2007 Applications (Curve B of 

Figure 5-1) ................................................................................................. A-2

Figure B-1. Individual Cost Data for SCR: Curve B of Figure 6-1...............................B-1
LIST OF TABLES

Table 3-1. Comparison Proximate Analysis, Select Ash Constituents, and Trace 

Constituents of Three Commonly Used U.S. Coals..................................... 3-4

Table 5-1. Example Fixed, Variable O&M for Wet FGD .............................................. 5-5

Table 5-2. Example Fixed, Variable Operation and Maintenance for Dry FGD............ 5-6

Table 6-1. Key SCR Operating Cost Components: 500 MW Reference Plant ............. 6-8

Table 7-1. Key Fabric Filter Operating Cost Components: 500 MW Reference Plant 

($250/kW Capital, 2011 Dollar Basis)......................................................... 7-7
Overview and Summary

1-1

SECTION 1

OVERVIEW AND SUMMARY

The utility industry is well into a third consecutive decade of aggressively retrofitting flue gas 

emission controls to existing power plants. These actions are in response to several federal and 

state mandates, including the Clean Air Interstate Rule (CAIR) and the Cross State Air Transport 

Rule (CSAPR) which require retrofit of flue gas desulfurization (FGD) and selective catalytic 

reduction (SCR) at many units by 2015. In a parallel effort, environmental controls are being 

retrofit to satisfy the Mercury and Air Toxics Standards (MATS). Further, FGD and SCR can be 

required to address regional haze through the Clean Air Visibility Rule (CAVR), as well as the 

increasingly stringent National Ambient Air Quality Standards (NAAQS). Finally, individual 

utility company Settlement Agreements with EPA and the Department of Justice (DOJ) over 

alleged New Source Review (NSR) violations will influence equipment installation for some 

owners. Many of these mandates require controls to be installed and operating by 2015.

The robust demand for control equipment experienced from 2006 through 2009 which strained 

international and domestic supply chains has relaxed. As a result, the availability and price of 

key components and corrosion-resistant metals (such as C276 Hastolloy) have changed – to the 

benefit of the purchaser. However, despite an increase in the supply of construction labor, hourly 

labor rates continue to increase, although less aggressively than in 2006-2009.

The capital cost to retrofit FGD and SCR equipment continues to escalate. This report also 

addresses the cost for fabric filters – heretofore not tracked over time – and shows such 

equipment is less costly than FGD or SCR, but still requires substantial investment. A key reason 

for continued escalation of FGD and SCR cost is the ever-increasing complexity of the host sites. 

The remaining units to be retrofit are typically located at older and more crowded sites, which 

provide less space to locate equipment and for construction. Such retrofits typically require 

convoluted and complex ductwork, increasing installation difficulty.

Capital cost for present-day FGD installations in 2012 and planned for 2014 has slightly 

escalated from the 2008-2011 timeframe. Specifically, retrofit of wet FGD to a 500 MW unit in 

the 2012-2014 timeframe requires $500/kW (2011 dollars).

The levelized cost of SO2 removal is determined from capital and operating cost, and reported as 

the cost to remove one ton of SO2. At $500/kW, a wet FGD process retrofit to a 500 MW unit 

firing coal with sulfur content of 5 lbs/SO2/MBtu, and incurring typical operating costs will 

expend near $600 to remove each ton of SO2. For a coal with this sulfur content, each increase in 

wet FGD capital cost by $100/kW elevates the cost of SO2 removal by almost $100 per ton. For 

PRB coal with a sulfur content of 0.9 lb SO2/MBtu, a $500/kW wet FGD process retrofit to a 500 

MW plant will expend $2,300/ton for SO2 removal. For this PRB coal each $100/kW increase in 

FGD capital cost will increase SO2 removal cost by $400/ton.
Overview and Summary

1-2

Capital cost for SCR NOx control has escalated at a materially higher rate over the same time 

period. Recent data show a 500 MW unit retrofitting SCR between 2012 and 2014 would incur 

on average a capital cost of $425/kW, which could vary between $300 and $550/kW (in 2011 

dollars). 

The prices for consumables driving SCR operating cost – catalyst and reagent – continue to 

evolve. Catalyst unit price has remained low in the last 4-5 years, with new catalyst requiring a 

cost of approximately $5,000/cubic meter. The cost of ammonia-based reagent appears to have 

“decoupled” from the historical relationship with natural gas, due to strong fertilizer demand. 

Typical delivered cost for anhydrous ammonia is $600-800/ton and these prices are expected to 

persist through about 2015. For most SCR applications, reagent has replaced catalyst supply as 

the largest SCR operating cost component.

Similar to SO2, the levelized cost for NOx control is determined from capital and operating cost, 

and reported as the cost to remove one ton of NOx. For a typical 500 MW unit firing an eastern 

bituminous coal, and equipped with a boiler generating 0.38 lb/MBtu of NOx, an SCR process 

requiring $450/kW provides NOx removal for about $5,200/ton. For this same unit, each 

$100/kW increase in SCR capital cost elevates NOx removal cost by about $1,200/ton. For a 500 

MW unit firing PRB and producing NOx at a rate of 0.20 lb/MBtu, an SCR process requiring 

$450/kW provides NOx removal for about $11,000/ton. Each $100/kW increase in SCR capital 

cost incurred for this unit increases NOx removal cost effectiveness by $2,400/ton.

More important than calculated cost per ton of pollutant removal is the impact of retrofit 

environmental controls on the cost-competitiveness of a unit in wholesale power markets. It is 

well known that recent low natural gas prices have reduced wholesale power prices in the U.S., 

by an average of 12% in 2012 compared to 2011. Excluding the hydropower-dominated CAISO 

region in the Pacific Northwest, wholesale power prices throughout the U.S. ranged from about 

$30/MWh at Palo Verde to $46/MWh for NYISO. The retrofit of FGD alone for a 500 MW unit 

can add $16/MWh to the production cost that must be bid into the market – approximating the 

fuel cost for a coal-fired boiler. Such an additional cost can render a unit uncompetitive.

In summary, although material and labor shortages witnessed during the 2006-2009 timeframe 

have abated, the cost to retrofit FGD and SCR equipment continues to increase. The extent of 

escalation is small for wet FGD, but notable for SCR. The cost increases are driven by the 

increasing complexity of smaller sites, hosting generally older units. Typically, large units with 

accessible, open sites have already been retrofit, as the most cost effective projects were first 

sought. The additional cost of deploying FGD and SCR has reduced the competitiveness of these 

units compared to natural gas-fired generation. 
Background

2-1

SECTION 2

BACKGROUND

2.1 INTRODUCTION

The cost to retrofit air pollution controls to coal-fired power stations escalated rapidly over the 

ten-year period starting from the year 2000. Despite the slowing world-wide economy, the cost 

to retrofit air pollution controls since 2010 remains at elevated levels. 

Several factors drive the escalated costs. First, although prices for specialized materials of 

construction have subsided, specialized labor costs have not materially changed. Perhaps more 

important, the remaining generating sites to be retrofit are more challenging – these complex 

sites’ limited access for construction personnel and equipment. 

These costs are not anticipated to relax. Several competing mandates are evolving that will 

require additional equipment operating within the next few years. A review of these mandates 

and cost pressures follows.

2.2 ENVIRONMENTAL MANDATES

Several major environmental control regulations have been issued in recent years, all requiring 

compliance within a short time period. 

Most notably, the Clean Air Interstate Rule (CAIR) and the Cross State Air Transport Rule 

(CSAPR) – require retrofit of FGD and SCR at many units by not later than 2015. At nearly the 

same time, environmental controls are required to satisfy the Mercury and Air Toxics (MATS) 

rule. Further, initiatives to address regional haze such as the Clean Air Visibility Rule (CAVR) 

and increasingly stringent National Ambient Air Quality Standards (NAAQS) can affect SO2 and 

NOx emission rates and the need for FGD and SCR. Finally, individual utility company consent 

decrees with EPA, the Department of Justice (DOJ) and some states over alleged New Source 

Review (NSR) violations will influence equipment installation for some owners. 

Each of these mandates is described as follows.

Clean Air Interstate Rule (CAIR) and the Cross-State Air Pollutant Rule (CSAPR). The details 

and history of how these two inseparable rules evolved is beyond the scope of this paper. In 

brief, both rules employed Phase 1 and Phase 2 compliance dates for SO2 and NOx emissions 

which were vacated by the courts. CSAPR was proposed in August of 2011 to replace CAIR –

the latter vacated in 2008. However, CSAPR itself was vacated in August of 2012 – altering the 

2015 plans for many operators. With CSAPR vacated, CAIR has been reinstated – thus CAIR’s 

Phase 2 mandate is in force requiring additional FGD and SCR by 2015.
Background

2-2

Mercury and Air Toxic Standards (MATS). The MATS rule, by requiring control of mercury 

(Hg), fine particulate matter, and hydrogen chloride (HCl), requires additional control equipment 

to be installed by 2016. This rule requires the retrofit of baghouses to enable controlling fine 

particles and providing a favorable environment to remove Hg and HCl with reagents. The 

MATS rule also prompts owners to consider upgrades or refinements to SCR and FGD, which 

through “co-benefits” remove Hg. 

National Ambient Air Quality Standards (NAAQS). NAAQS are reviewed every 5 years as 

stipulated under the Clean Air Act and often result in lower ambient standards. EPA’s revisions 

to NAAQS require States with air basins exceeding the ambient standards to develop State 

Implementation Plans (SIPs) to improve air quality. States predominantly look to power plants to 

further reduce emissions.

Clean Air Visibility Rule (CAVR). This federal regulation requires all states to revise their SIPs 

to improve visibility in Mandatory Class I Federal Areas, which are national parks and 

wilderness areas. Consequently, states may require retrofit of emissions controls, above and 

beyond other environmental requirements, to achieve “reasonable progress” toward improving 

visibility in Mandatory Class I Federal Areas. These plans designate a Best Available Retrofit 

Technology (BART) that must be installed.

For example, the states of Illinois, Indiana, Michigan, and Wisconsin, through the Lake 

Michigan Air Directors Consortium, periodically consider controls for SO2 and NOx beyond 

other federal programs (e.g., CAIR or CSAPR). Regulatory agencies in other regions in the 

country such as the southeast (VISTAS) and far west (WRAP) routinely consider revising local 

mandates. The extent and timing of these mandates is uncertain, but some initiatives could be 

proposed to require control equipment during the 2014 to 2018 period. 

Settlements Regarding Alleged NSR Violations. Allegations by the U.S. EPA that provisions of 

the CAA regarding NSR were violated prompted several owners to agree to install FGD and 

SCR on schedules that differ from those required to meet CAIR.

2.3 FGD AND SCR INVENTORY

Figures 2-1 to 2-6 report the inventory of FGD (both wet and dry) and SCR process equipment 

that has been installed, or is planned to be installed, to meet regulatory mandates. Figure 2-1 

shows the generating capacity (MW) equipped with either wet or dry FGD each year through 

2012, and projections for 2013 through 2015. The peak of at least 20,000 MW each year 

occurred in 2008, 2009, and 2010. Figure 2-2 presents the cumulative capacity equipped with 

FGD since 2001 – approaching 120,000 MW by the end of 2012. Added to the inventory of 

almost 96,000 MW prior to the year 2002, at about 225,000 MW of the U.S. coal-fired fleet will 

be equipped with FGD by 2015.
Background

2-3

Figure 2-1. Historical and Projected Wet, Dry FGD Capacity: Installed MW per Year

Figure 2-2. Historical and Projected Wet, Dry FGD Capacity: Cumulative MW per Year
Background

2-4

The trends in SCR are equally important. Figure 2-3 shows the annual generating capacity 

retrofit with SCR over the same time period. Since the peaks in 2002 to 2004, the generating 

capacity retrofit with SCR in each year ranges between about 4,000 and 10,000 MW. Figure 2-4 

presents the cumulative generating capacity equipped with SCR, which approaches 130,000 MW 

in 2012.

One additional factor prompting SCR and FGD retrofit is their removal of Hg and other 

hazardous air pollutants (HAPs) by “co-benefits”. Specifically, SCR is known to prompt Hg 

oxidation to a soluble state (mercuric chloride, Hg(Cl)2) increasing removal by wet FGD. A 

select inventory of units is equipped with both SCR and FGD. Figures 2-5 and 2-6 report this 

inventory in terms of annual and cumulative generating capacity, respectively. Both figures 

identify the installation year as the first year of operation with both control systems. Unlike 

Figures 2-1 and 2-2, the data in Figures 2-3 and 2-4 reflect FGD installed prior to 2002. (Thus, 

almost all of the FGD equipment reported for the years 2003 through 2005 reflect FGD installed 

prior to 2002). Figure 2-6 shows almost 70,000 MW of capacity is equipped with both SCR and 

FGD through 2012. Many of these units are operated to provide some degree of Hg removal. 

Figure 2-3. Historical and Projected SCR Capacity: Annual Installed Capacity (MW)
Background

2-5

Figure 2-4. Historical and Projected SCR Capacity: Cumulative Installed SCR Capacity 

(MW)

Figure 2-5. Historical, Projected FGD and SCR Annual Capacity (MW)
Background

2-6

Figure 2-6. Historical, Projected FGD and SCR Cumulative Capacity (MW)

2.3 NEW GENERATING STATIONS

The projected number of new coal-fired units planned to begin operations between 2013 and 

2020 has decreased notably. As of early 2013, approximately 2,500 MW of coal-fired capacity is 

either in final engineering or under construction. The efforts to acquire the necessary permits 

have been initiated – and in some case completed – for an additional 4,300 MW but it is not clear 

how many of proposed units will actually be built. Both the present economic climate, and the 

regulatory uncertainty with regard to CO2 regulation have all dampened interest. The most 

notable source of regulatory uncertainty is EPA’s April 13, 2012 proposed New Source 

Performance Standards (NSPS) for CO2 emissions from coal-fired power stations.
Factors Affecting Reported Capital Cost

3-1

SECTION 3

FACTORS AFFECTING REPORTED CAPITAL COST 

This section reviews the factors that affect the capital cost for air pollution control equipment. 

These factors include (a) the methodology by which costs are developed, (b) how cost is 

escalated over time, (c) features of the host power stations. 

3.1 CAPITAL COST REPORTING METHODOLOGY 

Accurately reporting the cost for air pollution control equipment requires a consistent accounting 

method. Both direct and indirect costs to acquire the process, and fixed and variable operating 

costs must be accounted for. EPRI’s Technical Assessment Guide1provides one such 

methodology which has served as a model used by DOE, EPA, and other organizations assess 

costs.

The focus of this report is installed capital cost for environmental control equipment. The capital 

cost consists of several key components, defined as follows: 

Process Equipment. The reaction vessels, absorbers, reagent receiving and supply systems, 

process controls, and initial inventory of catalysts, reagent, and filter (for baghouses) comprise 

this category of cost.

General Facilities. The land occupied by the process, access roads, support buildings and 

laboratories make up general facilities.

Installation Charges. These costs include construction and installation labor, materials, and 

special equipment (rental of cranes, etc.).

Engineering Charges. Engineering charges include selecting the process, defining the specific 

conditions are the site, optimizing the process design for the site, integrating the process design 

with balance-of-plant equipment, and procurement.

Owner’s Costs. Owner’s costs include staff for management, engineering, and developing 

proper operating practices. 

Finance, Other Charges. Finance charges are mostly Allowance for Funds Used During 

Construction, an accounting charge to accommodate the financing during construction when the 

equipment is not in use. In addition, some states (e.g., New Mexico) impose a “gross receipts” 

tax, essentially a sales tax on industrial equipment. 

 

1

TAGTM Technical Assessment Guide: Electricity Supply – 1993, EPRI TR-102275-V1R7, Volume 1: Rev 7, June 

1993.
Factors Affecting Reported Capital Cost

3-2

Preproduction, Inventory Capital. Spare parts and the initial (typically 30 day) supply of reagent 

and chemicals comprise this charge. 

Not all cited environmental control costs reflect a complete scope. For example, Tampa Electric 

in 1998 reported installing FGD for less than $100/kW2, but this cost did not include reagent 

preparation equipment or other support facilities that were previously installed for two earlier 

FGD towers. Similarly, the cost for PacifiCorp to convert an existing hot-side ESP at the 

Wyodak station to a fabric filter was not used to reflect the cost of retrofitting a stand-alone 

installation. Public Service of New Mexico recently expended significant funds to provide stateof-art wet FGD at the San Juan Generating Station; however this work utilized components of 

the legacy Wellman-Lord process preventing the true cost of a stand-alone process to be 

determined.

Capital costs are reported as received from the owner. Where costs are adjusted, the purpose, 

methods, and significance of the adjustment are explained in an accompanying footnote.

3.2 CAPITAL COST ESCALATION

Capital cost was adjusted to account for the escalation over the time periods in this analysis. The 

earliest periods for which costs are 1995 are for the “Phase 1” retrofit of flue gas desulfurization 

processes, per the 1990 Clean Air Act Amendments. The costs incurred in these years are 

escalated to 2011 using the Bureau of Economic Analysis (BEA) Implicit GDP Price Deflator. 

This index is one of several metrics that could be used to measure price changes due to dilution 

of purchasing power of the dollar, exclusive of price changes due to demand. A definition of the 

BEA GDP Implicit Deflator is found on the BEA website.3

Figure 3-1 depicts the GDP Implicit Deflator that is used to adjust environmental control costs 

from the year incurred to the end-of-year 2011 dollar basis. 

3.3 SITE AND DESIGN FACTORS

This report cites single-point costs for environmental controls based on what an owner has 

incurred, or estimates to be incurred in the next 12-24 months. Using a single point to represent 

cost for an environmental control system suggests a definitive understanding of costs that does 

not exist. In reality, the cost for such complex equipment varies over a wide range, even for a 

narrowly defined specification or set of process conditions. This variability will be evident in 

graphical depictions of process cost presented in Sections 5-7. 

 

2

“Tampa Electric announces plans to reduce emissions from Big Bend Units One and Two”, New Release, July 20, 

1998, TECO/Tampa electric, available at: 

http://www.tampaelectric.com/company/mediacenter/article/index.cfm?article=110

3

http://www.bea.gov/faq/index.cfm?faq_id=513&start=0&cat_id=0
Factors Affecting Reported Capital Cost

3-3

Figure 3-1. Bureau of Economic Analysis (BEA) Implicit GDP Deflator

A brief summary of site-specific factors, and how they impact capital cost, is as follows:

Fuel Composition. The fuel defines the volume of combustion products, the content of 

particulate matter, SO2, and NOx, and the composition of fly ash. These flue gas characteristics 

define process equipment size and cost. For example, Powder River Basin (PRB) or other subbituminous coals can generate up to 30% greater volume flue gas, compared to an eastern 

bituminous coal, to be processed for the same generating capacity. The quantity of sulfur to be 

processed and the fate of the byproduct – extent of dewatering, and preparation for resale or 

disposal – also affect cost. For SCR reactors, the fly ash composition and presence of trace 

elements such as arsenic and phosphorous can determine reactor volume and catalyst 

arrangement. 

Table 3-1 compares the composition of three coals widely used in the U.S. These coals represent 

the categories of (a) eastern bituminous, (b) Powder River Basin, representing the most popular 

subbituminous coal, and (c) lignite coal from Texas. It is not possible to designate any one coal 

as more problematic than another – each has features that challenge the design and operation of 

air pollution control equipment.
Factors Affecting Reported Capital Cost

3-4

Table 3-1. Comparison Proximate Analysis, Select Ash Constituents, and Trace 

Constituents of Three Commonly Used U.S. Coals

Units Texas Lignite Powder River 

Basin

Eastern 

Bituminous

Proximate (%, as-received)

Moisture %, as received 26.41-36.00 26.8 6.2

Ash “ 8.45-22.01 4.8 9.9

Fixed Carbon “ 15.42-31.05 35.6 49.7

Volatiles “ 21.1-38.05 32.9 34.0

Sulfur “ 0.76-1.98 0.20 1.60

Heating Value Btu/lb (Btu/kg) 5,768-7,848 (2765) 8861 (4019) 12,386 (5618)

Selected Ash Analysis

PO5 % 0.10-0.20 1.9 0.1

SiO2 “ 24.63-55.85 21 49

Fe2O3 “ 0.09-16.47 10 3.7

Al2O3 “ 12.36-25.86 16 26.5

TiO2 “ 1.03-2.08 2.4 1.5

MN3O4 “

- 0.10 -

CaO “ 6.19-31.41 33 0.9

Mgo “ 1.44-3.59 5.0 0.5

K2O “ 0.18-1.03 0.44 1.7

Na2O “ 0.15-1.0 2.1 0.4

SO3 “ 5.76-20.93 4.4 0.6

SrO “

- 0.3 0.2

BaO “

- 1.6 0.78

Selected Trace Elements

As (mg/kg) 2-7 1 5

Cl “ <100 <100 1,300

Hg “ 0.18-0.32 .09 0.10

Specifically, eastern bituminous coals generate relatively low flue gas volume per unit of output, 

but can contain large amounts of sulfur that elevate FGD cost. Further, arsenic content can be 

high, which if not mitigated by alkalinity from calcium, will accelerate catalyst deactivation. In 

contrast, PRB coals generate a substantial volume of flue gas per unit output, increasing the size 
Factors Affecting Reported Capital Cost

3-5

of reaction vessels, but contain less sulfur compared to bituminous coals, lowering the mass of 

sulfur byproduct that must be removed. The NOx generated by PRB is relatively low minimizing 

the catalyst volume for SCR process equipment.

Texas lignite composition is highly variable, and can contain substantial amounts of high silicacontaining ash, which erodes ductwork and catalyst. The lower gas velocities generally required 

for this application increase equipment size and cost. 

Further discussion of how coal properties affect environmental control cost is presented in the 

subsequent sections reporting FGD, SCR, and fabric filter cost. 

Site Congestion and Retrofit Difficulty. Limited space on-site complicates construction – there 

is less access to “lay-down” equipment prior to erection, locate cranes, and productively use 

labor. As a result installation time is extended increasing capital cost. A site with three or more 

older units of small generating capacity will almost invariably incur high retrofit costs due to 

limited access. This cost penalty can be partially offset if gas flow from multiple small units is 

treated in a single device – only applicable to wet FGD. In contrast, a site that hosts a sole large 

unit provides for economies of scale, and can offer unconstrained space for construction.

Figure 3-2 shows perhaps one of the most constrained sites in the U.S. – First Energy’s Sammis 

Station. The site, comprised of seven generating units ranging from 190 to 680 MW, is bordered 

by steep terrain, a four-lane highway, and the Ohio River. First Energy required more than four 

years to retrofit two SCR reactors (to Units 6 and 7), and three FGD absorbers each sized for 800 

MW. 

The work at Sammis was complicated by a previous project that placed four fabric filter 

collectors across the four lane highway from the station. Due to the constrained site and presence 

of the retrofit equipment, the capital cost for the Sammis SCR and FGD process are among the 

highest over the 2006-2010 timeframe.

Existing Site Auxiliary and Support Facilities. FGD and SCR process equipment demand 

auxiliary power, steam, and compressed air. As the availability of these consumables at a site 

varies, additional infrastructure to supply and distribute these consumables may be necessary. 

The most costly can be new power distribution infrastructure including transformers, switchgear 

and/or “motor control centers.” The escalation in price until 2008 of copper-containing electrical 

subsystems has contributed to cost increases; during periods of peak copper pricing electrical 

infrastructure escalated from 5-6% of an FGD budget to more than 10%.

Flue Gas Draft System Upgrades. The retrofit of environmental controls will change the static 

pressure within the ductwork, which may require upgrades to fans, new fan motors, upgraded 

electrical systems, and strengthening of ductwork, ESPs, and boiler walls. The upgrade and 

strengthening of ductwork and boiler walls is necessary to prevent collapse or implosion. 
Factors Affecting Reported Capital Cost

3-6

Figure 3-2. First Energy Sammis Station: Constrained Site

Waste Water Treatment Requirements. For wet FGD, the need to treat process discharge water 

varies depending on permitted limits. Zero-water discharge requirements can impose large costs 

on the entire FGD slurry treatment and dewatering systems, and may possibly interfere with 

FGD chemistry. For wet FGD process equipment installed at a site in North Carolina, wastewater 

treatment facilities comprised between 9 and 14% of the total capital cost. The design of a waste 

water treatment system has been a key point of contention in the retrofit of wet FGD to the 

PSNH Merrimack Station, contributing in part to this FGD process incurring perhaps the highest 

capital cost on record. Waste water treatment equipment alone for this station has been estimated 

to cost $23M.4

Stack: Rebuild or Replace. Retrofit of wet FGD process equipment can require replacement of 

or a major rebuild of the stack. Flue gas treated by wet FGD poses corrosion and deposition 

potential, due to relatively low saturation temperature and content of SO3. The least cost solution 

can involve a new stack rather than retrofitting corrosion-resistant liners to an existing stack. 

Figure 3-2 shows the location of the new stack to accommodate the three retrofit FGD processes.

 

4

Expert Report of John H. Koon in the Matter of Comments on the NPDES Permit for PSNH’s Merrimack Station 

(2012), February 24, 2012, available at www.epa.gov/region1/npdes/merrimackstation/pdfs/.../PC-6.pdf
Factors Affecting Reported Capital Cost

3-7

Equipment Sparing and Redundancy Philosophy. The operating strategy of the owner, and the 

cost incurred for an FGD outage determines the equipment sparing and redundancy. Sparing 

philosophy can affect capital cost by 10-20%. Operators with sufficient margin in meeting the 

SO2 or NOx “cap,” or for whom SO2 or NOx “allowances” are available, may choose to lower 

capital cost by minimizing redundant equipment. Conversely, operators for whom access to SO2

or NOx allowances is limited or costly may elect to invest in more spare equipment. 

Materials of Construction. Special-purpose materials can resist corrosion and erosion, and 

support high reliability, but elevate capital cost. Specifically, using high alloy containing steels 

or rubber-lined absorber vessels or pumps will increase reliability. The ability of a fluid to 

corrode, erode, or otherwise compromise piping must be considered when selecting construction 

materials. For wet FGD using higher alloy and lined equipment adds 10-20% to project capital 

cost.

Capital versus Operating Cost. Many decisions revert to a tradeoff between capital and 

operating cost; some capital savings are derived only at the expense of higher operating cost. For 

SCR, a key example is the catalyst layout – the number of initial and final layers of catalyst 

utilized. For example, a reactor layout of 2 initial layers and 1 spare layer (i.e., 2+1) will result in 

a lower capital but higher operating cost, compared to utilizing 3 initial layers and 1 spare layer 

(i.e., 3+1). The key difference is higher catalyst consumption over a long-term period. 

Site complexity is perhaps the most important of these preceding factors. Capital costs continue 

to escalate because sites where FGD and SCR are to be retrofit are more complex than many 

prior applications for several reasons. The largest generating capacity units with the best site 

access have already been equipped with FGD and SCR, leaving smaller and older units for 

retrofit today.

The case of SCR retrofit to Public Service New Mexico’s (PNM) San Juan Station illustrates this 

point.5Figure 3-3 presents a satellite image of the San Juan Station, which similar to the First 

Energy Sammis Station required retrofit of state-of-art air pollution controls for SO2, particulate 

matter, and NOx. The San Juan station when constructed was equipped with what at the time was 

state-of-art FGD technology. PNM was one of several utility operators in the 1970s that 

promoted the application of “regenerable” SO2 controls – in this case the Wellman-Lord process 

for converting captured SO2 into marketable sulfuric acid. The Wellman-Lord FGD process, 

although state-of-art at the time of installation, was not able to provide the SO2 removal 

capability and reliability required by PNM in the present operating environment. The original 

FGD process was removed and conventional limestone-based FGD process installed, along with 

fabric filters to improve particulate matter control. The additional equipment limited access for 

cranes and construction equipment to install SCR. 

 

5 Evaluation of Engineering and Analytical Studies to Assess the Cost of Selective Catalytic Reduction (SCR) NOx 

Control Technology, for the Public Service Company of New Mexico San Juan Generating Station, prepared for 

PNM Resouces, January 31, 2012.
Factors Affecting Reported Capital Cost

3-8

Figure 3-3. Confined Site at PNM San Juan Station: Retrofit Fabric Filters, Upgraded 

FGD, Candidate SCR Locations

The need to accommodate SCR escalated the estimate of total gas pressure drop across the entire 

air pollution control system. This additional gas pressure drop, along with other operating 

factors, prompted the need to include plans to adopt “balanced draft” gas handling. The cost 

impact of conversion to balanced draft – not only gas handling equipment but structural 

reinforcement of the boiler – added considerably to the estimated cost to retrofit SCR on all four 

units at this station.

Cost estimates for SCR for these and other facilities are described in Section 6.
Material and Labor Escalation

4-1

SECTION 4

MATERIAL AND LABOR ESCALATION

The cost of basic material and labor has significantly escalated in the last decade, specifically 

from the year 2000 through 2012. The escalation of material prices in 2008 and 2009 has abated, 

with most prices “relaxed” from peak values observed at that time. Labor costs have not 

decisively changed from peak values. This section discusses how material prices and labor costs 

impact equipment cost.

4.1 BASIC MATERIALS 

Basic materials required to fabricate air pollution control equipment are iron ore for products 

such as structural steel and ductwork, copper for wire and cable, and elements such as nickel and 

molybdenum for processed metals. These materials, along with the cost and productivity of 

labor, determine the price of finished equipment such as pumps, valves, piping, instrumentation 

and control systems. Demand for these materials from approximately 2006 through most of 2008 

was strong due to robust world-wide construction in process industries. Since 2008 the demand 

for such materials and has declined. This recent trend has mitigated but not eliminated cost 

concerns.

Figures 4-1 to 4-4 present price escalation data for basic materials over the last 10 years (with the 

exception of iron ore, for which data are only available over a three year period). These data, 

accessed either from the U.S. Bureau of Economic Analysis6(BEA) or a commercial source7, 

reflect pricing from 2002 to the present. The data in Figures 4-1 to 4-4 show prices for key 

materials have relaxed from the 2008-era, reverting to 2007 levels. Consequently, all material 

prices are lower than their 2008 peaks but remain above mid-decade values. 

Specifically, Figure 4-1 presents the change in the BEA cost index for steel products (1982 

prices as a base case). Figure 4-1 shows 2009 steel mill prices to be 60-70% of peak prices 

reported in the mid-2008, returning in 2012 to 80% of peak levels. Similarly, Figure 4-2 shows 

the price for iron ore pellets, after escalating from 2009 through 2011 by almost a factor of two, 

reverting to early 2009 levels by the end of 2012.

 

6

 See U.S. Bureau of Economic Analysis, “Price Indices for Gross Domestic Product by Major Type of Product”, 

revised December, 2009, http://www.bea.gov/national/nipaweb/SelectTable.asp?Selected=Y

7

See www.Infomine.com
Material and Labor Escalation

4-2

Figure 4-1. Steel Mill Products Cost History

Figure 4-2. Iron Ore Cost Escalation
Material and Labor Escalation

4-3

The cost for special alloys used for wet FGD absorbers and reaction vessels, and for high 

pressure, high temperature boiler components, has also relaxed from peak 2008 values. Both 

nickel and molybdenum, key ingredients to corrosion-resistant and high-strength materials, 

experienced increased demand and higher prices up to 2007. Copper is an important component 

of electrical distribution and wiring systems. Figure 4-3 presents price trends for molybdenum, 

nickel, and copper over the time period of 2003 through most of 2012. Figure 4-3 shows prices 

for molybdenum and nickel escalated from 2003 by almost a factor of 10, but in late 2012 

reverted to about twice the 2003 price. In contrast, the price of copper, which escalated by up to 

a factor of 8 in the 2008 peak, in 2011 revisited the peak. In late 2012 copper prices remain 

elevated.

Figure 4-3. Price History Escalation: Nickel, Molybdenum, and Copper

The price of delivered, finished equipment – as reflected by Federal Reserve Economic Data 

(FRED) – has continued to escalate as finished goods require manufacturing labor in addition to 

materials. Depending on the specific product, the manufacturing labor can represent a cost that 

exceeds the contribution of materials, specifically for certain pumps, gas fans, valves, and alloy 

steel plates, the latter with specific surface features. Figure 4-4 shows how the prices of finished 

goods continued to escalate through the recession period in the 2008 and 2009 timeframe. 
Material and Labor Escalation

4-4

Figure 4-4. U.S. Bureau of Economic Analysis Finished Goods Capital Price Index

FGD projects implemented from 2006 through 2008 incurred schedule delays due to limited 

availability of equipment for reagent preparation, slurry recirculating pumps, agitator pumps, 

certain forced and induced draft fans, and stack construction. Equipment availability rarely 

imposes similar limits in the present market.

4.2 CONSTRUCTION LABOR

The availability of qualified field labor has been a historical concern to support the timely and 

effective installation of process equipment. Typically labor rates can be a premium and escalate 

rapidly for crafts with the most lengthy apprenticeship programs (e.g., boilermakers), as well as 

crafts with less restrictive training (pipefitters, electricians). Escalation in specialty construction 

labor was documented by the industry through 20078, but such escalation has abated in the last 

5 years.

Figure 4-5 presents wage escalation for private construction workers observed since 2000. This 

category of construction laborer reflects broad construction trades, not necessarily the specialized 

trades for heavy equipment construction, but is believed indicative of utility construction costs. 

This escalation in labor wage rate in Figure 4-5 is equal to an annual rate of 3-4% from 2008 

through 2012.9

The labor rate escalation shown in Figure 4-5 will increase installed equipment cost, but is not a 

dominant factor as experienced prior to 2008.

 

8 Building New Baseload Generation in the Midwest, MMEA Presentation, Black & Veatch, May 11, 2006.

9

See Table 5, “Natural Resources, Construction, and Maintenance”, change registered in September 2009 versus 

September 2008, U.S. Bureau of Labor Statistics, www.bls.gov/news.release/eci.t05.htm
Material and Labor Escalation

4-5

Figure 4-5. U.S. Bureau of Economic Analysis Private Industry Construction Worker 

Labor Rate Index
Flue Gas Desulfurization Costs

5-1

SECTION 5

FLUE GAS DESULFURIZATION COSTS

This section discusses capital and operating costs for wet and dry FGD process equipment, 

reflecting units installed from 1995 and through 2011. The estimated cost for FGD installations 

being installed or planned from 2012 to 2014 is also presented.

5.1 FGD CAPITAL COSTS 

The capital cost reported in this section describes a complete scope of work, including all 

indirect charges and Allowance for Funds Used During Construction, escalated into end-of-year 

2011 basis using the BEA Implicit GDP Deflator.

It should be cautioned not all data presented in this section reflect comparable cases – each unit 

will differ with respect to inlet SO2, SO2 removal, fuel type, absorber design, dewatering and 

byproduct management, and balance-of-plant equipment. The general cost trend shown in the 

figures is believed to reflect the industry average.

5.1.1 Wet FGD

Figure 5-1 presents capital cost data for four deployment periods, from 1995 through 2014. 

Capital cost (unit basis, or $/kW) is displayed versus generating capacity. Three curves represent 

capital cost versus generating capacity for the earliest deployment periods. The most recent 

installations – in 2012 or planned through 2014 – are represented by five discreet data points. 

Most FGD units employ limestone reagent, and with few exceptions, are designed for 95% SO2

removal, forced oxidation treatment of byproduct, and are equipped with mist eliminators.

Curve A represents the capital cost for units that started commercial service prior to January 

1995 to comply with Phase 1 of acid rain rules. Curve A is based on the capital cost of 16 units, 

for which 11 provide 95% or greater SO2 removal. All units but two employ limestone as 

reagent, with the remainder using magnesium-enhanced lime. Curve A shows for these early 

installations that unit capital cost ($/kW) decreases only slightly with increasing generating 

capacity. Further, capital cost widely varies around the average values shown. Appendix A 

presents the 16 data points for Curve A, and shows that the average value of $370/kW represents 

costs that vary mostly between $300 and $495/kW. 

Curve B represents the capital cost for units that started commercial service over the ten-year 

period from 1997 through 2007. Due to the predominant use of low sulfur Power River Basin 

coal for compliance, a relatively small number of units started commercial service during this 

period. Twelve units provide the basis for Curve B, which exhibits a more conventional 

relationship between generating capacity and unit capital cost. Appendix A presents the 

individual data points for Curve B, showing the extent the cost data vary around the mean values. 

For example, at 600 MW Curve B reveals a capital cost of $310/kW, when the actual data ranged 

from a low of about $220/kW to $480/kW.
Flue Gas Desulfurization Costs

5-2

Figure

Figure 5-1. Wet FGD Process Equipment Cost: Four Periods of Deployment

Curve C presents capital cost for units that started commercial service between 2008 and 2011. 

Most of these units were deployed to meet Phase 1 of the CAIR mandates; other units were 

constructed to comply with NSR consent decrees agreed to with the Department of Justice. A 

large number of units began service in this time period – Curve C is based on 28 separate FGD 

facilities. Significant variability in the 28 data points is exhibited around the mean values. 

The large number of cost data in the 2008-2011 timeframe enables comparing the cost to retrofit 

FGD to two or more units at one site. The results (not shown) indicate there is no distinguishable 

difference in cost ($/kW basis) when retrofitting FGD to more than one unit at a site, compared 

to a single stand-alone unit of approximately the same capacity. 

Capital cost for the most recent inventory of FGD processes – those installed in 2012, or planned 

for startup not later than 2014 – are represented by five discreet points in Figure 5-1.
Flue Gas Desulfurization Costs

5-3

These data in Figure 5-1 suggest the following observations:

Capital Cost has Escalated with Time. With the exception of the early Phase 1 acid rain FGD 

retrofits, Figure 5-1 shows the cost to retrofit FGD has increased for each of the four time 

periods. For a 400 MW unit, the average capital cost incurred for FGD installed by 1995 

compared to units installed by 2008 is very similar. However, the unit cost for FGD increases by 

almost $150/kW for units installed in the 2008-2011 timeframe. Cost data for units retrofit in 

2012 and through 2014 are limited but suggest no change or perhaps a slight escalation from the 

most recent (2008 -2011) timeframe. 

Most Capital Cost Data Exhibit Significant Economies of Scale. With the exception of the 

Phase 1 acid rain rule FGD retrofits, the minimum unit capital cost ($/kW) is incurred at higher 

generating capacities. This observation is consistent with historical trends for process equipment.

FGD processes retrofit by 1995 to meet the Phase 1 acid rain rules are an exception. The 1990 

CAA Amendments was the first federal mandate to create SO2 emission allowances – enabling 

averaging or production of SO2 emission credits. Many Phase 1 FGD processes were designed 

for 93% SO2 removal and greater, and employed single FGD absorber towers to treat up to 700 

MW of flue gas. The use of a single absorber tower for such large units was not unprecedented –

but there was limited experience from which to derive a commercial design. It is possible the 

Phase 1 acid rain units were designed conservatively, thus economies-of-scale were negligible.

5.1.2 Dry FGD

Figure 5-2 depicts capital cost for lime-based dry FGD presented as a function of generating 

capacity. The costs represented include the reagent supply equipment, the spray dryer absorber 

vessel, and the fabric filter to capture both fly ash and particulate from sulfation. Similar to the 

case for wet FGD, these costs are expressed in 2011 dollars, and reflect all direct and indirect 

charges. Most dry FGD equipment represented in Figure 5-2 is designed for 93-95% SO2

removal. Depending on the specific application, the original particulate collector removes fly ash 

(an ESP in most cases) so ash handling and disposition is the same as prior to retrofit.

Two sources of data are used for Figure 5-2. A curve describing dry FGD unit capital cost 

($/kW) based on a system study for eleven units at a Midwestern utility is included, reflecting 

cost for application to units from 200 to 800 MW. These estimates were developed in 2006 and 

are escalated to 2011.

Actual dry FGD costs incurred are reported for the time periods of 2008-2011 and 2012-2014. 

Costs reported for the time period 2008-2011 decrease with increasing generating capacity, and 

are consistent with the 2006 system design study. 

Costs reported for units installed between 2012 and 2014 also decrease with increasing 

generating capacity. The unit dry FGD costs appear to have notably increased from 2008-2011; 

however, the relatively few data points limit drawing a conclusion.
Flue Gas Desulfurization Costs

5-4

Figure 5-2. Dry FGD Process Equipment Cost: Various Sources

The observations from the dry FGD installations are parallel to those of wet FGD, and are as 

follows:

Unit Capital Cost Has Escalated with Time. Dry FGD capital cost appears to have escalated 

from the 2008-2011 timeframe, to present installations for 2013 and 2014. Limited cost data 

implies caution regarding this conclusion.

Capital Cost Exhibits Significant Economies of Scale. Within the limitations of the data, unit 

capital cost decreases considerably with increasing generating capacities. Data from all three 

sources exhibit this trend: the power-law fit from the study for a Midwestern utility; the data 

from 2008-2011; and the two data reported for installations planned for 2013 and 2014. The 

limited number of data risks drawing conclusive evidence, but the trend parallels that of wet 

FGD and other process equipment. 

5.2 FGD OPERATING COST

Operating costs are comprised of fixed components, whose content does not appreciably change 

with generator output, and variable components, whose content changes in proportion of 

generator output. Fixed and variable components of FGD operation are summarized as follows:

Fixed O&M. The fixed operating and maintenance (O&M) cost is comprised of materials and 

operating staff that are required, independent of how much the process is operated. The fixed 

O&M is estimated based on a fixed percent of the capital cost – and the size – of equipment. 
Flue Gas Desulfurization Costs

5-5

Variable O&M. The variable O&M cost is mostly comprised of reagent consumption, solid 

waste byproduct and disposal, auxiliary power consumption, and make-up water. 

Examples of operating cost incurred for wet and dry FGD systems are described subsequently.

5.2.1 Wet FGD

Table 5-1 presents an example of the fixed and variable operating cost components for a wet 

FGD system for a 500 MW unit, as recommended by Sargent & Lundy.10 For example, fixed 

O&M labor is based on an additional 12-16 plant operators must be added to support wet FGD, 

depending on the size of the generating unit.

Table 5-1 reports for a typical 500 MW plant, firing eastern bituminous coal with an SO2 content 

of 3 lbs/MBtu (i.e., about 1.5% sulfur by weight), wet FGD requires fixed O&M of $8.15 /kW-y 

and variable O&M of $3.60/MWh. This wet FGD process is assumed to require 1.6% of the total 

plant generating capacity to operate. The auxiliary power consumption is assigned a cost penalty 

based on the wholesale energy price. 

Table 5-1. Example Fixed, Variable O&M for Wet FGD

Operating Cost Units Value Comment or Input

Fixed

Additional Labor $/kW-y 3.00 8 additional operators

Maintenance Labor, Material $/kW-y 5.00

Administrative Labor $/kW-y 0.15

Variable

Limestone Reagent $/MWh 0.66 Limestone at $15/ton

Waste Disposal $/MWh 2.47 Disposal at $30/ton

Make-up Water $/MWh 0.08 Make-up water

Auxiliary Power $/MWh 0.40 Based on 1.6% power 

consumption, energy 

price of $25/MWh 

5.2.2 Dry FGD

Table 5-2 presents an example of the fixed and variable operating cost components for a 

500 MW dry FGD system, as recommended by Sargent & Lundy.11

Table 5-2 reports that for a typical 500 MW plant, firing low sulfur eastern bituminous coal 

(0.5% sulfur content), dry FGD requires fixed O&M of $8.61/kW-yr and variable O&M of 

 

10 IPM Model – Revisions to Cost and Performance for APC Technologies: Wet FGD Cost Development 

Methodology Final, prepared by Sargent & Lundy, August 2010, Project 12301-007, for Perrin Quarles Associates, 

Inc.

11 IPM Model – Revisions to Cost and Performance for APC Technologies: SDA FGD Cost Development 

Methodology Final, prepared by Sargent & Lundy, August 2010, Project 12301-007, for Perrin Quarles Associates, 

Inc.
Flue Gas Desulfurization Costs

5-6

$1.40/MWh. The dry FGD process is assumed to require 1.35% of the plant generating capacity. 

The auxiliary power consumption is assigned a cost penalty based on the wholesale energy price.

Table 5-2. Example Fixed, Variable Operation and Maintenance for Dry FGD

Operating Cost Units Value Comment or Input

Fixed

Additional Labor $/kW-y 3.33 8 additional operators

Maintenance Labor, Material $/kW-y 5.12

Administrative Labor $/kW-y 0.16

Variable

Lime Reagent $/MWh 0.60 Lime at $95/ton

Waste Disposal $/MWh 0.43 Disposal at $30/ton

Make-up Water $/MWh 0.03 Make-up water

Auxiliary Power % MW 

production 

lost

1.35% or 

$0.34/MWh

$0.34/MWh based on 

wholesale energy price of 

$25/MWh

5.3 LEVELIZED REMOVAL COST PER TON

The total cost of deploying wet or dry FGD will include the capital charge and the sum of fixed 

and variable operating charges.

For a 500 MW power plant, Figure 5-1 suggests wet FGD capital cost for units installed in 2012 

or thereafter is about $500/kW, equal to $250 M capital investment. The annual charge for this 

capital – based on a 20-year recovery period and applying the capital cost recovery factor from 

EPRI’s Technical Assessment Guide (0.13), is $32.5 M. In addition to this annual charge for 

capital, wet FGD operating costs will be incurred as exemplified by Table 5-1 for eastern 

bituminous coal with 3 lbs SO2/MBtu sulfur content. Operating cost for lower sulfur coals are 

analogous to Table 5-2 but are lower in approximate proportion to sulfur content. 

Figure 5-3 summarizes these charges, cast in terms of cost per ton of SO2 removed. Figure 5-3 

shows the divergence in cost for controlling SO2 from a higher sulfur eastern bituminous coal, 

and relatively low sulfur coal such as PRB.

In the present utility operating environment, it is likely more important to view FGD cost in 

terms of compromising the economic position of a unit in a competitive power market. A 

comparison of how FGD variable and total carrying costs affect the competitiveness of a 

500 MW unit in the wholesale power market is presented in Section 8.
Flue Gas Desulfurization Costs

5-7

Figure 5-3. Calculated SO2 Removal Cost per Ton: Wet FGD Retrofit to 500 MW 

Reference Unit 
Selective Catalytic Reduction Cost

6-1

SECTION 6

SELECTIVE CATALYTIC REDUCTION COST

This section presents capital and operating costs for SCR NOx control, reflecting units installed 

from 1994 through planned for 2014. 

6.1 SCR CAPITAL COST

Figure 6-1 summarizes capital cost data for four deployment periods, starting as early as 1994 

and projected through 2014. Three curves represent unit capital cost ($/kW) vs. generating 

capacity for three periods of historical data. Eight discrete cost data are presented for units 

retrofit in 2012 and projected through 2014. 

Figure 6-1 represents cost data from over sixty SCR installations. The costs are reported as 2011 

dollars, and include both staff engineering and owners’ engineering charges, and financing 

charges (AFUDC). As with FGD process equipment, it should be cautioned that not all cost data 

represent comparable cases – most differ in inlet NOx, NOx removal, fuel type, reactor design 

and arrangement, number of catalyst layers, and balance-of-plant equipment. However, the trend 

in cost shown in Figure 6-1 is believed an accurate reflection of the industry average. 

Figure 6-1 presents four curves reflecting cost incurred over discrete time periods. These include 

the years (a) pre-2000, reflecting the earliest projects, (b) 2000-2007, reflecting the class of units 

installed prior to broad Phase 1 CAIR compliance, (c) 2008-2011, reflecting units installed 

during the height of Phase 1 CAIR compliance, and (d) 2012 and beyond, reflecting units 

recently installed or presently under construction. The individual data points are omitted for 

clarity. The complete set of data and cost curves can be viewed in Appendix D. 

Curve A represents capital cost for five units retrofit with SCR for operation prior to 2000 to 

comply with either a state regulation or the 1997 SIP-Call. Also, Phase 2 of the acid rain 

program required approximately 50% NOx reduction for the “Group 2” boilers, achievable for 

many units only with SCR. Curve A shows the earliest units retrofit with SCR incurred capital 

cost ($/kW basis) did not change with generating capacity – the average cost was about 

$100/kW.

Curve B represents the capital cost for units starting commercial operation from about 2000 

through 2007. Curve B was derived from 32 units, most of which were deployed to meet Phase 1 

CAIR mandates for NOx; although some units were constructed to satisfy consent decrees in 

regard to alleged New Source Review (NSR) violations. Curve B data exhibit a modest 

relationship between generating capacity and capital cost - higher generating capacity enables 

slightly lower unit cost ($/kW basis). Appendix B presents the actual cost data showing the 

variation around the mean, with values as low as $100/kW and as high as $275/kW.
Selective Catalytic Reduction Cost

6-2

Figure 6-1. Capital Cost of SCR Process Equipment vs. Generating Capacity: 

Four Time Periods

Curve C represents the capital cost for sixteen units starting commercial service between 2008 

and 2011, with most intended for Phase 1 CAIR mandates. Individual data for the 16 separate 

SCR facilities (not shown) exhibit great variability. 

Curve D reflects cost for units either retrofit with SCR in 2012, or projected cost for units to be 

operating in 2014.

Comparing the cost described by the three curves and the cost data for 2012-2014 installations 

suggests the following:

Capital Cost has Escalated with Time. Capital investment required for SCR has escalated since 

the earliest installations prior to 2000. For a 500 MW unit, the average capital cost incurred for 

units installed between 2003 and 2008 increased by $75/kW compared to those installed prior to 

2000. The capital required for a 500 MW unit increased by another $100/kW for units installed 

in 2008-2011; and by $200/kW for units installed in 2012-2014. Meaningful escalation in cost is 

clear despite the variability in the data. 

Capital Cost Exhibits Significant Economies of Scale. Lower capital cost per unit ($/kW) output 

is observed at higher generating capacities – materially so in many cases. An exception in this 

trend is noted for the units installed prior to 2000 to meet Phase 1 of the 1997 SIP-Call. Similar 

to the case of wet FGD, this early data cohort does not exhibit this trend – perhaps also a 
Selective Catalytic Reduction Cost

6-3

consequence of higher design margins to account for uncertainty in the largest units, and limited 

experience. 

Figure 6-2 presents the increase in SCR capital cost over the four time periods. Figure 6-2 

reports a total escalation of $166/kW over 12 years – about $14/kW per year. This trend is 

anticipated to continue to 2015, as SCR is installed on smaller generating units located at 

complex sites continues. 

Figure 6-2. Increase in SCR Capital Cost Based on Four Time Periods 

(Three Increments)

An example of how market forces and site characteristics affect SCR cost is demonstrated by the 

two SCR installations at the Consumers Energy Campbell station, separated by 4-5 years.

Consumers Energy installed SCR at Campbell Unit 3 (915 MW) for start-up in 2007, and 

incurred a capital cost used as one of the data points to derive Curve B. Figure 6-3 presents a 

satellite image showing the layout of the Campbell station and the location of Units 1-3. The 

SCR for Unit 3 was designed and constructed by a leading engineering firm and has proved a 

capable design. Consumers Energy was able to exploit market forces at the time – arranging for 

contracting in approximately 2004 and constructing the process to be operable by 2007 – ahead 

of the surge in orders for Phase 1 CAIR compliance. Figure 6-3 shows ample access to Unit 3 on 

both sides for construction activities. Unit 2 does not offer the same equipment access.
Selective Catalytic Reduction Cost

6-4

Figure 6-3. Site Layout for Consumers Energy Campbell Station: Units 1-3 (SCR Retrofit 

to Units 2, 3)

In 2010, Consumers Energy engaged the same supplier to retrofit SCR to the 424 MW Unit 2. 

The timing of the project prevented Consumers Energy from replicating the favorable market 

conditions encountered for Unit 2 – demand for this type of process equipment was much greater 

than in 2004. Economies-of-scale also played a role, with Unit 2 less than half of the generating 

capacity of Unit 3. The demand for components, materials, and construction labor during the 

2008-2010 timeframe substantially exceeded that for Unit 3. As a consequence, the capital cost 

to retrofit SCR to Unit 2 for 2013 startup per unit capacity ($/kW) exceeds that for Unit 3 by 

more than 50%. The experience of Consumers Energy – that an SCR-savvy owner incurred very 

different costs at adjacent units at the same station – demonstrates the role of market forces and 

site conditions in controlling technology cost. 

6.2 OPERATING COST

Operating costs for SCR processes consist mostly of replacement catalyst and ammonia-based 

reagent. The cost for each of these consumables has changed in the last 10 years. In the early 

phases of SCR operation, replacing catalyst was the largest component of operating cost, 

followed by reagent. In the last ten years, a decrease in catalyst cost and escalating ammonia 

prices have inverted this relationship – for most units reagent supply now dominates operating 

cost. Fixed operating and maintenance costs are generally small compared to these two 

components. 

Factors affecting catalyst and reagent supply and reagent cost are discussed subsequently. 
Selective Catalytic Reduction Cost

6-5

6.2.1 SCR Catalyst

The unit cost of catalyst has decreased significantly since the early 1980s. Further, the ability to 

regenerate or rejuvenate catalyst for a cost equivalent to approximately 50% of the cost for new 

product restrains price. 

Figure 6-4 presents the unit price of catalyst since the early 1980s, corrected to a 2011-dollar 

basis. Figure 6-4 shows a decrease in unit price by a factor of five since the earliest commercial 

bids. Minimum prices of near $4,000/m3 were observed in 2005. At this time the demand for 

catalyst was low – generating units in the U.S. equipped with SCR had not yet required 

substantial replacement catalyst – most installations were relatively new and operated 

“seasonally” from May 1 through September 30. Also, in 2005 the demand for SCR equipment 

to meet Phase 1 of CAIR – with the requirement that equipment be installed and operational by 

2009 – had not yet materialized. Since 2005 catalyst prices have escalated slightly due to 

demand – despite the cost pressures of catalyst regeneration which can provide replacement 

catalyst for approximately 50% of new material price. 

Catalyst prices at present remain in the approximate range of $5,000-6,000/m3, although there 

have been reports of cost below $5,000/m3in the last 12 months. 

Figure 6-4. History of SCR Catalyst Prices: 1980-2012 (2011 Dollar Basis)
Selective Catalytic Reduction Cost

6-6

6.2.2 Reagent

Any savings in SCR operating cost due to decreases in catalyst price have been offset by higher 

cost for ammonia-based reagent. SCR operators can choose from four types of ammonia-based 

reagent: anhydrous ammonia, aqueous ammonia of 19.5% NH3 content or 29% NH3 content, or 

urea. For the purposes of this discussion, anhydrous ammonia will be discussed as an example, 

recognizing that alternative reagent forms are equally viable. 

Historically, the cost of anhydrous ammonia is largely determined by the cost of natural gas 

feedstock. In late 2008, the cost for anhydrous ammonia for both agricultural and industrial 

application exceeded $1,000/ton for many suppliers. Figure 6-5 depicts the cost of anhydrous 

ammonia in the Midwest, showing the relationship with time. Over the same period natural gas 

prices have decreased to the range of $2-3/MBtu. 

Anhydrous ammonia prices at present are more driven by the demand for fertilizer due to strong 

prices for corn and other agricultural products. Figure 6-6 depicts the ratio of wholesale 

anhydrous ammonia process to natural gas. The escalation in the ratio of ammonia to natural gas 

in 2008 exhibits the decoupling of the price of these two products, reflecting the strong 

agricultural demand. 

Figure 6-5. Midwestern Anhydrous Ammonia Prices: August 2008-June 2012
Selective Catalytic Reduction Cost

6-7

Figure 6-6. Ratio of Anhydrous Ammonia to Natural Gas Price: 2001-2011

6.2.3 Example Operating Cost

The operating and maintenance cost for an SCR process can be developed (for a 500 MW unit) 

based on assumptions in Table 6-1. These are: 

Fixed O&M. Spare parts and support for miscellaneous duties that must be executed regardless 

of unit operation. Experience suggests this cost can be $200,000 annually.

Catalyst Supply. Catalyst supply cost is determined by periodic purchases from which an annual 

charge can be calculated. The periodic purchases add catalyst to the spare layer or replace 

existing catalyst. For an SCR reactor with a 2+1 catalyst arrangement, designed with an initial 

space velocity of 3,200 l/h and a 16,000 operating hour guarantee, the purchase of one layer 

every 16,000-20,000 operating hours may be required. Operating experience suggests this 

replacement frequency can be a best-case scenario, and greater catalyst changeout needed.

Reagent Cost. The purchase of anhydrous ammonia for 87% NOx removal from 0.35 lb/MBtu, 

at 80% capacity factor, defines the reagent cost. A delivered price of $750/ton is assumed.

Auxiliary Power. Auxiliary power for an additional 5 inch water gauge (w.g.) flue gas pressure 

drop is assumed – 4 inch w.g. for the process flange-to-flange, and an additional 1 inch w.g. 

across the air heater. 
Selective Catalytic Reduction Cost

6-8

Catalyst Cleaning. Sootblower consumption of 0.2% of the plant steam output is adopted; this 

steam is assigned a cost of $1/MBtu. Many new SCR installations employ acoustic horns for 

cleaning, which require auxiliary power that constitutes approximately the same cost. 

Operating Staff. One additional operator dedicated to 50% duty is assumed to be required to 

maintain the above components. Also, a part time (50%) engineer to assess operation and 

evaluate data is assumed. The need to account for additional staff due for SCR operation is 

highly variable; some owners report additional operating or engineering staff is not added for 

these purposes.

Table 6-1 provides a summary of SCR operating cost. The analysis cites fixed O&M, additional 

labor for operating staff, steam for sootblowers, reagent for NOx reduction, auxiliary power and 

an annualized charge for catalyst supply. Of note is that for the reference case presented, the 

annual equivalent charge for replacement catalyst is about 1/3 of the annual charge for anhydrous 

ammonia – a prospect unthinkable in the last decade. Clearly, the high cost of reagent –

prompted by agriculture demand for fertilizer and fertilizer feedstock – elevates the control cost 

per ton.

Table 6-1. Key SCR Operating Cost Components: 500 MW Reference Plant 

Operating Cost Units Value Comment or Input

Fixed

Consumable materials, 

Maintenance staff 

$/kW-y 0.40 Percent of process capital 

($200,000 for 500 MW)

Operators/engineering $/kW-y 0.80 50% of one operator, one 

engineer

Variable

Ammonia reagent $/MWh 0.42 Anhydrous ammonia at $750/ton 

Catalyst replacement (annual 

equivalent)

$/MWh 0.13 Acquire one layer at 16,000 hr 

operating intervals

Fuel cost (auxiliary steam) $/MWh 0.03 Make-up water

Auxiliary power $/MWh 0.08 Based on 5” w.g. @ energy price 

of $25/MWh 

6.2.4 Levelized Removal Cost Per Ton

The levelized cost of NOx control per ton of NOx removed is determined from both operating 

costs and capital recovery charges, normalized by the amount of NOx removed.

The 500 MW reference plant described in Section 5 is used as the basis for this analysis. This 

boiler emission rate for this reference unit, firing bituminous coal, is assumed to be 0.35 lb 

NOx/MBtu, and require control to a stack outlet value of 0.05 lb/MBtu (86% reduction). 

The total charges can be developed for a 500 MW unit retrofit with SCR in 2012 or thereafter. 

Figure 6-1 suggests a 500 MW plant adopting SCR will incur a capital charge of approximately 

$450/kW, thus requiring $225 M. Based on a 20-year life and using the capital cost recovery 
Selective Catalytic Reduction Cost

6-9

factor from EPRI’s TAG of 0.13, an annual charge for capital is estimated to be $28.5 M. 

Consequently, the sum of total operating costs and the annual charge for capital recovery will be 

$2.972 and $28.5 M, totaling $31.5 M. 

Figure 6-7 presents the levelized cost of NOx removal, in terms of cost incurred per ton of NOx

removed, as a function of SCR capital cost. The results are shown for both an eastern bituminous 

coal and PRB, the latter characterized by a boiler emission rate of 0.20 lb/MBtu. The lower 

boiler NOx emission rate elevates the cost per ton, despite lower reagent consumption. 

In the present utility operating environment, it is likely more important to view SCR retrofit cost 

in terms of compromising the economic position of a unit in a competitive power market. A 

comparison of how the retrofit of SCT affects the wholesale power price in competitive markets 

is presented in Section 8. 

Figure 6-7: NOx Control Cost per Ton of NOx Removed
Fabric Filter Control Technology Costs

7-1

SECTION 7

FABRIC FILTER CONTROL TECHNOLOGY COSTS

Section 7 presents capital and operating costs for fabric filter particulate controls, commonly 

referred to as “baghouses,” retrofit to existing units. The reasons to retrofit fabric filter 

equipment are numerous. These reasons include (a) satisfying consent decrees over alleged New 

Source Review violations, (b) as part of a dry FGD process equipment, and (c) to comply with 

the Mercury and Air Toxics (MATS) rule.

Similar to SCR and FGD, fabric filter control technology has evolved in recent decades. 

Figure 7-1 presents a perspective view of a fabric filter with the inset showing how the filter bags 

are arranged and the gas flow pattern.

Figure 7-1. Fabric Filter Particulate Control Device and Detail of Filter Material12

Fabric filter controls can employ thousands of individual filters – 14,000 for a 500 MW plant, 

arranged in perhaps 8 to 15 individual compartments. These filters are configured as “bags” and 

are oriented so particulate-laden flue gas enters from the periphery (outside) of the filter, with 

flue gas flowing radially inward. Particulate matter is removed on the fabric. The bags are 

periodically cleaned of the collected ash by any of several methods; the present state-of-art 

 

12 Source: Adopted from B&W Brochure, Pulse-Jet Fabric Filters, available at 

http://babcock.com/products/environmental_equipment/particulate_and_dust_control.html
Fabric Filter Control Technology Costs

7-2

approach is a cleaning “pulse” of high-pressure air that dislodges the ash. Fabric filter particulate 

collectors that employ this method of cleaning are referred to as the “pulse-jet” design. The 

cleaning cycle is typically intervals of several hours.

7.1 FABRIC FILTER CAPITAL COST 

Fabric filter capital cost is reported in Figure 7-2 for a complete scope of work, including all 

indirect charges and Allowance for Funds Used During Construction, escalated into end-of-year 

2011 dollar basis.

Figure 7-2 displays fabric filter capital cost as a function of generating capacity for seventeen 

units, representing a wide range of generating capacity and application. The costs reported 

include both the fabric filter and ancillary equipment, such as flue gas fans and additional 

ductwork. 

Figure 7-2. Fabric Filter Capital Cost (2011 $ Basis) vs. Generating Capacity

The costs in Figure 7-2 are highly variable. Most notably, there is no clear relationship between 

capital cost and generating capacity. 

The capital cost to retrofit fabric filters, similar to FGD and SCR, depends on numerous sitespecific factors. These include (a) available space for ductwork near the air heater, (b) clear 
Fabric Filter Control Technology Costs

7-3

access by cranes and construction equipment, and (c) the cost for process equipment and 

construction labor. 

Several example sites are discussed, categorized in terms of site access as either “good” or 

“limited”.

7.1.1 Good Site Access

Two generating sites with “good” access – Dairyland Power Madgett Unit 1 and Dynegy 

Vermillion Units 1 and 2 – are described. Sites designated with “good” access typically incurred 

a fabric filter capital cost of less than $200/kW.

Figure 7-3 depicts the site layout for Dairyland Madgett Unit 1. The fabric filter, denoted within 

the blue circle, processes flue gas from the boilerhouse after passing through the SCR reactor. 

The gas flow path is shown exiting the boilerhouse, passing through and exiting the SCR reactor 

(red arrows). The flue gas then passes through the air heater (red circle) and continues into the 

fabric filter (blue circle). The flue gas exits the fabric filter and enters the stack along the path 

indicated by the green arrows. 

Figure 7-3. Dairyland Power Madgett Unit 1: Fabric Filter Installation

Figure 7-4 presents the site layout for Dynegy Vermilion Units 1 and 2. The flue gas from each 

unit exits the boilerhouse and passes through the air heater (red circle), then enters a common 

duct leading to the fabric filter (blue circle). The flue gas from the fabric filter returns to the 

stack (ductwork indicated by the green arrows). 
Fabric Filter Control Technology Costs

7-4

Figure 7-4. Dynegy Vermilion Units 1 and 2: Fabric Filter Installation

7.1.2 Limited Site Access

The highest cost fabric filters (from $200-400/kW) are located at sites where construction access 

is severely inhibited. Two stations are discussed for this category – Arizona Public Service’s 

Cholla Units 3 and 4, and Alliant Lansing Unit 4.

Figure 7-5 depicts Arizona Public Service’s Cholla site. Units 3 and 4 are “interior” and 

“exterior” units, respectively. Figure 7-5 shows gas flows for both units from each boilerhouse 

into an SCR reactor, which after passing through the air heaters (red circle) enters the fabric filter 

(blue circle). The flue gas from the fabric filter returns to the stack as indicated by the green 

arrows.

Cholla Unit 3 presents limited access compared to Unit 4 – the abandoned Unit 4 ESP further 

complicates crane location. As a result of the difference in construction access, Unit 3 fabric 

filter capital and installation cost exceeded that for Unit 4 by 30%. 

Alliant’s Lansing Station offers a second example of a site with limited access. Figure 7-6 

depicts the Unit 4 layout, showing the fabric filter (blue circle) as retrofit in 2008. The adjacent 

water body restricts crane location to one of the four sides, which complicated installation. 

Figure 7-6 shows gas flows from the boilerhouse into an SCR reactor, and transits through 

extended ductwork to the fabric filter. The return gas ductwork (green arrows) is partially 

blocked by the stack. 
Fabric Filter Control Technology Costs

7-5

Figure 7-5. Arizona Public Service’s Cholla Units 3 and 4: Fabric Filter Retrofit 

(Moderate Difficulty)

Figure 7-6. Alliant Lansing Unit 4: Fabric Filter Retrofit (Moderate Difficulty 
Fabric Filter Control Technology Costs

7-6

7.2 EXAMPLE OPERATING COST

The operating and maintenance cost for a fabric filter can be developed (for a hypothetical 500 

MW unit), based on assumptions in Table 7-1 that define the conditions of operation. These are: 

7.2.1 Fixed O&M

Fixed operating and maintenance (O&M) expenditures consist of spare parts and services for 

miscellaneous duties – independent of how much the fabric filter is operating. This cost is 

assumed to be equivalent to 0.25% of process capital.

In addition, one operator at 50% duty is required for general maintenance. A part time (50%) 

engineer is also assumed to be required to assess operation and evaluate data. The specific staff 

needs are highly variable; some owners report adding operating staff while others require these 

duties to be absorbed by existing staff.

7.2.2. Variable O&M. 

Replacement filter bags and cages, and auxiliary power are key components to variable O&M.

Replacement Bags and Cages Supply. The 500 MW reference unit is assumed to contain 14,000 

individual filter bags, which (with support cages) are assumed replaced at 3-year intervals. 

Consistent with assumptions developed by Sargent & Lundy for EPA, the replacement bags and 

support cages are assumed to cost $80 and $60 each, respectively.13 The annual cost to replace 

bags and cages is developed assuming 1/3 of the total filter bag and cage inventory is replaced 

annually.

Auxiliary Power. The auxiliary power demand depends on the design of the fabric filter, most 

notably the air/cloth ratio. Typically, the fabric filter pulse-jet design that uses high air/cloth 

ratios (~6 ft/s) will incur a greater gas pressure drop than designs based on conventional reversegas or shake-deflate cleaning. A typical pulse-jet unit with an air/cloth ratio of 6 ft/s will incur an 

additional 6 inch water gauge (w.g.) gas pressure drop. For the present analysis, an additional 

auxiliary power of 8-inch w.g. gas pressure drop is assumed – comprised of 6 inch w.g. for the 

fabric filter and an additional 2 inch w.g. for ductwork.

Table 7-1 summarizes the operating cost components for a fabric filter retrofit to the 500 MW 

reference unit. The cost analysis includes fixed O&M, labor required for operating staff, and the 

variable O&M for replacement filters and auxiliary power. 

 

13 IPM Model – Revisions to Cost and Performance for APC Technologies: Particulate Control Cost Development 

Methodology Final, prepared by Sargent & Lundy, March 2011, Project 12301-009, for Systems Research and 

Applications Corporation. 
Fabric Filter Control Technology Costs

7-7

Table 7-1. Key Fabric Filter Operating Cost Components: 500 MW Reference Plant 

($250/kW Capital, 2011 Dollar Basis)

Cost 

Component Basis Annual Cost for500 MW ($/yr)

Annual Cost for

500 MW 

(mills/kWh)

Operations

Fixed O&M Process Capital 312,500 0.084

Labor Operators/Part-time Engineer 396,360 0.106

Total Fixed O&M 708,860 0.190

Variable O&M

Replacement 

Filter 

Materials

Based on individual filter cost 

of $80 each, and support cage 

cost of $60/each

650,000 0.173

Auxiliary 

Power

8 inch w.g. total @ $20/MWh 430,000 0.115

Total Variable O&M 1,074,000 0.289

Total Operations 1,783,846 0.48

Capital

Capital 

Requirement

Based on unit cost of 

$250/kW, and capital 

recovery factor of 0.13

16,250,000 4.37

Total: Levelized Operations and Capital 18,038,500 4.85

7.3 LEVELIZED COST

Table 7-1 summarizes levelized cost of deploying fabric filter control technology is developed, 

based on capital recovery and operating cost.

Levelized costs are developed for the 500 MW reference plant described in Section 5, retrofit 

with a fabric filter in 2011. Table 7-1 reflects a fabric filter capital charge of approximately 

$250/kW, thus requiring $125 M. Based on a 20 year life and using the capital cost recovery 

factor from EPRI’s TAG of 0.13, the annual charge for capital is estimated to be $16.25 M. 

The sum of all operating costs and the annual charge for capital recovery will be $1.78 and 

$16.25 M, totaling $18.03 M. Levelized cost per production basis to deploy a fabric filter for the 

500 MW reference unit is 4.85 mills/kWh.
Cost Competitiveness

8-1

SECTION 8

COST COMPETITIVENESS

This report has summarized the cost of FGD, SCR, and fabric filter air pollution controls. The 

cost metrics considered are capital requirement, and fixed and variable operating costs for a 

500 MW reference plant.

Historically, the cost for environmental controls has been measured in terms of the cost per ton 

($/ton) for removing SO2, NOx, or particulate matter. The significance of this cost index is 

perhaps diminished in the present economic climate, where total emission “caps” and ambient air 

standards are driven by mandates within CAIR, CSAPR, and MATS. Further, most control 

equipment contributes to removing more than one pollutant – SCR and FGD remove not only 

NOx and SO2, but assist in mercury and acid gas (e.g., hydrochloric acid) removal. Fabric filters 

remove particulate matter but also help remove mercury and acid gases. As a result, measuring 

the value of environmental controls in terms of removing one pollutant does not always reflect 

the complete benefit.

Perhaps more important in the present economic climate is how retrofit of air pollution controls 

affects the wholesale power price of units in power markets. Analyses released by The Brattle 

Group14, Bloomberg Government15, and SNL Financial16 predict unit retirements based on the 

added cost for environmental controls and the wholesale energy price in a local market.

Several examples illustrate this point. First, the fuel cost for both coal-fired and natural 

gas/combined cycle (NG/CC) generation is compared to U.S. wholesale energy prices. Two 

reference cases demonstrate how the cost to retrofit environmental controls affects 

competitiveness in power markets. The cost to retrofit FGD, SCR and fabric filter equipment to a 

500 MW reference unit is compared to the 2012 U.S. wholesale energy price. In addition, the 

cost to retrofit and operate a fabric filter to a smaller (300 MW) unit, operating at lower capacity 

factor and using “allowances” to comply with NOx and SO2 limits, is compared to the wholesale 

energy price. 

8.1 POWER MARKET REFERENCE

The incremental cost to retrofit and operate environmental controls to a 500 MW unit is 

compared to both fuel and U.S. wholesale energy prices. The fuel cost for a combined cycle 

generating unit is also compared. 

 

14 Potential Coal Plant Retirements in the U.S. and Impacts on Gas Demand, prepared by Metin Celebi, presentation 

at CERI Conference, Calgary, CN, February 27, 2012.

15 The Twilight of Coal-fired Power? The EPA’s New Standards for Greenhouse Gases, prepared by R. Barnett et. 

al., Bloomberg Government, May 1, 2012.

16 Upcoming, recent coal-fired power plant retirements, M. Niven, et al., SNL Financial, Wednesday, March 28, 

2012.
Cost Competitiveness

8-2

Figure 8-1 presents 2012 wholesale energy prices for eight power markets in the U.S.17 The fuel 

cost for conventional coal-fired generation is also shown, along with fuel cost for natural gas 

combined cycle generators – the most prominent alternative to coal-fired power.

Two scenarios of fuel cost are represented for both coal-fired and natural gas/combined cycle 

generation. For coal-fired generation, fuel cost for a delivered fuel price of $1.50/MBtu and a 

9,600 Btu/kWh heat rate (low cost) and $2.25/MBtu and heat rate of 11,500 Btu/kWh (higher 

cost) are reported. Fuel cost for natural gas/combined cycle generation is shown for low cost 

($3/MBtu and 7,000 Btu/kWh heat rate) and higher cost ($4/MBtu and 8,000 Btu/kWh heat rate) 

scenarios. 

0

5

10

15

20

25

30

35

40

45

50

NG/CC Fuel Cost 

($3/MBtu, 7,000 

Btu/kWh)

NG/CC Fuel Cost 

($4/MBtu, 8,000 

Btu/kWh)

Coal Boiler Fuel Cost 

($1.5 0/MBtu, 9,600 

Btu/kWh)

Coal Boiler Fuel Cost 

($2.5 0/MBtu, 1 1,500 

Btu/kWh) Wholesale Power Price or Fuel Cost (2012, $/MWh)

Range of 2012 

Wholesale Power Prices 

Figure 8-1. Competitive Power Landscape: Wholesale (Peak) Power Prices, and Fuel Cost 

for Generating Options 

Figure 8-1 shows for coal-fired or natural gas/combined cycle generation that the cost for fuel 

comprises a large fraction of, or even exceeds, wholesale power prices in certain regions in the 

U.S. The cost for fuel under the least fuel cost scenarios for natural gas/combined cycle and 

steam boiler operation can comprise 50-65% of the median wholesale energy prices. The cost for 

fuel for higher cost scenarios exceeds the minimum wholesale power price and approaches the 

median wholesale power prices. 

 

17 Today In Energy, U.S. Energy Information Agency, January 9, 2013, available at 

http://www.eia.gov/todayinenergy/detail.cfm?id=9510
Cost Competitiveness

8-3

The cost of fuel relative to a whole energy market leaves little margin to absorb for air pollution 

control costs.

8.2 SCR, FGD REFERENCE UNIT COST

The total cost for SCR and FGD for coal-fired generators – fixed and variable operating cost, and 

capital recovery – is compared to the wholesale energy price, and fuel charges for natural 

gas/combined cycle and coal-fired generators. The analysis is conducted for a 500 MW reference 

unit firing eastern bituminous coal.

Figure 8-2 compares the cost for FGD and SCR to the fuel cost for coal-fired boilers, the fuel 

cost for natural gas/combined cycle generation, and the range of wholesale energy prices.

0

5

10

15

20

25

30

35

40

45

FGD Var 

O&M

FGD Total 

(8 5% C.F.)

FGD Total 

(6 5% C.F.)

SCR Total 

(8 5% C.F.)

SCR Total 

(6 5% C.F.)

Total FGD, 

SCR (8 5% 

C.F.)

NG/CC Fuel 

Cost 

($3/MBtu, 

7,000 

Btu/kWh)

NG/CC Fuel 

Cost 

($4/MBtu, 

8,000 

Btu/kWh)

Coal Boiler 

Fuel Cost 

($1.5 0/MBtu, 

9,600 

Btu/kWh)

Coal Boiler 

Fuel Cost 

($2.5 0/MBtu, 

1 1,500 

Btu/kWh) Wholesale Power Price or Environmental Control Cost 

(2012, $/MWh)

Range of 2012 

Wholesale Power Prices 

FGD SCR FGD + SCR

Figure 8-2. FGD and SCR Incremental and Total Carrying Costs Compared to Fuel Costs 

for NG/CC and Steam Boilers

Wet FGD. Three cost cases are presented for wet FGD deployed to a 500 MW unit firing eastern 

bituminous coal. These are the FGD variable O&M cost, and total cost for a 65% and 85% 

capacity factor. The variable cost of almost $4/MWh is small compared to the total cost of 

$13/MWh, as calculated for an 85% capacity factor. The total FGD cost increases to $16/MWh if 

the capacity factor decreases to 65%. 
Cost Competitiveness

8-4

Figure 8-2 shows the cost for FGD can be up to half or more of the lowest 2011 wholesale 

energy price. The wet FGD total cost can approach or equal the fuel charge for a coal-fired 

generator experiencing a low cost fuel scenario (coal at $1.50/MBtu and a 9,600 Btu/kWh heat 

rate). 

SCR. Two cost cases are presented for SCR. Figure 8-2 shows total incurred cost is about $8 

and $11/MWh for the 85% and 65% capacity factor cases, respectively. Figure 8-2 shows the 

cost to deploy SCR about 2/3 the cost to deploy wet FGD, at the same capacity factor. 

Wet FGD and SCR. The combined total cost for wet FGD and SCR – about $23/MWh – almost 

equals the lowest wholesale energy price for 2011. Figure 8-2 shows the combined cost for FGD 

and SCR exceeds the fuel cost for either natural gas/combined cycle or coal-fired boilers (the 

low cost scenario). The combined wet FGD and SCR cost is about 75% of the fuel cost for 

natural gas/combined cycle and coal-fired boilers for the high cost scenario.

Figure 8-2 shows the total cost for wet FGD and SCR, by almost equaling the fuel price, can 

eliminate a unit from competitive power generation. 

8.3 ROLE OF FABRIC FILTER

A fabric filter will be required by many units to improve control of particulate matter and 

provide a favorable environment to remove mercury and acid gases. This section will consider 

the cost to retrofit fabric filters to the 500 MW reference case. In addition, the cost to retrofit and 

operate a fabric filter to a small generating capacity, low capacity factor unit that complies with 

NOx and SO2 emission limits using allowances will be considered.

Figure 8-3 presents the total fabric filter cost for both applications – the 500 MW reference plant 

operating at 80% capacity factor, and a 300 MW unit operating at 50% capacity factor. The 

capital cost for this equipment is derived from Figure 7-1: an intermediate value of $250/kW is 

selected for the 500 MW cases, and $325/kW for the 300 MW case. The operating costs are 

defined by a 3-year changeout period for fabric filter media and cages, and a gas pressure drop of 

8 inch w.g.

Figure 8-3 shows for the 500 MW reference unit that a fabric filter requires about half of the 

capital for either of wet FGD and SCR. As a result, total incurred cost for a fabric filter is about 

$5/MWh for the 80% capacity factor case. This cost – although notable for a 500 MW unit –

may not remove the unit from wholesale energy markets.

The cost impact can be very different for a 300 MW unit that employs allowance purchases to 

meet NOx and SO2 mandates. A 300 MW unit, if incurring a fabric filter capital charge of 

$325/kW and operating at a 50% capacity factor, will incur a total additional cost of $10/MWh.

Retrofitting a fabric filter to a 300 MW unit imposes a competitive disadvantage compared to 

natural gas/combined cycle generation. Figure 8-3 shows the incurred total cost for a fabric filter 

for this unit is about 1/2 the fuel cost for natural gas/combined cycle generation, for the $3/MBtu 

and 7,000 Btu/kWh heat rate, and about 1/3 the fuel cost for $4/MBtu and 8,000 Btu/kWh heat 

rate.
Cost Competitiveness

8-5

0

5

1 0

1 5

2 0

2 5

3 0

3 5

4 0

4 5

5 0

500 MW, 8 0% Capacity 

Factor

300 MW, 5 0% Capacity 

Factor

Fuel: NG/CC at $3/MBtu 

7000 Btu/kWh

Fuel: NG/CC at $4/MBtu 

8000 Btu/kWh Wholesale Power Price or Environmental Control Cost 

(2011, $/MWh)

NG/CC Fuel:

- $3.00 per MBtu

- 7,000 Btu/kWh

Total FF Cost 

(80% C.F.)

Total FF Cost 

(300 MW, 

50% C.F.)

NG/CC Fuel:

- $4.00 per MBtu

- 8,000 Btu/kWh Range of 2013 

Wholesale Power 

Prices at "Peak"

Figure 8-3. Fabric Filter Total Cost vs. NG/CC Fuel Charge: 300 and 500 MW Units
Current Capital Cost and Cost-Effectiveness

of Power Plant Emissions Control Technologies

A-1

APPENDIX A

EXAMPLE WET FGD CAPITAL COST DATA

Figure A-1. Individual Cost Data for Wet FGD: Phase 1 CAAA Applications 

(Curve A of Figure 5-1)
Current Capital Cost and Cost-Effectiveness

of Power Plant Emissions Control Technologies

A-2

Figure A-2. Individual Cost Data for Wet FGD: 2003-2007 Applications 

(Curve B of Figure 5-1)
Current Capital Cost and Cost-Effectiveness

of Power Plant Emissions Control Technologies

B-1

APPENDIX B

EXAMPLE SCR CAPITAL COST DATA

Figure B-1. Individual Cost Data for SCR: Curve B of Figure 6-1