CURRENT CAPITAL COST AND COST-EFFECTIVENESS 

OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES 

Prepared by 

J. Edward Cichanowicz 

Prepared for 

Utility Air Regulatory Group 

June, 2007 

CURRENT CAPITAL COST AND COST-EFFECTIVENESS 

OF POWER PLANT EMISSION CONTROL TECHNOLOGIES 

Section/Title Page No.

SECTION 1 SUMMARY......................................................................................................................... 1 

SECTION 2 INTRODUCTION ............................................................................................................... 3 

SECTION 3 BACKGROUND ................................................................................................................. 4 

3.1 INTRODUCTION .................................................................................................................... 4 

3.2 RETROFIT OF CONTROL TECHNOLOGY......................................................................... 4 

3.3 NEW GENERATING STATIONS .......................................................................................... 5 

SECTION 4 MATERIAL AND LABOR ESCALATION ...................................................................... 9 

4.1 BASIC MATERIALS............................................................................................................... 9 

4.2 LABOR................................................................................................................................... 13 

4.2.1 Labor Cost Escalation..................................................................................................... 13 

4.2.2 Labor Pool Availability .................................................................................................. 14 

4.3 FGD COST ESCALATION................................................................................................... 15 

SECTION 5 FACTORS AFFECTING CAPITAL COST ESTIMATES .............................................. 17 

5.1 CAPITAL COST ESTIMATING METHODOLOGY........................................................... 17 

5.2 SITE AND DESIGN FACTORS............................................................................................ 19 

SECTION 6 FLUE GAS DESULFURIZATION COSTS ..................................................................... 21 

6.1 FGD CAPITAL COST ........................................................................................................... 21 

6.1.1 Anonymous..................................................................................................................... 21 

6.1.2 Publicly Released Studies............................................................................................... 22 

6.2 OPERATING COST .............................................................................................................. 24 

SECTION 7 SCR NOx COST................................................................................................................ 27 

7.1 SCR CAPITAL COST............................................................................................................ 27 

7.2 THREE SURVEYS ................................................................................................................ 27 

7.3 COST ESCALATION............................................................................................................ 28 

7.4 OPERATING COST .............................................................................................................. 29 

7.4.1 SCR Catalyst................................................................................................................... 29 

7.4.2 Reagent ........................................................................................................................... 30 

7.4.3 Example Operating Cost................................................................................................. 31

SECTION 8 IMPLICATIONS FOR Hg CONTROL............................................................................. 33 

SECTION 9 CONCLUSIONS ............................................................................................................... 35 

SECTION 10 REFERENCES ................................................................................................................ 37 

SECTION 11 FGD COST REFERENCES ............................................................................................ 39 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

1 

SECTION 1 

SUMMARY 

The utility industry faces numerous mandates to retrofit air emission controls to existing power 

plants. Specifically, the Clean Air Interstate Rule (CAIR), Clean Air Visibility Rule (CAVR), 

settlements with the Department of Justice over alleged NSR violations, and the Clean Air 

Mercury Rule (CAMR) all require retrofit of control technology. Many of these rules and 

consent decrees require equipment installation and operation on or before 2010, with mandates 

for more equipment retrofits shortly thereafter. The schedule for this significant emission control 

retrofit program is coincident with the anticipated construction of approximately 80 GW of new 

power plants according to some estimates (Figueroa, 2006). 

This demand for emission control equipment has strained domestic supply chains. 

Internationally, robust demand for materials and labor for petrochemical industries, urban 

infrastructure, and power generation in developing countries consumes much of the international 

supply. As a consequence, capital cost has escalated for flue gas desulfurization (FGD) and 

selective catalytic reduction (SCR) equipment, and material/labor shortages force construction 

delays. Some owners of small generating units simply cannot access control equipment as 

suppliers are overbooked – some requests-for-proposals for FGD receive no bids, or limited bids 

at a premium price. These issues complicate, if not prevent, complying with the regulations 

within the timeframe specified by the regulatory actions. 

For example, in the case of wet FGD, prices for components such as electrical transformers, flue 

gas stacks, and specialty steel pipe have increased 40% and 50% between 2003 and 2007. The 

price of field fabricated steel tanks, slurry pumps, reagent pulverizers, reagent conveyors, and 

flue gas booster fans has escalated 15-23% over the same period. The lead time from order to 

delivery for components such as ball mills for reagent preparation, rubber-lined recycle pumps, 

fans, and spray headers has more than doubled in many cases. 

Consequently, FGD capital cost has escalated at a rate equivalent to 7-9% annually since 2003. 

The example of Allegheny Energy is instructive – firm bids received in 2006 for wet FGD for Ft. 

Martin Units 1-2 and Hatfield Ferry Units 3-4 exceeded cost estimates developed in 2004 by an 

average of $100/kW. This is not an isolated event, and the consequences are significant. For a 

coal with sulfur content of 6 lbs/SO2/MBtu, an increase in capital cost of $100/kW can translate 

into higher SO2 removal cost effectiveness of several hundred dollars per ton. The same 

escalation in FGD capital cost for a PRB coal with typical sulfur content of 0.9 lbs SO2/MBtu 

will increase SO2 removal cost effectiveness by $800/ton. 

Regarding schedule, under the best conditions a wet FGD retrofit can be completed within 36 

months, but only if none of the key suppliers are overbooked for the project duration. This is 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

2

typically not the case – some constructors and erectors of specialty items are booked for the next 

4 years1. It should be noted that in 2002 EPA projected that FGD installations for CAIR would 

require a 28 month schedule from inception to startup (EPA, 2002). 

The cost for SCR NOx control has similarly escalated. The most recent reports show SCR capital 

cost averages $200/kW because the remaining sites to be retrofit present significant challenges. 

Catalyst unit price has dropped fivefold since the earliest commercial applications, but the 

increasingly complex sites and escalation in material cost have offset any cost benefits. The cost 

of ammonia-based reagent, of which 80-90% is determined by the price of natural gas, now 

averages $400/ton. Reagent cost is now the largest SCR operating cost component. 

For a typical 500 MW unit firing an eastern bituminous coal and producing NOx at a rate of 0.38 

lbs/MBtu, a $100/kW increase in SCR capital cost will elevate NOx removal cost effectiveness 

by $800/ton (annual operation). For a 500 MW unit firing PRB and producing NOx at a rate of 

0.20 lbs/MBtu, a capital cost increase of $100/kW will increase NOx reduction cost effectiveness 

by almost $2,000/ton. 

Hg control plans may also be impacted by the supply and demand imbalance. EPA estimates a 

total of 1,900 MW of fabric filter (FF) capacity will be installed for use with mercury-specific 

sorbent, such as activated carbon injection (ACI) to meet CAMR by 2010 (EPA, 2006). The 

basis of EPA’s estimate is not revealed, and it is not possible to judge how realistic this 

prediction is. Based on the emissions control rule proposed by the state of Georgia, it is likely the 

actual installed inventory of FF retrofit will be greater than predicted by EPA’s analysis, which 

did not consider state-specific Hg regulations. Finally, EPA assumptions of co-benefits of Hg 

removal by SCR and FGD may be optimistic, especially for those applications involving low 

rank coals. These short-falls in Hg removal would then have to be compensated for by greater 

control by ACI with FF. 

In summary, the converging mandates for control of SO2, NOx, and possibly Hg, combined with 

proposed new coal-fired generation, will significantly stretch control technology supply chains. 

The result will be severe price escalation and threats to timely project completion. 

 

1

 According to some observers, there are three erectors of stacks in the world with qualified experience to provide a 

satisfactory design; all are reportedly booked through 2011. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

3 

SECTION 2 

INTRODUCTION 

The cost for capital equipment for the power industry is rapidly escalating. In the U.S., several 

environmental mandates for control of flue gas emissions that stem from the 1990 Clean Air Act 

Amendments (CAAA) are converging within the time span of only a few years. In addition, the need 

for new, predominantly coal-fired power stations not only in the U.S. but around the world has 

increased the demand for material and labor. Internationally, the general robust world-wide demand for 

chemical processing facilities, transportation, and urban infrastructure further absorb material and 

specialized construction labor. As a consequence, the capital cost for almost all power industry 

equipment has increased, and delivery times extended. 

On the supply side, the dearth of construction in the mid 1990s for equipment and services of this type 

prompted suppliers and specialized construction labor to migrate to other industries. Consequently, the 

supply field is limited, particularly for specialty items required in general chemical and industrial 

applications, such as rubber-lined slurry pumps, pulverization and reagent grinding equipment, and 

flue gas emission stacks. 

The combination of higher equipment costs and schedule delays challenges utilities implementing 

plans to meet emission caps or other emission reduction requirements for SO2, NOx, and Hg. Some 

operators may not be able to meet their compliance mandates on schedule without purchase of 

emissions allowances, or will incur escalated compliance costs. 

This paper summarizes the cost trends observed in recent years for flue gas controls for both SO2 and 

NOx, and the prospects for Hg controls. Section 3 provides relevant background information, 

addressing the projected capacity to be retrofit of environmental controls, and projected capacity of 

new coal-fired plants. Section 4 summarizes the key issues important to escalation of both material and 

labor. Section 5 highlights the factors affecting capital cost of both flue gas desulfurization (FGD) and 

selective catalytic reduction (SCR) NOx control process equipment. Section 6 overviews recent reports 

of incurred and projected FGD cost, and Section 7 addresses the same for SCR NOx control. The 

implications of this building environment on Hg control are presented in Section 8, and a summary 

presented in Section 9. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

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SECTION 3 

BACKGROUND 

3.1 INTRODUCTION 

Numerous regulatory programs prompt the installation of environmental control equipment for the 

U.S. power industry. In addition to the retrofit of existing units, the large number of new units 

proposed impacts the availability of equipment, resources and construction labor. This section reviews 

these driving forces. 

3.2 RETROFIT OF CONTROL TECHNOLOGY 

Retrofit of control technology to existing plants is mandated by several actions subsequent to the 1990 

Clean Air Act Amendment: the Clean Air Interstate Rule (CAIR), and regional haze initiatives such as 

the Clean Air Visibility Rule (CAVR). Further, settlements with EPA and the Department of Justice 

(DOJ) over alleged new source review (NSR) violations may affect plans for SO2 and NOx reduction. 

Each of these is addressed in the following. 

Clean Air Interstate Rule (CAIR). This two-phase program mandates reducing NOx and SO2 in an 

initial Phase 1 (2009 for NOx and 2010 for SO2), and a subsequent Phase 2 (2015 for both SO2 and 

NOx). The CAIR program is the key driving force behind FGD and SCR deployment. 

Best Available Retrofit Technology (BART). BART requirements are part of the Clean Air Visibility 

Rule (CAVR). These federal regulations require all states to revise their State Implementation Plans 

(SIPs) to address visibility impairment in Mandatory Class I Federal Areas, which are specific national 

parks and wilderness areas across the country. One of the provisions of the federal regulations is the 

application of BART to certain existing major stationary sources that were put into service between 

1962 and 1977. The rule requires these facilities to conduct BART analysis (a very extensive 

undertaking) on each affected unit to determine the control technology and the level of emission 

controls representing BART. Consequently, even in the case of facilities that are not required to install 

additional emission controls to meet BART requirements, states may require retrofit of emissions 

controls to implement the CAVR directive that states develop plans to achieve “reasonable progress” 

toward eliminating manmade impairment of visibility in Mandatory Class I Federal Areas. 

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

Directors Consortium (LADCO), are considering additional control measures for SO2 and NOx beyond 

CAIR. Regulatory agencies in other regions in the country such as the southeast (VISTAS) and far 

west (WRAP) are considering similar mandates. The extent and timing of these mandates is uncertain, 

but most proposed initiatives will require control equipment by the 2014 to 2018 time period. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

5

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

CAAA regarding New Source Review (NSR) were violated prompted several owners to alter FGD and 

SCR schedules from that required to meet CAIR. 

Retrofit of FGD and SCR to a significant population of coal-fired stations is required to meet these 

existing and proposed mandates. Figures 3-1 to 3-6 depict the inventory of wet and dry FGD, and SCR 

process equipment that has been announced to meet the CAIR and other mandates. Figure 3-1 shows 

the annual addition as generating capacity (MW) of both wet and dry FGD, and Figure 3-2 the 

cumulative totals, both through 2010. Figures 3-3 and Figure 3-4 show the incremental and cumulative 

generating capacity retrofit with SCR over the same time period. 

Of significance to CAMR compliance is the “co-benefit” of Hg control where oxidized Hg is removed 

as a consequence of SCR and wet FGD. Figures 3-5 and 3-6 show the annual and cumulative 

generating capacity predicted to be equipped with both SCR and wet FGD, designated by the first year 

of operation with both control systems. Figures 3-5 and 3-6 provide an estimate of generating units that 

can conceivably exploit NOx and SO2 controls for mercury removal. 

3.3 NEW GENERATING STATIONS 

The number of new coal-fired units planned for operation between 2009 and 2020 is unprecedented, 

and will further stretch resources for construction of new FGD and SCR process equipment. 

Approximately 80 GW of new coal-fired generating capacity has been proposed (Figueroa, 2006). 

Although it is not clear how many of these units will actually be built, even one-half of the proposed 

capacity will exert considerable strain on suppliers, resources and construction labor. 

There is already evidence that the significant number of retrofit emission control technologies and new 

plants is straining resources. This evidence can be seen by the escalation in prices of basic materials, 

and delays in schedule to procure these basic materials. The price escalation and schedule delays are 

addressed in the next section. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

6

0

5,000

10,000

15,000

20,000

25,000

Through

2001

2002 2003 2004 2005 2006 2007 2008 2009 2010

Year Operational

Capacity (MW)

Figure 3-1. Historical and Projected Wet, Dry FGD Capacity: Installed MW per Year 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Through

2001

2002 2003 2004 2005 2006 2007 2008 2009 2010

Year Operational

Capacity (MW)

Figure 3-2. Historical and Projected Wet, Dry FGD Capacity: Cumulative MW per Year 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

7

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Through 2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Annual SCR Capacity Installed (MW)

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

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

1995

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2012

First Year of Operation

Installed Retrofit SCR Capacity (MW)

Figure 3-4. Historical and Projected SCR Capacity: Cumulative Installed SCR Capacity (MW) 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

8

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Through

2001

2002 2003 2004 2005 2006 2007 2008 2009 2010

Year Operational

Capacity (MW)

Figure 3-5. Historical and Projected Capacity: FGD and SCR, 

Annual Installed Capacity (MW) 

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Through

2001

2002 2003 2004 2005 2006 2007 2008 2009 2010

Year Operational

Capacity (MW)

Figure 3-6. Historical and Projected Capacity: FGD and SCR Cumulative Installed Capacity 

(MW) 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

9 

SECTION 4 

MATERIAL AND LABOR ESCALATION 

This section addresses the cost escalation of material and labor, and the impact of installed equipment 

cost and construction schedule. 

4.1 BASIC MATERIALS 

Among the basic materials required for both installation of retrofit of control technology and new 

generating equipment are structural steel, ready-mix concrete, copper wire and cable, and fabricated 

steel plate. These materials are broadly available in the U.S. and throughout the world, but are 

experiencing strong demand due to world-wide needs for process industries and infrastructure. 

Figures 4-1 to 4-4 present price escalation data for these materials over the last five years, from 

December 2002 and into early 2007, as reported to the U.S. Bureau of Economic Analysis2

. For three 

categories of these materials, prices have increased by 40% over the December 2002 value. The 

exception is for Copper Cable and Wiring for which price has increased by a factor of three. 

Prices for special alloys used in wet FGD reaction vessels, and high pressure, high temperature boiler 

components have also escalated. Both nickel and molybdenum, key to production of corrosionresistant and high strength materials, have witnessed increased demand and price. Figures 4-5 and 4-6 

present price trends for molybdenum and nickel, showing prices have escalated by factors of 3 to 5, 

respectively. Although the mass content of these components in finished steel product is small, 

escalations of these magnitudes will have a material affect final product cost. 

The impact of this escalation on the cost of components for wet and dry FGD and SCR is shown in 

Table 4-1, as witnessed from 2004 to early 2007. Although all of these factors are important, perhaps 

most significant is stack cost – driven by both material demand and the limited supply of qualified 

erectors. The limited number of stack erectors world-wide, coupled with the demand for new stacks for 

both retrofit of wet FGD and new generating units, has significantly elevated costs. 

The limited supply of materials not only elevates cost but can delay construction schedule. Table 4-2 

reports the increase in component lead time, as measured in terms of weeks from order to delivery 

time. The lead time for several of these components has more than doubled, based on comparing data 

for December 2006 and September 2003. 

These basic materials, once procured, may incur a further delay to be installed. A world-wide shortage 

of cranes has added to the schedule delay and cost escalation (Brat, 2007). 

 

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

April 27, 2007, downloaded May 25, 2007, http://www.bea.gov/national/nipaweb/SelectTable.asp?Selected=Y
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

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Figure 4-1. Structural Steel Cost Escalation 

Figure 4-2. Ready-Mix Concrete Cost Escalation 

Cost Index for Ready-Mix Concrete

Producer Price Index (Source: Bureau of Labor Statistics)

(Curve from Jan 1996 to Jan 2003 Not Shown)

100.0

120.0

140.0

160.0

180.0

200.0

220.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07

Month-Year

Ready Mix Concrete (1/1982 = 100)

Compound Esc. from 2003 to 2007 = 7.6%

Compound Esc. from 1996 to 2003 = 2.0%

Cost Index for Structural Steel

Producer Price Index (Source: Bureau of Labor Statistics)

(Curve from Jan 1996 to Jan 2003 Not Shown)

100.0

120.0

140.0

160.0

180.0

200.0

220.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07

Month-Year

Structural Steel (Jan 1982 = 100)

Compound Esc. from 2003 to 2007 = 7.7%

Compound Esc. from 1996 to 2003 = 1.0%
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

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Figure 4-3. Fabricated Steel Plate Cost Escalation 

Figure 4-4. Copper Wire and Cable Cost Escalation 

Cost Index for Fabricated Steel Plates

Producer Price Index (Source: Bureau of Labor Statistics)

(Curve from Jan 1996 to Jan 2003 Not Shown)

100.0

120.0

140.0

160.0

180.0

200.0

220.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07

Month-Year

Steel Plates (Jun 1982 = 100)

Compound Esc. from 2003 to 2007 = 9.4%

Compound Esc. from 1996 to 2003 = -0.3%

Cost Index for Copper Wire & Cable

Producer Price Index (Source: Bureau of Labor Statistics)

(Curve from Jan 1996 to Jan 2003 Not Shown)

100.0

150.0

200.0

250.0

300.0

350.0

400.0

May-02 Dec-02 Jun-03 Jan-04 Aug-04 Feb-05 Sep-05 Mar-06 Oct-06 Apr-07

Month-Year

Copper Wire & Cable (Dec 1986 = 100)

Compound Esc. from 2003 to 2007 = 26.2%

Compound Esc. from 1996 to 2003 = -2.2%
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

12

Figure 4-5. Molybdenum Price Escalation 

Figure 4-6. Nickel Price Escalation 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

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Table 4-1. Escalation of Key Wet FGD Components: 2004 – 2007 

FGD Component Price Increase, %

Transformers 50+ 

Stack 50 

Steel Pipe 40+ 

Field Fabricated Steel Tanks 23 

Pumps 18 

Pulverizers 18 

Conveyors 17 

Fans 16 

Table 4-2. Increase in Component Lead Time, Weeks (December 2006 vs. September 2003) 

 Total Lead Time, Weeks 

Equipment Sept ‘03 Oct ‘05 Aug ‘06 Dec ‘06 

Ball Mills 32 65 68 70 

Rubber-lined Recycle Pumps 26 52 92 112 

Booster Fans - 54 54 60 

Oxidation Air Compressors 32 44 44 52 

Internal Recycle Spray Headers 28 40 40 48 

Source: Katzberger, 2007 

4.2 LABOR 

The present cost trends and potential for shortages for qualified field labor are discussed in this section. 

4.2.1 Labor Cost Escalation 

Labor cost escalation experienced by the industry is shown in Table 4-3. This data, developed by an 

architect/engineering firm involved in the construction of several new Midwestern plants, shows the 

annual labor escalation to be between 5.2 and 7.4% per year, averaging 6.2%. 

Labor and equipment required for installing a control technology constitutes about half the total cost – 

with the remaining costs being due to process equipment acquisition and design. Not all installation 

cost is devoted to labor – cranes and other heavy equipment are required – but the labor component is 

significant. Inevitably, escalating labor cost will translate into higher installed emission control 

equipment cost. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

14

Table 4-3. Recent Cost Escalation: Labor Rates ($/hr) for Midwestern Coal Plant Construction 

CRAFT 2005 2006 2007 Annual Escalation 

Rate, % 

Operators 28.06 29.56 31.06 5.3 

Laborers 19.50 20.70 21.90 6.1 

Millwright 30.00 31.85 33.70 6.2 

Ironworker 25.10 26.95 28.80 7.4 

Carpenter 25.65 27.50 29.35 7.2 

Pipefitter 32.73 34.83 36.93 6.4 

Electricians 30.73 32.58 34.43 6.0 

Boilermaker 27.80 28.60 30.10 5.2 

Total 6.2 

Source: Black & Veatch, 2006 

4.2.2 Labor Pool Availability 

The specialized labor pool required for SCR and FGD retrofit is subject to high demand and may limit 

equipment installation. Table 4-3 defined the skilled labor categories required for power plant 

construction. As noted in Table 4-3, labor rates for all categories are subject to cost pressure. Perhaps 

the most critical craft is “boilermakers” – the highly skilled metalworkers needed to fabricate the high 

pressure, high temperature steam tubes and supply casings. This labor pool is restricted due to a 

lengthy apprenticeship that is necessary to assure quality fabrication. 

The limited boilermaker labor pool could restrict the installation of SCR and FGD process equipment. 

UARG comments submitted in 2003 addressing CAIR described how the installation of SCR and FGD 

could be limited by boilermaker availability (UARG, 2003); an updated version of these comments 

considering the revised SCR and FGD installation schedules and new plant construction is presented in 

the following section. 

Supply. The International Brotherhood of Boilermakers (IBB) reported boilermaker membership as 

approximately 24,000 members in 2003, with a targeted 5.3% growth rate. The IBB did attain this 

growth rate, as membership in early 2007 is reported to be 32,000. Assuming a continued 5% increase 

in membership, the boilermaker pool will expand to approximately 36,000 members by 2010, 40,000 

members by 2012, and about 46,000 members by 2015. Additional resources of 6,600 members in 

Canada are reported in early 2007. 

Labor Requirements for SCR, FGD. The labor required by approximately 2010 to install SCR and 

FGD equipment can be estimated, using knowledge of the (a) number of manhours of labor required to 

construct FGD and SCR, (b) generating capacity of FGD and SCR retrofitted, and (c) the sequence of 

labor charges over the project duration. 

Wet FGD installation for a 500 MW unit requires from 600,000 to 900,000 manhours of labor, 

depending on the design and site-specific conditions. The average value of 750,000 manhours equates 

to 1,500 manhours per MW of generating capacity. For SCR, an average of 500,000 hours is required 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

15

for a 500 MW unit, which equates to 1,000 man-hours per MW of capacity. These assumptions are 

based on discussions with FGD and SCR process suppliers. 

Installing FGD and SCR individually at a given site is assumed to require 36 and 28 months, 

respectively. The demand for boilermaker manhours required over the project duration is presented in 

Table 4-4, based on discussions with suppliers. Using the preceding information, and EPA’s estimate 

that a typical boilermaker will work 1685 hours per year (EPA, 2003), the total number of 

boilermakers can be determined. 

Table 4-4. Distribution of Boilermaker Labor Requirements: 

Hypothetical Retrofits at a 500-MW Unit 

Technology Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8 Q9 

FGD 0 0 0 0 10 27 34 23 6 

SCR 0 0 0 20 25 40 15 n/a n/a 

Labor Required for New Plant Construction. Black & Veatch has estimated the labor demand to 

construct the 80 GW of new plant capacity (Black & Veatch, 2006). Specifically, total craft labor is 

estimated to require more than 12,000 full-time equivalent positions in 2008 and 2009, decreasing to 

10,000 in 2010. The number of boilermakers is conservatively estimated to constitute half of the craft 

labor. This projection allows the total number of boilermaker positions to be estimated from 2007 

through 2013. It should be noted these are for plants announced as of 2006; this number could decrease 

(due to cancellations) or increase. 

Figure 4-7 shows the full time boilermaker positions required for retrofit of SCR and FGD, and new 

plant construction, from 2008 through 2012. The projected supply of boilermakers in 2010 is 

approximately 31,000; thus the estimated demand of 20,000 represents a large fraction of the 

workforce. It should also be noted that regularly scheduled maintenance of power plants also relies 

upon this pool of boilermaker labor. It is unrealistic to assume that the cumulative demand on labor 

expended to meet the needs of the power industry will be provided without significant cost escalation 

and delays. 

4.3 FGD COST ESCALATION 

The escalation in basic materials and labor costs has elevated the cost of FGD and all categories of 

control technology. One index of this cost escalation, the Vatavuk cost index, reflects significant 

appreciation in the last 5 years. Figure 4-8 presents the trend in this cost index, showing a 50% 

increase since 1997. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

16

-

5,000

10,000

15,000

20,000

25,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Full-time Equivalent BoilerMaker Demand

FGDs

SCRs

New EGUs

Figure 4-7. Full Time Boilermaker Demand: SCR, FGD, and New Coal-fired Units 

Figure 4-8. Vatavuk Index for Wet FGD Scrubbers 

Cost Index for Wet Scrubbers

Vatavuk Index (Source: Chemical Engineering)

100.0

110.0

120.0

130.0

140.0

150.0

160.0

170.0

180.0

190.0

200.0

210.0

220.0

1996 1998 2000 2002 2004 2006 2008

Year

Wet Scrubbers (1994 = 100)

Compound Esc. From 2003 to 3rd Qtr.2006 = 9.7%

Compound Esc. From 1997 to 2003 = 1.6%
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

17 

SECTION 5 

FACTORS AFFECTING CAPITAL COST ESTIMATES 

A review of factors affecting capital cost estimates is presented in this section. These involve the 

costing methodology, and site-specific and engineering decisions. 

5.1 CAPITAL COST ESTIMATING METHODOLOGY 

Evaluating the capital cost of environmental controls requires a consistent accounting of costs. All 

direct and indirect costs are to be considered. EPRI’s Technical Assessment Guide (TAG, 1993) 

defines a consistent method, and has served as a model by which DOE and other organizations assess 

costs. 

Figure 5-1 schematically depicts the key components of a capital cost estimate. The first factors 

establish the capital required to fabricate, deliver, and install the equipment at the site. The capital 

equipment directly purchased from the supplier, and installed by a construction contractor comprises 

the Total Process Capital. Several indirect charges consequential to these direct charges are incurred: 

(a) engineering design, (b) general facilities, (c) owners costs, and (d) contingencies (usually both a 

process and a project). Indirect fees should be consistent when comparing costs from various suppliers. 

Table 5-1 presents typical ranges of values historically used by EPRI, DOE, and EPA. Together with 

the Total Process Capital, these indirect charges comprise the Total Plant Cost. 

A second series of indirect charges are incurred based on project execution: fees for the prime 

contractor, and financing for the construction period. Adding these costs to the Total Plant Cost 

determines the Total Plant Investment. 

Finally, the equipment and site must be equipped with spare parts, and a supply of reagents, chemicals, 

or fuels, prior to operation. These pre-production charges and inventory capital complete the Total 

Capital Requirement. 

Ideally, evaluating capital costs would utilize similar charges as defined in Figure 5-1 and Table 5-1. 

Some but not all data presented in Section 6 have been developed on a consistent basis. However, most 

reported costs are derived from the same suppliers and A/E’s that use similar assumptions. These costs 

are inevitably scrutinized by the public utilities commissions and thus eventually tested for 

reasonableness. Accordingly, comparing lump-sum costs has limits but can identify trends. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

18

Figure 5-1. Graphic Depiction of Cost Elements 

Table 5-1. Examples of Indirect Charges, Assumptions 

Cost Element Purpose Range, % 

Engineering Establish design 7-15 

General Facilities Roads, buildings, shops, 

laboratories 

2-5, based on process capital 

Owner’s Cost Staff, management 5-10 

Process Contingency Uncertainty in process 

operation 

5-10, for a mature process 

Project Contingency Uncertainty in site 

installation 

5-10, if detailed engineering initially 

completed 

Prime Contractor Fees Business cost 2-8 

AFDC Financing during 

construction 

5-10 

Preproduction Supply of parts, consumables 2, based on total process investment, plus 

30 days fixed, variable O&M 

Inventory Capital Supply of consumables Based on 30 day reagent, chemicals storage 

Equipment 

fabricated 

and delivered

Installation

Total

Process

Capital

Indirect Charges:

• Engineering design

• General facilities

• Owners cost

• Contingencies

Total

Plant

Cost

• Prime contractor fees

• Financing during construction

Total

Plant

Investment

• Preproduction 

(reagents, chemicals)

• Inventory capital

Total

Capital

Requirement
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

19

5.2 SITE AND DESIGN FACTORS 

Site characteristics and the operating philosophy, particularly the owner’s tolerance for equipment 

outages, affect capital cost. These and other factors are responsible for significant variation in 

estimates of capital cost among projects. 

The key site specific factors that define capital cost are: 

Fuel Composition. The fuel defines the volume of combustion products, content of particulates, SO2, 

and NOx production rates, and composition of fly ash. These characteristics drive process equipment 

cost. Most significant is the volume of flue gas produced by fuel combustion. For example, PRB or 

other sub-bituminous coals can generate 30% greater volume flue gas to be treated, compared to an 

eastern bituminous coal, per unit generating capacity. For FGD, the amount of sulfur to be processed 

and the disposition of the byproduct are factors. For SCR, the flue gas volume, and composition of ash 

and trace elements such as arsenic can determine reactor volume and catalyst layout. 

Site Congestion and Retrofit Difficulty. Limited space for equipment location, access for construction, 

and access for labor will extend installation time. Generally, older units of smaller generating capacity 

will incur high costs due to limited access (as well as penalties due to economies-of-scale). Large 

generating units do not necessarily guarantee adequate space for equipment installation. For example, 

at Duke Power’s Belews Creek station, the large site for these two 1200 MW units was constrained, 

necessitating locating the pre-assembly “laydown” area over 1 mile from the plant. Access for SCR 

retrofit requires construction near the boiler economizer exit, and is usually more constrained than for 

wet FGD, typically located near the stack. 

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

power, steam, and compressed air. The availability of these consumables at a site varies, and additional 

infrastructure to supply and distribute these consumables may be necessary. The most costly of these 

can be a power distribution or “motor control center”. The escalation in price of copper-derived 

electrical subsystems has contributed to cost increases; historically electrical infrastructure has been 5-

6% of an FGD budget but now can exceed 10% for some applications. 

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. 

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

depending on permitted limits. Zero-water discharge requirements can impose significant costs on the 

entire FGD slurry treatment and dewatering systems, and may possibly interfere with FGD chemistry. 

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

significant rebuild of the stack. Flue gas treated by wet FGD poses corrosion and deposition potential, 

due to relatively low saturation temperature and high content of SO3. The least cost solution usually 

requires a new stack rather than retrofitting corrosion-resistant liners to an existing stack. FGD 

implementation can be limited by the availability of expertise and resources to erect a new stack. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

20

Equipment Sparing Philosophy. The operating strategy of the owner, and the cost incurred for an FGD 

outage in terms of compliance margin and SO2 allowances determines the equipment sparing strategy. 

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. Sparing philosophy can affect capital cost by 10-20%. 

Materials of Construction. The use of materials that resist corrosion and erosion, in an effort to obtain 

high reliability, can elevate capital cost. Specifically, high alloy containing steels or rubber-lined 

absorber vessels or pumps have historically increased reliability. Decisions affecting materials of 

construction, similar to those for equipment sparing, are driven by the incurred cost for an FGD or 

SCR outage. For wet FGD, the use of higher alloy and lined equipment can add 10-20% to the project 

capital cost. 

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

capital savings derived can be 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 (e.g., 2+1) will provide a lower capital but higher operating cost, 

compared to utilizing 3 initial layers and 1 spare layers (e.g. 3+1). The key difference is higher catalyst 

consumption over a long-term period. 

Of these factors, perhaps the most important is site complexity. Plant sites where FGD and SCR are to 

be retrofit have become more complex: longer ductwork runs are required, and access for construction 

equipment is limited, restricting labor productivity and extending construction time. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

21 

SECTION 6 

FLUE GAS DESULFURIZATION COSTS 

This section presents capital and operating costs for wet and dry FGD process equipment. 

6.1 FGD CAPITAL COST 

Figure 6-1 depicts capital cost presented as a function of generating capacity, for wet FGD and dry 

FGD processes. The design basis for these installations is described as follows: 

Wet FGD. All units employ limestone reagent, forced oxidation, deliver at least 95% SO2 removal, 

and are equipped with mist eliminators. The influence of design or performance conditions different 

from those stated will impact cost, perhaps most significantly due to variations in inlet SO2 and the size 

of byproduct handling equipment. However, these cost variations are believed to be no greater than 

those due to physical differences between sites. 

Dry FGD. The costs for all units with a lime-based spray dryer absorber (SDA) include a secondary 

fabric filter particulate collector. Most SDA equipment is designed for 93-95% SO2 removal. The fly 

ash is removed in the existing particulate control device (an ESP in all cases), so ash handling and 

disposition is the same as prior to retrofit. Similar to the case for wet FGD, any differences in dry FGD 

SDA design from those stated are not anticipated to effect capital cost. 

Capital costs in this figure are expressed in end-of-year 2006 dollars, and represent the owner’s best 

estimate for a ready-to-operate FGD process accounting for all direct and indirect charges. Two 

sources of costs are discussed: anonymous and fully disclosed. Given the competitive nature of the 

industry, and the of role SO2 allowances in compliance, some owners are concerned knowledge of 

FGD cost will bias their allowance prices. The cost sources are discussed by category. 

6.1.1 Anonymous 

Sargent & Lundy (S&L) Engineers conducted a detailed study for three Midwestern systems: Wet and 

dry FGD for System A; Dry FGD alone for System B; and Wet and Dry FGD for System C. These 

three systems comprise 10 wet and 24 dry FGD units for installed generating capacity varying between 

approximately 200 and 800 MW. Discussions with S&L staff indicate that the assumptions in Table 

5-2 are generally consistent for all generating systems. Notably, the capital cost for System A exceeds 

that for Systems B and C, as the former sites are more congested than the latter, complicating retrofit 

and construction. 

Two units in the Southeast of 850 and 1100 MW generating capacity exhibit wet FGD costs of almost 

$300/kW and $275/kW, respectively. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

22

0

100

200

300

400

500

600

0 200 400 600 800 1000 1200 1400

Generating Capacity, MW

Unit Dry or Wet FGD Cost, $/kW (EOY 2005)

Wet FGD: System A

Dry FGD and FF: System A

Belews Creek 1, 2

EW Brown, Ghent

Amos

Southeast Installation

Dallman31-32

Dry FGD/FF System B

DryFGDStation C

WetFGDStation C

FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

Monroe 3, 4 2006

Allen 1-5 2006

Marshall

Gorgas 8-10

1999 EPA IPM 

Wet FGD 

Reference

Wet FGD 

Curve:

2004-2005 

Installations

2006 EPA IPM 

Wet FGD 

Reference

Figure 6-1. Wet, Dry FGD Process Equipment Cost: Various Sources 

6.1.2 Publicly Released Studies 

Publicly released cost data are described as follows: 

American Electric Power (AEP): Amos. The Amos units, at nearly 1000 MW, will require $375/kW. 

Allegheny Energy: Fort Martin, Hatfield Ferry. Wet FGD for these 600 MW units was estimated in 

2004 to require more than $300/kW. As will be noted subsequently, actual costs incurred in 2006 for 

these units significantly exceeded this value. 

Detroit Edison Company: Monroe 3, 4: These 800 MW units will incur capital cost greater than 

$300/kW, despite exploiting economies of scale in engineering and procurement. 

Duke Energy has publicly released all wet FGD costs to comply with North Carolina Clean Air 

Legislation (Everett, 2007): 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

23

• Belews Creek 1, 2. The wet FGD $238/kW capital cost for these units is one of the lowest 

encountered. Duke achieved this relatively low cost by developing a system-wide design to 

apply to over 4,000 MW of capacity, utilizing two generic spray tower designs and common 

water management and solid processing equipment for the entire system (McCarthy, 2004). 

Economies-of-scale for engineering and procurement also contribute to the lower cost, as well 

as the relatively early date (2002) in which Duke engaged the FGD contractor. 

• Allen Units 1-4. The relatively small generating capacity of these units (190 MW) imposes 

capital cost penalties due to scale, even though four units of nearly identical design are 

installed, utilizing the generic system spray towers (McCarthy, 2004). At more than $400/kW, 

these FGD installations are among the highest cost. 

• Marshall Unit 1-4. Four units at Marshall (2 x 650 MW and 2 x 350 MW) employ the wet 

FGD system design and incur slightly greater than $200/kW. This site benefits from 

economies-of-scale to lower the average unit cost to this value. 

East Kentucky Power: E.W. Brown, Ghent. These units incur relatively low costs of $300/kW. The 

remote location and relative good access likely contributes to these lower costs. 

CIPS Springfield: Dallman, and South Illinois Power Co-Operative: Marion. Both of these units incur 

capital of less than $200/kW, for units in which contracts were signed in 2002. 

WE Energies: Pleasant Prairie Units 1, 2. The design and cost for these twin 617 MW units was 

established in 2004, and equipment contracted for mostly in 2004 and 2005. The capital cost of 

$218/kW (2006 dollar basis) exploits economies-of-scale due to two identical unit designs, and 

common facilities such as a new stack, waste water treatment, and reagent preparation facilities. 

The “Wet FGD Curve” depicted in Figure 6-1 approximates the capital cost for wet FGD processes 

based on a system study for the former Cinergy by S&L. 

Figure 6-2 compares wet FGD cost for units where competitive bids were received in 2006. For 

reference, Figure 6-2 includes a curve based on Figure 6-1 that reflects wet FGD capital cost for units 

procured in 2004 and 2005. Also shown is the IPM cost curve as utilized by EPA in 2006 for regional 

modeling. 

Revised wet FGD costs for two generating stations – Allegheny Energy’s Hatfield and St. Martin – are 

also presented in Figure 6-2. These data provide comparisons to the 2004 values. Each of these stations 

in 2006 received bids for wet FGD that significantly exceeded engineering estimates generated in 

2004, by $75-150/kW. Although details of the higher costs are not available, the most significant 

contributing factors are higher installation costs and material prices. In addition, wet FGD capital cost 

for Reliant Energy’s Cheswick Station reported in mid-2006, and for Gulf Power’s Crist Units 4-7 

(April, 2007) are presented. The wet FGD design for Crist is reported to exceed $500/kW, and will 

utilize two absorber vessels to treat flue gas from four units, ranging from 94 MW (two units) up to 

578 MW. The disparity in generating unit size and arrangement of equipment likely contributes to this 

high cost, as well as 2007-based prices for material and labor. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

24

0

100

200

300

400

500

600

0 100 200 300 400 500 600 700 800 900 1000

Generating Capacity, MW

Unit Dry or Wet FGD Cost, $/kW (EOY 2005)

FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

RecentPowerLaw

Fort Martin 1-2 2006

Hatfield Ferry 1-3 2006

Crist 4-7

2006 EPA IPM wet 

FGD Reference

2006 vs. 2004: 

Fort Martin 1, 2

2006 vs. 2004

Hatfield Ferry 1-3

Wet FGD Curve:

2004-2005 

Installations

Figure 6-2. Wet, Dry FGD Process Equipment Cost: Various Sources 

Of note is the disparity between cost projected by EPA and those actually incurred. The source of this 

disparity is unclear – the EPA methodology employs the same cost accounting principles described in 

Section 5, and is reported to consider balance-of-plant impacts. It is possible EPA projections are 

based on dated information, derived with budgetary-type analysis, as opposed to a detailed design 

study. It is unlikely the EPA cost algorithm reflects authentic balance-of-plant costs. For example, 

Duke Energy required a unique waster water management system at the Belews Creek and Marshall 

generating stations that employed specially-constructed wetlands. Also, Marshall required extensive 

duct runs to tie in the new stack. The EPA estimates do not appear to include a complete list of 

balance-of-plant items. 

6.2 OPERATING COST 

Operating cost is defined in several ways – total operating cost per unit of capacity per year, 

normalized to power generated, or per unit of emission species removed. 

Figure 6-3 is a reproduction of a graphic presented by Sargent & Lundy at the November 2006 

PowerGen conference (Sargent & Lundy, 2006). Figure 6-3 compares (for a 500 MW plant) the 

various contributors to total operating cost for a limestone-based wet FGD process, designed for 95-

97% SO2. Total O&M ranges from approximately $15 to $38/kW/yr, and is almost equally comprised 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

25

of fixed and variable components. As noted in Figure 6-3, limestone reagent cost for this size of unit 

varies in direct proportion to the amount of sulfur in the coal. Other operating cost components directly 

related to sulfur content including operating and maintenance labor, and byproduct management. 

Figure 6-3. Range of Wet FGD Operating Costs for 500 MW Units 

(after Sargent & Lundy, 2006) 

The capital cost ranges in Figures 6-1 and 6-2, when combined with operating costs, provide an 

indicator of FGD cost-effectiveness, or the cost per ton of SO2 removed. Figure 6-4 presents the cost 

per ton of SO2 removal for a hypothetical 500 MW unit, utilizing a limestone based forced oxidation 

process. Calculations are reported for coal with intermediate sulfur content (6 lb SO2/MBtu) and for 

PRB (0.90 lb SO2/MBtu). Figure 6-4 results are based on median operating costs reported in Figure 6-3 

for the 6 lb SO2 coal, and minimum values for PRB. The operating cost estimates are consistent with 

published sources for wet FGD, and those derived for a 500 MW unit with EPA’s CUCOST software 

program3

. It is possible higher operating costs may be incurred that reflect higher labor rates. Figure 6-

4 results also assume a 15-year book life (e.g., cost recovery period) and thus a capital recovery factor 

of 0.12. 

 

3

 Using CUCost Version 3, the sum of fixed and variable O&M for a wet limestone forced oxidation FGD process is within 

5% of that derived using 500 MW generating basis, Ohio coal of 5.8 lbs SO2/MBtu, 85% capacity factor, and 10,000 

Btu/kWh heat rate. Cost results are presented on a 2006 dollar basis using the CUCost imbedded routine to escalate costs 

with the CE Plant Index. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

26

For the case of 6 lb SO2/MBtu coal, an increase in capital cost from $250/kW to $450/kW increases 

the cost of SO2 removal from $270 to $450/ton. For PRB coal, the same capital cost increase will 

elevate SO2 removal cost from approximately $1,500 to $2,300/ton. The costs will change in 

proportion to the sulfur content of the fuel. 

-

500

1,000

1,500

2,000

2,500

200 250 300 350 400 450 500

Wet FGD Capital Cost, $/kW

Calculated SO2 Removal Cost, $/Ton

E. Bit Coal (6 lbs SO2)

PRB Coal (0.9 lbs SO2)

Figure 6-4. SO2 Removal Cost per Ton ($/Ton), Year 2006 Basis 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

27 

SECTION 7 

SCR NOx COST 

This section presents capital and operating costs for SCR NOx control. 

7.1 SCR CAPITAL COST 

The capital cost for SCR process equipment has been the subject of several surveys in the last four 

years. In most cases, the costs are reported as anonymous; the costs for only a few named units are 

publicly available. This section of the report will highlight results from these surveys, almost all of 

which were conducted prior to the cost escalation witnessed in the last 24 months. Limited data 

released in the last 12 months and reflecting the cost escalation will also be presented. 

7.2 THREE SURVEYS 

Three surveys have documented the increase in SCR capital cost: Hoskins (2003), Cichanowicz 

(2004), and Marano (2006). The findings from these surveys are not directly comparable to each other, 

as each utilizes a different unit population, and design features. Further, important factors such as the 

scope of equipment supply and construction labor rates have not been normalized. Table 7-1 shows the 

average capital cost and size of generating unit in the survey, the range of costs incurred, and includes 

important observations concerning these surveys. The results of each survey are summarized as 

follows: 

Hoskins, 2003. This survey of 20 units determined an average cost of $120/kW, for units with an 

average generating capacity of 400 MW. More than 75% of these units reported capital costs that 

exceeded $100/kW. A weak relationship between capital cost and scale was noted; that is, unit cost 

($/kW) did not significantly change with increasing generating capacity. 

Cichanowicz, 2004. This survey of over forty units reveals a relationship between cost and generating 

capacity. Units of small-intermediate generating capacity (100-400 MW) required $123/kW, while the 

largest units (800-1200 MW) required $85/kW. This survey compared the capital cost provided by 

each supplier with the order of installation – that is, comparing the cost of the first unit installed by a 

supplier versus subsequent units. Four categories of generating capacity were examined, and in every 

case the least cost units were among the first installed, suggesting that either increased experience by 

the supplier or complexity of the unit increased the capital cost. This trend was observed prior to the 

recent cost escalation. 

Marano, 2005. This most recent (2005) and comprehensive (60+ units) survey showed that most units 

reported costs of $100-200/kW, with units greater than 900 MW averaging $118 /kW, and those less 

than 300 MW averaging $167/kW. Marano noted that units from 600-900 MW appear to be the most 

difficult to retrofit. This observation is consistent with the observation of Cichanowicz, which shows 

capital cost actually increase with generating capacity in this range. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

28

Table 7-1. SCR Capital Cost Survey Results 

Reference Average 

Capital, MW 

($/kW, 2006 

Basis)) 

Low-High Cost 

Observed 

($/kW) 

Observation 

Hoskins, 2003 128 (400 MW) 80-160 Cost Basis: 2002. 15 of 20 

reported unit costs exceeded 

$100/kW. Weak relationship 

of unit cost and scale. 

Cichanowicz, 

2004 

84 (600-899 

MW) to 128 

(100-399 MW) 

56-185 Cost Basis: 2003. For four 

categories of generating 

capacity, the least cost units 

were among the first installed. 

Marano, 2006 118 (>900) to 

167 (<300 

MW) 

Most costs 

reported to be 

within 100-200 

Cost Basis: 2005. “Units with a 

capacity of 600 to 900 MW 

appear to be more difficult to 

retrofit than those in other size 

ranges.” 

The most significant observation from the surveys reported in Table 7-1 is the low number of units 

with reported costs <$100/kW, and the inability of units of large generating capacity to deliver low 

installed cost. The case of Duke Energy’s Belew’s Creek Station, where the construction “laydown” 

area was one mile from the unit has been well documented (Power Engineering, 2002). Marano (2006) 

notes the early SCR adopters incurred lower capital cost, with the year of 2003 recognized as a 

milestone after which costs increased significantly. 

7.3 COST ESCALATION 

Figure 7-1 depicts the escalation of SCR capital cost over four periods of time, spanning 15 years. 

This escalation is described as follows: 

Phase 1 and Phase 2 installations incurred atypically low capital cost. It is likely these installations did 

not reflect the conventional SCR retrofit in terms of access, NOx removal performance, and 

reactor/catalyst arrangement. 

Phase 3 installations reflected increasing retrofit complexity and higher NOx control performance; 

process demand was robust but did not overburden the suppliers over this time period. Over 2/3 of 

these units incurred capital cost exceeding $100/kW. 

Phase 4 comprises the recent applications that either become operational in 2006, or will start up in 

2007 or 2008. These costs exceed $200/kW on a routine basis, well above the cost historically 

incurred. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

29

1993

1995

1997

1999

2001

2003

2005

2007

2009

0 50 100 150 200 250 300 350

SCR Capital Cost ($/kW)

Installation Date

Phase 2: 1st -time 

and early applications

Phase 3: mature 

applications and 

t

Phase 1: EPA, 

NESCAUM, and ICAC; 

Merrimack Unit 2 and 

Stanton Unit 3

Phase 4: Leftovers 

Figure 7-1. Escalation of Cost for SCR Installation with Time 

7.4 OPERATING COST 

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

Each of these cost components has experienced significant price changes in the last 10 years. 

7.4.1 SCR Catalyst 

Historically, supply of catalyst comprised the largest operating component of SCR NOx control. The 

unit cost of catalyst has significantly decreased since the early 1980s, as the entry of several large 

multi-national firms increased supply faster than demand. Further, the ability to regenerate or 

rejuvenate catalyst for approximately 50% of new product price further restrains price. 

Figure 7-2 presents the unit price of catalyst since the early 1980s, corrected to a 2006 dollar basis, 

showing a decrease in unit price by a factor of five since the earliest commercial bids. The minimum 

price of near $4,000 m3 was witnessed in 2005; however, recent experience suggests prices are 

increasing due to a large number of units for which a first catalyst addition or supplement is required. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

30

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

1980 1985 1990 1995 2000 2005 2010

Year

Catalyst Unit Price, $/Yr (2006 $ Basis)

Catalyst Unit Prices 

Increasing in 2007 

Figure 7-2. History of SCR Catalyst Prices (2006 Dollar Basis) 

The consequence of this catalyst price decrease is that catalyst procurement does not dictate SCR cost 

as historically witnessed. In fact, catalyst management decisions at present can exploit low prices to 

insure the reactor features adequate catalyst activity, to confine catalyst replacement to major outages, 

avoiding unit shutdown for the purpose of catalyst addition or exchange. 

7.4.2 Reagent 

Any savings in SCR operating cost due to catalyst price decreases has been offset by escalation in 

delivered price of ammonia-based reagent. SCR operators can choose from four types of ammoniabased 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 the alternative reagent forms are equally viable. 

The cost of anhydrous ammonia is as much as 80-90% determined by the cost of natural gas feedstock. 

In late 2006, typical prices for anhydrous for agriculture were approximately $400/ton. This value 

exceeds the 175 to $250/ton historically noted. As natural gas prices are anticipated to remain high, the 

price of $400/ton is anticipated to represent future cost (Clark, 2006). 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

31

7.4.3 Example Operating Cost 

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

unit), based on assumptions in Table 7-2 that define the conditions of operation. These are: 

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

operation are assumed to require 0.50% of process capital. 

Catalyst Supply. Catalyst supply cost is determined by long-term purchases from which an annualequivalent average can be calculated. The long-term purchases are dictated by catalyst addition to the 

empty spare layer, and replacement of existing layers. For an SCR reactor employing a 2+1 catalyst 

arrangement, 3,200 1/h initial space velocity, and a 16,000 hour initial operating guarantee, the 

purchase of 1 layer for every 20,000 operating hours may be required. 

Reagent Cost. The purchase of anhydrous ammonia for 90% NOx removal from 0.35 lbs/MBtu, at 

85% capacity factor, defines the reagent cost. A delivered price of $400/ton is assumed. 

Auxiliary Power. Auxiliary power for an additional 6 in. water gauge (w.g.) flue gas pressure drop is 

assumed – 5 in. w.g. for the process flange-to-flange, and an additional 1 in. w.g. across the air heater. 

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

assigned a cost of $1/MBtu. 

Operating Staff. The addition of one operator is assumed for maintenance of the above components. 

Also, a part time (25%) engineer to assess operation and evaluate data is assumed. 

Table 7-2. Key SCR Operating Cost Components: 500 MW Reference Plant 

($150/kW Capital Basis) 

Operating Cost 

Component 

Basis Annual Cost for 

500 MW ($/yr) 

Annual Cost for 

500 MW (mills/kWh) 

Fixed O&M 0.5% of Process 

Capital 

150,000 0.04 

Labor Operators/Part-time 

Engineer 

125,000 0.03 

Fuel Cost Auxiliary Steam 100,000 0.02 

Reagent 90% NOx removal 

(from 0.38 lbs/MBtu) 

885,000 0.25 

Auxiliary power 6 in. w.g. total @ 

$20/MWh 

265,000 0.07 

Catalyst Supply 16,000 hr guarantee for 

2+1 reactor 

675,000 0.15 

Total 2,200,000 0.59 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

32

The capital cost observed in Figure 7-1, when combined with updated operating costs in Table 7-1, 

provides an indicator of SCR cost-effectiveness, or the cost per ton of NOx removed. Figure 7-2 

presents the cost per ton of NOx removal for a hypothetical 500 MW unit, utilizing a 2+1 catalyst 

arrangement, with an initial NOx input of 0.38 lbs/MBtu, as a function of SCR capital cost. 

Calculations are reported for an eastern bituminous coal with approximately 0.38 lbs/MBtu furnace 

NOx exit, and a PRB-fired unit assumed to produce 0.20 lbs/MBtu. Results presented in Figure 7-2 for 

the eastern bituminous coal employ operating cost in Table 7-1, while calculations for PRB coal 

employ lower cost for reagent use and catalyst consistent with lower inlet NOx. Figure 7-2 results also 

assume a 15-year book life (e.g., cost recovery period) and thus a capital recovery factor of 0.12. 

For the eastern bituminous coal, an increase in capital cost from $100/kW to $300/kW elevates the cost 

of NOx removal from $2,200 to almost $6,000/ton. For the PRB coal, with lower inlet NOx rate and 

lower operating costs, the same capital cost increase elevates NOx removal cost from approximately 

$1,200 to $3,200/ton. The costs will change in proportion to the boiler NOx generated. 

0

1,000

2,000

3,000

4,000

5,000

6,000

0 50 100 150 200 250 300 350

SCR Capital Cost, $/kW

Calculated NOx Removal Cost, $/Ton (2006 Basis)

PRB Coal

E. Bit Coal

Figure 7-3. NOx Removal Cost per Ton ($/ton), Year 2006 Basis 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

33 

SECTION 8 

IMPLICATIONS FOR Hg CONTROL 

This report has focused on cost and schedule issues attendant to the retrofit or construction of new 

FGD and SCR equipment. The Clean Air Mercury Rule (CAMR) also mandates installing control 

technology over the same time period. Although many units are anticipated to comply with Hg 

removal through wet FGD, the use of sorbent or activated carbon injection (ACI) upstream of an 

existing ESP or fabric filter (FF) may be needed. 

EPA has projected the generating capacity that could be retrofit with ACI in FF to meet CAMR 

mandates (EPA, 2006). EPA’s predictions suggest about 1,900 MW of ACI into FF could be deployed 

by 2010, with this amount increasing to 2,400 MW by 2015. EPA did not reveal details of its analysis. 

More importantly, EPA’s analysis only addressed the federal CAMR and not the numerous statespecific initiatives, all of which are more strict than CAMR. As an example, the state of Georgia has 

proposed an emission control rule that at one site requires almost 3,300 MW of coal-fired capacity to 

be retrofit with fabric filters for particulate matter control (Georgia Environmental Protection 

Department, 2007). Consequently, EPA is likely under-predicting the utilization of ACI in FF by the 

utility industry. 

The need for significant ACI/FF could further burden labor demand. A UARG analysis in 2003 

assumed fabrication and installation of a typical FF would require 300 manhours of labor per MW of 

generating capacity, with half of that amount being boilermakers. The total of 150,000 manhours for a 

500 MW unit, of which 75,000 are boilermakers, is small compared to the labor demand for SCR and 

FGD. However, the strained labor pool may not be able to accommodate any additional demand. 

Finally, it should be noted that FF cost for use with ACI has escalated significantly since first proposed 

for Hg control. Specifically, early cost projections by EPRI suggested a FF retrofit cost of $50-60/kW, 

a value widely use by EPRI and adopted by UARG. Subsequently, experience from the Gaston trials in 

2005 suggested design changes to improve Hg removal were warranted, such as using a lower air/cloth 

ratio (4-6 compared to 8-12) and thus higher filter area (Berry, 2004). This requirement, combined 

with a more complex equipment layout, has elevated capital estimates to more than $100/kW. The cost 

for 270 MW FF module for the Presque Isle station was $127/kW in 2004 dollars. This reference cost 

is used to project capital cost for larger units using conventional power-scaling law. 

A recent study using Presque Isle as a reference design suggests typical FF costs are even higher, and 

approach $150/kW (EPRI, 2006). The degree that the design of the FF module at Presque Isle 

represents future applications is questioned by some, claiming the site characteristics atypically elevate 

cost. Presque Isle Units 7-9 do comprise a congested site, as effluent from three 90 MW units merge 

into one FF module. However, actual FF applications for Hg removal may incur these same challenges. 

In fact, the sites that could need ACI/FF for high Hg removal may be those not equipped with SCR and 

FGD, and be smaller, older generating units – exactly those represented by Presque Isle. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

34

In summary, the need for at least several thousand MW and perhaps greater of ACI/FF will further 

exacerbate the schedule and cost pressures imposed by FGD and SCR. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

35 

SECTION 9 

CONCLUSIONS 

The significant demand for environmental controls for retrofit to existing units – combined with the 

construction of perhaps 80 GW of new coal-fired capacity – has elevated capital costs, both incurred 

and estimated. These escalated costs, combined with delays in installation due to equipment and 

personnel shortages, will challenge the ability of some operators to meet CAIR mandates. Further, the 

decision to comply using either control technology versus the purchase of emissions allowance may 

change over the timeframe from planning to execution. 

Notably for FGD, the most recent capital cost data suggest a 30% increase over the last two years. 

Worldwide demand for material and personnel resources, combined with numerous and overlapping 

utility industry mandates, is believed responsible for this escalation. As depicted by the Vatavuk index 

reflecting scrubber costs presented in Section 4, FGD capital costs have increased at an annual rate of 

7-9% for the past three years. These same cost pressures apply to SCR, and will also likely impact any 

large deployment of FF for use with ACI for future mercury emission controls. 

These capital cost pressures could affect “scrub vs. switch” decisions. Specifically, the decision to 

“scrub” a coal with sulfur content of 6 lbs SO2/MBtu may be based on preliminary engineering, and 

may adopt a FGD capital cost of $200/kW with SO2 reduction generated for $250/ton. If actual 

construction costs increase to $400/kW, SO2 removal is provided for $375/ton which may exceed the 

allowance price. The conclusions can be even more distorted for PRB coal, with an escalation in 

capital from $250/kW to $400/kW increasing SO2 removal costs from $1550 to more than $2100/ton. 

Similar trends are noted in escalation of NOx compliance costs and the decision to deploy SCR NOx 

control versus another strategy. 

This report revealed significant schedule pressures that threaten a utility company’s prospects of 

complying with CAIR mandates. In 2002, EPA presumed installation schedules for SCR and FGD 

were 21 and 27 months, respectively (EPA, 2002). UARG comments filed in response to this EPA 

claim offered more realistic schedules for SCR and FGD of 28 and 32 months, respectively (UARG, 

2003). 

The construction schedules have since been further extended. Specifically, SCR installation at present 

requires 36 months. Figure 9-1 presents a schedule for constructing the SCR for Associated Electric 

Co-Operatives New Madrid Unit 3, depicting a three-year duration from start to unit startup (Johnson, 

2006). FGD schedules similarly extend to 36 months, or more if key items such reagent or slurry 

pumps cannot be acquired, or stacks erected. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

36

Figure 9-1. Project Timeline for New Madrid Unit 3 SCR Installation and Startup 

(after Johnson, 2006) 

The combination of higher capital cost and extended installation schedules may prevent many owners 

from meeting compliance deadlines for CAIR or other initiatives. Particularly for smaller generating 

systems, access to the necessary technology may not be available, or only available at exorbitant costs. 

The case of South Mississippi Electric Power Association (SMEPA) is instructive regarding this item. 

In late 2006, SMEPA received bids for wet FGD and SCR equipment that specified a combined capital 

cost of about $1,000/kW for each unit. Although the small generating capacity of the host units (~200 

MW each for two units) contributed to these costs, the extreme competition for resources and 

manpower are at least equally culpable. SMEPA is presently exploring alternative means to meet the 

CAIR mandates. 

As a consequence, both the cost and schedule plans for FGD and SCR by many utility owners are at 

risk, compromising their ability to meet the numerous mandates. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

37 

SECTION 10 

REFERENCES 

Reference Author 

Black & Veatch, 

2006 

Black & Veatch, “Building New Baseload Generation in The Midwest”, 

presentation to MMEA, April 11, 2006. 

Berry, 2004 Berry, M. et al., “Field Test Program for Long-Term Operation of a COHPAC 

System For Removing Mercury from Coal-fired Flue Gas”, Proceedings of the 

Combined Power Plant Air Pollutant Control Mega Symposium, August 30-

September 2, 2004, Washington, DC. 

Brat, 2007 Brat, I., “Crane Migration Hinders Builders”, The Wall Street Journal OnLine, June 18, 2007. 

Cichanowicz, 2004 Cichanowicz, J.E., “Why are SCR Costs Still Rising”, Power Magazine, April, 

2004. 

Clark, 2006 Clark, E., “Price Predictions”, Apply, May 1, 2006. 

EPA, 2002 “Engineering and Economic Factors Affecting the Installation of Control 

Technologies for Multi-Pollutant Strategies”, EPA Report EPA/600/R-02/073, 

October, 2002 

EPA, 2006 Contributions of CAIR/CAMR/CAVR to NAAQS Attainment: Focus on 

Control Technologies and Emission Reductions In The Electric Power Sector, 

Office of Air & Radiation, U.S. EPA, April 18, 2006. Downloaded from EPA 

Air & Radiation Site. 

EPRI, 2006 EPRI, “Mercury Control Technology Selection Guide”, EPRI Report 

1012672, September, 2006. 

Figueroa, 2006 “Carbon Dioxide Capture and Sequestration Potential and Issues the U.S.”, 

Presentation by JD. Figueroa, DOE NETL, to the APPA New Generation 

meeting, June 28, 2006, Washington, DC. 

Georgia EPD, 2007 www.gaepd.org/environet/1/20070413_Amendments_CAMR.pdf

Hoskins, 2003 Hoskins, B. et al., “Uniqueness of SCR Retrofits Translates Into Broad Cost 

Variations”, Power Engineering, May, 2003. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

38

Katzberger, 2007 Katzberger, S. et al., “Impact of a Resource-Constrained FGD Market”, 

Electric Power 2007 Conference and Exhibition, May 1-4, 2007, Chicago, IL. 

Marano, 2006 Marano, M. et al., “Estimating SCR Installation Costs”, Power, 

January/February 2006. 

McCarthy, 2004 McCarthy, J. et al., “Duke Power WFGD Retrofit Program: Achieving the 

Lowest Cost System-Wide Compliance”, Proceedings of the Combined Power 

Plant Air Pollutant Control Mega Symposium, August 30-September 2, 2004, 

Washington, DC. 

Sargent & Lundy, 

2006 

Sargent & Lundy, “The Real Cost of Wet FGD Retrofit Projects”, presentation 

to Power-Gen, November, 2007, Orlando, FL. 

TAG, 1993 EPRI Technical Assessment Guide, “Electricity Supply – 1993”, EPRI TR102275-V1R7, June, 1993. 

UARG, 2003 Observations and Comments on the Report, Engineering and Economic 

Factors Affecting the Installation of Control Technologies for Multi-Pollutant 

Strategies, submitted by the Utility Air Regulatory Group, May, 2003. 
Capital Cost and Cost-Effectiveness: 

Power Plant Emission Control Technologies 

39 

SECTION 11 

FGD COST REFERENCES 

Generating Station Citation 

Duke Energy: Allen, 

Belews Creek, 

Marshall 

Everett, George, letter to Ms. Renne Vance, March 30, 2007, Exhibit C, 

downloaded from the North Carolina Public Utilities commission website 

LG&E EW Brown, 

Ghent 

“PSC Approves Environmental Projects for LGE, KU”, press release 

downloaded from Kentucky Public Utilities Commission website, June 20, 

2005. 

Ft. Martin, Hatfield 

2006a 

Allegheny Energy’s Emission Reduction Efforts Reach New Milestone at 

Pleasants Station”, Allegheny Energy Press Release, July 20, 2006. 

Ft. Martin, Hatfield 

2006b 

“Allegheny Energy Scrubber Projects to Cost More Than Expected”, Power 

Engineering, September 8, 2006 

Crist 7-10 “Southern Company to Install Sulfur Dioxide Controls at NW Florida Plant”, 

E&E Publishing, April 6, 2007 

Gorgas 8-10 “Alabama Power to Install One of Worlds Largest Scrubbers”, E&E 

Publishing, April 12, 2007 

Monroe 3, 4 “WGI to Construct Scrubbers”, July 5, 2006, Yahoo Finance 

TVA Unit Personal Communication, Rick Collins, TVA, May 6, 2007.