Final Report 

ANALYSIS OF MOG AND LADCO’S FGD AND SCR CAPACITY AND COST 

ASSUMPTIONS IN THE EVALUATION OF PROPOSED EGU 1 AND EGU 2 

EMISSION CONTROLS 

Prepared for 

Midwest Ozone Group 

Prepared by 

James Marchetti 

J. Edward Cichanowicz 

January 19, 2007 
2

Executive Summary 

 The focus of this analysis is two-fold: (i) to evaluate differences in the levels of 

FGD and SCR capacity estimated by the Midwest Ozone Group (MOG) and the Lake 

Michigan Air Directors Consortium (LADCO) in their evaluations of proposed “CAIRPlus” control measures for electric generation units in the Midwest (EGU1 and EGU2); 

and, (ii) to assess the difference in control cost assumptions used in both analyses. 

LADCO Database Accuracy 

The LADCO database does not contain emission controls on several units known 

to be installed and operating. These include, among others, SCR installations at Merom 

Units 1 and 2, and Petersburg Units 2 and 3. Omission of these and other control 

technology installations likely causes LADCO’s estimates of SO2 and NOx emissions to 

exceed expected levels, and thus to impose a higher percent reduction than is actually 

needed. 

Similarity of LADCO and MOG Technology Estimates When SO2 Allowances Are Not 

Banked

The use of allowance banking in the LADCO study – and how allowances are 

used – is a primary factor responsible for differences in estimates of technology 

deployment between LADCO and MOG. LADCO’s analyses assume that banked 

allowances would be used to defer the installation of emission controls, thus deferring the 

eventual costs of control with EGU1 and EGU2. However, if SO2 and NOx allowance 

banking is not considered, then estimates of technology deployment between the two 

studies would be similar. 

Significantly Higher Capital Costs 

LADCO’s capital cost estimates for EGU1 and EGU2 compliance are based on 

cost assumptions for FGD and SCR that do not reflect actual costs incurred by industry. 

Specifically, LADCO’s FGD capital costs are approximately $200/kW below industry 

estimates, while SCR equipment costs range from $25 to $45/kW below industry 

experience. The IPM model’s significant understatement of equipment capital costs 

explains much of the difference between MOG and LADCO’s estimates of the costs of 

implementing EGU1 and EGU2. 

Finally, as discussed below, a number of assumptions were made in our 

assessment of LADCO’s control proposals, based on limited information contained in the 

initial LADCO EGU White Paper. LADCO’s subsequent IPM modeling reveals several 

critical additional dimensions to the EGU proposals, including the use of multiple phases 

and a “floating” emission rate-based cap. Our estimates of EGU control costs assumed a 

more traditional tonnage-based cap similar to that used in the acid rain program and the 

EPA NOx SIP Call. 
3

INTRODUCTION 

In January 2005, the Midwest Regional Planning Organization (MRPO) issued a 

White Paper outlining a possible set of control measures that electric generating units 

within the states of Illinois, Indiana, Michigan, Ohio and Wisconsin would have to meet 

beginning in 2008 and with final implementation in 2013. These control measures would 

establish regional emission caps based upon specified emission rates for both NOx and 

SO2. Two sets of emission rates are described in the White Paper: referred to as Electric 

Generating Unit (EGU) 1 and 2. Since the release of this initial White Paper, two 

economic studies have been conducted to evaluate the compliance implications to electric 

generators in meeting EGU1 and EGU2. The first study was conducted by the Midwest 

Ozone Group (MOG) in the spring of 2005.1

 The second study was conducted by the 

Lake Michigan Air Directors Consortium (LADCO) in the fall of 2006.2

This analysis evaluates differences in the levels of FGD and SCR capacity 

estimated by MOG and LADCO needed to comply with EGU1 and EGU2, and discusses 

differences in the control cost assumptions used in both analyses. The discussion of cost 

assumptions is an update of a previous analysis for MOG.3

 

EMISSIONS, CAPS AND CONTROL TECHNOLOGIES – HAS THE IPM 

ANALYSIS MODELED ENOUGH SO2 AND NOx CONTROL TECHNOLOGY 

TO ACHIEVE EGU2? 

 This section evaluates the level of SO2 and NOx control technology that has been 

modeled by LADCO to achieve the reduction targets outlined by EGU2, and whether the 

level of capacity approaches the level of capacity modeled by MOG in order to achieve 

EGU2 emission caps. 

It should be noted that LADCO’s (IPM) modeled control capacity seems to 

represent “summer net” capacity, while MOG’s estimated control capacity is the 

“nameplate” capacity of the affected generating units Therefore, to enable a better 

comparison between MOG and LADCO’s modeled control capacities, we converted 

MOG’s “nameplate” to “summer net” capacity. 

SO2 and NOx Control Capacity in 2012 

Before evaluating the LADCO modeled control capacities for EGU2, we 

compared the level of existing, planned and modeled FGD and SCR expected to be online beginning in 2012 under CAIR. It should be noted that 2012 is also the first year of 

 

1

 Marchetti, Cichanowicz and Hein, (MCH), Evaluation of the Midwest RPO Interim Measures and EGU1 

and EGU2, August 1, 2005. 2

 ICF Resources, Implementation of EGU1 and EGU2 Policies Using the Integrated Planning Model in the 

Midwest RPO Region, September, 2006. 3

 Marchetti, Cichanowicz and Hein, Comparison of FGD and SCR Capital Cost Assumptions Used by 

MCH and EPA, September 29, 2005. 
4

implementation of EGU1 and EGU2 in the 5-State MRPO. The MOG capacity levels are 

drawn from its 2005 study and updated information from the Emission-Economic 

Modeling System’s Data Base, while the LADCO capacity levels were obtained from its 

VISTASII_PC_1f run, which includes the 5-State MRPO Region. 

 Table 1 compares the level of existing and planned capacity in both studies, 

revealing significant differences between the two sources. Specifically, MOG has 

identified almost 37.9 GW of FGD capacity that is or will be installed (existing and 

planned) by electric generators in the 5-State Region by 2012, while IPM only shows 

14.7 GW. This same type of differential can also be seen with regard to SCR capacity in 

the 5-State Region. Specifically, MOG estimates 36.8 GW of SCR capacity (existing and 

planned) will be in operation by 2012, while IPM only has 26.4 GW operating in 2012. 

Table 1: Comparison of 2012 Controlled Capacity in the 5-State MRPO (GW) 

FGD Capacity Existing (2005) Planned Modeled Total 

MOG 12.0 25.9 2.2 40.1 

LADCO 11.9 2.8 18.4 33.1 

 

SCR Capacity 

MOG 27.5 9.3 9.1 45.9 

LADCO 23.0 3.4 10.3 36.7 

Note: 1. Existing is installed capacity for year end 2005. 

 2. Planned capacity is based upon announced FGD and SCR systems by electric generators in the 5- 

 State MRPO. 

Even taking into account the modeled capacity (additional technology required 

beyond already known deployments) to meet CAIR for both SO2 and NOx, the IPM 

results fall significantly below the MOG results. Consequently, there is a concern that 

base data used in the IPM analysis is not reflective of industry experience/compliance, 

specifically with regard to what is installed and planned to be installed. For example, 

MOG indicates there are 27.5 GW of existing SCR capacity, while LADCO (IPM) shows 

only 23.0 GW, a 4.5 GW difference. In reviewing the IPM file (VISTASII_PC_1f), we 

noticed several operating SCRs missing, including E.W. Stout 7 (422 MW), Merom 1 & 

2 (1,020 MW), Warrrick 4 (270 MW) and Petersburg 2 & 3 (917 MW). Therefore, if the 

base data is not correct, the question then arises whether the modeled data is a realistic 

representation of industry compliance and thereby may have over-estimated pre-EGU 1 

and 2 SO2 and NOx emission levels. 

SO2 and NOx Control Capacity to Meet EGU2

 The LADCO report contains several new elements related to EGU compliance 

with EGU1 and EGU2, which were not made known to us when our original work was 

undertaken in the spring of 2005. These new elements are as follows: 
5

• EGU1 and EGU2 compliance date is 2012, whereas, the MOG analysis 

assumed 2013; 

• The EGU SO2 and NOx emission caps are moving or floating caps, 

which change from year-to-year based upon changes in annual heat input, 

unlike the MOG caps which are fixed and based upon a historical 

baseline; 

• Compliance with EGU1 and EGU2 utilizes two phases: (i) Phase I is from 

2009 to 2011, which has caps based upon the Interim Measures in the 

White Paper; and, (ii) Phase II is 2012 and beyond and has caps based 

upon EGU emission rates from the White Paper; 

• MRPO electric generators that over-control in Phase I are able to carryforward their excess/banked allowances for compliance in Phase II. This 

feature was not included in the MOG analysis because phases were not 

assumed or modeled and the White Paper did not mention that generators 

would be allowed to carry-forward allowances from a earlier phase; and, 

• MRPO electric generators are allowed to sell excess/banked allowances 

from EGU1 and EGU2 compliance to electric generators outside the 5-

State MRPO Region. 

Our review compares incremental control capacity, as modeled by MOG and 

LADCO, which generators in the 5-State MRPO Region would install under EGU2. The 

LADCO EGU2 policy run is identified as LADCO_PC_1d. However, both analyses were 

modeled under different regulatory regimes; therefore, our approach compares outcomes 

under a similar regulatory regimes and data. As mentioned above, the MOG analysis 

assumed a 2013 compliance date, with no carry over of allowances from any earlier 

phases. Under this type of regulatory regime, electric generators within the 5-State 

MRPO Region would be required to meet EGU2 SO2 and NOx emission caps by that 

date. The LADCO analysis indicates EGU2 would be implemented in 2012; however, 

between 2012 and 2020, generators are allowed to carry-forward both SO2 and NOx 

allowances for compliance, as illustrated in Table 6 of the LADCO report. 

There is a particular concern with regard to modeling in 2012. The LADCO 

report illustrates in 2012 affected units within the 5-State MRPO Region would have SO2 

emissions of 432,000 tons under EGU2. Also shown in Table 6, the 2012 EGU2 SO2 

emission budget computed by IPM is 473,000 tons, which seems to allow the banking of 

excess allowances. However, there may be an issue concerning the precision of the IPM 

model related to emissions and banking, which ultimately would affect the deployment of 

technology. Since the model does not evaluate compliance on an annual basis, the 

LADCO report indicates the 2012 cap is an average of 2010 – 2013 year caps, which 

encompasses the two phases of EGU2. Also, the related LADCO Stratus report seems to 

imply on pages ES-2 and ES- 4 that the SO2 emissions may be an average of the same 

years.

4

 As mentioned earlier, Phase II of EGU2 compliance begins in 2012, when 

affected EGUs would have to meet SO2 emission caps based upon an SO2 emission rate 

 

4

 Stratus Consulting Inc., Benefit Study of MRPO Candidate Control Options for Electricity Generation, 

August 25, 2006. 
6

of 0.10 lbs/mmbtu, and not an average or hybrid cap. Consequently, the lack of precision 

in the LADCO IPM report could erroneously project a 2012 EGU2 SO2 cap and 

emissions that are too high. This error creates unrealistic SO2 reduction targets and 

allowance banks from 2010 to 2013, which results in the deferral of technology 

deployment beyond 2012. 

Differences in Heat Input Assumptions 

Regardless of these concerns about banked allowances, our review of the LADCO 

report suggests that by 2020 electric generators would achieve the 2020 SO2 EGU2 cap 

without the use of banked allowances. Further, their NOx emissions would be slightly 

above the EGU2 cap, requiring the withdrawal of a small amount of banked NOx 

allowances. In addition, as best as we can determine, LADCO’s 2020 regional heat 

input of 6,011 TBtu is comparable to MOG’s 2013 regional heat input of 6,088 TBtu.5

 

A discrepancy does arise when performing the same calculation using the 2020 NOx 

EGU2 cap (from Table 6) and the EGU2 NOx emission rate. This method provides an 

estimate of 2020 regional heat input of 6,482 TBtu, representing a significant difference. 

Therefore, two questions arise: (i) is there a computational error in computing the 

regional heat input; or, (ii) has the LADCO report included more capacity in computing 

the EGU2 NOx budget than they used in computing the EGU2 SO2 budget. Since this 

question cannot be answered based upon the available information in the LADCO report, 

we used the regional heat input derived from the SO2 budget of 6,011 TBtu. This value 

is very close to MOG’s 2013 regional heat input (for units >25 MW) of 6,088 TBtu, and 

allows a better comparison of technology deployment. 

Therefore, comparing MOG’s 2013 technology deployment with LADCO’s 2020 

technology deployment is appropriate, because LADCO’s compliance requires either 

very little or no use of allowances, and the regional heat input is comparable to both 

studies. However, we were unable to obtain and review the IPM parsed files for 2018 

and 2020 for the EGU2 policy run (LADCO_PC_1d); consequently, we had to make 

some inferences on the level of FGD and SCR capacity that would have to be installed 

within the LADCO region to meet EGU2 in 2020. To do this, we evaluated two distinct 

data sets, based upon available data. 

 

Because only aggregated information is available from the LADCO report, we 

can make only initial comparisons between MOG’s 2013 compliance and LADCO’s 

2018 compliance estimates. As shown in Table 2, MOG’s FGD capacity in 2013 is about 

9.3 GW greater than LADCO, while MOG’s SCR capacity is 13.1 GW greater than 

LADCO. 

 

 

5

 The 2020 LADCO regional heat input is determined by dividing the 2020 SO2 EGU cap of 301,000 tons 

(from Table 6) by the EGU SO2 emission rate (0.10 lbs/mmbtu) yields a regional heat input of 6,011 TBtu. 
7

Table 2: Estimated Incremental FGD & SCR Capacity under EGU2 (GW) 

Study FGD SCR 

MOG (2013) 60.7 41.0 

LADCO (2018) 51.4 27.9 

As mentioned earlier, the LADCO analysis allows for the banking and carrying 

forward of allowances, which allows for the deferral of both FGD and SCR deployment, 

while the MOG analysis did not allow for this type of banking. Even with the use of 

banked SO2 allowances for compliance and a less stringent emission cap in the LADCO 

analysis, the levels of FGD capacity in the two studies are very close. So the question 

arises, when the banks are drawn down to zero, would the LADCO FGD and SCR 

capacity mirror the MOG capacity? 

Comparison of Emissions and Caps 

Evaluating regional heat input and emissions in 2020 may provide additional 

insight. Using the regional heat inputs described earlier and computed emission rates 

from Table 6 of the LADCO report yields the following emission/cap comparisons for 

both studies: 

Table 3: 5-State SO2 & NOx Emissions and Caps under EGU2 (tons) 

 MOG (2013) LADCO (2020) 

 Emissions Cap Over/Under Emissions Cap Over/Under

SO2 371,536 304,403 67,133 300,530 300,530 0 

NOx 249,203 213,082 36,121 213,391 210,385 3,006 

Regional 

Heat 

Input 

6,088 TBtu 6,011 Tbtu 

Note: 1. The 2020 LADCO NOx emissions are based upon multiplying a computed NOx emission rate (from Table 6) of 0.071 and multiplying it by the LADCO regional heat input. 

 2. The SO2 and NOx caps for both MOG and LADCO were computed by multiplying the EGU2 

 SO2 and NOx emission rate by the regional heat input. 

 As shown in the above table, both the SO2 and NOx emission caps for both MOG 

and LADCO are very close; however MOG’s emissions are higher. The primary factor 

affecting the emissions disparity between MOG and LADCO are assumptions defining 

the capabilities of control technologies. LADCO assumes more aggressive control levels 

can be achieved by FGD and SCR technology. Specifically, LADCO estimates that 

electric generators would achieve a NOx emission rate of 0.071 lbs/mmbtu and a SO2 

emission rate of 0.10 lbs/mmbtu by 2020. In comparison, MOG estimated control levels 

of 0.082 lbs/mmbtu for NOx and 0.122 lbs/mmbtu for SO2. 

It should be noted that MOG modeling to achieve these NOx and SO2 emission 

rates showed 18.6 GW of existing coal-fired capacity would switch to PRB coal with 

FGD systems. The LADCO study still models a NOx bank; however to achieve a region-
8

wide SO2 emission rate of 0.10 lbs/mmbtu it would seem the LADCO modeling would 

require either: (i) a larger shift to PRB coal with scrubbing within the 5-State Region than 

projected by MOG; or, (ii) the retirement of a significant amount of existing coal 

capacity. Therefore, it seems the use of banked allowances has allowed LADCO to defer 

the level FGD and SCR capacity to 2020 or beyond what MOG projected in 2013 under a 

no allowance carry-over regime. This suggests that the compliance implications 

discussed by MOG eventually would occur in the LADCO modeling if it were extended 

further in time.

IPM COSTS AND INDUSTRY EXPERIENCE 

This second section of the analysis provides an update of control technology 

capital costs for flue gas desulfurization (FGD) and NOx control, focusing on wet FGD 

for the former and selective catalytic reduction (SCR) NOx control for the latter. The wet 

FGD process cited in this documents refers to a wet limestone-based process, producing 

gypsum as a byproduct, and capable of 95-97% SO2 removal, depending on coal 

composition and averaging time. 

Background 

There is considerable information both in the public domain and reported 

anonymously describing the capital and operating cost of process equipment to control 

SO2 and NOx. Significant discrepancies exist among these various data sources 

provided by equipment suppliers, EPA, and industry. 

Recent capital cost estimates for conventional wet FGD and SCR reported by 

owners significantly exceed those estimated using information published by the supplier 

community or the EPA. Several factors are likely responsible for this discrepancy; one 

significant factor is the strong demand for environmental control equipment, coinciding 

with strong demand for general chemical process facilities. The confluence of these 

demands escalates the cost of labor and materials essential for this category of equipment. 

Compounding these differences in capital cost estimates is that some source data from 

EPA may not represent current market conditions, due to both the methodology and 

timing of the estimate. 

It is instructive to consider the escalation in the cost for chemical process 

equipment. One popular indicator of such costs is the Chemical Engineering Plant Index, 

which reflects the escalation in cost for a wide variety of process equipment. Figure 1 

depicts the change in the Chemical Engineering Plant Index (Chemical Engineering, 

2006) reflecting the construction cost of general plant process equipment, specifically 

from 1995 through mid-2006. 
9

Figure 1: Chemical Engineering Plant Index (CEPI): 1995 – July 2006) 

(Note: 1957-1959 = 100) 

200

250

300

350

400

450

500

550

1994 1996 1998 2000 2002 2004 2006 2008

Year of Cost Basis

Chemical Engineering Plant Index

Figure 1 shows little change in the Chemical Engineering Plant Index from 1995 

through the end of 2003, but 2004 marked the beginning of significant escalation that 

continues unabated. This trend reflects several factors important to environmental 

controls, such as escalation in material cost for upgrading electrical equipment. Due to 

intensive use of copper and a four-fold increase in copper prices, this index has risen 

rapidly since 2003. Competition for materials from China, driven by their rapid 

electrification program, is adding demand-push pressures to U.S. pollution control 

construction costs. Figure 1 shows that even with all other factors equal, cost escalation 

due to a robust demand will increase installed cost of process equipment. 

Comparison of FGD Estimates: 2000-2006 

Estimates of capital and operating cost for both wet and dry FGD equipment have 

been derived in the last five to seven years from a variety of sources. These include 

estimates for CAIR compliance, specific costs announced for CAIR retrofits, and 

projections by EPA and regulatory agencies based upon knowledge of equipment cost 

and availability. Compounding the complexity of preparing realistic cost estimates is the 

uncertainty in labor pool availability and cost, and the project scope – what equipment 

changes are included or excluded in the budget. This section summarizes the cost trends 

noted prior to the year 2006. 

Figure 2 presents a summary of FGD capital cost, shown as a function of unit 

generating capacity, for both dry and wet FGD, derived from a number of sources. All 

reported equipment costs have been adjusted to the end-of-year 2005, using the GDP 

escalating factor. It should be noted that FGD costs for all generating stations are 

reported per unit of generating capacity, even for system-wide designs for large 
10

generating systems. For example, FGD capital for Duke Energy’s Allen Units 1-4 is 

reported for a single Allen unit capacity of 270 MW; however the design is predicated on 

the generating capacity of the entire station of 1200 MW. Consequently, the available 

economies of scale – particularly important in reagent receiving and solid byproduct 

management - serve to reduce the unit cost. 

Figure 2 shows a wide disparity in projected costs between several sources and 

periods of time. These are discussed in the following sections. 

2006 EPA IPM Data 

The lowest capital cost projections for wet FGD are derived by EPA using their 

IPM cost correlations, which are applied for EPA modeling of system compliance costs. 

The IPM supporting documentation (EPA, 2006) and the key source papers (Staudt, 

2006, and Khan, 2004) describe the basis of the estimates. The estimating methodology 

appears to reflect authentic utility cost accounting, and considers both direct and indirect 

costs. However, it is not clear if these estimates reflect a complete suite of balance-ofplant items, such as upgrade of flue gas fans and electrical distribution components, or 

reflect the most recent market conditions. 
11

Figure 2: Wet and Dry FGD Capital Cost: Estimates Prior to 2006 (End-of-Year 2005 

Dollar Basis) 

0

100

200

300

400

500

600

0 200 400 600 800 1000 1200

Generating Capacity, MW

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

Wet FGD: System Study

Dry FGD and FF: System Study

Belews Creek 1, 2

EW Brown, Ghent

Amos

Southeast Installation

Dallman31-32

SystemStudyD

CinergyReference

DryFGDStationA

WetFGDStationA

FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

Monroe 3, 4 2006

Allen 1-5 2006

IPM 2006 Wet FGD

Wet FGD 20042005

1999 IPM Curve

Power (IPM 2006 Wet FGD)

Cinergy 2003 System 

Wet FGD Reference

1999 EPA IPM Wet 

FGD Reference

Wet FGD Curve:

2004-2005 

Installations

2006 EPA IPM Wet 

FGD Reference

The EPA IPM capital costs were based on soliciting budget estimates of 

uninstalled capital equipment costs – and as stated in the reference paper (Staudt, 2006) 

only one response was received. It is possible that the exploratory and budgetary nature 

of the estimate as developed by the supplier resulted in an atypically low estimate, which 

could not be detected by comparison to other sources. In addition, the supplier developed 

equipment costs for a new “greenfield” application, with the installed retrofit cost 

provided by a semi-quantitative “retrofit” factor. The retrofit factor selected for this 

analysis of 1.3 – an appropriate selection by historical standards – may be too small to 

reflect the complexity of the most recent sites for which FGD is considered. It is widely 

believed that the first 100,000 MW of FGD capacity retrofit were installed first on those 

units that provided the lowest removal cost ($ per ton basis), which implies the least 

capital cost. The units remaining may present more challenging site conditions for 

retrofits. 

Also shown in Figure 2 for comparison is the wet FGD capital cost curve used by 

EPA in IPM modeling in 1999, which has served as the basis for all but the most recent 

IPM modeling runs. The projected capital costs (also in end-of-year 2005 dollars) are 

slightly higher than the updated 2006 cost curve. It is not clear why the 2006-derived 

costs are lower, given significant increases in demand and material cost as shown by 

Figure 1. 

 
12

Cinergy 2003 System Wet FGD Study 

A comprehensive evaluation of wet FGD cost for the Cinergy system was 

conducted in 2003 by Sargent & Lundy Engineers. Individual data points derived in this 

analysis are not shown but the curve fit for the seven units in the study is reported and 

corrected to an end-of-year 2005 dollar basis. The shape of the curve is similar to that 

projected by EPA, but for the same generating capacity, Cinergy projects approximately 

$75 to $100/kW higher capital cost. 

2004-2006 Industry Estimates 

Figure 2 reports a locus of points for both wet and dry FGD, derived from 

numerous cost references in 2004 and 2006, some of which are public. For example, 

AEP published wet FGD capital cost for Amos, and Allegheny Energy for both Hatfield 

Ferry Units 1-3 and Fort Martin Units 1 and 2. Detroit Edison released capital cost for 

Monroe Units 3 and 4. Duke Power released costs for Belews Creek and five units at 

Allen, the latter each 270 MW but totaling 1200 MW of generating capacity. LG&E 

energy similarly published results for E.W. Brown and Ghent. 

Several anonymous sources contributed cost estimates based on thorough 

engineering procurement studies: a southeast utility and two system studies for operators 

in the Midwest. 

The locus of data points from these estimates –all derived during the 2004-2006 

timeframe – is shown. Also shown is a curve reflecting the general relationship between 

these data points. Significantly, these costs exceed those projected by EPA for IPM by 

over $200/kW – more than double the projected level. 

Sources for Cost FGD Differences 

There are several reasons why EPA and industry-generated wet FGD capital costs 

differ to the extent reported in Figure 2. Each of these is addressed in the following 

sections. The individual data points on Figure 2 may not all be directly comparable. 

Except for adjusting all cost estimates to an end-of-year 2005 dollar basis, no effort has 

been made to assure a uniform basis. The following factors, also included in the EPA 

methodology (Staudt, 2006), are all usually derived as a fraction of the total process 

capital, which describes the total cost for process equipment prior to installation. The 

cost factors are described as follows: 

Engineering and Construction Management Charges. The cost for engineering services 

to define the design of process equipment, and management of these services, is generally 

10%, similar to that assumed by Staudt (2006). It is possible that challenging retrofit 

requires greater engineering expenditure. 

Process & Project Contingency. The usual assumptions for these standard contingency 

values for the relatively mature wet and/or dry FGD is 10% and 5%, respectively. For 
13

reported costs that reflect firm prices from suppliers, it is unlikely any such charges are 

included as line-item cost elements. For these fixed price bids, each equipment and 

process supplier will utilize an internal proprietary margin to account for uncertainties. 

Projects that are conducted on an “open book” basis with a strategic partner will not 

include such cost elements, but allow cost recovery if actual incurred costs exceed those 

predicted. 

General Facilities. This cost element covers roads, providing for special access, and 

buildings; any differences are expected to be small. 

Contractor Profit/Fees. These charges can be 5-10% of the total 

Project Scope. The specific equipment included in the FGD budget can vary. For 

example, Staudt (2006) discusses the possibility of fan modifications and ductwork 

changes in an FGD retrofit, but these items are not addressed in the cost estimate. The 

additional resistance to flue gas flow for a conventional wet and dry FGD system – from 

4 to 8 in w.g. – will in most cases require some type of fan upgrade. Further, depending 

on how the flue gas handling system was originally designed, a significant run of 

ductwork may have to be strengthened, to avoid damage from significant negative 

pressure. Again, there is no indication these or the costs – albeit very site specific – are 

included in the EPA-derived estimates. 

Timing of Costs. The significant demand in flue gas processing equipment – for both 

FGD and SCR – has evolved into a premium for equipment and services since 2000, and 

especially so in the last year. 

The role of the project schedule and the subsequent timing of the cost estimate are 

shown by Figure 3. This figure repeats the curve-fit description of capital cost presented 

in Figure 2, along with 2006 revised costs as reported for two Allegheny Power stations – 

Fort Martin and Hatfield Ferry. Fort Martin’s capital costs escalated significantly from 

estimates prepared in 2004. 

Discussions with representatives of architectural engineering companies involved 

in wet FGD procurement indicate that a strong demand for essential equipment and 

services is responsible for the cost escalation. Specific examples are: 

Limited access to flue gas fans and slurry pumps. A limited number of equipment 

suppliers are qualified to provide the large, high reliability fans for flue gas and pumps 

for process slurry that are critical to reliable performance. At present, the manufacturing 

capabilities of key suppliers are booked – and establish the limiting step in FGD 

installation of 30-36 months. Both the shortage of equipment and willingness of 

purchasers to pay to expedite procurement contribute to these higher costs. 
14

Figure 3: FGD Capital Cost: 2004 vs. 2006 Estimates (End-of-Year 2005 Dollar Basis) 

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)

CinergyReference

FortMartin 1, 2 2004

Hatfield Ferry 1-3, 2004

2006 EPA IPM

RecentPowerLaw

Fort Martin 1-2 2006

Hatfield Ferry 1-3 2006

Power (2006 EPA IPM)

Cinergy 2003 System 

Wet FGD Reference

2006 EPA IPM wet 

FGD Reference

2006 vs. 2004: 

Fort Martin 1, 2

2006 vs. 2004

Hatfield Ferry 1-

Wet FGD Curve:

2004-2005 

Installations

Some observers have noted that the U.S. utility industry qualifies a limited 

number of suppliers of this equipment, and that relaxing qualification requirements is one 

way to increase the number of suppliers (Hartenstein, 2006). Given the large and 

complex nature of recent system FGD installations, it is not known if this action would 

introduce the use of equipment with less proven reliability. 

Limited Stack Erectors. Similarly, there are reportedly a limited number of suppliers 

world-wide that can fabricate the wet stack designs required to withstand the wet flue gas 

from FGD. Similar to the case for flue gas and slurry equipment, this can be a limiting 

step in FGD process installation. At present, it is reported that the four major stack 

erectors are booked through 2010; any new installation reportedly will not be able to 

install new wet stacks before the beginning of 2011. 

Electrical Equipment. The requirement for additional power for pumps, fans, and 

associated equipment can significantly increase the on-site demand for power, and 

distribution such as motor control centers for power management and distribution. The 

cost of these upgrades – dependent on copper-containing products – has increased 

reflecting the four-fold increase in copper prices in recent years. Upgrade of electrical 

subsystems – historically 6-8% of an FGD project - can now exceed 15%. 

Installation Difficulty. The units reflected in Figure 2 and 3 represent approximately the 

second 100 GW of wet FGD installed. As discussed previously, the first 100 GW were 

initially selected for a large number of reasons – of which ease of retrofit and low capital 
15

cost was likely the most significant factor. It is these early applications that provided the 

bases for the historical retrofit factor of 1.3. It is likely that units within the second 100 

GW of retrofit candidates represent more difficult retrofit applications, which the 

historical 1.3 retrofit factor does not capture. Compounding the retrofit difficulty is the 

higher cost of labor, due to shortages reported by many operators of FGD process 

equipment. 

In summary, the capital cost for wet FGD process equipment between estimates 

derived for use in IPM modeling and industry-reported costs differ significantly, by 

approximately a factor of two. The key reasons for this difference are likely the timing of 

the estimates (e.g. reflecting 2005 and 2006 market conditions), the complexity of the 

retrofit sites, and the scope of equipment included. 

The consequence of the difference in capital cost, combined with differences in 

operating cost assumptions (the latter not addressed in this document) is a similarly wide 

difference in calculated cost per ton ($/ton) of SO2 removal. Specifically, the reported 

marginal cost values in Table 3 of the ICF report for the EGU2 category notes a range 

from $1,847 to $2,951/ton for SO2. In contrast, the recent analysis of the authors 

evaluating the IL Mercury Rule reports dry FGD removal costs between $2,600 and 

$4,200/ton.6

 These costs are based upon inputs from system generators in Illinois and 

reflect industry FGD capital costs discussed in this section. 

SCR NOx Control 

Similar to the case of wet FGD, capital cost estimates derived for SCR NOx 

control from industry-reported sources and EPA differ significantly. Several reports of 

SCR capital cost have been published in recent years (Hoskins, 2003; Cichanowicz, 

2004; Marano, 2006). The most detailed and comprehensive analysis is provided by 

Marano, reporting global trends based on approximately 70 SCR installations erected 

between 1999 through 2005. As shown in Table 4, Marano reports most SCR costs range 

from $100 to $200/kW. There is a noted increase in capital cost for units installed after 

2003. 

It is instructive to compare the trend in reported and estimated SCR capital 

between industry sources and projections by EPA. Figure 4 depicts this trend, utilizing 

the individual data points reported by Cichanowicz. (Marano did not report individual 

data so developing such a trend is not possible). Figure 4 shows the wide disparity in 

capital cost for industry-reported units, which vary by a factor of two or more. The 

industry-reported data show that increasing generating capacity does not always lower 

unit (e.g. per $/kW) process cost, as the complexities imposed by the larger generating 

sites can complicate installation and elevate cost. Also shown on Figure 4 is the trend in 

projected SCR capital using the relationship employed in EPA IPM modeling (Khan, 

2004). This trend is well below that reported by industry. 

 

6

 Testimony of James Marchetti before the Illinois Pollution Control Board in rulemaking R06-25 dated 

July 28, 2006. 
16

Table 4: SCR Capital Cost Survey Results 

Reference Average Capital, 

MW 

($/kW) 

Low-High 

Cost 

Observed 

($/kW) 

Observation 

Hoskins, 2003 120 (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 

81 (600-899 MW) 

to 123 (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.” 

As explained by Khan (2004), the EPA IPM methodology uses reports of industry 

SCR costs but adopts these into a fixed scaling relationship. In contrast, we relied on the 

trend curve depicted in Figure 4 to estimate SCR capital costs. 
17

Figure 4. SCR Capital Cost: Industry Reports versus EPA IPM Modeling (2005 

End-of-Year Dollar Basis) 

 

0

50

100

150

200

250

0 200 400 600 800 1000 1200 1400

Unit Generating Capacity, MW

SCR Capital Cost ($/kW, 2005)

EPA IPM SCR 

Cost Curve

Curve Fit of Data From 

Industry Survey

The reason for the disparity in SCR capital costs is likely the same as cited for wet 

FGD: the recent escalation in material prices has elevated the cost of materials and labor, 

and the plant sites for industry-reported costs may be more complex than earlier 

estimates. Consequently, the difference between EPA and estimates derived from 

industry experience for SCR equipment can range from $25 to $45/kW. 

Similar to the case for wet FGD, the EPA IPM cost assumptions for SCR are 

significantly below those reported by industry. The consequence of the difference in 

capital cost, combined with differences in operating cost assumptions (the latter not 

addressed in this document) is a similarly wide variance in calculated cost per ton ($/ton) 

for SCR NOx removal. Specifically, the reported marginal cost values in Table 3 of the 

ICF report cites for the EGU2 category a range from $$639 to $1,020/ton for NOx. In 

contrast, the MCH recent analysis evaluating the IL Mercury Rule reports SCR NOx 

removal costs between $1,500 to $9,800/ton.7

 These costs are based upon inputs from 

system generators in Illinois and reflect industry SCR capital costs discussed in this 

section.

 

7

 Ibid. 
18

 References 

Author, Date Reference 

Chemical Engineering, 

2006 

Economic Indicators, Chemical Engineering, October, 2006 

Cichanowicz, 2004 Cichanowicz, J.E., Why are SCR Costs Still Rising, Power 

Magazine, April, 2004. 

EPA, 2006 Documentation for EPA Base Case 2006 (V.3.0) Using the 

Integrated Planning Model, Environmental Protection Agency, 

2006, November, 2006. 

Hartenstein, 2006 Hartenstein, H., personal communication, August 30, 2006. 

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

Broad Cost Variations, Power Engineering, May, 2003. 

Khan, 2004 Khan, S., Updating Performance and Cost of NOx Control 

Technologies in the Integrated Planning Model, Proceedings of 

the 2006 Mega-Symposium, August, 2006, Baltimore, MD. 

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

January/February 2006 

Staudt, 2006 Staudt, J. et. al., Updating Capital Cost of SO2 Control 

Technologies in the Integrated Planning Model and the Coal 

Utility Environmental Cost Model, Proceedings of the 2006 

Mega-Symposium, August, 2006, Baltimore, MD.