October 2010 

Revised BART 

Cost-Effectiveness Analysis for 

Flue Gas Desulfurization at 

Coal-Fired Electric Generating 

Units in Oklahoma: 

Sooner Units 1 & 2 

Muskogee Units 4 & 5 

Northeastern Units 3 & 4 

Final Report

Prepared for 

Ellen Belk 

U.S. Environmental Protection Agency Region 6 

Multi-media Planning and Permitting Division 

1445 Ross Avenue, Suite 1200 

Mail Code: 6PD 

Dallas, TX 75202-2733 

Prepared by 

Phyllis Fox, Ph.D., PE 

(Consultant) 

RTI Project Number 0209897.004.085 
iii 

TABLE OF CONTENTS 

I. INTRODUCTION..................................................................................................1 

II. SUMMARY & CONCLUSIONS..........................................................................2 

III. REVISED COST ANALYSIS FOR SOONER AND MUSKOGEE DRY 

 SCRUBBER ............................................................................................................3 

A. DESIGN BASIS.......................................................................................................3 

1. Option 1: Increased Emission Reductions ...........................................................5 

2. Option 2: Decreased Scrubber Cost .....................................................................6 

B. COSTING METHOD ..............................................................................................9 

1. Capital Cost: Failure to Follow Cost Manual ...................................................10 

a. Escalation ...............................................................................................................11

b. Allowance for Funds Used During Construction (AFUDC) .................................11 

c. Bond Costs .............................................................................................................12 

d. Contingency ...........................................................................................................12 

e. BOP Profits ............................................................................................................13 

f. Capital Recovery Factor ........................................................................................13 

 i. Scrubber Lifetime ......................................................................................14 

 ii. Interest Rate ...............................................................................................15 

g. Construction Costs .................................................................................................15 

 i Labor Rates ................................................................................................15 

 ii. Per Deim Expense ......................................................................................16 

 iii. Labor Productivity .....................................................................................18 

 iv. Overtime Inefficiency ................................................................................18 

2. Capital Cost: Double Counting ..........................................................................19 

a. Owner's Cost ..........................................................................................................19 

b. Engineering/Procurement ......................................................................................20 

c. Construction Management .....................................................................................20 

d. Startup & Commissioning Craft Support ...............................................................21 

e. Operator Training & Manuals ................................................................................21 

f. Other Factored Sums ..............................................................................................22 

g. Initial Fabric Filter Replacement Materials ...........................................................22 
iv

3. Capital Cost: Overestimating .............................................................................22 

a. Multiple Unit Discounts .........................................................................................23 

b. Common Facilities .................................................................................................23 

c. Cost Capacity ........................................................................................................24 

d. Other Cost Options ................................................................................................24 

 i. Recycle Scrubber .......................................................................................24 

 ii. Electrostatic Precipitator (ESP) .................................................................25 

 iii. Fabric Filter Baghouse ...............................................................................26 

4. Operating and Maintenance Costs (O&M) .......................................................27 

a. Variable O&M Costs .............................................................................................27 

 i. Lime Costs .................................................................................................27 

 ii. Water Cost .................................................................................................28 

 iii. FGD Waste Disposal..................................................................................29 

 iv. Bag and Cage Replacement Cost ...............................................................30 

 v. Auxiliary Power Costs ...............................................................................31 

b. Indirect Operating Costs ........................................................................................33 

5. OG&E Cost Summary .........................................................................................33 

IV. REVISED COST ANALYSIS FOR NORTHEASTERN DRY SCRUBBER 35 

A. CAPITAL COST ...................................................................................................36 

1. Unit Capital Cost..................................................................................................36 

2. Capital Recovery Factor ......................................................................................36 

B. OPERATING COSTS ...........................................................................................37 

1. Water .....................................................................................................................37 

2. FGD Waste Disposal ............................................................................................38 

3. Bag and Cage Replacement .................................................................................38 

4. Fixed O&M (Labor) ............................................................................................38 

5. Insurance ..............................................................................................................38 

 

6. Property Taxes .....................................................................................................39 

C. EMISSION REDUCTIONS ..................................................................................39 
v

D. NORTHEASTERN COST SUMMARY ...............................................................39 

V. COST EFFECTIVENESS: DRY SCRUBBER .................................................40 

VI. BART EMISSION LIMIT: DRY SCRUBBER ................................................41 

VII. WET SCRUBBING .............................................................................................47 

A. CONTROL EFFICIENCY .....................................................................................47 

B. COST EFFECTIVENESS OF WET SCRUBBING ..............................................48 

C. COLLATERAL EFFECTS OF WET SCRUBBING ............................................49 

1. Sulfuric Acid Mist ................................................................................................49 

2. Water .....................................................................................................................50 

3. Wastewater ...........................................................................................................51 

4. Excess Particulate Emissions ..............................................................................51 

5. Reactant ................................................................................................................51 

6. Plume Issues .........................................................................................................52 

D. BENEFITS OF WET SCRUBBING .....................................................................52 

1. Reliability ..............................................................................................................52

2. Maintenance Emissions .......................................................................................53 

VIII. BART EMISSION LIMIT: WET SCRUBBING ..............................................53 

APPENDIXES 

1: Revised Cost Effectiveness Analysis for Dry Flue Gas Desulfurization at 

Sooner Units 1 and 2 and Muskogee Units 4 and 5 ...........................................55 

2: Revised Cost Effectiveness Analysis for Flue Gas Desulfurization at 

Northeastern Units 3 & 4 ....................................................................................57 
vi

TABLES 

Table 1. Dry Scrubber Control Options Evaluated by Sargent & Lundy ...........................4 

Table 2. Option 1 Revised Cost Effectiveness, Increased Emission Reductions (91.5% SO2 

Reduction from Scrubber Inlet of 1.176 lb/MMBtu) ...........................................................6 

Table 3. Option 2 Revised Cost Effectiveness, Increased Emission Reductions (80% SO2 

Reduction from Scrubber Inlet of 0.509 lb/MMBtu) ...........................................................8 

Table 4. Oklahoma BART-Eligible Coal-Fired Electric Generating Units .......................23 

Table 5. Naughton BART Analysis ...................................................................................26 

Table 6. Auxiliary Power Per Unit (MWh/yr) ...................................................................32 

Table 7. Comparison of SO2 BART Cost Effectiveness Values for Dry Scrubbers & Low Sulfur 

Coal with Revised OG&E and AEP/PSO Values ..............................................................42 

Table 8. Comparison of Average Cost Effectiveness for Dry and Wet Scrubbers ............48 

FIGURES 

Figure 1. Non-Union Construction Hourly Wage & Benefit Rates by Region by Position - 

Region 6 .............................................................................................................................17 

Figure 2. Wet and Dry Scrubber Unit Cost ........................................................................35 

Figure 3. Relation Between Inlet SO2 and SO2 Removal Efficiency for a Dry Scrubber 44 

Figure 4. Newmont TS Power Plant, Unit 1, SO2 Rate, 2008 - June 2010 .......................46 

Figure 5. Pleasant Prairie Unit 1, SO2 Rate, 2007 - June 2010 .........................................54 
1 

I. INTRODUCTION 

 On February 17, 2010, Oklahoma submitted its Regional Haze State Implementation Plan 

("SIP") to EPA.1

 This SIP revision concluded that Oklahoma BART-subject sources included 

the following coal-fired electric generating stations: Sooner Units 1 and 2; Muskogee Units 4 

and 5; and Northeastern Units 3 and 4. These are all similar tangentially fired pulverized coalfired boilers ranging in size from 490 MW to 572 MW gross that burn low sulfur, Powder River 

Basin (PRB) sub-bituminous coal. 

 This SIP revision concluded that BART for SO2 for these six units was satisfied by 

continuing to burn low-sulfur coal and meeting an SO2 emission limit of 0.65 lb/MMBtu, based 

on a 30-day rolling average.2

 This determination does not comply with presumptive BART 

(95% SO2 reduction or an SO2 emission limit of 0.15 lb/MMBtu) and allows an increase in SO2 

emissions from current levels of 0.51 lb/MMBtu to 0.65 lb/MMBtu at Muskogee and Sooner. 

 This SIP revision concluded that both dry and wet scrubbers, widely used in similar 

applications,3

 are not cost effective for these six coal-fired units without citing any unusual 

circumstances. This conclusion is based on cost analyses performed by Sargent & Lundy4

 for 

Oklahoma Gas & Electric (OG&E) Sooner Units 1 and 2 and Muskogee Units 4 and 5 and by 

Trinity Consultants5 for American Electric Power/Public Service Company of Oklahoma 

(AEP/PSO) Northeastern Units 3 and 4. The focus of these company analyses is the use of dry 

scrubbing (or dry wet flue gas desulfurization) to control SO2. Wet scrubbing was eliminated 

based on incremental cost and adverse collateral impacts in earlier, 2008 analyses. The 

company's cost estimates for dry and wet scrubbers are much higher than costs estimated at other 

similar facilities, calling the reliability of these estimates into question. Thus, the following 

sections review and revise the company's cost estimates. 

II. SUMMARY AND CONCLUSIONS 

 

 I reviewed the dry scrubber cost analyses prepared by the companies: (1) Sargent & 

Lundy for the Sooner and Muskogee plants in the 12/28/09 S&L FollowUp Report6

 and (2) 

Trinity Consultants for Northeastern Units 3 and 4 in the 5/30/08 Trinity Report.7 Based on this 

 

1

 Regional Haze Implementation Plan Revision, State of Oklahoma, February 2, 2010, Submitted via Letter from 

J.D. Strong, Oklahoma Secretary of Environment, to Alfredo Armendariz, Regional Administrator, EPA Region 6, 

Re: Oklahoma Regional Haze State Implementation Plan ("OK Regional Haze SIP"). 

2

 OK Regional Haze SIP, Table IV-6, IV-7, and IV-10. 

3

 Carl Weilert & Emily Meyer, Burns & McDonnell, Utility FGD Design Trends, Power Engineering, August 2010, 

Table 1: Currently Operating FGD Units in the United States. 

4

 Sargent & Lundy, Sooner Units 1 & 2, Muskogee Units 4 & 5 Dry FGD BART Analysis Follow-Up Report, 

Prepared for Oklahoma Gas & Electric, December 28, 2009 ("12/28/09 S&L Followup Report"). 

5

 Trinity Consultants, Best Available Retrofit Technology (BART) Determination, American Electric Power, 

Northeastern Power Plant, May 30, 2008 (5/30/08 Trinity Report). 

6

 12/28/09 S&L FollowUp Report. 

7

 Trinity Consultants, Best Available Retrofit Technology (BART) Determination, American Electric Power, 

Northeastern Power Plant, May 30, 2008 (5/30/08 Trinity Report). 
2

review, I prepared revised cost analyses, correcting some of the errors that I found. It was not 

possible to correct all errors as the parties declined to provide copies of their spreadsheets 

disclosing their cost calculations and failed to support many critical assumptions. 

 This report summarizes the results of my review and recalculation. My revised cost 

analysis for Sooner and Muskogee is presented in Appendix 1 and for Northeastern in Appendix 

2. Each cost component that I revised is highlighted in blue in these Appendixes. My basis is 

explained in the following sections. 

 

 My analysis indicates the cost to install dry scrubbers at all six of these units is 

significantly overestimated for four principal reasons. First, a much bigger scrubber was costed 

than assumed in the BART analysis, resulting in a mismatch between annual costs and emission 

reductions. Second, the companies did not follow standard BART cost estimating guidelines. 

Third, some costs were significantly outside of the range of the actual costs. Fourth, the cost 

estimates contain double counting. Fifth, the cost estimates failed to evaluate the most cost 

effective options. 

 When these errors are corrected, the average cost effectiveness for dry scrubbing declines 

at Sooner from $6,747/ton to $1,291/ton; at Muskogee from $7,435/ton to $1,317/ton; and at 

Northeastern from $3,294/ton to $1,544/ton, in 2009 dollars. Actual costs could be even lower 

as I was unable to correct all of the overestimates that I identified due to lack of support and 

underlying calculations. My revised cost effectiveness values are within the range of values 

found to be cost effective at other similar facilities. In addition, my analysis indicates that a dry 

scrubber at any of these units could achieve a BART emission limit of 0.06 lb/MMBtu, based on 

30-day rolling average, when burning low sulfur coal. 

 BART analyses performed for many similar facilities nationwide indicate that the cost 

effectiveness of a wet scrubber is about 9% higher than for a dry scrubber. In cases where an 

existing electrostatic precipitator can be used instead of a new fabric filter baghouse, the cost 

effectiveness of wet scrubbing is lower than dry scrubbing and the incremental cost effectiveness 

is zero. This is likely the case for the subject units, but this option was not evaluated by the 

companies. 

 I revised the wet scrubber cost analyses based on the ratio of my revised dry scrubber 

cost to the initial company costs. This lowered the cost of wet scrubbing at Sooner from 

$8,101/ton to $1,555/ton; at Muskogee from $8,001/ton to $1,417/ton; and at Northeastern from 

$3,625/ton to $1,699/ton. Wet scrubbers can remove up to 98% of the SO2 from low sulfur 

coals and meet SO2 emission limits of 0.03 lb/MMBtu based on a 365-day rolling average and 

0.06 lb/MMBtu based on a 24-hour average. 

 
3

III. REVISED COST ANALYSIS FOR SOONER AND MUSKOGEE 

 DRY SCRUBBER 

 The Sargent & Lundy cost effectiveness analysis is contained in the "12/28/09 S&L 

FollowUp Report".8

 This report was prepared in response to Oklahoma's draft Regional Haze 

SIP, which required Sooner and Muskogee to install dry flue gas desulfurization systems 

(scrubbers) to satisfy BART. Oklahoma rejected Sargent & Lundy's earlier BART cost 

effectiveness analyses as they were "substantially higher than those reported for similar 

projects." The FollowUp Report is a response to Oklahoma's concern about the cost analyses. 

The revised costs, while somewhat lower, are still substantially higher than those reported for 

similar projects without the presence of any "unusual circumstances." 

A. DESIGN BASIS 

 Cost effectiveness analysis evaluates the cost of controlling pollution in dollars per ton of 

pollutant removed. Cost effectiveness is calculated according the EPA Air Pollution Control 

Cost Manual or "Cost Manual",9

 as stipulated in the BART Guidelines. A control technology is 

considered to be “cost effective” if it falls within a reasonable range of cost-effectiveness 

estimates. 

 Cost effectiveness determinations include several steps. First, the capital cost is 

estimated and annualized using a capital recovery factor. Second, the operating and maintenance 

(O&M) costs are estimated. Third, these costs are summed and divided by the tons of pollutant 

removed. This calculation requires that the costs for the control technology are consistent with 

the claimed emission reductions. 

 In performing its BART analysis, Sargent & Lundy assumed that the Sooner and 

Muskogee plants burned coal with a higher sulfur content than they are currently burning. This 

necessitated costing a much bigger scrubber than is necessary for the coal they are currently 

burning. However, Sargent & Lundy also assumed the emissions corresponded to these plants’ 

presently lower sulfur coal. This mismatch overestimated cost effectiveness (i.e., resulted in a 

higher dollars per ton) by about a factor of three. In other words, the costed scrubber is much 

more efficient than the one required to deliver the assumed BART performance level. 

 The FollowUp Report indicates that two separate cases were considered as summarized 

in Table 1: (1) reduction of SO2 from coal containing 1.176 lb/MMBtu SO2 to 0.10 lb/MMBtu 

and (2) reduction of SO2 from coal containing 0.509 lb/MMBtu SO2 to 0.10 lb/MMBtu. 

However, in the Sargent & Lundy cost effectiveness analysis, Option 1 was used to estimate 

capital cost and Option 2 was used to estimate O&M costs and emission reductions. This 

mismatch significantly overestimates the calculated cost effectiveness of the dry scrubber. The 

 

8

 Sargent & Lundy, Sooner Units 1 & 2, Muskogee Units 4 & 5 Dry FGD BART Analysis Follow-Up Report, 

Prepared for Oklahoma Gas & Electric, December 28, 2009 ("12/28/09 S&L Followup Report"). 

9

 U.S. EPA, EPA Air Pollution Control Cost Manual, Report EPA/452/B-02-001, 6th Ed., January 2002 ("Cost 

Manual"), The EPA Air Pollution Control Cost Manual is the current name for what was previously known as the 

OAQPS Control Cost Manual, the name for the Cost Manual in previous (pre-2002) editions of the Cost Manual. 
4

high sulfur design-basis coal used to cost the scrubbers represents a significant increase in the 

sulfur content of the coal that is currently burned (0.51 lb/MMBtu).10 The emission reductions 

that Sargent & Lundy used to calculate cost effectiveness, on the other hand, were based on only 

a 76% to 79% reduction in SO2 from a coal containing 0.51 lb/MMBtu SO2.11 

Table 1 

Dry Scrubber Control Options 

Evaluated by Sargent & Lundy 

In other words, larger scrubbers than are needed for the coal currently burned were 

costed, which skewed the cost effectiveness in dollars per ton to the high side. When calculating 

the tonnage removed, a lower scrubbing efficiency, corresponding to a smaller scrubber was 

used, which skewed the cost effectiveness to the high side. The use of a larger scrubber provides 

the operator with the flexibility to burn higher sulfur coals than are currently being burned. 

However, that increases the cost over what would be needed to minimally satisfy BART. 

This mismatch in design causes a dilemma in analyzing the cost effectiveness that is not 

completely resolvable within the scope of this work. An ideal analysis would be to contrast the 

cost effectiveness of the larger scrubbers, using a range of coals to the cost effectiveness of 

smaller scrubbers burning the current coal. The basic decision point for EPA, however, is 

whether scrubbers are cost effective and what emission limit should be specified. Therefore, in 

this section, I construct two costing options to bound the problem, within the parameters 

introduced by Sargent & Lundy. In subsequent sections, I revised the Sargent & Lundy analysis, 

which uses Option 1 for cost data and Option 2 for emissions data. 

 

10 12/28/10 S&L FollowUp Report, Table 9, pdf 21. 

11 12/28/10 S&L FollowUp Report, Table 5. Emission reductions calculated as 100(annual emission 

reductions)/baseline annual SO2 emissions. For Muskogee 4, SO2 reduction = 100(6953/9113) = 76.3%, for 

Muskogee 5, SO2 reduction = 100(6846/9006) =76.0%, for Sooner 1 = 100(7377/9349) = 78.9%, and for Sooner 2 

= 100(6553/8570) = 76.5%.

Option 

1 

Option 

2 

S&L 

Analysis 

Inlet S (lb/MMBtu) 1.176 0.509 

Outlet S (lb/MMBtu) 0.10 0.10 

SO2 Reduction (%) 91.5% 80% 

Annual Cost ($/yr) 

 Sooner 93,664,600 63,988,436 93,664,600 

 Muskogee 102,600,400 70,396,326 102,600,400 

Emission Reduction (ton/yr) 

 Sooner 43,428 13,930 13,930 

 Muskogee 46,458 13,799 13,799 

Cost Effectiveness ($/ton) 

 Sooner 2,157 4,594 7,147 

 Muskogee 2,208 5,102 7,435 
5

 

 The first option, costing the larger scrubber, as is demonstrated below, is more cost 

effective and it provides the owner much greater flexibility in coal selection, allowing the use of 

higher sulfur coals. This option was likely intended as it allows the owner to switch to higher 

sulfur coals in the future as the supply of lower sulfur coals diminishes or to use cheaper higher 

sulfur coals to reduce operating costs. This first option is carried throughout the balance of this 

report because Sargent & Lundy assumed a higher sulfur coal would be burned when it costed 

the scrubbers. The second option, costing a smaller scrubber, is discussed in Section III.A.2 to 

demonstrate that it is less cost effective. 

1. Option 1: Increased Emission Reductions Relative to Costed Case 

 Table 1 shows that a scrubber designed to remove 91.5% of the SO2 from an inlet of 

1.176 lb/MMBtu (Option 1) would remove more SO2 than a scrubber designed to remove only 

80% of the SO2 from an inlet of 0.51 lb/MMBtu (Option 2). Thus, for a given annual cost, the 

calculated cost effectiveness in dollars per ton declines as emission reductions increase. 

 Cost effectiveness could be estimated using the cost of the larger scrubber and the 

emission reductions that could be achieved with this larger scrubber, assuming an outlet of 0.1 

lb/MMBtu SO2. The use of higher sulfur coal, 1.176 lb/MMBtu SO2, differs from past 

practices, burning a 0.509 lb/MMBtu SO2 coal. Thus, the new baseline for purposes of 

estimating emission reductions is 1.176 lb/MMBtu. 

 The impact of using actual emission reductions for Option 1 on calculated cost 

effectiveness is summarized in Table 2, assuming all else remains the same. This table indicates 

that the mismatch reduces the cost effectiveness in dollars per ton for the OG&E plants from 

about $7,100/ton to about $2,100/ton (Table 2), or by over a factor of three.12 Actual emission 

reductions that could be achieved with the Option 1 scrubber are larger than stated in Table 2 as 

the costs correspond to a 95% efficient scrubber and an outlet emission limit lower than 0.1 

lb/MMBtu is feasible. 

 

12 Actual cost effectiveness would be somewhat higher as the O&M costs included in the Option 1 annual costs are 

for Option 2. This is corrected in subsequent sections of this report. 
6

Table 2 

Option 1 

Revised Cost Effectiveness 

Increased Emission Reductions 

(91.5% SO2 Reduction from 

Scrubber Inlet of 1.176 lb/MMBtu)

 The revised cost effectiveness values in Table 2 do not include any of the other revisions 

I make below to align costs with Regional Haze Guidelines and to eliminate double counting and 

other overestimates. These additional revisions, coupled with the increased SO2 emission 

reductions shown in Table 2 result in an average cost effectiveness value for the two plants of 

$1,304/ton, which is within the range of cost effectiveness values for other similar scrubbers. 

2. Option 2: Decreased Scrubber Cost Relative to Costed Case 

 Alternatively, cost effectiveness could be estimated for Option 2, removing 80% of the 

SO2 from an inlet of 0.51 lb/MMBtu, by costing a smaller scrubber. This would result in a 

higher dollars per ton value than estimated in Table 2 for the higher sulfur case. Sargent & 

Lundy did not provide any scrubber cost analysis for this current coal option. 

 A widely used approximation can be used to estimate the cost of the smaller scrubber. 

The fixed capital of a process having one capacity can be scaled from that with another capacity 

by using the "six-tenth rule," named for the exponent, which is typically close to 0.6. The capital 

cost of a process is related to capacity by the equation: 

 Cb = Ca(Sb/Sa)

n

where Cb is the approximate cost ($) of a process or equipment having size Sb and Ca is the 

known cost ($) of a process or equipment having corresponding size Sa. The ratio Sb/Sa is known 

 

13 12/28/09 S&L FollowUp Report, Table 6, Column labeled "Annual Cost." 

14 The per unit SO2 emissions at the inlet of each Muskogee scrubber is 6,440 lb/hr and at each Sooner scrubber it is 

6,020 lb/hr. 12/28/09 S&L FollowUp Report, pdf 76, 78. Thus, the potential SO2 emission reductions, assuming 

91.5% SO2 reduction and a 90% capacity factor: Muskogee: (0.9)(0.915)(6,440 lb/hr)(8,760 hr/yr)/2,000 lb/ton = 

23,229 ton/yr; Sooner: (0.9)(0.915)(6,020 lb/hr)(8,760 hr/yr)/2,000 lb/ton = 21,714 ton/yr. 

15 Total Annual Cost divided by Design Basis Reduction. 

Unit Total 

Annual 

Costs13

($/yr) 

Design 

Basis 

Reduction14

(ton/yr) 

Revised 

Cost 

Effect.15

($/ton) 

 

Sooner 93,664,600 43,428 2,157 

Muskogee 102,600,400 46,458 2,208 
7

as the size factor, which is dimensionless.16 The exponent, n, varies depending upon the type of 

process unit. This equation indicates that a log-log plot of capacity versus equipment cost for a 

given type of equipment should be a straight line with a slope equal to the exponent n. 

 The exponent n is typically 0.8 to 0.9 for processes that use a lot of mechanical work or 

gas compression. For typical petrochemical processes, n is usually about 0.7. For small-scale, 

highly instrumented processes, n is about 0.6.17 The average exponent for a large number of 

different processes is 0.69,18 which I use in my analysis.19 The use of this rule is an 

oversimplification as the actual values of the cost-capacity exponent ranges from less than 0.2 to 

greater than 1.0. I am not aware of any public data specific to dry scrubbers. However, it is 

appropriate here as Sargent & Lundy did not supply any cost data for the smaller scrubber case, 

the extrapolation is less than a 10-fold capacity range, and the scrubbers are similar with regard 

to type of construction, materials of construction, temperature and pressure operating range, and 

other key variables. 

 I based my analysis on the capacity of the scrubber system to remove SO2 in pounds per 

hour calculated from Sargent & Lundy's material balances in the 12/28/09 S&L FollowUp 

Report. This calculation yields a size factor of 0.51.20 In other words, the fixed capital cost of 

the smaller scrubber, that can reduce the SO2 from 0.51 to 0.10 lb/MMBtu, is 51% of the cost of 

the larger scrubber, that can reduce the SO2 from 1.18 to 0.10 lb/MMBtu. The cost effectiveness 

is re-calculated in Table 3, using all of Sargent & Lundy's assumptions, modifying only the 

annual capital. 

 

16 Gael D. Ulrich and Palligarnai T. Vasudevan, Capital Costs Quickly Calculated, Chemical Engineering, April 

2009, pp. 46 - 52; Max S. Peters, Klaus D. Timmerhaus, and Ronald E. West, Plant Design and Economics for 

Chemical Engineers, McGraw-Hill, Inc., 5th Edition, 2003, pp. 242 - 244 and Kenneth K. Humphreys and Paul 

Wellman, Basic Cost Engineering, 3rd Ed., Marcel Dekker, Inc., 1996, pp. 8-20. 

17 Gavin Towler and Ray Sinnott, Chemical Engineering Design: Principles, Practice and Economics of Plant and 

Process Design, 2008, pp. 307-308. 

18 Kenneth K. Humphreys and Paul Wellman, Basic Cost Engineering, 3rd Ed., Marcel Dekker, Inc., 1996, Table 

2.1. 

19 This value is consistent with wet scrubber data summarized in Shoou-Yun Chang and Angel L. Rivera, Theory 

and Evidence of Economies of Scale in the Development of Waste Management Systems, October 1989, Figure 13. 

The slope of the line, n, from Figure 3, for 400 to 600 MW: (88/116) = (400/600)n Thus, n = ln(88/116)/ln(400/600) 

= 0.68. 

20 For Sooner, from 12/28/09 S&L FollowUp Report, pdf 76 - 77, high sulfur case (Option 1), the scrubber inlet SO2 

("ID Fan Outlet") is 6,015 lb/hr and the outlet ("Stack Inlet") is 511 lb/hr. Thus, 6,015 - 511 = 5,504 lb/hr of SO2 is 

removed. For Sooner, low sulfur case (Option 2), the scrubber inlet SO2 is 2,605 lb/hr and the outlet is 513 lb/hr. 

Thus, 2,605 - 513 = 2,092 lb/hr of SO2 is removed. The size factor is: (2,092/5,504)0.69 = 0.51. For Muskogee, 

from 12/28/09 S&L FollowUp Report, pdf 78-79, high sulfur case, the scrubber inlet SO2 ("ID Fan Outlet") is 6,442 

lb/hr and the outlet ("Stack Inlet") is 548 lb/hr. Thus, 6,442 - 548 = 5,894 lb/hr of SO2 is removed. For Muskogee, 

low sulfur case, the scrubber inlet SO2 is 2,778 lb/hr and the outlet is 550 lb/hr. Thus, 2,778 - 550 = 2,228 lb/hr of 

SO2 is removed. The size factor for Muskogee is: (2,228/5,894)0.69 = 0.51.
8

Table 3 

Option 2 

Revised Cost Effectiveness 

Reduction In Scrubber Cost 

(80% SO2 Reduction from 

Scrubber Inlet of 0.509 lb/MMBtu)

Unit Revised 

Annual 

Costs21

($/yr) 

S&L 

Emission 

Reduction22

(ton/yr) 

Revised 

Cost 

Effect.23

($/ton) 

Sooner 63,988,436 13,930 4,594 

Muskogee 70,396,326 13,799 5,102 

 This table indicates that costing a smaller scrubber would reduce the dollar-per-ton cost 

effectiveness at Sooner from $6,747/ton to $4,594/ton and at Muskogee from $7,435/ton to 

$5,102/ton or by about one third. Thus, it is more cost effective to build a larger scrubber and 

burn a higher sulfur coal (Table 2) than to build a smaller scrubber for a lower sulfur coal (Table 

3), all else being held constant. Higher sulfur coal would improve the economics of Option 1. 

The revised cost effectiveness values in Table 3 do not include any of the other revisions I make 

below to align costs with Regional Haze Guidelines and to eliminate double counting and other 

overestimates. These additional revisions would significantly reduce these values. 

 Thus, it would be in the owner's interest to build the larger scrubber based on the higher 

sulfur coal as it is not only more cost effective, but it provides greater flexibility in future 

operations. While this is a good business strategy, it contravenes the BART Guidelines, which 

require that reasonable assumptions be made on control efficiencies as "An unrealistically low 

assessment of the emission reduction potential of a certain technology could result in inflated 

cost-effectiveness figures."24 Cost effectiveness is determined by dividing the cost of the 

designed scrubbed by the emission reductions that that design can achieve, not by emission 

reductions from a much smaller scrubber. Thus, I used the increased emission reductions in 

Table 2 to estimate cost effectiveness for Sooner and Muskogee in Appendix 1. 

 

B. COSTING METHOD 

 In evaluating cost effectiveness, it is important that a consistent set of rules be 

used. Otherwise, one runs the risk of comparing apples with oranges when making the cost 

effectiveness determination. For power plants having a capacity in excess of 750 MW, as here, 

Section 169A(b) of the CAA requires that States follow guidelines promulgated by EPA for 

 

21 Revised Annual Costs for Sooner: ($60,563,600/yr)(0.51) + $33,101,000/yr = $63,988,436/yr. Revised Annual 

Costs for Muskogee: ($65,722,600)(0.51) + $36,877,800/yr = $70,396,326/yr. 

22 12/28/09 S&L FollowUp Report, Table 6. 

23 Revised Annual Cost divided by S&L Emission Reduction. 

24 70 FR 39168 (July 6, 2005). 
9

determining BART.25 The responsive guidelines are contained in Appendix Y to Part 51, 

"Guidelines for BART Determinations Under the Regional Haze Rule." These Guidelines 

include methods to determine both cost and cost effectiveness. For cost analyses, the Guidelines 

stipulate: "In order to maintain and improve consistency, cost estimates should be based on the 

OAQPS Cost Control Manual, where possible."26 

 Sargent & Lundy asserted that they followed these Guidelines "[t]o the extent possible."27 

However, as demonstrated below, they did not follow these Guidelines, but rather followed 

utility industry cost estimating practices such as the levelized cost method, a method developed 

by the Electric Power Research Institute (EPRI) for estimating capital investment and O&M 

costs specific to utilities. These methods are used for internal project justification or other 

accounting purposes but are not appropriate for use in a BART analysis. Sargent & Lundy 

escalated costs to future build dates (BART is based on present dollars); included contingencies 

that are excessive for BART determinations; failed to optimize costs; double counted costs; and 

used inflated factors. Oklahoma did not challenge these estimates and used them as the basis of 

its BART determination. However, the costs that Oklahoma relied on to determine BART are 

overestimated and not comparable to those in other BART determinations. 

 The Cost Manual28 sets out a generic method to estimate the cost of pollution control 

equipment. It also provides specific cost algorithms to estimate capital and O&M costs for some 

types of pollution control equipment. The Cost Manual does not include specific cost algorithms 

for SO2 scrubbers, considered as BART for the OG&E units. Regardless, it is possible to follow 

the generic costing method in the Cost Manual, while relying on vendor quotes and other 

information to estimate scrubber capital and O&M costs. Sargent & Lundy used vendor 

estimates for equipment costs but did not follow the generic costing method. 

 Sargent & Lundy used a costing method that deviates in important ways from the Cost 

Manual. This makes it appear that the cost to control SO2 is higher than at other similar sources. 

However, these apparently higher costs are due in part to the costing method, not to any unique 

circumstances at the units that make retrofit of scrubber unusually costly. The Guidelines 

require that documentation be provided for "any unusual circumstances that exist for the source 

that would lead to cost-effectiveness estimates that would exceed that for recent retrofits."29 No 

unique circumstance is identified in any of the documentation to the BART determinations. 

 These deviations resulted in excessively high scrubber costs compared to estimates in 

other BART analyses and in published cost surveys.30 The cost metric estimated in the Manual 

is real or constant-dollar costs in that the effect of inflation has been removed. Capital cost are 

annualized using a capital recovery factor based on a 7% social rate of interest. In contrast, 

Sargent & Lundy escalated capital costs from the year of estimate, 2010, to the year of 

construction; included various future costs of borrowing money; used an unreasonable 

 

25 See, e.g., 70 FR 39158 (July 6, 2005) ("States must follow the guidelines in making BART determinations on a 

source-by-source basis for 750 megawatt (MW) power plants...") 

26 70 FR 39166 (July 6, 2005). 

27 12/28/09 S&L FollowUp Report, pp. 1 - 2. 
10

contingency; and used an incorrect capital recovery factor. Revising these four factors alone 

significantly lowers annual costs. 

 

1. Capital Cost: Failure To Follow Cost Manual 

 One of the factors that is evaluated in a BART determination is cost effectiveness of the 

control options. Cost effectiveness is determined by comparing annual cost per ton of pollutant 

removed for the source of interest to the range of cost effectiveness values for other similar 

permit decisions. If a given cost effectiveness value falls within the range of costs borne by 

others, it is per se cost effective unless unusual circumstances exist at the source.31 Thus, cost 

effectiveness is a relative determination, based on costs borne by other similar facilities. To 

compare costs among units, a level playing field must be established by following the same cost 

rules in each determination.32 The Sargent & Lundy cost estimating method deviates from the 

standard procedure used to establish the range of acceptable cost effectiveness values. In other 

words, the Sargent & Lundy cost effectiveness analyses compare apples and oranges. 

 28 U.S. EPA, EPA Air Pollution Control Cost Manual, Report EPA/452/B-02-001, 6th Ed., January 2002 ("Cost 

Manual"), p. 2-21. The EPA Air Pollution Control Cost Manual is the current name for what was previously known 

as the OAQPS Control Cost Manual, the name for the Cost Manual in previous (pre-2002) editions of the Cost 

Manual. 

29 70 FR 39168 (July 6, 2005). 

30 Sharp, George, “Update: What’s That Scrubber Going to Cost?”, Power Magazine, March 1, 2009; J. Edward 

Cichanowicz, Current Capital Cost and Cost Effectiveness of Power Plant Emissions Control Technologies, 

Prepared for Utility Air Regulatory Group, June 2007, Section 6, Flue Gas Desulfurization Costs; 3/07 S&L 

National Lime Association Report.

31 70 FR 39168 (July 6, 2005). 

32 See discussion of this issue in Letter from John Bunyak and Sandra V. Silva, Fish & Wildlife Service, to Mary 

Uhl, New Mexico Environmental Department, August 17, 2010, p. 5, footnote 9 ("November 7, 2007, statement 

from EPA Region 8 to the North Dakota Department of Health: "...in order to maintain and improve consistence, 

cost estimates should be based on the OAQPS Cost Control Manual. Therefore, these analyses should be revised to 

adhere to the Cost Manual methodology."), p. 6 (quoting a May 10, 2010 EPA letter to North Dakota Department of 

Health: "These accounting items [owner's cost] are unauthorized under the Cost Control Manual, create an unlevel 

playing field for comparison with other BACT analyses and alone account for an increase in capital costs from the 

Cost Control Manual by a factor of 1.6."). See discussion in: Letter from Andrew M. Gaydosh, Assistant Regional 

Administrator, EPA Region 8, to Terry O'Clair, Director, Division of Air Quality, North Dakota Department of 

Health, Re: EPA's Comments on the North Dakota Department of Health's April 2010 Draft BACT Determination 

for NOx for the Milton R. Young Station, May 10, 2010, pp. 14-16. 
11

 The Sargent & Lundy estimate of capital cost failed to follow the BART Guidelines Cost 

Manual by including: escalation, bond cost, and AFUDC; using an excessive contingency; and 

by annualizing costs using an inflated capital recovery factor. Cost items such as escalation of 

costs, bond cost, and AFUDC are not part of the Cost Manual methodology for estimating costs. 

These items are strictly contingencies, future transfers of monies, and accounting procedures not 

included in cost effectiveness analyses. These types of costs create an unlevel playing field for 

comparison with other BART analyses.33 The impact of these and other factors discussed in this 

report on the cost effectiveness analysis are summarized in Appendix 1. 

 

a. Escalation 

 The Sargent & Lundy cost estimates include escalation of equipment (2.5% for 2010 and 

4% for 2011 - 2014), material (3% for 2011 and 5% for >2012), labor (3% for 2010 and 4% for 

2011-2014), and indirects (3% for 2010 and 4% for 2011-2015) to the year of expenditure.34 The 

Cost Manual approach, recommended by the BART Guidance, explicitly excludes future 

escalation as cost comparisons are made on a current real dollar basis. Inflation is not included 

in cost effectiveness analyses as they rely on the most accurate information available at current 

prices and do not try to extrapolate those prices into the future.35 The assumed wage escalation, 

for example, is much higher than recent reports of 1.3% for union construction workers.36 

Further, escalation is a contingency and is double counted as discussed elsewhere. Escalation of 

costs from past to the current year of analysis is permitted, as costs are compared based on the 

time of estimate, but future escalation is not. Thus, I have set escalation equal to zero in my cost 

analysis in Appendix 1, Line 40. 

 

33 Ibid. 

34 3/28/09 S&L FollowUp Report, Appendix A, Dry FGD Design and Cost Estimate Basis Document, Sec. 8.3.8, 

Escalation Rates, pp. 7-8, pdf 66 - 68. 

35 See, e.g., Cost Manual, p. 2-36, pdf 50. 

36 Ken Simonson, Associated General Contractors of America, Beige Book Finds Construction Still Weak; Wages 

Cool: Hiring Up But Outlook Stays Dim, September 10, 2010. See also: Construction Labor Research Council at 

www.circdata.org ("Wage and benefit settlements for construction union employees so far in 2010 have resulted in 

an average first-year increase of $0.64 or 1.3%.") 
12

b. Allowance for Funds Used During Construction (AFUDC)

 The Sargent & Lundy cost estimates include a charge of 8.66% of total capital expended 

to account for the cost of funding the cash flow during the construction period. AFUDC is an 

accounting method. Assets under construction do not provide service to current customers and 

thus associated interest and allowed return on equity are not charged to current customers. 

Instead, AFUDC capitalizes these costs and adds them to the rate base so that they can be 

recovered from future customers when the assets are used. Thus, these charges represent future 

cash income to the utility. In other words, AFUDC is the accumulated cost of carrying capital 

and holding it waiting to spend, so money can be made in the future, by selling electricity. 

Future income should not be charged against the cost of a scrubber in a BART cost effectiveness 

analysis. 

 These costs are not part of the constant dollar approach found in the EPA Control Cost 

Manual and should not be included in BART cost-effectiveness analyses. The most recently 

issued sections of the Manual, for example, explicitly set AFUDC equal to zero.37 Thus, I have 

set AFUDC equal to zero in my cost analysis in Appendix 1, Line 43. 

c. Bond Costs

 The Sargent & Lundy cost estimates include bond costs estimated as 1% of total project 

cost with escalation and contingency, but without AFUDC.38 The basis and justification for 

these costs is not stated. These costs appear to represent a portion of the cost of financing the 

project and thus are similar to AFUDC. These costs are transfer payments and thus are not valid 

under the constant dollar approach in the Cost Manual and should not be included in BART cost 

effectiveness analyses. Thus, I have set bond cost equal to zero in my cost analysis in Appendix 

1, Line 42. 

d. Contingency

 The Sargent & Lundy capital cost estimates include a contingency of about 14%39 of the 

total project capital cost plus escalation. This value corresponds to the upper 95% confidence 

level, calculated using range estimating techniques.40 The details of how this value was 

calculated are not disclosed. However, it is unprecedented to use range estimating, a financial 

risk management and decision making technique,41 in a cost effectiveness analysis. This use 

inflates the cost of the OG&E scrubbers compared to other estimates that do not use risk 

 

37 Cost Manual, Section 4, Chapter 1, Table 1.4, pdf 424 and Chapter 2, Table 2.5, pdf 486. 

38 12/28/09 S&L Followup Report, Attach A, pdf 41, 56. 

39 12/28/09 S&L FollowUp Report, Appendix A. The contingency for Sooner 1&2 was estimated as 13.97% of total 

project capital plus escalation and for Muskogee 4&5 as 14.085% of total project capital plus escalation. 

40 12/28/09 S&L FollowUp Report, p. 5. 

41 Kenneth K. Humphreys, Project Risk Management - Advantages and Pitfalls, AACE Transactions, 1998, 

Available at: http://www.icoste.org/ICMJ%20Papers/Humphreys-Slovenia.pdf. See also AACE International 

Recommended Practice No. 40R-08, Contingency Estimating - General Principles, Available at: 

http://www.aacei.org/technical/rps/40R-08.pdf. 
13

management to estimate costs. Sargent & Lundy claims their revised cost estimate is accurate to 

within +/-20%.42 However, the need for a 14% contingency would seem to be inconsistent with 

this claim. 

 Thus, while this method may be chosen by a project proponent to forecast final costs at 

an early planning stage, before committing capital, it is not appropriate for determining BART 

cost effectiveness, which must follow the Cost Manual, as the resulting cost will ultimately be 

compared to costs borne by others. The same costing method must be used to assure like is 

compared to like. While BART Guidelines only require the use of the Cost Manual approach "if 

possible", it is certainly possible to follow the standard EPA contingency guidance. 

 A contingency factor in a cost effectiveness analysis "should be reserved (and applied to) 

only those items that could incur a reasonable but unanticipated increase but are not directly 

related to the demolition, fabrication, and installation of the system."43 An example would be a 

hundred year flood that postpones delivery of materials, but their arrival at the job site is not a 

problem unique to the retrofit. The standard contingency factor used in a cost effectiveness 

analysis, when it is included, is 3% of purchased equipment cost.44 Thus, I revised the 

contingency in my analysis to use 3%, shown in Appendix 1, Line 41. 

e. BOP Profits

 The Sargent & Lundy cost analyses include a balance of plant (BOP) contractor's profit 

figured as 10% of balance of plant materials and labor, exclusive of equipment costs. These 

costs amount to $14,817,240 for Sooner and $15,710,910 for Muskogee. Profits are commonly 

embedded in labor rates, supplies and materials. No support or justification for these estimates 

was provided. I did not adjust these costs as inadequate information was supplied to determine 

the basis of balance of plant material and labor. However, the costs are overestimated as they are 

factored from labor costs that are high due to inflated labor productivity and wage rates, 

discussed elsewhere. The BOP profits should be documented and critically evaluated in future 

work. 

f. Capital Recovery Factor

 A capital recovery factor or CRF is used to convert a present value into a stream of equal 

annual payments over a given time at a given interest rate. Under the Cost Manual methodology, 

total capital costs are annualized by calculating an annual payment sufficient to finance the 

investment over its entire life. This payment is calculated by multiplying the total capital 

investment by a capital recovery factor calculated from a formula based on interest rate and 

equipment lifetime.45 The longer the service life and the lower the interest rate, the lower the 

annualized capital costs and the lower the cost effectiveness in $/ton. 

 

42 12/28/09 S&L FollowUp Report, p. 2. 

43 Cost Manual, Chapter 2, Cost Estimation: Concepts and Methodology, Sec. 2.5.4, p. 2-30, pdf 44. 

44 See, for example, Cost Manual, Section 5.2, Post-Combustion Controls, Chapter 1: Wet Scrubbers for Acid Gas, 

Table 1.3 and Section 6, Chapter 1: Baghouses and Filters, Table 1.9. 

45 Cost Manual, p. 2-21, pdf 35. 
14

 Sargent & Lundy did not use the standard capital recovery method as required by the 

Manual, but rather (as mentioned earlier) a levelized annual cost method that included not only 

capital recovery, but also debt return, equity return, and income taxes, transfer payments not 

allowed under the Cost Manual. This method resulted in an annual levelized charge of 10.36%.46 

Thus, total capital costs were annualized by multiplying them by 0.1036. This is equivalent to 

assuming a 20-year life and an interest rate of 8.23% in the capital recovery method. I 

recalculated the capital recovery factor as 0.0806, assuming a scrubber lifetime of 30 years and a 

social interest rate of 7%, for the reasons set out below. My revised CRF is included in 

Appendix 1, Line 45 and the basis for my assumptions are discussed below. 

i. Scrubber Lifetime

 The lifetime used to calculate the capital recovery factor is the actual or service life of the 

equipment, not the depreciable life used by Sargent & Lundy.47 The lifetime is important 

because the shorter the lifetime, the higher the capital recovery factor and the higher the annual 

capital cost used to determine cost effectiveness. I used 30 years compared to 20 years used by 

Sargent & Lundy. Increasing the lifetime from 20 years to 30 years while holding all else 

constant would decrease annual capital costs by about 30% (0.1036/0.0806), a significant 

amount when dealing with capital costs of tens of millions of dollars. 

Scrubber vendors indicate that the lifetime of a scrubber is equal to the lifetime of the 

boiler, which might easily be over 60 years. There are, for example, many scrubbers that were 

installed between 1975 and 1985 that are still in operation today (e.g., Coyote Station, H.L. 

Spurlock Unit 2, East Bend Unit 2, Laramie River Unit 3,48 Cholla 5, Basin Electric, Mitchell 

Unit 33). Standard cost estimating handbooks49 and published papers50 report 30 years as a 

typical life for a scrubber. Further, many utilities routinely specify 30+ year lifetimes in requests 

for proposal and to evaluate proposals. The original Sargent & Lundy cost estimate, for 

example, assumed a 25 year lifetime, which was lowered to 20 years in the revised 2009 analysis 

without comment. The BART determination for Big Stone Unit 1, on-line in 1974, assumed a 30 

years scrubber life. Thus, I used 30 years in my revised cost estimates. 

In response to questions from EPA, Sargent & Lundy justified the 20 years as the 

"estimated remaining depreciable life for Sooner and Muskogee Stations as of 2014/2015 

according to OG&E's depreciation studies of those plants."51 The depreciable life is not used in 

capital recovery calculations, but rather the actual service life. Further, when the lifetime of the 

 

46 12/28/09 S&L FollowUp Report, Table 3 and Appx. B, Table B-5. 

47 12/28/09 S&L FollowUp Report, pdf 9-10. 

48 See, for example, EPRI, A Review of Literature Related to the Use of Spray Dryer Absorber Material: Production, 

Characterization, Utilization Applications, Barriers, and Recommendations, December 6, 2006, Table 1-2. 

49 William M. Vatavuk, Estimating Costs of Air Pollution Control, Lewis Publishers, 1990, p. 198. 

50 J. Warych and M. Szymanowski, Optimum Values of Process Parameters of the “Wet Limestone Flue Gas 

Desulfurization System, Chemical Engineering & Technology, v. 25, 2002, pp. 427-432. 

51 2/8/10 S&L Memorandum, Question 1. 
15

scrubber effects the BART determination, as here, this would require a federally-enforceable 

restriction preventing further operation after a date certain.52 Such a date has not been proposed. 

 ii. Interest Rate

 The interest rate used to calculate the capital recovery factor is the cost of borrowing or 

the social interest rate established by the Office of Management and Budget for comparison of 

public policy issues.53 Sargent & Lundy's cost estimate assumed an interest rate of 8.23% (when 

the effect of debt, equity and taxes are included). It has long been standard practice to use an 

interest rate of 7% in regulatory cost effectiveness analyses, as this is the social cost of 

borrowing for governmental analyses.54 In fact, permit applications that AEP, the owner of 

Northeastern, submitted to the states of Ohio and West Virginia, use the standard interest rate of 

7%.55 Increasing the interest rate to 8.26% from 7% while holding all else constant would 

increase the capital costs by about 13% (0.0911/0.08059), a significant amount when dealing 

with capital costs of tens of millions of dollars. 

g. Construction Costs

 Certain "other costs" required to construct the project, including additional crane rental 

allowance, mobilization/demobilization, scaffolding, temporary facilities, overtime inefficiency, 

per deim expense and BOP contractor's general & administrative costs, are overestimated. Some 

of these overestimates are discussed below. 

 i. Labor Rates

 The FollowUp Report states that labor cost estimates were developed using Oklahoma 

area wage rates.56 However, the labor rates actually used by Sargent & Lundy are excessive for 

an open shop project in Oklahoma and the general region, ranging from about $40 to $80/hr. 

Many public sources demonstrate these are excessive. No support is provided for these out-ofrange rates. 

 

52 70 FR 39169 (July 6, 2005). Where the date that a facility permanently stops operation affects the BART 

determination, "this date should be assured by a federally- or State-enforceable restriction preventing further 

operation.". 

53 Cost Manual, pdf 26; Circular A-4, U.S. Office of Management and Budget, September 2003. Available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/#d. 

54 Cost Manual, pdf 27 and Circular A-4, U.S. Office of Management and Budget, September 2003. Available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/#d. 

55 Application to the West Virginia Department of Environmental Protection for a Permit to Construct, AEP – 

Appalachian Power Company Mountaineer IGCC Facility, September 2006, p. AII-13; Letter from Welch, Dennis 

E., Vice President – Columbus Southern Power Company and Ohio Power Company, subsidiaries of American 

Electric Power to Ponchak, Dean, Ohio EPA, Division of Air Pollution Control, Southeast Division. AEP Great 

Bend IGCC Project – Permit to Install Application, p. 5-11. 

56 12/28/09 S&L FollowUp Report, p. 6. 
16

 The Bureau of Labor Statistics website indicates the second quarter 2010 total cost to 

employer for construction workers is $31.44/hr. This is a national average, including heavily 

unionized California and the northeastern states. Oklahoma is below the average. This same 

website shows the average nonunion wage is $15.25/hr. Construction managers top out the slate 

at $39.36/hr.57 

 The Davis-Bacon58 prevailing wages on federally funded work in Oklahoma for 

carpenters, piledrivers, equipment operators, reinforcing steel, etc. is typically $7-11/hr 

throughout most of the state. The highest wages I found were in Oklahoma County at $35/hr to 

$40/hr (including fringe benefits) for electricians, pipefitters, and sheetmetal workers. Sooner, 

Muskogee, and Northeastern are located in Noble, Muskogee, and Rogers counties, respectively. 

Open shop wages would be less than prevailing wages on federally funded projects. 

 A 2008 wage survey59 summarizes union and nonunion wages by craft within regions. 

This survey, reproduced in Figure 1, shows that the highest wage plus benefits in Region 6 (AR, 

LA, NM, OK, TX) for non-union construction workers is about $25/hr to $27/hr for masons, 

boilermakers, electricians, heavy equipment operators, ironworkers, millwrights, pipefitters, and 

riggers. None of the skilled craft workers in this survey approach the wage rates assumed by 

Sargent & Lundy. Wages have generally fallen since this survey. 

 

57 Bureau of Labor Statistics, Construction: NAICS 23. Available at: 

http://www.bls.gov/iag/tgs/iag23.htm#earnings. 

58 Davis-Bacon Wage Determinations by State, Available at: http://www.gpo.gov/davisbacon/OK.html. See, for 

example, general decisions OK201000023, OK20100024, and OK20100030 for some of the highest wages in the 

counties where the projects are located. 

59 FMI Management Consulting, Craft Worker Compensation Research Report, January 2008, Ex. 36, 41 - 54. 

Available at: 

http://www.agc.org/galleries/laborhr/AGC%20Craft%20Worker%20Compensation%20Research%20Report%20-

%20Final%201-4-08.pdf. 
17

Figure 1 

 The wages used in the Sargent & Lundy analysis are factors of two to three times higher 

than those reported in these sources. The files that I reviewed contain no support for these high 

labor rates. I did not change the labor rates in my revised cost analysis as the parties declined to 

supply the electronic spreadsheets with embedded calculations, which would have facilitated 

such a change. Further, the specific craft that is required for the various tasks is not indicated, 

but rather only crew names. In addition to the very high wage starting point, Sargent & Lundy 

boosted the cost of labor even more by using high labor escalation rates and adding additional 

charges in the "other cost" portion of its cost spreadsheets. These are discussed below. 

 ii. Per Deim Expense

 The FollowUp Report states that per diem is included in the wage.60 However, the cost 

spreadsheet in Attachment A include certain "other costs", which include a per diem expense of 

$10/hr that is added to the already high labor rates for every single hour (1,790,700 hrs for 

Sooner and 1,854,271 hrs for Muskogee) required to build the project. This is excessive for the 

Oklahoma market where current per deim rates are about $50/day to $70/day. As the costs are 

based on six 10 hour days, this amounts of $100 per day for per diem, or about $18 million for 

each plant. 

 Further, as per diem pays for living expenses, this implies that 100% of the workforce 

will be drawn from outside of the area. This is not believable, particularly in the current job 

market. Finally, per diem is not being paid for open shop jobs in today's soft labor market. 

Thus, additionally adding per diem, on top of the high wage rates used to calculate direct labor is 

 

60 12/28/09 S&L FollowUp Report, p. 13. 
18

double counting. Per diem should either not be paid at all or only be paid for a portion of the 

labor force, as some of the construction workers will be drawn from the surrounding areas. This 

factor was not adjusted in my revised cost analysis as the record contains no basis for the 

assumed labor rate. 

 iii. Labor Productivity

 Sargent & Lundy increased the estimate of manhours to install equipment by 15% to 

account for "productivity," such factors as inability to attract labor, weather conditions, etc.61 

This is unprecedented in a cost effectiveness analysis and is another form of contingency, 

specifically disallowed by the Cost Manual, as discussed above. It also is double counting as a 

general contingency is included elsewhere in the cost analysis. It is unlikely that there would be 

any trouble attracting labor in the current and reasonably foreseeable labor market. Further, the 

Sargent & Lundy Design and Cost Estimate Basis Document in the 12/28/09 S&L FollowUp 

Report states that "no allowances have been made to cover items such as the loss in 

productivity..."62 Thus, I adjusted the cost to use unadjusted manhours. 

 For Sooner, the difference between total productivity-adjusted manhours (1,647,446 hrs) 

and actual manhours (1,432,562 hrs) is 214,884 hours. The value of these hours is $14,276,530, 

based on Sargent & Lundy's calculations.63 For Muskogee, the difference between total 

productivity-adjusted manhours (1,705,929 hrs) and actual manhours (1,483,417 hrs) is 222,512 

hours. The value of these hours at Muskogee is $14,918,100, based on Sargent & Lundy's 

calculations.64 Thus, I subtracted the 15% productivity contingency from the estimated capital 

costs in Appendix 1, Line 23. 

 iv. Overtime Inefficiency

 The Sargent & Lundy cost analyses contain another contingency in the "other costs" 

portion of its spreadsheets, called "cost due to overtime inefficiency working 5x10s."65 This is 

another form of contingency, specifically disallowed by the Cost Manual, as discussed above. It 

also double counts, as a general contingency is included elsewhere in the cost analysis. The new 

scrubbers would be installed during normal maintenance outages by working five 10 hour days. 

Efficient scheduling of the labor pool should not result in an overtime inefficiency. The 

12/28/09 S&L FollowUp Report contains no support for overtime inefficiency. Thus, I have set 

overtime inefficiency equal to 0 in Appendix 1, Line 28. 

 

61 12/28/09 S&L FollowUp Report, Attach. A, pdf 28 - 56. 

62 12/28/09 S&L FollowUp Report, Attach. A, pdf 66. 

63 12/28/09 S&L FollowUp Report, Attach. A. For Sooner, calculated from the electronic spreadsheet, line 585 as 

$109,453,400 - $109,453,400 /1.15 = $14,276,530. 

64 12/28/09 S&L FollowUp Report, Attach. A. For Muskogee, calculated from the electronic spreadsheet, line 611 

as $114,372,100 - $114,372,100 /1.15 = $14,918,100. 

65 12/28/09 S&L FollowUp Report, Attach. A, pdf 40, 55. 
19

2. Cost: Double Counting 

 In addition to failing to follow the standard cost estimating protocol required by the 

Guidelines, Sargent & Lundy also double counted some costs and overestimated other due to 

erroneous assumptions. Further, as many components of Sargent & Lundy's cost estimates are 

factored from other costs, such as total direct costs, reductions in items included in these sums 

lead to reductions in the factored costs. These various issues are discussed below for capital 

costs. 

a. Owner's Cost

 The Sargent & Lundy cost analyses include owner's costs as a separate indirect capital 

cost, estimated as 5% of total capital expended. These costs have been estimated by Sargent & 

Lundy as 2% of total capital expended in other BART analyses.66 These are reportedly costs 

incurred by the owner in managing and implementing a capital project. They include staff for 

site coordination during construction, equipment receiving, contract management, interface with 

regulatory agencies, owner engineering costs, warehousing, normal overhead of a corporation, 

and accounting support.67 

 While owners do incur some costs, they have been double counted and overestimated 

here. Owners generally do not manage and implement capital projects, but rather retain 

engineering firms, called the owner's engineer, to perform these functions. The costs that owners 

incur are included under "indirect capital cost," which also includes engineering/procurement 

estimated at 6.5% of total direct costs and construction management, estimated as 2% of total 

direct costs. These costs are high compared to costs that result when using the Cost Manual 

(both engineering and construction/field expenses are estimated as 10% of purchased equipment 

costs). Owner's cost is part of the factored estimate for engineering, procurement, and 

construction management. Owner's costs are not separately included in BART cost effectiveness 

analyses and have been more than double counted here. In its May 10, 2010 formal comments to 

the North Dakota Department of Health, for example, EPA rejected the inclusion of "owner's 

costs" in a cost analysis for the Milton R. Young facility.68 Thus, I set owner's cost equal to zero 

in Appendix 1, Line 38. 

b. Engineering/Procurement

 The Cost Manual estimates engineering and procurement as 10% of the purchased 

equipment cost. Sargent & Lundy estimated engineering and procurement, an "indirect capital 

cost", as 6.5% of the total direct costs. As can be seen from examining Appendix 1, direct costs 

 

66 See, e.g., Sargent & Lundy, Dry FGD and ID Fan & Auxiliary Power Conceptual Design Costs, Conceptual Cost 

Estimate, Prepared for Nebraska Public Power District, Gerald Gentleman Station, Units 1&2, February 7, 2008. 

67 12/28/09 S&L FollowUp Report, pdf 40, 56, 66, 67. 

68 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O'Clair, Director, 

Division of Air Quality, North Dakota Department of Health, Re: EPA's Comments on the North Dakota 

Department of Health's April 2010 Draft BACT Determination for NOx for the Milton R. Young Station, May 10, 

2010. 
20

include much more than just the purchased equipment costs. The Sargent & Lundy 

engineering/procurement costs are $21,144,700 for Sooner and $21,784,400 for Muskogee.69 

These values are very high compared to estimates using the Cost Manual approach of 10% of 

purchased equipment cost. The Cost Manual estimates are one-third of the Sargent & Lundy 

estimates, or $7,050,000 for Sooner and $7,120,000 for Muskogee.70

 A portion of the Sargent & Lundy engineering/procurement costs is double counted. The 

vendor proposals that Sargent & Lundy relied on include the cost to both design and supply the 

dry scrubber and baghouse. This is common, and costs are typically reported on an all-in basis. 

Thus, because Sargent & Lundy also separately calculated engineering/procurement, the 

engineering and procurement costs for the vendor-supplied portion of the capital costs are double 

counted. The 6.5% factor should only apply to the balance of plant materials and labor, which 

exclude the scrubber system, fabric filter, and the scrubber contractor's scope for the ash 

recycling system. 

 The engineering and procurement costs, based only on the balance of plant equipment, 

material and labor costs as revised in Appendix 1, Line 34, are $8,371,56371 for Sooner and 

$8,840,09072 for Muskogee, or less than half of the Sargent & Lundy estimate. This change 

reduces the engineering and procurement costs by $12,773,100 at Sooner73 and by $12,944,277

at Muskogee.74 These values are still high compared to estimates based on the Cost Manual 

method of 10% of purchased equipment cost. 

c. Construction Management

 The balance of plant (BOP) construction management costs were double counted. They 

occur in two places. Under "total indirect costs", Sargent & Lundy estimated construction 

management as 2% of the total direct costs, which include both vendor and balance of plant 

costs. Elsewhere, under "other costs", Sargent & Lundy estimated the balance of plant 

contractor's general and administrative costs, a subset of construction management, as 5% of 

balance of plant materials and labor costs. This double counts the balance of plant contractor's 

general and administrative costs and is removed in my cost analysis, Appendix 1, Line 29, by 

 

69 12/28/09 S&L FollowUp Report, pdf 40, 56. 

70 Purchased equipment cost for Sooner reported in 12/28/09 S&L FollowUp Report, pdf 94. Comparable data was 

not reported for Muskogee. Muskogee purchased equipment cost assumed to be about 3% higher based on vendor 

quotes. 

71 Revised Engineering/Procurement Cost Sooner: (0.065)[(273,104,770 - 86,859,600-46,335,000-11,116,900)] = 

$8,371,563. 

72 Revised Engineering/Procurement Cost Muskogee: (0.065)[(280,718,380 - 86,741,200-45,872,900-12,102,900)] = 

$8,840,090. 

73 Reduction in Engineering/Procurement Cost Sooner, Appendix 1, Line 34: (0.065)[(273,104,770 - 86,859,600-

46,335,000-11,116,900)] - 0.065(325,302,500) = -$12,773,100. 

74 Reduction in Engineering/Procurement Cost Muskogee, Appendix 1, Line 34: (0.065)[(280,718,380 - 86,741,200-

45,872,900-12,102,900)] - 0.065(335,144,100) = -$12,944,277. 
21

subtracting the values assumed in Sargent & Lundy's analysis for "BOP contractor's general & 

admin".75 

 The Sargent & Lundy construction management costs are factored from total direct costs, 

calculated as 2% of total direct costs, or $6,506,100 at Sooner and $6,702,900 at Muskogee. As 

my revisions lower total direct costs, other items factored from total direct costs must be 

adjusted. Thus, I revised construction management costs in Appendix 1, Line 35, to account for 

other revisions I made to total direct costs. These revised fees, $5,462,095 at Sooner76 and 

$5,685,568 at Muskogee,77 were estimated as 2% of revised total direct costs. This reduces the 

construction management costs in Appendix 1, Line 35, by $1,043,955 at Sooner78 and by 

$1,017,314 at Muskogee.79 

d. Startup & Commissioning Craft Support

 Sargent & Lundy estimated startup and commissioning craft support, an indirect cost, as 

2% of an unidentified capital sum about 8% less than the vendor portion of equipment, materials 

and labor costs (e.g., $163,695,000 for Sooner). These costs amounted to $3,273,900 for Sooner 

and $3,417,600 for Muskogee.80 However, the vendor proposals that Sargent & Lundy relied on 

include the cost to commission the units. Thus, these costs are double counted and are 

eliminated in Appendix 1, Line 36. 

e. Operator Training & Manuals

 Sargent & Lundy estimated operator training and manuals, an indirect cost, as 0.55% of 

the total construction & erection cost portion of total equipment, material and labor, or 

$163,695,000 for Sooner and $170,881,000 for Muskogee. These costs amounted to $900,300

for Sooner and $939,800 for Muskogee.81 However, the vendor proposals that Sargent & Lundy 

relied on include these costs. Thus, these costs are double counted and are eliminated in 

Appendix 1, Line 37. 

f. Other Factored Sums

 There are other items that are factored from various unidentified sums, including 

additional crane rental allowance, mobilization/demobilization, scaffolding, temporary facilities 

and construction utilities, consumables, BOP contractor's profit, and freight to site.82 The 

 

75 12/28/09 S&L FollowUp Report, pdf 40 (Sooner) and pdf 55 (Muskogee). 

76 Revised Construction Management at Sooner: (0.02)(273,104,770) = $5,462,095. 

77 Revised Construction Management at Muskogee: (0.02)(280,718,380) = $5,614,368. 

78 Reduction in Construction Management Costs at Sooner: (0.02)[273,104,770 - 325,302,500] = -$1,043,955. 

79 Reduction in Construction Management Costs at Muskogee: (0.02)[280,718,380 - 335,144,100] = -$1,088,514. 

80 12/28/09 S&L FollowUp Report, pdf 40, 56. 

81 12/28/09 S&L FollowUp Report, pdf 40, 56. 

82 12/28/09 S&L FollowUp Report, Attach. A. 
22

underlying sums are not available as Sargent & Lundy did not provide an electronic copy of the 

Excel cost spreadsheets that contained the formulas. Thus, the origin of the underlying sums, 

necessary to modify them, can only be determined through trial and error, which is beyond the 

scope of my work. However, it is likely that all of these factored items would decline, further 

reducing the dollar-per-ton cost effectiveness analyses. 

g. Initial Fabric Filter Replacement Materials

 The spray chamber (i.e., scrubber absorber) is followed by a fabric filter baghouse to 

remove fly ash and scrubber solids. A fabric filter baghouse is a multi-compartment enclosure, 

each containing up to several thousand long (10-26 feet), vertically supported, small diameter (5-

6 inches) fabric bags supported internally from a metal wire cage to prevent bag collapse. 

Particulate-laden gases pass through the bags, depositing 99.9%+ of the entrained solids on the 

bags. Thus, the bags and their cages must be periodically changed out, every 2 to 3 years. 

 The Sargent & Lundy cost estimates include charges for replacing the bags and cages 

every 3 years as an operating and maintenance (O&M) expense.83 The annual cost of 

replacement parts is estimated the same way as the annual cost of capital, by multiplying the 

current cost of replacing all of the bags/cages by a capital recovery factor based on the life of the 

bags and the social interest rate of borrowing. As the bags and cages are part of the baghouse 

and must be in place when the units start operating, the vendor's cost estimate for the baghouse 

includes the cost of these replacement parts. However, this same cost is included in the first 

year's annualized replacement costs. Thus, it is double counted. The annualized cost of the 

baghouse should be reported net of the cost of replacement materials needed at the beginning of 

operations to prevent this double counting.84 I did not make this change due to the complexity of 

revising costs without the original electronic spreadsheets. However, in future cost estimates, the 

cost of the baghouse should be reported net the annualized cost of bag/cage replacement. 

3. Capital Cost: Overestimating 

 Capital projects should be designed to minimize capital and construction costs. The 

company estimates made no apparent effort to minimize costs and overlooked many obvious 

opportunities to lower costs, including factoring in capital cost reductions due to multiple 

identical units, use of common facilities, use of existing equipment, and consideration of other 

scrubbing options. If the scrubbers were designed to minimize capital costs, the general design 

would be different and the cost of materials and labor much less. These types of issues are 

explicitly recognized in one of the vendor proposals that Sargent & Lundy relied on. 

a. Multiple Unit Discounts

 The vendor costs relied on by Sargent & Lundy were estimated on a per generating unit 

basis and doubled for the plant. However, considerable savings could be achieved in capital 

 

83 12/28/09 S&L FollowUp Report, Attach. B. 

84 Cost Manual, pdf 47. 
23

costs and labor by designing and constructing both units in one fell swoop. This section 

discusses multiple unit discounts and the next section discusses combined facilities. 

 The six units consist of nearly identical pulverized coal fired boilers installed around the 

same time that burn similar low sulfur PRB coal, as summarized in Table 4. 

Table 4 

Oklahoma BART-Eligible 

Coal-Fired Electric Generating Units 

Unit Install 

Date 

Capacity 

MWg 

Firing 

Rate 

(MMBtu/hr) 

Firing 

Mode 

Baseline 

Coal S 

(lb/MMBtu) 

Muskogee 4 1978 572 5480 Tang 0.51 

Muskogee 5 1979 572 5480 Tang 0.51 

Sooner 1 1979 570 5116 Tang 0.51 

Sooner 2 1980 570 5116 Tang 0.51 

Northeastern 3 1979 490 4775 Tang 0.91 

Northeastern 4 1980 490 4775 Tang 0.91 

 There are many economies involved in designing, procuring, and installing all four 

identical OG&E units from the same vendor. The scrubbing systems installed on the four OG&E 

units would be identical. Thus, only one system must be designed, which could be replicated for 

the other three, reducing engineering and shop setup time. Thus, vendors typically offer 

discounts for awards of multiples of the same system. 

 I cannot precisely estimate the reduction in cost from taking into account multiple units 

because Sargent & Lundy did not supply the required information. However, based on my 

experience, vendors would offer at least a 5% discount on equipment cost for multiple identical 

units. This reduction is included in Appendix 1, Line 24. 

b. Common Facilities

 Capital and labor costs also could be reduced by combining processing units, e.g., a 

single lime preparation system, a single ash handling system, a single fabric filter. Installing two 

separate units essentially doubles the balance of plant labor and increases capital costs. Common 

facilities should have been designed and costed. 

 I cannot precisely estimate the reduction in cost from taking into account common 

facility issues because Sargent & Lundy did not supply the required information. Optimizing the 

design to use single systems serving Sooner and Muskogee instead of doubling the design of a 

single unit would reduce equipment, material, and labor costs by about 5% compared to the 

current design. This reduction is included in Appendix 1, Line 25. 

c. Cost Capacity

 The per unit cost of a given piece of equipment drops as the capacity increases. This 

relationship, known as the "six-tenth-factor rule," results in lower capital costs for larger pieces 
24

of equipment. See Section III.A.2. The company's cost estimates were based on per unit costs 

and doubled for each plant. This overestimates costs by basing them on unit costs for smaller 

equipment. For example, one large compressor would be cheaper than two smaller ones with the 

same output. The reduction in costs for this factor is included in the vendor discount adjustment 

in Appendix 1, Line 24. 

d. Other Cost Options 

 There are more economical options for designing and integrating the scrubbers into the 

plant that were not explored. These include using the existing electrostatic precipitators instead 

of installing new baghouses and using a one-pass scrubber rather than the more expensive 

recycle system. The reductions in cost due to the use of these options are not included in my 

revised cost analyses as there is inadequate basis. 

 

 i. Recycle Scrubber

 In dry scrubbing, flue gases enter a spray chamber or absorber where a reagent is sprayed 

into the gas stream and reacts with SO2. An electrostatic precipitator or fabric filter baghouse 

typically follows the spray chamber to collect the reagent, flyash, and reaction products. Lime is 

the primary reagent used in these systems and is proposed here. Dry scrubbing systems that use 

only lime as the reagent are known as "single pass systems." Some of the lime does not react 

with SO2 after a single pass through the spray chamber. This unreacted lime and other high 

alkalinity solids from burning low sulfur PRB coal are collected in a dust collection device and 

can be recycled to the spray chamber to reduce lime demand. In a recycle system, these solids 

are collected, mixed with water, and reinjected into the spray chamber. This type of dry scrubber 

is referred to as a "recycle system."85 The dry scrubbers that were evaluated for Sooner and 

Muskogee are recycle systems. 

 Recycle systems generally have higher capital costs and are more expensive to operate 

than single pass systems, due to the extra equipment required to recycle the solids and more 

power and water required to operate the recycle system. The capital cost of the recycle system is 

high, amounting to about 6-10% of the purchased equipment costs. Springerville Unit 3 (454 

MW), which burns a similar low sulfur PRB coal, found that O&M costs with recycle operations 

are greater than the additional lime and disposal costs without recycle. The Springerville dry 

scrubber was designed to achieve SO2 removal efficiencies as high as 93.3% without the use of 

recycle.86 Other vendors have noted the same in BART analyses.87 A single pass option was not 

evaluated for Sooner or Muskogee and should be. 

 

85 Babcock & Wilcox, Steam Its Generation and Use, 2005, pp. 35-12 to 35-18. 

86 Phil Rader and Caio Botelho, FGD Technologies Achieving SO2 Compliance at the Lowest Lifecycle Cost, 

Power-Gen Latin America 2003, November 11-13, 2003, p. 5. 

87 Colorado Air Pollution Control Division, Best Available Retrofit Technology (BART) Analysis of Control 

Options for Colorado Springs Utilities -- Drake Plant, ("The March 2007 submittal also incorporates budgetary 

quotes from vendors for the major pieces of equipment as well as noting the need for a non-recycling LSD due to the 

ash removal system's operation at a very high capacity factor. As depicted in Figure 3, a non-recycling LSD would 

eliminate slurry solids; instead the FGD solids (removed in the baghouse) are immediately disposed.") 
25

 ii. Electrostatic Precipitator (ESP)

 As noted above, a dry scrubbing system consists of a spray chamber followed by a dust 

collection device. These two devices together are referred to as a dry scrubber or dry flue gas 

desulfurization unit (DFGD). The costs for the Sooner and Muskogee dry scrubbers include a 

new fabric filter baghouse at each unit. This baghouse accounts for about one-third of the 

purchased equipment cost.88 However, all of the BART-subject, coal-fired units are currently 

equipped with electrostatic precipitators, a dust collection device that could be used instead of 

the new baghouse. The costs for a new baghouse, when an acceptable dust control device is 

already present, could make a significant difference in an incremental cost comparison with a 

wet scrubber, which does not require a downstream baghouse. 

 Existing electrostatic precipitators are strong candidates for dust collection in retrofit 

applications. While extra collecting surface may be needed in some cases, they generally do not 

require any upgrade as the resistivity of the dust is drastically reduced during dry scrubbing, 

improving collection efficiency.89 The only extra cost would be duct work to tie in the spray 

chamber. The plot plans in the S&L Followup Report suggest no retrofit issues for this option at 

Sooner or Muskogee. No plot plans were provided for Northeastern. The cost to use the existing 

electrostatic precipitators to remove particulate would likely be much less than the cost of new 

baghouses. This option was not considered but should have been.90 

 This option was evaluated for Naughton Units 1 and 2 in Wyoming. The results are 

summarized in Table 5, extracted from Wyoming's BART analysis. This table shows that the 

use of the existing electrostatic precipitator, instead of adding a new fabric filter baghouse, 

reduces the cost effectiveness by $734/ton and that the cost effectiveness of dry and wet 

scrubbing are the same when a new baghouse is not included in the cost of the dry scrubber. A 

wet scrubber was selected as BART for Naughton 1 using the existing ESP. 

Table 5 

Naughton BART Analysis91

 

88 12/28/09 S&L Followup Report, Attach. 5, Summary of DFGD Vendor Quotations, of Attach. A. 

89 Stefan Ahman, Charles B. Barranger, and Peter G. Maurin, Alstom Power's Flash Dryer Absorber For Flue Gas 

Desulfurization, Proceedings of 2002 International Joint Power Generation Conference, June 24-26, 2002. 

90 See 12/4/09 USFWS Comments, Attachment, pp. 3, 6. 

91 Wyoming Department of Environmental Quality, BART Application Analysis, May 28, 2009, Table 20. 
26

 The BART determination must consider "any pollution control equipment in use or in 

existence at the source..."92 The EPA explained in its BART Guidelines that "it is important to 

include control options that involve improvements to existing controls and not to limit the 

control options only to those measures that involve a complete replacement of control devices."93 

 iii. Fabric Filter Baghouse

 The baghouse was designed to achieve a filterable particulate emission rate of 0.010 

lb/MMBtu. However, the targeted BART filterable emission limit is 0.10 lb/MMBtu, or ten 

times higher, met with the existing electrostatic precipitators. Thus, the baghouse included in 

the OG&E dry scrubber costs is over designed for its function in the dry scrubber. Baghouse 

removal efficiency increases in direct proportion to gas filtration velocity and bag cleaning 

method.94 Thus, a baghouse designed to remove ten times more particulate than required to 

support the scrubber is significantly more expensive than a baghouse designed to meet the BART 

limit. I have not modified the baghouse cost due to inadequate information in the documents I 

reviewed. This issue should be addressed in future work. 

 

92 OK Regional Haze SIP, p. 75; 70 FR 39157 (July 6, 2005) ("In identifying a level of control as BART, States are 

required by section 169A(g) of the CAA to consider:...(c) Any existing pollution control technology in use at the 

source..."; CAA Section 169A(g) ("States must identify the best system of continuous emission control technology 

for each source subject to BART taking into account the technology available, the costs of compliance, the energy 

and non-air quality environmental impacts of compliance, any pollution control equipment in use at the source...") 

93 70 FR 39164 (July 6, 2005). 

94 Mario G. Cora and Yung-Tse Hung, Controlling Industrial Particulate Emissions: A Practical Overview of 

Baghouse Technology, Environmental Quality Management, Summer 2002, pp. 53 - 64; Kenneth E. Noll, 

Fundamentals of Air Quality Systems: Design of Air Pollution Control Devices, American Academy of 

Environmental Engineers, 1999, Chapter 6: Fabric Filters. 
27

4. Operating and Maintenance Costs (O&M) 

 Operating and maintenance (O&M) costs comprise the sum of variable O&M, fixed 

O&M, and indirect O&M. The Sargent & Lundy O&M cost estimates require adjustment of 

both variable and indirect O&M costs. 

a. Variable O&M Costs

 Variable O&M costs are those that vary in proportion to the amount of SO2 that is 

removed. The Sargent & Lundy variable O&M costs were estimated from material mass 

balances in Attachment 1 to the Basis Document.95 The Basis Document contains mass balances 

for two cases: (1) reducing SO2 from 1.176 lb/MMBtu to 0.10 lb/MMBtu (91% SO2 control or 

Option 1) and (2) reducing SO2 from 0.509 lb/MMBtu to 0.100 lb/MMBtu (80% SO2 control or 

Option 2). 

 The Sargent & Lundy variable O&M costs and emission reductions were based on 

Option 2, the lowest performance option, while the scrubber sizing and capital costs were based 

on Option 1, the highest performance option. This mismatch error results in underestimating 

emission reductions and fixed O&M costs and overestimating capital costs. The net effect of 

correcting these errors is to significantly decrease the cost per ton of SO2 removed, improving 

the cost effectiveness of the dry scrubber. The Sargent & Lundy variable O&M costs also 

contain other errors, which cancel some of the O&M cost underestimate. Each component of 

variable O&M cost that I adjusted to address these issues is discussed below and shown in blue 

highlighting in Appendix 1. 

 i. Lime Cost

 Sargent & Lundy estimated lime cost based on lime feed rates (stream 1) from the 

"average sulfur case" mass balance ("80% SO2 control case" or Option 2) and delivered lime 

costs based on budgetary quotations.96 There are two problems with this estimate. 

 First, Sargent & Lundy estimated the amount of lime that would be required to operate a 

scrubber designed to remove 80% of the SO2 from 0.51 lb/MMBtu coal (80% control case) 

while the capital costs were based on a scrubber designed to remove 91% of the SO2 from a 1.18 

lb/MMBtu coal (91% control case). As a result, Sargent & Lundy underestimated the amount of 

lime that would be required to operate the scrubbers that were costed. 

 Second, Sargent & Lundy overestimated the amount of lime required for the 80% SO2 

case that was costed. It estimated that 2.0 ton/hr of lime would be required at Sooner and 2.1 

ton/hr at Muskogee, based on 90% capacity. This corresponds to an unrealistically high 

stoichiometric ratio. For a dry scrubber, the amount of lime required to remove a specific 

amount of SO2 is expressed as the ratio of moles of calcium in the lime to moles of sulfur at the 

 

95 12/28/09 S&L FollowUp Report, Attach. A, Dry FGD Design and Cost Estimate Basis Document, Attach. 1, 

Mass Balance Diagrams for Sooner Station and Muskogee Station. 

96 2/8/10 Memo from Snell and Wroble to Benham, Q10; 12/28/09 S&L FollowUp Report, p. 9 (pdf 11). 
28

inlet to the scrubber. The rule of thumb for this ratio is 1.2 for a retrofit dry scrubber burning 

low sulfur Powder River Basin coal, as here. Sargent & Lundy used this value to estimate lime 

demand in a study of scrubber technology for the National Lime Association.97 However, in the 

mass balances for Sooner and Muskogee, Sargent & Lundy used a lime stoichiometric ratio of 

1.5.98 

 The net effect of these two items is an underestimate in lime costs. Sargent & Lundy 

estimated that each Sooner unit would require 2.0 ton/hr of lime and each Muskogee unit would 

require 2.1 ton/hr of lime for the 80% SO2 control case (Option 2).99 The design basis for the 

91% control case is 4.45 ton/hr at each Sooner unit and 4.77 ton/yr at each Muskogee unit. As 

the 91% control case (Option 1) is the basis of the cost analysis, it should be used to estimate 

lime costs. 

 I revised the lime cost using the Option 1 lime feed rates. This increases the lime costs at 

each Sooner unit from $1,826,900 to $4,167,955/yr100 or by $4,682,111/yr for the total plant. It 

increases the lime costs at Muskogee from $1,730,600/yr to $3,968,632/yr101 or by 4,476,064/yr. 

The resulting increase in lime cost is added to my revised cost estimate in Appendix 1, Line 51. 

 ii. Water Cost

 The Sargent & Lundy cost estimates for water use are based on the total water demand 

(stream 13) 102 for the 80% SO2 control option (Option 2) and the cost of water per 1,000 gallons 

as estimated by OG&E.103 These costs assume that the Sooner scrubber would require 410 gpm 

and the Muskogee scrubber would require 439 gpm.104 This works out to 5.3 gallons of water 

for every MMBtu of heat input (5.3 gal/MMBtu).105 This is beyond the upper end of the range of 

 

97 Sargent & Lundy, Flue Gas Desulfurization Technology Evaluation: Dry Lime vs. Wet Limestone FGD, March 

2007 ("3/07 S&L National Lime Association Report"), Table 5.1-1. 

98 Sargent & Lundy stoichiometric ratio (based on Sooner): moles/hr of S at scrubber inlet = [(2,605 lb SO2/hr)(32 

lb S/mol/64 lb SO2/mol)]/32 lb S/mol = 40.7 mol S/hr; moles/hr of Ca in lime = (3,511 lb CaO/hr)(40 lb Ca/mol/56 

lb CaO/mol)]/40 lb Ca/mol = 62.7 mol Ca/hr. Stoichiometric ratio = 62.7/40/7 = 1.54 mol Ca/mol S. Calculations 

based on SO2 and CaO as reported in 12/28/09 S&L FollowUp Report, pdf 77 and used in fixed O&M calculations 

at pdf 101. 

99 12/28/09 S&L FollowUp Report, pdf 76-79. 

100 Revised Sooner per unit lime costs: (4.45 ton/hr)($118.8/ton)(8,760 hr/yr)(0.9) = $4,167,955/yr. 

101 Revised Muskogee per unit lime costs: (4.77 ton/hr)($105.53/ton)(8,760 hr/yr)(0.9) = $3,968,632/yr. 

102 Sum of slaker water, recycle water, and pin mixer water. 

103 12/28/09 S&L FollowUp Report, p. 9 (pdf 11) and pdf 101-104. The Muskogee water cost includes the cost of 

purchasing water, while Sooner has no water purchase costs. 

104 Compare 12/28/10 S&L FollowUp Report, pdf 77 (410 gpm) & 79 (439 gpm) with the gpm backcalculated from 

the water costs for Muskogee at pdf 101-102 ($534,100/yr/[($2.57/1000 gal)(8760 hr/yr)(60 min/hr)(0.9)] = 439 

gpm) and for Sooner at pdf 103-104 ($95,100/yr/[($0.49/1000 gal)(8760 hr/hr)(60 min/hr)(0.9)] = 410 gpm. 

105 Sooner unit water use = (410 gal/min)(60 min/hr)/(5116 MMBtu/hr)(0.9) = 5.34 gal/MMBtu. 
29

3.6 to 4.4 gal/MMBtu for other similar dry scrubbers.106 The vendor design was based on an 

average makeup demand within the usual reported range for other similar scrubbers. 

 Using the vendor water demand decreases the per unit cost of water at Sooner from 

$95,100/yr to $85,299/yr or by $9,801/yr. At Muskogee, this adjustment decreases the per unit 

annual cost of water from $534,100/yr107 to $443,735/yr108 or by $90,365$/yr. The decrease in 

water cost is added to my revised cost estimate in Appendix 1, Line 52. The accuracy of the unit 

water cost cannot be evaluated as the basis is not stated in the documents that I have reviewed. 

 iii. FGD Waste Disposal Cost

 The Sargent & Lundy cost estimates for FGD waste disposal are based on solids to 

landfill (stream 12) for the 80% SO2 control option and the unit cost to landfill the solids.109 

These costs assume that the Sooner scrubber would generate 11,105 lb/hr and the Muskogee 

scrubber would generate 11,839 lb/hr of FGD solids for landfilling.110 There are three problems 

with this estimate. 

 First, the amount of solids produced by the scrubber is underestimated as it is based on 

the 80% SO2 control case, rather than the case that was costed. The 91% SO2 control case 

(Option 1) indicates that 26,283 lb/hr would be generated at Sooner and 28,153 lb/hr at 

Muskogee, or about 13.6 ton/hr per unit. 

 Using Sargent & Lundy's unit cost to landfill and the 91% SO2 control case, the per unit 

cost of landfilling FGD wastes at Sooner increases from $1,733,500/yr to $4,102,860/yr111 or by 

$2,369,360/yr. At Muskogee, this adjustment increases the per unit cost from $1,849,300/yr to 

$4,504,643/yr112 or by $2,655,343/yr. The increase in landfill cost is added to my revised cost 

estimate in Appendix 1, Line 53. 

 

106 E-mail from Michael Meadows, Black & Veatch, January 30, 2007; Babcock & Wilcox, Steam, Its Generation 

and Use, 2005, p. 35-17, Table 8 (total water demand = 48+269 = 317 gpm for a 500 MW net unit which would 

have a heat rate of about 4,800 MMBtu/hr. Thus, unit water demand (317 gpm)(60 min/hr)/(4,800) MMBtu/hr)(0.9) 

= 4.4 gal/MMBtu). 

107 12/28/10 S&L FollowUp Report, pdf 101-102. 

108 Revised Sooner per unit water cost: (368 gpm)(60 min/hr)(8,760 hr/yr)(0.9)($0.49/1000 gal) = $85,299/yr. 

Revised Muskogee per unit water cost: (365 gpm)(60 min/hr)(8,760 hr/yr)(0.9)($2.57/1000 gal) = $443,735/yr. 

109 12/28/09 S&L FollowUp Report, p. 9 (pdf 11) and pdf 101-104. 

110 Compare 12/28/09 S&L FollowUp Report, pdf 77 (11,105 lb/hr) & 79 (11,839) with the lb/hr of landfilled solids 

backcalculated from the FGD waste disposal costs for Muskogee at pdf 101-102 (($1,894,300/yr)/($40.59/ton)[2000 

lb/ton/(8,760 hr/yr)(0.9)] = 11,839 lb/hr) and for Sooner at pdf 103-104 ($1,733,500)/($39.60/ton)[2000 lb/ton/8,760 

hr/yr)(0.9)] = 11,105 lb/hr). 

111 Revised Sooner FGD Waste Disposal Cost: [(26,283 lb/hr)/(2000 lb/ton)](8760 hr/yr)(0.9)($39.60/ton) = 

$4,102,860/yr. 

112 Revised Muskogee FGD Waste Disposal Cost: [(28,153 lb/hr)/(2000 lb/ton)](8760 hr/yr)(0.9)($40.59/ton) = 

$4,504,643/yr.
30

 Second, the unit cost to dispose of the FGD solids is high compared to other similar 

BART cost analyses. The unit disposal cost for Sooner is $39.60/ton and for Muskogee 

$40.59/ton for on-site disposal.113 Other similar BART cost analyses, as summarized by Sargent 

& Lundy, show a range from $5/ton to $24.33/ton.114 The basis for Sargent & Lundy's high 

estimate for Sooner and Muskogee is not provided. I did not adjust the unit disposal cost as no 

information was provided about the on-site landfilling operations. These unit costs should be 

critically evaluated in future work. 

 Third, the estimate assumes that 100% of the FGD solids will be disposed in a landfill. 

Dry FGD solids are currently being used in agriculture, concrete, concrete products, flowable 

fill, mining applications, soil stabilization, structural fills and embankments, and synthetic 

aggregate.115 Selling the FGD solids would reduce or eliminate the cost of landfilling. A market 

study should be conducted to explore this option. 

 iv. Bag and Cage Replacement Cost

 Sargent & Lundy estimated the cost to replace fabric filter bags and cages at Sooner and 

Muskogee to be about $700,000/yr per unit.116 The estimates assumed an air-to-cloth ratio of 

3.5, a dollars per square foot replacement cost, a 3-year bag life, an unspecified exhaust gas 

flowrate, and a 4% contingency for bag cleaning. I was unable to reproduce Sargent & Lundy's 

costs with the reported information as it did not include the flowrate and the basis of the 

contingency (i.e., 4% of what?). 

 However, I used the reported information to make an independent calculation. I used the 

same air-to-cloth ratio and replacement part unit cost, the design SDA outlet flowrate for the 

91% SO2 control case (Option 2), and eliminated the contingency. The contingency is not 

warranted as the cost of bag cleaning is an auxiliary power cost, accounted for elsewhere. 

Further, such contingencies are not consistent with the Cost Manual approach, as explained 

elsewhere. I annualized the cost of replacement parts (bags, cages) using the capital recovery 

approach, assuming a social interest rate of 7% and a 3 year bag life.117 

 For Sooner, my costing approach decreases the per unit replacement cost from 

$653,300/yr to $544,026/yr118 or by $109,274/yr. For Muskogee, my costing approach 

decreases the per unit replacement cost from $675,100/yr to $599,020/yr119 or by $76,080/yr. 

 

113 12/28/09 S&L FollowUp Report, Attach. B, pdf 102-104. 

114 12/28/09 S&L FollowUp Report, Attach. C, pdf 109 (Gerald Gentleman - $5/ton; White Bluff - $8.58/ton; 

Boardman - $10/ton; Naughton - $24.33/ton; Nebraska City - $9/ton). 

115 Electric Power Research Institute (EPRI), A Review of Literature Related to the Use of Spray Dryer Absorber 

Material: Production, Characterization, Utilization Applications, Barriers, and Recommendations, December 6, 

2006. 

116 12/28/10 S&L FollowUp Report, pdf 101-104. 

117 Capital recovery factor for replacement parts: [(0.07(1.07)3

]/[(1.073 - 1] = 0.3811. 

118 Revised Sooner replacement costs: [(1,724,051 ACFM)($3.22/ft2

)(0.9)(0.3811)/3.5 ACFM/ft2 = $544,026/yr. 

119 Revised Muskogee replacement costs: [(1,846,716 ACFM)($3.31/ft2

)(0.9)(0.3811)/3.5 ACFM/ft2 = $599,020/yr. 
31

The decrease in bag and cage replacement cost is included in my revised cost estimate in 

Appendix 1, Line 54. 

 v. Auxiliary Power Costs

 Auxiliary power is the sum of the demand by the scrubber, baghouse, and booster fans, 

the latter required to overcome the increase in backpressure from adding these controls. The 

Sargent & Lundy auxiliary power costs are overestimated for two reasons. First, the auxiliary 

power demand used to calculate O&M costs is much higher than usually assumed for dry 

scrubbers. Second, the unit cost of electricity is much higher than the cost to OG&E to produce 

electricity. 

 The auxiliary power requirements used in the Sargent & Lundy cost analyses are much 

higher than those: (1) derived from the stated assumptions (1% gross power for DFGD and 0.5% 

gross power for baghouse);120 (2) calculated in the Design Document from individual motors 

based on the 91% SO2 control case;121 (3) assumed by Sargent & Lundy in the National Lime 

Association Report for similar plants (1.2% gross output);122 and (4) estimated by the vendors. 

The various estimates of auxiliary power, assuming 90% capacity factor, are summarized in 

Table 6. 

Table 6 

Auxiliary Power Per Unit (MWh/yr) 

Estimate Sooner Muskogee Source 

S&L Cost Estimate 67,290123 67,644 12/28/09 S&L Followup 

Report, pdf 101-104 

S&L Cost Estimate Based 

on Stated Assumptions 

67,408124 67,645 12/28/09 S&L Followup 

Report, pdf 101-104 

S&L Design Document 58,342125 61,495 12/28/09 S&L Followup 

Report, pdf 84-87 

S&L National Lime Report 53,927126 54,116 3/7 S&L Report, 

 Table 5.2-2 

Average Vendors 59,134 57,372 Vendor quotes 

 

120 12/28/09 S&L FollowUp Report, pdf 101-104 (8.5 MW for Sooner and 8.6 MW for Muskogee). 

121 12/28/09 S&L FollowUp Report, pdf 84-87 (7.4 MW for Sooner and 7.8 MW for Muskogee). 

122 3/07 S&L National Lime Association Report, Table 5.2-2 (1.20% of gross plant output, which is 6.84 MW for 

Sooner and 6.86 MW for Muskogee). 

123 $5,640,900/yr/$83.83 MWh = 67,289.75 MWh/yr. 

124 1% gross for DFGD (570 MW)(0.01)(8760 hr/yr)(0.9) = 44,938.8 MWh/hr; 0.5% gross for baghouse (570 

MW)(0.005)(8760 hr/yr)(0.9) = 22,469.4 MWh/hr. Total auxiliary power = 44,938.8 + 22,469.4 = 67,408.2 

MWh/yr. 

125 Reported as 7.4 MW for Sooner. Thus, (7.4 MW)(8760 hr/yr)(0.9) = 58,341.6 MWh/hr. 

126 Reported as 1.2% of gross plant output. Thus, (570 MW)(0.012)(8760 hr/yr)(0.9) = 53,926.5 MWh/yr. 
32

As the vendor quotes were the basis of the capital cost analyses, the vendor estimate of auxiliary 

power should also be used to estimate O&M costs. The vendor estimate is also close to the 

middle of the range of reported values. 

 The cost of electricity used in Sargent & Lundy's cost estimate is also high compared to 

other estimates. They assumed $85.93/MWh for Sooner and $83.83/MWh for Muskogee. 

Auxiliary power is the power required to run the plant, or power not sold. Cost effectiveness 

analyses are based on the cost to the owner to produce the electricity, or the busbar cost, not 

market retail rates, which is apparently what was used. 

 Oklahoma Gas and Electric (OG&E) is a regulated utility and its electricity rates are 

posted on its website.127 The posted rates for energy charges for various types of off-peak uses 

are under $50/MWh, as low as $32/MWh for power & light uses in the winter and $36/MWh for 

public school summer offpeak and all winter demand. Thus, the busbar cost to produce 

electricity is under $50/MWh. Cost effectiveness analyses typically estimate auxiliary power at 

$50/kW or less. The Northeastern cost effectiveness analysis used $50/MWh. Sargent & Lundy 

assumed $45/MWh for Sooner and Muskogee in its initial 2008 cost analysis.128 Further, 

Sargent & Lundy's summary of auxiliary power costs in the FollowUp Report indicates the range 

for other similar facilities is $30/MWh to $50/Mwh.129 Thus, I estimated the cost of auxiliary 

power using $50/MWh, an upper bound consistent with Northeastern and other BART 

determinations. 

 Correcting these two items reduces the per unit auxiliary power cost at Sooner from 

$5,640,900/yr to $2,956,700/yr or by $2,684,200/yr. At Muskogee, it reduces the per unit 

auxiliary power cost from $5,812,000 to $2,868,600 or by $2,943,400/yr. These reductions are 

included in my cost analyses in Appendix 1, Line 55. 

b. Indirect Operating Costs

 Property taxes, insurance, and administrative charges are fixed annual charges, estimated 

as a percentage of certain other costs in the spreadsheets in the FollowUp Report, Attach. A. 

Sargent & Lundy estimated property taxes as 0.6% (Sooner) to 0.85% (Muscogee) of total 

capital investment and insurance as 0.0105% of total capital investment. As total capital 

investment was revised as discussed above, the factors that rely on them must also change. This 

is accommodated in my cost analysis in Appendix 1, Lines 56-58, by recalculating property taxes 

and insurance using Sargent & Lundy's factors and my revised subtotals. 

 

127 Oklahoma Rate Tariffs, http://www.oge.com/residential-customers/billing-and-payment/Pages/RateInfo.aspx. 

128 Sargent & Lundy and Trinity Consultants, Sooner Generating Station Best Available Retrofit Control 

Technology Evaluation, May 27, 2008, pp. A-11/12 and Sargent & Lundy and Trinity Consultants, Muskogee 

Generating Station Best Available Retrofit Control Technology Evaluation, May 28, 2008, pp. A-11/12. 

129 12/28/09 S&L FollowUp Report, Attach. C, pdf 109 (Gerald Gentleman - $45.65/MWh; White Bluff - 

$47/MWh; Boardman/Northeastern/Naughton - $50/MWh; Nebraska City - $30/MWh). 
33

5. OG&E Cost Summary 

 The Sargent & Lundy dry scrubber cost analyses relied on in Oklahoma's SO2 BART 

determination significantly overstate the cost of the proposed control. My revisions, summarized 

in Appendix 1, lower the calculated cost effectiveness for Sooner from $6,724/ton130 to 

$1,291/ton and for Muskogee from $7,435/ton to $1,317/ton. 

 

 My revised estimates are consistent with BART Guidance and estimates made by others. 

Sargent & Lundy, for example, calculated the cost of a retrofit dry scrubber very similar to the 

subject BART sources (500 MW, 5186 MMBtu/hr, 1.44 lb SO2/MMBtu) in a March 2007 report 

prepared for the National Lime Association. In this study, the calculated cost effectiveness of a 

500 MW retrofit dry scrubber on low sulfur PRB coal (1.44 lb/MMBtu) based on 95% SO2 

control in 2006 dollars was $1,320/ton.131 Adjusting to 2009 dollars, the cost effectiveness of a 

nearly identical retrofit calculated by the same engineering firm is $1,379/ton.132 This value 

contains cost adders (e.g., AFUDC) that are not allowed in an apples-to-apples cost effectiveness 

analysis prepared pursuant to the EPA Cost Manual. 

Capital costs are commonly expressed as dollars per kilowatt of capacity. The total direct 

capital costs, when reduced to dollars per kilowatt of capacity dropped from $534/kW to 

$265/kW. Sargent & Lundy's estimates of $513/kW for Sooner and $555/kW for Muskogee are 

outside of the range of actual costs for similar sized plants with no serious retrofit issues. The 

plot plans indicate no retrofit issues that would justify such high capital costs. The 12/28/09 S&L 

FollowUp Report notes: "In degree of difficulty, the retrofits at Sooner and Muskogee could be 

described as average."133 

The Utility Air Regulatory Group (UARG) presented a graphic of capital cost as a 

function of generating capacity in 2007 that summarizes a wide range of scrubber cost data 

(2004-2005), reported in year-end 2005 dollars and shown below in Figure 2.134 The costs in this 

figure for dry scrubbers are for lime-based spray dryer systems with fabric filter baghouses and 

represent the owner's best estimate for a ready-to-operate system accounting for all direct and 

indirect charges. These figures include the results of a detailed study by Sargent & Lundy of 

three midwestern systems (Systems A, B, and C) that included 24 dry scrubbers for generating 

capacities between 200 and 800 MW. 

 

130 The cost effectiveness estimated from the 12/28/09 S&L FollowUp Report is $6,747.50/ton. The value estimated 

in Appendix 1, using the input values from the 12/28/09 S&L FollowUp Report, Attachment A yield slightly 

different results, $6,724/ton. The difference is due to differences in rounding in the two spreadsheets. 

131 3/07 S&L National Lime Association Report, Table 7.3-4. 

132 Adjusting Sargent & Lundy's 2006 dollar estimate of the cost effectiveness of a retrofit dry scrubber on a 500 

MW PRB fired boiler to 2009 dollars using the Chemical Engineering Plant Cost Index (CEPCI) as reported in 

Chemical Engineering: (1,320)(521.9/499.6) = $1,379/ton. 

133 12/28/09 S&L FollowUp Report, p. 4, pdf 6. 

134 J. Edward Cichanowicz, Current Capital Cost and Cost Effectiveness of Power Plant Emissions Control 

Technologies, Prepared for Utility Air Regulatory Group, June 2007, Section 6, Flue Gas Desulfurization Costs, p. 

21 and Figure 6.1. 
34

 

Figure 2 

Wet and Dry Scrubber Unit Cost 

This figure shows that Sargent & Lundy's data, for Systems A, B and C, ranges from 

about $220/kW to $390/kW when adjusted to 2009 dollars, for units between 500 and 600 

MW.135 My revised estimates are at the lower end of this range. If just AFUDC were added 

back into my estimate, for an apples-to-apples comparison with the Sargent & Lundy data 

reported in the UARG study, my unit cost would increase from $265/kW to $362/kW, at the 

upper end of the range. The much higher values on Figure 2, >$350/kW to $500/kW, are for 

smaller units on sites with significant retrofit issues. Sargent & Lundy's capital cost estimates for 

Sooner and Muskogee correspond to those expected for small units, 200 MW to 400 MW on 

sites with significant retrofit issues, which are not present at either Sooner or Muskogee. 

IV. REVISED COST ANALYSIS FOR NORTHEASTERN DRY SCRUBBER 

 The Northeastern BART cost effectiveness analysis is contained in the 5/30/08 Trinity 

Report, Appendix F. It concluded the cost effectiveness of a dry scrubber at these units is 

 

135 The Sargent & Lundy plotted points range from about $200/kW to $350/kW. Conservatively assuming 2005 

dollars (when 2006 were reported by author) and using the CEPCI index (521.9/468.2), the 2009 range is $223/kW 

to $390/kW. The CEPCI index is recommended by the EPA (8/17/10 Fish & Wildlife Service Letter of New 

Mexico Environment Dept., p. 5, footnote 8). 
35

$3,266/ton. This analysis was slightly modified by the ODEQ, to $3,294/ton,136 but the record I 

reviewed contained no supporting calculations for their modification. Thus, my review is based 

on the 5/30/08 Trinity Report. The Trinity analysis significantly overestimates the dollars per 

ton cost to control SO2 with a dry scrubber for the reasons discussed below. The format of my 

Northeastern review differs from my Sooner and Muskogee review due to differences in the 

costing methodologies. 

A. CAPITAL COST 

 The total capital investment and annual capital cost are both overestimated, as explained 

below. 

1. Unit Capital Cost 

 The Northeastern analysis starts with an assumed unit capital cost, expressed in dollars 

per kilowatt of capacity ($/kW), that is not supported, but simply stated. It is reported as 

$555/kW in the Trinity Report137 and as $582/kW in the ODEQ BART analysis.138 As explained 

above, capital costs of this magnitude are outside of the range of actual costs for similar sized 

plants with no serious retrofit issues. These elevated values correspond to smaller units with 

significant retrofit issues. AEP, the owner of Northeastern, has publicly reported the capital cost 

of scrubber technology is about $262/kW.139 The information I reviewed does not identify any 

retrofit issues or unusual circumstances that would lead to such a high unit capital cost. 

 The unit capital cost for the two coal-fired Northeastern units should be about the same as 

for Sooner and Muskogee. These six units are similar-sized, tangentially-fired boilers that burn 

similar low sulfur PRB coal and were built about the same time (Table 4). They all use 

electrostatic precipitators for particulate control. Thus, absent a demonstration to the contrary, 

the unit capital cost for the Northeastern units should be about the same as for the Sooner and 

Muskogee units. 

 Thus, I revised the Trinity capital cost estimate using the average capital cost from my 

revised Sooner and Muskogee analysis in Appendix 1, Line 65. This value is $265/kW, without 

escalation, AFUDC, bond costs, and excessive contingency, which are not appropriate for BART 

cost effective analyses. The revised Northeastern capital cost is shown in Appendix 2, Line 12. 

2. Capital Recovery Factor 

 As explained above, a capital recovery factor, or CRF, is used to convert a present value 

(total capital investment) into a series of equal annual payments over a given time (service life) 

 

136 Oklahoma Department of Environmental Quality (ODEQ), BART Application Analysis, Northeastern Power 

Plant, January 19, 2010 (1/19/10 ODEQ Northeastern BART Report), Table 11. 

137 5/30/08 Trinity Report, Appx. F, pdf 155. 

1381/19/10 ODEQ Northeastern BART Report, Table 11. 

139 American Electric Power, 2008 Fact Book, 43rd EEI Financial Conference, Phoenix, AZ, p. 94, pdf 103. 
36

at a given interest rate (social interest rate). The Trinity analysis uses the correct capital recovery 

method, but uses incorrect inputs. 

 The capital recovery factor depends on the service life of the equipment and the public 

interest rate, 7%. The higher the interest rate and the shorter the service life, the higher the 

annual cost and the higher the dollars per ton cost effectiveness. The Trinity analysis 

overestimated annual costs by assuming a service life of only 20 years and an interest rate of 8%. 

These are incorrect, as previously explained in Section III.B.1.h. The revised Northeastern 

analysis in Appendix 2, Line 67, is based on capital recovery assuming a service life of 30 years 

and an interest rate of 7%. 

B. OPERATING COSTS 

 Operating and maintenance costs comprise the sum of variable O&M (utilities and 

replacement parts), fixed O&M (operating and maintenance labor), and indirect O&M 

(administrative/overhead). The Trinity analysis omitted some of the components of O&M and 

overestimated others. These errors and omissions are discussed below and corrected in 

Appendix 2. 

1. Water 

 A dry scrubber requires water to prepare the reagent slurry and to cool the flue gas 

stream. The cost to supply water was not included in the Trinity analysis. I added water cost, 

scaled from the water demand for Sooner and Muskogee. See Section III.B.4.a.ii. The average 

cost of water, based on Sargent & Lundy's tabulation of water cost for six similar facilities is 

$1.10 per 1,000 gallons.140 The water cost, calculated using these assumptions, is included in 

Appendix 2, Line 23. 

 

140 12/28/08 S&L FollowUp Report, pdf 109 (BART Cost Evaluation). 
37

2. FGD Waste Disposal 

 A dry scrubber generates about 5 pounds of solids per pound of SO2 removed.141 These 

solids may be reused, but most commonly, are disposed of at an on-site or off-site landfill. The 

capital cost estimates for Northeastern include costs for an on-site landfill. Sargent & Lundy 

summarized the O&M landfill disposal costs for eight similar facilities, including Sooner and 

Muskogee. The costs range from $5/ton at Gerald Gentleman to $40.59/ton at Muskogee.142 As 

the Northeastern costs include $25 million for an on-site landfill, disposal costs would be lower 

than off-site disposal and further can be optimized. Thus, they would be expected to fall at the 

lower end of the reported range, or $5/ton. Therefore, in Appendix 2, Line 24, I estimated the 

cost of on-site landfill disposal assuming that 5 pounds of solids would be generated for each 

pound of SO2 removed and that it would cost $5 per ton to dispose of them. 

3. Bag and Cage Replacement 

 The fabric filter baghouse, which follows the spray chamber, contains filter bags and 

supporting cages that are changed out every three years. These O&M costs were not included in 

the Northeastern cost analysis. These costs should be similar to those that I estimated for Sooner 

and Muskogee as the plants are similar. I estimated the cost of bag and cage replacement at 

Sooner to be $544,026/yr and at Muskogee to be $599,020/yr (Sec. III.B.4.a.iv). Thus, in 

Appendix 2, Line 25, I assume the cost of bag and cage replacement at Northeastern to be 

$572,000/yr. This should slightly overestimate the cost at Northeastern, as it has a smaller 

capacity. 

4. Fixed O&M (Labor) 

 The Trinity analysis did not include costs for the labor to operate and maintain the 

scrubber. These charges should be about the same as those calculated by Sargent & Lundy for 

Sooner and Muskogee, or an average of about $4 million per year. These costs are added to total 

direct costs in Appendix 2, Line 26. 

5. Insurance 

 Insurance for Northeastern was estimated as 1% of the total capital investment, based on 

the Cost Manual default. The Sargent & Lundy analysis for Sooner and Muskogee indicates that 

insurance rates for similar facilities are about a factor of ten lower, or 0.0105% of total capital 

investment.143 Thus, I revised the Northeastern insurance cost to use this value in Appendix 2, 

Line 32. 

 

141 12/28/09 S&L FollowUp Report, pdf 76-79 (mass balances for Sooner & Muskogee). 

142 12/28/09 S&L FollowUp Report, pdf 109 (BART Cost Evaluation). 

143 12/28/09 S&L FollowUp Report, p. 11, pdf 12. 
38

6. Property Taxes 

 Property tax for Northeastern was estimated as 1% of total capital investment, based on 

the Cost Manual default. The Sargent & Lundy analysis for Sooner and Muskogee indicates that 

property taxes in Oklahoma are lower, estimated as 0.60% of total capital investment at Sooner 

and 0.85% of total capital investment at Muskogee, based on actual rates.144 As the actual tax 

rate was not reported for Northeastern, my revised cost estimate assumes the upper end of the 

OG&E range or 0.85% of total capital investment. My revised estimate for Northeastern 

property tax is shown in Appendix 2, Line 33. 

C. EMISSION REDUCTIONS 

 The Northeastern cost effectiveness analysis for dry scrubbing is based on an 83% SO2 

control efficiency, resulting in emission reductions of 26,599 ton/yr.145 See Appendix 2, Lines 

45 and 59. However, BART requires the most stringent emission control level.146 As discussed 

elsewhere, a dry scrubber can achieve 95% SO2 control. 

 Further, the same mismatch problem discussed for Sooner and Muskogee exist here. The 

capital and O&M costs for Northeastern were scaled from capital costs and utility demands for 

the Sooner and Muskogee scrubbers, which were based on 91% SO2 control. Thus, I revised 

the SO2 control efficiency to 91% in Appendix 2, Line 59. This increases the SO2 emission 

reductions from 26,559 ton/yr to 29,119 ton/yr in Appendix 2, Line 45. 

D. NORTHEASTERN COST SUMMARY 

 The Northeastern cost analysis relied on in Oklahoma's SO2 BART determination 

overstates the cost of a dry scrubber. Trinity and ODEQ estimated the cost effectiveness of a dry 

scrubber at Northeastern to range from $3,266/ton (Trinity) to $3,294/ton (ODEQ). My revised 

analysis in Appendix 2, Line 47, indicates that the BART cost effectiveness, based on the 

Control Manual approach, is $1,544/ton. This value is consistent with a similar analysis 

prepared for AEP's White Bluff Units 1 and 2, which was submitted to EPA as part of the 

Arkansas SIP. This analysis reported a cost effectiveness value for a retrofit dry scrubber on 

similar units of $1,280/ton in 2006 dollars147 or $1,340/ton148 in 2009 dollars. 

V. COST EFFECTIVENESS: DRY SCRUBBER 

 

144 12/28/09 S&L FollowUp Report, p. 11, pdf 12. 

145 5/30/08 Trinity Northeastern BART Evaluation, Table 9-1 and Appx. F, BART Economic Analysis for DFGD, 

note 2. 

146 70 FR 39166 (July 6, 2005). 

147 ENSR Corporation, BART Analysis for the White Bluff Steam Electric Station, December 2006, Table 3-3. 

148 Adjusting 2006 dollars to 2009 dollars using the Chemical Engineering Plant Index: (521.9/499.6)(1,280) = 

$1,337/ton. 
39

 Cost effectiveness is measured in dollars per ton of pollutant removed, calculated 

according to the Cost Manual, as stipulated in the BART Guidelines. My revised cost 

effectiveness values are reported in Appendix 1, Line 63 for Sooner and Muskogee and in 

Appendix 2, Line 47 for Northeastern. A control technology is considered to be "cost effective" 

if it falls within a reasonable range of cost-effectiveness estimates. "A reasonable range would 

be a range that is consistent with the range of cost effectiveness values used in other similar 

permit decisions over a period of time."149 

 Dry scrubbers are being successfully applied to virtually every kind of stationary source 

worldwide, including many similar applications in the utility industry.150 Thus, dry scrubbing is 

clearly cost effective, barring an unusual, site specific condition. Without identifying any 

unusual condition, Oklahoma concluded that a dry scrubber is not cost-effective for SO2 control 

for any of the six coal-fired steam electric units reviewed, i.e., OG&E Sooner Units 1 and 2, 

OG&E Muskogee Units 4 and 5, and AEP Northeastern Units 3 and 4. Oklahoma reported costs 

far above the usual range for similar facilities, or $6,348/ton to $7,493/ton for Sooner and 

Muskogee and $3,294/ton for Northeastern.151 

 Oklahoma's conclusion, however, is based on flawed cost estimates from OG&E and 

AEP/PSO. As discussed above, I revised the company cost analyses to match up the design basis 

and SO2 reductions, conform the analysis to the Cost Manual, eliminate double counting, 

consider economies of scale, and adjust miscellaneous errors. My revised costs are compared 

with the companies' analyses in Appendixes 1 and 2. My revisions lower the cost effectiveness 

for Sooner from $6,747/ton to $1,291/ton, for Muskogee from $7,435/ton to $1,317/ton, and for 

Northeastern from $3,294/ton to $1,544/ton. These revisions also lowered the unit capital cost 

per kilowatt of capacity. 

 

 Table 7 summarizes BART cost effectiveness values for dry scrubbers on other similar 

facilities burning low sulfur Powder River Basin coal. Most of these determinations, prepared by 

engineering firms to estimate actual costs rather than regulatory costs, incorrectly contain 

escalation, contingency, and AFUDC deviations from the Cost Manual, as discussed above. In 

some cases, the Cost Manual methodology was not mandatory as the plant capacity was under 

750 MW. 

 Thus, to make an apples-to-apples comparison with my revised numbers, I added back in 

AFUDC, escalation, and contingency to my estimates to level the playing field. These revised 

dollars per ton values for Sooner ($1,670/ton), Muskogee ($1,738/ton), and Northeastern 

($2,232/ton) fall within the range of values found to be cost effective in other similar BART 

permit decisions, as summarized in Table 7. My calculated cost effectiveness values for Sooner 

($1,291/ton), Muskogee ($1,317/ton), and Northeastern ($1,544/ton), excluding AFUDC, 

 

149 70 FR 39168 (July 6, 2005). 

150 Electric Power Research Institute (EPRI), A Review of Literature Related to the Use of Spray Dryer Absorber 

Material: Production, Characterization, Utilization Applications, Barriers, and Recommendations, December 6, 

2006, Table 1-2. 

151 OK Regional Haze SIP, pp. 81-82, Table VI-15. 
40

escalation and contingency, fall at the lower end of the range. Thus, a dry scrubber is cost 

effective for Sooner, Muskogee, and Northeastern. 

The unadjusted company's and ODEQ's estimates of $3,266/ton to $3,294/ton for 

Northeastern are also cost effective as they fall within the range of reported values, within the 

limit of accuracy152 of the cost estimate (+/-30%).153 They are also well within the range of 

values that have been found to be cost effective in numerous BART determinations, as 

summarized by the National Park Service. The owner of Northeastern, American Electric 

Power, stated in a financial conference that it planned to install scrubbers at Northeastern, 

projected to be in service by 2012-2014.154 

VI. BART EMISSION LIMIT: DRY SCRUBBER 

 The Oklahoma Regional Haze SIP concluded that BART for SO2 for Sooner, Muskogee, 

and Northeastern is a 30-day rolling average emission rate (at the stack) of 0.65 lb/MMBtu and a 

12-month rolling average of 0.55 lb/MMBtu, achieved using low sulfur coal.155 These emission 

limits are higher than the presumptive BART limits and higher than achievable with current coal. 

A dry scrubber was eliminated based on cost effectiveness. The underlying analysis is not valid 

as costs were significantly overestimated, as explained above. This section discusses what the 

BART emission limit should be for a dry scrubber, given that it is cost effective. As explained 

below, a wet scrubber could achieve a lower emission limit and is cost effective and otherwise 

feasible. 

 

152 Cost estimates that are within the accuracy of the estimate are considered to be indistinguishable when comparing 

costs. See NSR Manual at B.44. 

153 The OK Regional Haze SIP, Table VI-15, reports a range of $3,294/ton to $6,146/ton for a dry scrubber at 

Northeastern. However, the upper end of this range is incremental cost effectiveness for a wet scrubber, not average 

cost effectiveness for a dry scrubber. Incremental cost effectiveness is irrelevant for the dry scrubber as it is the 

technology against which other more efficient controls are compared. 

154 American Electric Power, 2008 Fact Book, 43rd EEI Financial Conference, Phoenix, AZ, pp. 91, 93. 

155 OK Regional Haze SIP, Tables VI-6, VI-7, and VI-10. 
41

Table 7 

Comparison of SO2 BART Cost Effectiveness Values 

for Dry Scrubbers & Low Sulfur Coal 

with Revised OG&E and AEP/PSO Values

Unit Rating 

(Gross)

(MW) 

Coal 

Sulfur 

(lb/MMBtu)

Control 

Efficiency

(%) 

BART 

(lb/MMBtu) 

Cost 

Effect.

($/ton)

White Bluff 1&2156 2x750 1.88 92 0.15 1,280 

Big Stone 1157 475 0.86 90 0.09 1,462 

Nebraska City 1158 650 0.815 88 0.10 1,636 

Boswell 3159 375 0.947 90 0.09 1,640

Sooner (Ex. 1) 2x570 1.18 91 0.10 1,670

Presumptive Muskogee160 650 0.02 1,694 

Muskogee (Ex. 1) 2x572 1.18 91 0.10 1,738

Naughton 1161 176 1.18 87 0.15 1,877 

Naughton 2162 234 1.18 87 0.15 1,882 

Stanton 1163 188 1.2 90 0.12 2,006 

Northeastern 3&4 2x470 0.91 83 0.15 2,232 

White Bluff 1 & 2164 2x850 0.68 92.5 0.15 2,430 

 

156 ENSR Corporation, BART Analysis for the White Bluff Steam Electric Station, December 2006, Table 3-3. 

157 South Dakota's Regional Haze State Implementation Plan, Draft, Sec. 6.3.2 and Appendix C, Burns & 

McDonnell, Otter Tail Power Company Big Stone Generating Station Unit 1, Best Available Retrofit Technology 

Analysis, November 2, 2009, Section 3.0. 

158 Nebraska Department of Environmental Quality, Fact Sheet, BART & PSD Analysis for the Omaha Public 

Power District Nebraska City Station Unit #1, February 26, 2009, pp. 4, 11, 15 and Response to Comments, 

February 26, 2009. 

159 Minnesota Pollution Control Agency, Regional Haze State Implementation Plan, December 2009, Appendix 9.2, 

Memorandum from Anne Jackson to File Re: BART Determination for Minnesota Power Boswell Unit 3, October 

26, 2009, Table 4 and Minnesota Pollution Control Agency, MPCA Review of Minnesota Power's Boswell 3 

Emission Reduction Plan, April 25, 2007. The costs are for a wet scrubber. 

160Technical Support Document for the Best Available Retrofit Technology (BART) Notice of Final Rulemaking, 

Setting BART SO2 Limits for Electric Generating Units: Control Technology and Cost-Effectiveness, April 2005 

("TSD"), Appx. D. 

161 Wyoming Department of Environmental Quality, BART Application Analysis, May 28, 2009, Table 20. A wet 

scrubber was selected as BART for Naughton 1 ($1,707/ton using existing ESP). The costs are for the dry scrubber 

option that was also analyzed. 

162 Wyoming Department of Environmental Quality, BART Application Analysis, May 28, 2009, Table 21. A wet 

scrubber was selected as BART for Naughton 2 ($1,700/ton, using existing ESP). The costs are for the dry scrubber 

option that was also analyzed. 

163 North Dakota Department of Health, A Plan for Implementing the Regional Haze Program Requirements of 

Section 308 of 40 CFR Part 51, Subpart P - Protection of Visibility, February 24, 2010, Appendix B.1, Department 

BART Determination for Stanton Unit 1, November 18, 2009 and Appendix C.3, Great River Energy, Stanton 

Station Unit 1, Best Available Retrofit Technology Analysis, Revised January 2008, Available at: 

http://www.ndhealth.gov/AQ/RegionalHaze/. 

164 Arkansas Regional Haze Rule State Implementation Plan, September 9, 2008, Table 9.3a, p. 52 and 

ENSR/AECOM, Revised BART Analysis for the White Bluff Steam Electric Station, August 2008, Table A-1. 
42

Drake 7165 142 0.83 85 0.13 2,544 

Gerald Gentleman166 2x750 0.75 80 0.15 2,726 

Drake 6167 85 0.82 85 0.13 2,816 

Boardman168 617 0.61 80 0.12 3,055 

Silver Bay 2169 75 0.60 90 0.06 3,547 

 

 The BART analysis must include the maximum level of control that each technology is 

capable of achieving.170 In analyzing a technology, "you take into account the most stringent 

emission control level that the technology is capable of achieving."171 This is important as "[a]n 

unrealistically low assessment of the emission reduction potential of a certain technology could 

result in inflated cost-effectiveness figures."172 This has happened here. 

 The BART analysis evaluated a control efficiency of less than 80% for the dry scrubber 

at Sooner and Muskogee and at 83% at Northeastern. However, 95% SO2 control is achievable 

with a dry scrubber. 173 This is not the most stringent emission control levels that a dry scrubber 

is capable of achieving. 

 

 In its report for the National Lime Association, Sargent & Lundy stated that vendors 

guarantee SO2 reduction efficiencies of up to 95% or as low as 0.06 lb/MMBtu SO2 for dry 

 

165 Colorado Regional Haze SIP, Chapter 6, pp. 70-71; Colorado Air Pollution Control Division, BART Analysis of 

Control Options for Colorado Springs Utilities -- Drake Plant. 

166 Sargent & Lundy, Revised Best Available Retrofit Technology (BART) Analysis for Units 1 & 2 Gerald 

Gentleman Station, Sutherland, Nebraska, February 2008, Tables 4 and 8 and Nebraska Department of 

Environmental Quality, Fact Sheet, BART & PSD Analysis for the Nebraska Public Power District Gerald 

Gentleman Station, May 11, 2010. 

167 Colorado Regional Haze SIP, Chapter 6, pp. 70-71; Colorado Air Pollution Control Division, BART Analysis of 

Control Options for Colorado Springs Utilities -- Drake Plant. 

168 Oregon Department of Environmental Quality, Oregon Regional Haze Plan for Implementing Section 308 

(40CFR 51.308) of the Regional Haze Rule, Adopted by the Environmental Quality Commission June 19, 2009, pp. 

149-158 and Appx. D.1, Table 15, pdf 82. 

169 Minnesota Pollution Control Agency, Regional Haze State Implementation Plan, December 2009, Appendix 9.2, 

BART Determination for Northshore Mining Bay Power Plant, October 5, 2009, Table 4. The dry scrubber was 

eliminated due to "substantial difficulties" in securing the necessary water discharge permits. BART was set at 0.48 

lb/MMBtu. 

170 70 FR 39164, note 12 (July 6, 2005). 

171 70 FR 39166 (July 6, 2005). 

172 70 FR 39168 (July 6, 2005). 

173 Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC Technologies, SDA FGD Cost 

Development Methodology, Final, August 2010, p. 1 ("A least squares curve fit of proprietary in-house cost data 

was defined as a "typical" SDA FGD retrofit for removal of 95% of the inlet sulfur."). Available at: 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix51B.pdf. 
43

scrubbers.174 This report included a chart showing the relationship between inlet SO2 and 

removal efficiency, reproduced in Figure 3.175 

Figure 3 

Relation Between Inlet SO2 and SO2 Removal Efficiency 

for a Dry Scrubber.

 This figure shows that a dry scrubber on the Sooner and Muskogee units can remove 

about 90% of the SO2 when burning current coal (0.51 lb/MMBtu), 91.5% when burning the 

proposed BART coal (0.65 lb/MMBtu), and 95% when burning the coal used to size the scrubber 

(1.18 lb/MMBtu). This figure also indicates that a dry scrubber on the Northeastern units can 

remove 93% of the SO2 when burning current coal (0.9 lb/MMBtu) and about 91.5% when 

burning the proposed BART coal. Higher removal efficiencies, up to 96%, have been 

demonstrated at a 600 MW PRB coal fired plant in the United States and 98% on a 350 MW 

coal-fired boiler in Denmark for an entire year. Thus, the BART requirement to evaluate the 

maximum degree of reduction has not been satisfied. 

 

 A dry scrubber designed to remove 95% of the SO2 from an inlet of 1.18 lb/MMBtu 

would yield an outlet of 0.06 lb/MMBtu based on a 30-day rolling average. The Sooner and 

Muskogee units can meet an SO2 emission limit of 0.06 lb/MMBtu by operating the dry scrubber 

at its design efficiency and selecting coal to assure the limit is met. Similarly, a dry scrubber 

designed to remove 93% of the SO2 from an inlet of 0.91 lb/MMBtu would yield an outlet of 

0.06 lb/MMBtu. 

 The control efficiency is constant at and near the design removal efficiency when burning 

the design coal, but can drop when inlet SO2 loading is significantly lower than design. 

However, emissions also drop as the scrubber inlet SO2 drops. For example, a scrubber 

designed to remove 95% of the SO2 from a 1.18 lb/MMBtu coal would routinely achieve 95% 

when burning this coal. However, if the sulfur content dropped to 0.51 lb/MMBtu or less, the 

removal efficiency would decline to about 90% yielding an outlet of 0.05 lb/MMBtu. Thus, a 

 

174 See also Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC Technologies, SDA FGD 

Cost Development Methodology, Final, August 2010, p. 1 ("It should be noted that the lowest available SO2 

emission guarantees, from the original equipment manufacturers of SDA FGD systems, are 0.06 lb/MMBtu."). 

175 Sargent & Lundy, Flue Gas Desulfurization Technology, Dry Lime vs. Wet Limestone FGD, Prepared for 

National Lime Association, March 2007, pp. 6, 14 (Table 4.1-1), 25 (Table 5.1-1), p. 41 (Table 7.2) 
44

dry scrubber at Sooner or Muskogee, designed as costed, could meet an SO2 emission limit of 

0.06 lb/MMBtu based on 30-day rolling average, when burning coal containing 0.51 to 1.18 

lb/MMBtu SO2. The same is true for Northeastern. The reduction in removal efficiency of the 

dry scrubber would be offset by the reduction of sulfur in the coal. The owner is responsible for 

selecting coals that assure the BART limit is satisfied. In other words, low inlet sulfur loading is 

not a valid excuse for failing to select the top control option. 

 Final permits have been issued for two plants that will fire low sulfur PRB coal and use a 

dry scrubber to control SO2 emissions to comparable levels that are built or being built. 

 The Nevada Bureau of Air Pollution Control, for example, issued a PSD Operating 

Permit to Construct to Newmont Nevada Energy Investment in May 2005 for a 200 MW PRBfired boiler equipped with a spray dryer absorber.176 The Permit contains a two-tiered SO2 

BACT limit as follows: 

• 0.09 lb/MMBtu on a 24-hour rolling average and 95% minimum SO2 removal 

efficiency, when combusting coal with a sulfur content equal to or greater than 

0.45% (30-day rolling period) 

• 0.065 lb/MMBtu on a 24-hour rolling average and 91% minimum SO2 removal 

efficiency, when combustion coal with a sulfur content less than 0.45% (30-day 

rolling period). 

The Newmont facility has been operating since May 2008. Figure 4 shows that it has 

consistently achieved an SO2 emission rate of less than 0.06 lb/MMBtu based on a 30-day 

rolling average. Clean Air Markets SO2 CEMS data indicates that the dry scrubber at the 

Hopewell Power Station is also achieving an emission limit of 0.06 lb/MMBtu, based on a 30-

day average. 

 

176 Nevada Bureau of Air Pollution Control, Class I Air Quality Operating Permit to Construct, No. AP4911-1349, 

Issued to Newmont Nevada Energy Investment, LLC. 
45

Figure 4 

(Newmont) TS Power Plant, Unit 1, SO2 Rate, 2008 - June 2010

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

1/1/20083/1/20085/1/20087/1/20089/1/2008

11/1/2008

1/1/20093/1/20095/1/20097/1/20099/1/2009

11/1/2009

1/1/20103/1/20105/1/20107/1/20109/1/2010

11/1/2010

Time

SO2 Rate (Lbs/mmBTU)

SO2_Rate_Hourly SO2_24HR_Avg SO2_30DAY_Avg SO2_365DAY_Avg

The Georgia Department of Natural Resources issued a final PSD permit for the proposed 

Longleaf plant in May 2007.177 The permit was appealed and the final permit was only recently 

confirmed. This plant consists of two 600-MW supercritical boilers that will be designed to fire 

either 100% PRB or a blend of PRB and low sulfur Appalachian coals. A spray dryer absorber 

will be used to control SO2. The SO2 BACT limits are tiered based on sulfur content as follows: 

 

 0.065 lb/MMBtu on a 30-day rolling average when the uncontrolled sulfur 

dioxide emission rate is less than or equal to 1 lb/MMBtu; 

 0.08 lb/MMBtu on a 30-day rolling average when the uncontrolled sulfur dioxide 

rate is greater than 1 lb/MMBtu but less than 1.25 lb/MMBtu; 

 0.105 lb/MMBtu on a 30-day rolling average when the uncontrolled sulfur 

dioxide emission rate is greater than 1.25 lb/MMBtu but less than 1.6 lb/MMBtu 

on a 30-day rolling average. 

 0.12 lb/MMBtu during any 24-hour average. 

 As the baseline coal sulfur content at all of the subject units is less than 1 lb/MMBtu SO2 

or 0.45% sulfur, the lowest reported emission limit, 0.065 lb/MMBtu based on both a 24-hour 

and a 30-day average, would be most applicable to the subject units. A 24-hour limit of 0.065 

lb/MMBtu corresponds to a much lower limit than a 30-day rolling average as the 30-day periods 

gives more opportunity to average out spikes. 

 

177 Georgia Environmental Protection Division, Longleaf Energy Station, Permit No. 4911-099-0033-P-01-0, April 

9, 2010. Available at: http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI-18499. 
46

VII. WET SCRUBBING 

 There are two general classes of technologies that are widely used to control SO2

emissions: dry flue gas desulfurization (“DFGD” or “dry scrubbing”) and wet flue gas 

desulfurization (“WFGD” or “wet scrubbing”). The companies' and ODEQ's BART analyses 

eliminated wet scrubbing because the dollars per ton cost effectiveness was higher than for dry 

scrubbing; the incremental cost to go from dry to wet scrubbing was judged unacceptable; and 

wet scrubbing was alleged to have certain adverse impacts that dry scrubbing did not have. 

However, a viable and widely used control technology such as wet scrubbing cannot be 

eliminated simply because it costs more and has the same adverse impacts as all other wet 

scrubbers, none of which are unique or unusual. The BART analysis must identify the best 

available retrofit technology. These conclusions are incorrect for the reasons set out below. 

A. CONTROL EFFICIENCY 

 Cost effectiveness depends, in part, on the assumed SO2 control efficiency. Generally, 

cost effectiveness declines as control efficiency increases because emissions increase in direct 

proportion to control efficiency while cost increase much more gradually. The BART 

Guidelines note: "An unrealistically low assessment of the emission reduction potential of a 

certain technology could result in inflated cost-effectiveness figures."178 These Guidelines 

further require that "in analyzing the technology you take into account the most stringent 

emission control level that the technology is capable of achieving."179 The wet scrubber was 

assumed to remove only 95% of the SO2 in the BART analyses. 

 However, wet scrubbers on units burning low sulfur coal can achieve 97% - 98% removal 

efficiency or an outlet SO2 of 0.04 lb/MMBtu when burning low sulfur coals.180 The latest 

Integrated Planning Model (IPM), version 4.10, used by the U.S. EPA to estimate scrubber costs 

in various rulemakings, assumes 98% control of SO2 by wet scrubbers.181 Further, CEMS data 

for Pleasant Prairie Units 1 and 2 in Wisconsin show this level of performance has been 

demonstrated.182 These units are similar to Sooner, Muskogee, and Northeastern. They are 620 

MW pulverized coal fired boilers that burn similar low sulfur PRB coal (0.5 - 0.7 lb/MMBtu) 

that were placed into service in 1980 and 1985, respectively. They were retrofit with a wet 

scrubber in 2006 and 2007, respectively. 

 

 

178 70 FR 39168 (July 6, 2005). 

179 70 FR 39166 (July 6, 2005). 

180 3/07 S&L National Lime Association Report, p. 10 and Table 4.1-1; Sargent & Lundy, IPM Model - Revisions to 

Cost and Performance for APC Technologies, Wet FGD Cost Development Methodology, Final, August 2010, p. 1 

("It should be noted that the lowest available SO2 guarantees, from the original equipment manufacturers of wet 

FGD systems, are 0.04 lb/MMBtu."). 

181 U.S. EPA, Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, August 2010, p. 5-2. 

Available at: http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation. 

182 Inlet and Outlet NOx and SO2 CEMS Data, Pleasant Prairie Units 1 and 2, General Average Report, 1/1/07 – 

12/31/07, Wisconsin PSC Ref. #93460. 
47

 The average and incremental calculated cost effectiveness values would have been much 

lower if they had been based on 97% reduction of SO2 from the 1.176 lb/MMBtu coal at Sooner 

and Muskogee or from 0.90 lb/MMBtu coal at Northeastern. This level of control would yield 

an emission limit of 0.04 lb/MMBtu, which has been achieved at Pleasant Prairie (Fig. 4). 

B. COST EFFECTIVENESS OF WET SCRUBBING 

 The companies and ODEQ estimated the average and incremental cost effectiveness of 

both dry and wet scrubbing. In general, the average cost effectiveness of wet scrubbing is about 

10% higher than dry scrubbing. However, in some cases, wet scrubbing is more cost effective. 

These include cases in which a single large absorber is used for the wet scrubber183 while two 

smaller absorbers are required for the dry scrubber or in retrofit applications that have existing 

electrostatic precipitators. I would expect this to be true for Sooner, Muskogee, and 

Northeastern. However, the companies failed to evaluate these options. The relative magnitude 

of wet scrubbing compared to dry scrubbing is demonstrated in Table 8 which compares the 

average cost effectiveness of dry and wet scrubbing as calculated in 13 cost effectiveness 

analyses. 

Table 8 

Comparison of Average Cost Effectiveness 

for Dry and Wet Scrubbers 

($/ton) 

Plant Dry Wet Ratio

Sooner 1 6,348 7,413 1.17 

Sooner 2 7,147 8,788 1.23 

Muskogee 4 7,378 8,724 1.18 

Muskogee 5 7,493 7,278 0.97 

Northeastern 3,294 3,625 1.10 

3/7 S&L Report 1,320 1,230 0.93 

White Bluff 1,736 1,926 1.11 

Gerald Gentleman 2,726 2,724 1.00 

Boardman 3,055 3,933 1.29 

Naughton w/FF 1,882 1,700 0.90 

Naughton w/ESP 1,700 1,700 1.00 

Stanton 2,006 2,232 1.11 

Big Stone 1,462 1,699 1.16 

Average 1.09 

 Table 8 shows that the average calculated cost effectiveness of a wet scrubber is typically 

about 9% higher than for a dry scrubber, except in those cases where an existing ESP can 

 

183 The largest absorber module currently used for dry scrubbers is about 400 MW while single wet scrubber 

modules can exceed 1000 MW. Thus, for the subject units, two absorber modules would be required for dry 

scrubbing while only would be required for wet scrubbing. The cost per module decreases as the capacity increases. 
48

substitute for a new baghouse (see Naughton w/FF compared to Naughton w/ESP). I reviewed 

and revised the company's and ODEQ's dry scrubbing cost estimates in Appendixes 1 and 2. I 

did not revise the wet scrubbing cost estimates as wet scrubbing was eliminated early in Sargent 

& Lundy's analysis and thus detailed cost analyses were not prepared by the companies. 

However, the same sources of error are present in both sets of estimates, as discussed above. 

 Thus, I estimated the revised cost effectiveness for wet scrubbing based on the ratio of 

my revised value for dry scrubbing to the company estimate for dry scrubbing. This yields cost 

effectiveness values for wet scrubbing of $1,555/ton at Sooner;184 $1,417/ton at Muskogee,185

and $1,699/ton at Northeastern.186 While these values are about 9% higher than dry scrubbing, 

they are cost effective per se as they fall within the range of values found to be cost effective in 

other determinations. 

 

C. COLLATERAL EFFECTS OF WET SCRUBBING 

 The ODEQ determined that wet scrubbing was not BART for SO2 for any of the subject 

units, in part, based on several alleged adverse collateral impacts including: (1) increased sulfuric 

acid mist (SAM) in the flue gas; (2) excess particulate emitted due to location of scrubber 

downstream of particulate control device; (3) uses more reactant, generating more fugitive dust; 

(4) uses significantly more water; (5) generates a wastewater stream that must be treated; (6) 

creates higher visibility impairment due to lower exit velocity, lower stack temperature, and 

higher SAM emissions. These claimed adverse impacts are either wrong or overstated. Further, 

ODEQ failed to point out the benefits of wet FGD and the adverse collateral impacts associated 

with dry scrubbing.187 Some of these issues are discussed below. 

1. Sulfuric Acid Mist (SAM) 

 The ODEQ alleges that there will be more sulfuric acid mist in the flue gas from a wet 

scrubber than from a dry scrubber. This is a red herring. The PRB coals that these units burn 

have very low sulfur content and very high levels of alkalinity. This means that very little 

sulfuric acid mist will form and what does form is absorbed before it reaches the stack.188 

 

184 From Appendix 1 and OG&E 1/15/10 Sooner BART Analysis, the revised Sooner wet scrubbing cost 

effectiveness: (1,291/6,724)(8,101) = $1,555/ton. 

185 From Appendix 1 and OG&E 1/15/10 Muskogee BART Analysis, the revised Muskogee wet scrubbing cost 

effectiveness: (1,317/7,435)(8,001) = $1,417/ton.

186 From Appendix 2 and OG&E 1/19/10 Northeastern BART Analysis, the revised Northeastern wet scrubbing cost 

effectiveness: (1,544/3,294)(3,625) = $1,699/ton.

187 The adverse collateral impacts of dry scrubbing include: largest absorber module limited to 400 MW, requiring 

two smaller modules to treat flue gases from 570 MW to 572 MW units; uses more expensive lime reagent; reagent 

utilization is poorer compared to a wet limestone system; FGD solids have fewer uses; combined removal of flyash 

and byproducts precludes commercial sale of flyash; higher hazardous air pollutant (e.g., Hg) emissions; and higher 

short-term emissions of SO2, SAM, and particulates due to atomizer changeout. See 3/07 S&L National Lime 

Association Report, pp. 12-13. 

188 R.K. Srivastava, C.A. Miller, C. Erickson, and R. Jambhekar, Emissions of Sulfur Trioxide from Coal-Fired 

Power Plants, J. Air & Waste Management Association, v. 54, pp. 750-762 at p. 757; Electric Power Research 
49

Further, Sargent & Lundy note: "low-and medium-sulfur coals [which include the PRB coals 

used by OG&E and AEP/PSO]...typically produce insufficient SO3 to be a problem."189

 However, in fact, the opposite is true. Dry scrubbers create significant sulfuric acid mist 

when they are operated at maximum efficiency. In order to maximize the SO2 control from a 

dry scrubber, the scrubber exit temperature is decreased until it approaches the adiabatic 

saturation temperature.190 This increases the time for SO2 and lime to react. Id. However, this 

also increases sulfuric acid mist. Id. Therefore, as the SO2 control efficiency increases from a 

dry scrubber, SAM control decreases. A much higher SO2 control efficiency can be obtained 

with wet scrubbers without the risk of increased SAM emissions. 

 Further, as discussed below, a dry scrubber must be taken off-line periodically to change 

out the atomizer. During these changeout periods, no SAM control occurs at the offline dry 

scrubber. Thus, any SAM that did form, would not be removed. The wet scrubber, on the other 

hand, does not require these changeouts. In order to meet the SO2 limit, these very high 

changeout emissions must be averaged out by operating the dry scrubber at a higher SO2 control 

efficiency, up to 98%, for enough time to offset the short-term, uncontrolled SO2 spikes. These 

periods of higher control efficiency generate more SAM than present in wet scrubbers as they do 

not have this maintenance issue. If SAM were an issue due to these factors, a sorbent injection 

system would be required to control the emissions, increasing the cost of the dry scrubber 

relative to the wet scrubber. 

2. Water 

The ODEQ alleges that wet scrubbers use "significantly more" water than dry systems. 

This is not true. A wet scrubber does use more water than a dry scrubber in an absolute sense, 

roughly 50% more, primarily because it removes more SO2. However, about 90% of the wet 

scrubber demand can be recycled wastewater, compared to only 20% for the dry system.191 

Thus, a wet scrubber would decrease fresh water demand of the scrubber by about 80%. 

Further, freshwater (or new water) demand for a wet scrubber is a small fraction of the total plant 

water demand. Typically, about 90% of the freshwater water is used for wet cooling, 2% for wet 

scrubbing, and the balance for ash sluicing, boiler makeup, and other plant uses. When 

expressed on a gallon per ton SO2 removed basis, the total (reused plus fresh) water demand for 

the two systems is about the same, as the wet scrubber removes much more SO2. 

 Institute, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, 2010, p. 4-3, Table 4-1, and 

Figure 4-2. 

189 3/07 S&L National Lime Association Report, p. 19. 

190 Black & Veatch, Operational Limits on Semi-dry Absorbers, p. 1. 

191 1/30/07 Meadows E-mail, p. 2. ("There is an appreciable difference in the water quality demands of wet and 

semi-dry system. Wet systems need plant service quality water only for oxidation air humiliation water and vacuum 

filter seal water, which constitute about 10 percent of the total plant demand. The remainder can be cooling tower 

blowdown water, plant drain water, ash sluice water, etc. Semi-dry systems need portable quality water for lime 

slaking (about 15% of the total makeup demand) and plant service water for the remainder."). 
50

3. Wastewater 

The ODEQ alleges that the wet scrubber generates a wastewater stream that must be 

treated and discharged. This is not necessarily true. A purge stream is required for a wet 

scrubber to control the buildup of soluble chlorides. The purge stream from a wet scrubber is 

very small, typically only about 10-15 gpm in a 600 MW plant that produces saleable gypsum 

and half that amount if saleable gypsum is not produced. This wastewater can be reused 

elsewhere in the plant. 

There are several options for treating FGD wastewater: (1) eliminate the discharge using 

a zero liquid discharge system;192 (2) treat the wastewater with the power plant combined 

wastewater, thus not requiring a separate wastewater treatment system; (3) treat and discharge 

the wastewater separately (the only option mentioned); and (4) treat the wastewater and recycle 

within the plant.193 These other options were not evaluated. 

4. Excess Particulate Emissions 

The ODEQ alleges that total PM emissions will be higher with a wet scrubber as the 

absorber is located downstream from the baghouse. This is misleading. Gypsum fines and other 

particulate matter exiting a wet scrubber are removed by the mist eliminator at the top of the 

scrubber, which is an integral part of a wet scrubber. This mist eliminator is typically specified 

to require that outlet particulate loading is no higher than inlet particulate loading. Therefore, by 

design, the wet scrubber makes no net contribution to particulate emissions. 

5. Reactant 

The ODEQ alleges that wet scrubbers use more reactant (limestone) than do dry systems, 

thus generating more fugitive dust from limestone storage and handling. This is wrong. Dry 

scrubbers use lime, while wet scrubbers use limestone. The reagent utilization of a dry system is 

poorer compared to a wet system, i.e., it takes more tons of reagent to remove a ton of SO2 in a 

dry system than a wet system.194 Thus, the opposite is true. Regardless, the fugitive particulate 

matter emissions from reagent handling are de minimus. In fact, the operating costs of a dry 

scrubber are higher than those of a wet scrubber because the dry scrubber uses more costly lime 

and requires 20% more lime on a per mole basis than does the wet scrubber to accomplish 

comparable SO2 reductions. 

6. Plume Issues 

 The ODEQ alleges that a wet scrubber would result in higher visibility impairment due to 

reduced plume rise from a lower exit temperature. A wet FGD will result in a visible moisture 

 

192 Bryan D. Hansen, Burns & McDonnell, Minimizing FGD Costs, CoalGen 2006, Attachments, p. 7, FGD System 

Blowdown rate versus Unit size with Wyoming PRB Coal. 

193 Kuman Sinha, Colleen Layman, and Colleen Chapman, Bechtel Power Corp., Environmentally Acceptable 

Treatment Options for FGD Wastewater, Electric Power Conference, 2007. 

194 3/7 S&L National Lime Association Report, p. 13 and Table 5.1-1. 
51

plume and lower exit temperatures. However, the impact on visibility in Class I areas should be 

de minimus and offset by the much higher reductions in SO2 that is achievable with wet 

scrubbing. Further, dry scrubbers generate excess sulfuric acid mist emission not present with 

wet scrubber, which also offset any affect from lower exit temperatures. 

 However, if this issue were demonstrated to result in visibility impairment, which is 

unlikely, the owner could use stack gas reheat to raise the temperature of the gases above the 

condensation point. This is a common practice throughout Europe and could be used with either 

wet or dry scrubbing to improve plume buoyancy. This option was not evaluated. 

D. BENEFITS OF WET SCRUBBING 

The beneficial and adverse impacts of both scrubbing technologies must be evaluated. 

The ODEQ only identified adverse impacts of wet scrubbing compared to dry scrubbing. 

However, wet scrubbing has many beneficial impacts compared to dry scrubbing. Further, dry 

scrubbing has adverse impacts that were not discussed. Wet scrubbing achieves better mercury 

control, avoids the high short-term SO2 emission rates during atomizer change-out at a dry 

scrubber, creates a reusable byproduct, and does not contaminate the flyash. Furthermore, some 

types of wet scrubbers, such as the Chiyoda bubbling jet reactor and the double contact absorber, 

have fewer environmental impacts than the conventional wet scrubber that was evaluated by 

ODEQ, e.g., uses less power, removes more sulfuric acid mist, particulate matter, and mercury. 

1. Reliability

Wet scrubbers have a much longer and more extensive operating history than dry 

scrubbers. Wet scrubbing systems have demonstrated high availability (i.e., the number of hours 

the scrubber is available to operate), and all of them constructed in recent years have been able to 

maintain better than 98% availability.195 Operating data from six facilities using dry FGD was 

reviewed. This data showed these facilities were available much less than 98% of the time. The 

Hayden station, one of the better performing units, maintained an availability of only 95%.196 

 

2. Maintenance Emissions

 Dry scrubbers have very high short-term emissions and typically have permits that allow 

high 1-hour, 3-hour, and 24-hour emission limits to accommodate this maintenance.197 See, e.g., 

the permits issued to the Weston 4, Whelan, and Roundup facilities. Due to the abrasive nature 

of lime slurry, nozzle assemblies must be removed, cleaned and flushed, and replaced on a 

 

195 See, for example, Carl Weilert, FGD Systems Utilizing single Absorber Modules: The Wave of the Future for 

New Boilers?, Burns & McDonnell Technical Paper, 2002. 

196 See, e.g., James E. Staudt, Sikander R. Khan, and Manuel J. Oliva, Reliability of Selective Catalytic Reduction 

(SCR) and Flue Gas Desulfurization (FGD) Systems for High Pollutant Removal Efficiencies on Coal Fired Utility 

Boilers, 2004 Mega Symposium, 

197 E-mail from Gary T. Van Helvoirt, WPSC, to Rajen Vakharia, WDNR, Re: Weston 4 air permit submittal, 

February 9, 2004. 
52

routine basis, usually every 4 to 8 weeks, reducing the control efficiency of the dry scrubber by 

up to 50%.198 

 At the subject plants, two dry scrubber modules would likely service each unit. Atomizer 

maintenance requires one of the two modules to be removed from service for 1 to 2 hours so it 

can be swapped with another assembly. During this time, approximately half of the flue gas 

stream is uncontrolled, although some SO2 removal may still take place within the filter cake in 

the baghouse, if a baghouse is used to control particulate matter. The wet scrubber does not 

require similar routine maintenance and thus does not have elevated short-term SO2 emissions, a 

substantial advantage of the wet scrubbing over the dry system. Mitigating these short-term 

emissions would require a spare absorber or excess capacity in a two-absorber train. This would 

raise the cost of dry scrubbing compared to wet scrubbing, which does not have any atomizer 

emissions. 

VIII. BART EMISSION LIMIT: WET SCRUBBER 

 A wet scrubber can meet a lower SO2 emission rate than a dry scrubber as it is capable of 

greater SO2 removal efficiency, up to 98%. Pleasant Prairie Units 1 and 2, similar boilers that 

burn a low sulfur PRB coal similar, were retrofit with wet scrubbers in 2006 and 2007. The 

Clean Air Markets SO2 emissions data for Unit 1 for the period 2007 through June 2010 is 

shown in Figure 54. These data show the wet scrubber easily meets a 365-day rolling average of 

less than 0.03 lb/MMBtu. Comparably low SO2 emission limits have been established in BACT 

analyses and required in PSD permits, achieved with low sulfur coal and wet scrubbing. 

 

 

198 Letter from Kevin E. Redinger, Babcock & Wilcox, to Gary T. Van Helvoirt, Wisconsin Public Service 

Corporation, Re: Recommended Atomizer Maintenance, May 5, 2005; Atomizer Change-Out Interval Information 

from B&W. 
53

Figure 5 

Pleasant Prairie, Unit 1, SO2 Rate, 2007 - June 2010

0.000

0.005

0.010

0.015

0.020

0.025

0.030

0.035

0.040

0.045

0.050

1/1/20073/1/20075/1/20077/1/20079/1/2007

11/1/2007

1/1/20083/1/20085/1/20087/1/20089/1/2008

11/1/2008

1/1/20093/1/20095/1/20097/1/20099/1/2009

11/1/2009

1/1/20103/1/20105/1/20107/1/20109/1/2010

11/1/2010

Time

SO2 Rate (Lbs/mmBTU)

SO2_Rate_Hourly SO2_24HR_Avg SO2_30DAY_Avg SO2_365DAY_Avg

 

 In a 2008 BACT determination for Desert Rock, the U.S. EPA concluded that low sulfur 

coal and wet scrubbing were the most stringent combination of control technologies available for 

pulverized coal fired boilers.199 A final PSD permit was issued based on this determination with 

an SO2 emission limit of 0.060 lb/MMBtu, averaged over a 24-hour period.200 This limit 

corresponds to an SO2 emission reduction of 97% from a coal containing 1.88 lb 

SO2/MMBtu.201 

 The State of Nevada issued a draft PSD permit for Toquop Energy with an SO2 emission 

limit of 0.06 lb/MMBtu based on a 24-hour average, achieved using low sulfur PRB coal (0.69 

lb/MMBtu) and wet scrubbing.202 A 24-hour average is much more stringent than a 30-day 

rolling average. For example, on Figure 54, compare the blue line (30-day average) with the red 

line (24-hr average). This comparison indicates that a 30-day average is generally lower than a 

24-hour average. The longer averaging time allows short-term spikes to be averaged out. 

 

199 U.S. EPA, Region 9, Ambient Air Quality Impact Report, Desert Rock, p. 18. Available at: 

http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-R09-OAR-2007-1110. 

200 U.S. EPA, Region 9, Prevention of Significant Deterioration Permit, Desert Rock Energy Company, July 31, 

2008. Available at: http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-R09-OAR-2007-

1110. 

201 The coal quality for Desert Rock is reported in the PSD Application for Cottonwood Energy Center, March 

2004, Table 1-1. This application is in the Desert Rock docket. It reports the average SO2 content of Navajo mine 

coal of 1.84 lb/MMBtu of SO2. The SO2 removal efficiency is: 100[1-(0.06/1.84)] = 96.7%. Available at: 

Available at: http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-R09-OAR-2007-1110. 

202 Nevada Bureau of Air Pollution Control, Draft Permit No. AP4911-1146, Toquop Energy LLP, Special 

Conditions, December 2007 and ENSR, Toquop Energy Project, Class I-B Operating Permit to Construction 

Application, July 2007, Appendix 10, BACT Analysis. Available at: http://ndep.nv.gov/bapc/toq.html. 
54
55

1 APPENDIX 1 

2 Revised Cost Effectiveness Analysis for 

3 Dry Flue Gas Desulfurization at 

4 Sooner Units 1 and 2 and Muskogee Units 4 and 5203

5 

6 

Sooner 1 

&2 Sooner 1&2 

Muskagee 

4&5 

Muskagee 

4&5 

7 S&L Fox S&L Fox 

8 

9 

10 Capacity (MW) 570 570 572 572

11 Vendor Quote 70,500,000 70,500,000 71,200,000 71,200,000

12 Dry FGD System 86,859,600 86,859,600 86,741,200 86,741,200

13 Fabric Filter 46,335,000 46,335,000 45,872,900 45,872,900

14 

Ash Recycling System - DFGD 

Contractor's Scope 11,116,900 11,116,900 12,102,900 12,102,900

15 

Waste Ash and Fly Ash Handling 

System 14,265,600 14,265,600 14,311,500 14,311,500

16 Ash Recycling - BOP Scope 955,600 955,600 

17 Flue Gas System 42,463,000 42,463,000 52,238,200 52,238,200

18 Mechanical - Balance of Plant 6,891,300 6,891,300 6,201,400 6,201,400

19 

Electrical:Auxiliary Power and 

Balance of Plant Electrical Work 41,935,100 41,935,100 37,923,600 37,923,600

20 Controls & Instrumentation 5,088,500 5,088,500 5,088,500 5,088,500

21 Civil Work 3,597,400 3,597,400 3,597,400 3,597,400

22 

Removal & Relocation of Existing 

Equipment & Infrastructure 2,047,600 2,047,600 4,134,800 4,134,800

23 Manhour Productivity Factor -14,276,530 -14,918,100

24 Vendor Discount Equipment -3,525,000 -3,560,000

25 Optimizing Design Vendor Scope -8,734,800 -9,073,560

26 

Subtotal Equipment Material & 

Labor Costs 261,555,600 235,019,270 268,212,400 240,660,740

27 Other Costs 61,016,900 61,016,900 63,987,800 63,987,800

28 Overtime Inefficiency -9,518,000 -9,945,000

29 

BOP Contractor's General & 

Admin -7,408,600 -7,855,500

30 

Spare Parts, Special Tools % 

Consumables 794,000 794,000 807,000 807,000

31 Freight, Duties & Taxes 1,936,000 1,936,000 2,136,900 2,136,900

32 325,302,500 281,839,570 335,144,100 289,791,940

33 Total Indirect Costs 48,090,100 48,090,100 49,601,900 49,601,900

34 Engineering/Procurement -12,205,338 -12,354,495

35 Construction Management -869,259 -907,043

36 

Startup & Commissioning Craft 

Support -3,273,900 -3,417,600

37 Operator Training & Manuals -900,300 -939,800

38 Owner's Cost -16,265,125 -16,757,205

39 Revised Total Indirect Costs 48,090,100 14,576,178 49,601,900 15,225,756

40 Escalation 46,602,900 0 63,277,100 0

41 Contingency 58,673,400 2,115,000 63,104,100 2,136,000

42 Bond Cost 4,786,700 0 5,111,300 0

43 AFUDC 101,133,800 0 118,148,300 0

 

203 For electronic version of this spreadsheet, including calculations, see file Appendix1.xls. 
56

44 Total Project Cost 584,589,400 298,530,748 634,386,800 307,153,696

45 CRF 0.1036 0.0806 0.1036 0.0806

46 Annual Capital 60,563,462 24,057,519 65,722,472 24,752,412

47 Variable O&M 19,899,400 19,899,400 21,292,200 21,292,200

48 Fixed O&M 8,027,400 8,027,400 8,439,200 8,439,200

49 Indirect O&M 5,174,200 5,174,200 7,146,400 7,146,400

50 Total O&M 33,101,000 33,101,000 36,877,800 36,877,800

51 Lime 4,682,110 4,476,064

52 Water -19,602 -180,730

53 FGD Waste Disposal Cost 4,738,721 5,310,685

54 Bag & Cage Replacement Cost -218,548 -152,160

55 Auxiliary Power -5,368,400 -5,886,800

56 Property Taxes -4,862,997 -3,926,797

57 Insurance -60,072 -68,719

58 Revised O&M 33,101,000 31,992,212 36,877,800 36,449,343

59 Total Annual Cost ($) 93,664,462 56,049,731 102,600,272 61,201,755

60 SO2 Emission Reduction (ton/yr) 13,930 13,930 13,799 13,799

61 

Revised Emission Reduction 

(ton/yr) 43,428 46,458

62 S&L Cost Effectiveness ($/ton) 6,724 7,435 

63 

Revised Cost Effectiveness 

($/ton) 1,291 1,317

64 

Revised (AFUDC, escalation, 

contingency) 1,670 1,738

65 Cost ($/kw) 513 262 555 268

66 Cost ($/kw) Utility Comparison 351 372
57

1 APPENDIX 2 

2 Revised Cost Effectiveness Analysis for 

3 Flue Gas Desulfurization at 

4 Northeastern Units 3 & 4204

5 

6 

7 Trinitya

 Fox Section

8 

9 

10 CAPITAL COST SUMMARY 

11 

12 Purchased Equipment Cost (PEC) 547,080,000 249,100,000 

13 Landfill Construction 25,000,000 25,000,000 

14 

15 TOTAL CAPITAL INVESTMENT (TCI) 572,080,000 274,100,000 

16 

17 

18 ANNUAL COST SUMMARY 

19 

20 DIRECT OPERATING COST 

21 Lime Injection 6,178,600 6,178,600 

22 Operating Electricity 3,022,200 3,022,200 

23 Water 423,100 

24 FGD Waste Disposal 727,981 

25 Bag & Cage Replacement 572,000 

26 Fixed O&M 4,116,350 

27 

28 TOTAL DIRECT COST (DC) 9,200,800 15,040,232 

29 

30 INDIRECT OPERATING COSTS 

31 Administrative Charges (2% TCI) 11,441,600 5,482,000 

32 Insurance (1% TCI) 5,720,800 28,781 

33 Property Taxes (1% TCI) 5,720,800 2,329,850 

34 Capital Recovery (CRFxTCI) 58,267,612 22,088,733 

35 

36 TOTAL INDIRECT COST (IC) 81,150,812 29,929,364 

37 

38 TOTAL ANNUALIZED COST (DC+IC) 90,351,612 44,969,595 

39 

40 

41 COST EFFECTIVENESS SUMMARY 

42 

43 Annual Control Cost 90,351,612 44,969,595 

44 

45 SO2 to be Removed (ton/yr) 26,559 29,119 

46 

47 CONTROL COST EFFECTIVENESS ($/ton) 3,402 1,544 

48 

49 

50 

 

204 For electronic version of this spreadsheet, including calculations, see file Appendix2.xls. 
58

51 INPUTS 

52 DFGD Capital Cost ($/kW) 582 265 

53 Net Rating (MW) 940 940 

54 Landfill costs estimated by AEP ($) 25,000,000 25,000,000 

55 Estimated Lime Usage (ton/yr) 30,893 30,893 

56 Lime Cost ($/ton) 200 200 

57 Estimated Electricity Usage (kW/hr) 6,900 6,900 

58 Cost of Electricity ($/kW) 0.05 0.05 

59 SO2 Removal Rate 0.83 0.91 

60 Water (gal/MMBtu) 4.25 

61 Water Cost ($1.40/1000 gal) 1.40 

62 Solids Generated (lb solids/lb SO2) 5 

63 Solids Disposal Cost ($/ton) 5 

64 Baseline emissions (lb SO2/MMBtu) 0.90 0.90 

65 Annual Average Firing Rate (MMBtu/hr) 4,775 4,775 

66 Capacity Factor 0.85 0.85 

67 Capital Recovery Factor 0.1019 0.0806 

68 Interest Rate 0.08 0.07 

69 Scrubber Lifetime (yr) 20 30 

70 

(a) 5/30/08 Trinity Report, Appx. F, BART Economic Analysis for DFGD (SO2). 

 Modified to replace $555/kW with $582/kW, based on 1/19/10 ODEQ BART Report, Table 11. 
1 EPA modification of Exhibit 1

2 Revised Cost Effectiveness Analysis for Dry Flue Gas Desulfurization at

3 Sooner Units 1 and 2 and Muskogee Units 4 and 5

4 to Extend Fox Option 2 Case

5

6 Sooner 1 &2 Sooner 1&2 Sooner 1&2 Muskogee 4&5 Muskogee 4&5 Muskogee 4&5 Notes

7 S&L Fox EPA S&L Fox EPA 1

8

9

10 Capacity (MW) 570 570 572 572

11 Vendor Quote 70,500,000 70,500,000 71,200,000 71,200,000

12 Dry FGD System 86,859,600 86,859,600 86,741,200 86,741,200

13 Fabric Filter 46,335,000 46,335,000 45,872,900 45,872,900

14

Ash Recycling System - DFGD Contractor's 

Scope 11,116,900 11,116,900 12,102,900 12,102,900

15 Waste Ash and Fly Ash Handling System 14,265,600 14,265,600 14,311,500 14,311,500

16 Ash Recycling - BOP Scope 955,600 955,600

17 Flue Gas System 42,463,000 42,463,000 52,238,200 52,238,200

18 Mechanical - Balance of Plant 6,891,300 6,891,300 6,201,400 6,201,400

19

Electrical: Auxiliary Power and Balance of Plant 

Electrical Work 41,935,100 41,935,100 37,923,600 37,923,600

20 Controls & Instrumentation 5,088,500 5,088,500 5,088,500 5,088,500

21 Civil Work 3,597,400 3,597,400 3,597,400 3,597,400

22

Removal & Relocation of Existing Equipment & 

Infrastructure 2,047,600 2,047,600 4,134,800 4,134,800

23 Man-hour Productivity Factor -14,276,530 -14,918,100

24 Vendor Discount Equipment -3,525,000 -3,560,000

25 Optimizing Design Vendor Scope -8,734,800 -9,073,560

26 Subtotal Equipment Material & Labor Costs 261,555,600 235,019,270 268,212,400 240,660,740

27 Other Costs 61,016,900 61,016,900 63,987,800 63,987,800

28 Overtime Inefficiency -9,518,000 -9,945,000

29 BOP Contractor's General & Admin -7,408,600 -7,855,500

30 Spare Parts, Special Tools % Consumables 794,000 794,000 807,000 807,000

31 Freight, Duties & Taxes 1,936,000 1,936,000 2,136,900 2,136,900

32 325,302,500 281,839,570 335,144,100 289,791,940

33 Total Indirect Costs 48,090,100 48,090,100 49,601,900 49,601,900

34 Engineering/Procurement -12,205,338 -12,354,495

35 Construction Management -869,259 -907,043

36 Startup & Commissioning Craft Support -3,273,900 -3,417,600

37 Operator Training & Manuals -900,300 -939,800

38 Owner's Cost -16,265,125 -16,757,205

39 Revised Total Indirect Costs 48,090,100 14,576,178 49,601,900 15,225,756

40 Escalation 46,602,900 0 63,277,100 0

41 Contingency 58,673,400 2,115,000 63,104,100 2,136,000

42 Bond Cost 4,786,700 0 5,111,300 0

43 AFUDC 101,133,800 0 118,148,300 0

44 Total Project Cost 584,589,400 298,530,748 153,594,070 634,386,800 307,153,696 158,829,176 2

45 CRF 0.1036 0.0806 0.1036 0.0806

46 Annual Capital 60,563,462 24,057,519 12,377,594 65,722,472 24,752,412 12,799,472

47 Variable O&M 19,899,400 19,899,400 19,899,400 21,292,200 21,292,200 21,292,200

48 Fixed O&M 8,027,400 8,027,400 8,027,400 8,439,200 8,439,200 8,439,200

49 Indirect O&M 5,174,200 5,174,200 5,174,200 7,146,400 7,146,400 7,146,400

50 Total O&M 33,101,000 33,101,000 33,101,000 36,877,800 36,877,800 36,877,800

51 Lime 4,682,110 0 4,476,064 0 3

52 Water -19,602 0 -180,730 0 4

53 FGD Waste Disposal Cost 4,738,721 0 5,310,685 0 5

54 Bag & Cage Replacement Cost -218,548 -218,548 -152,160 -152,160 6

55 Auxiliary Power -5,368,400 -5,368,400 -5,886,800 -5,886,800 7

56 Property Taxes -4,862,997 -7,326,921 -3,926,797 -5,706,691 8

57 Insurance -60,072 -90,509 -68,719 -99,867 9

58 Revised O&M 33,101,000 31,992,212 20,096,622 36,877,800 36,449,343 25,032,281

59 Total Annual Cost ($) 93,664,462 56,049,731 32,474,216 102,600,272 61,201,755 37,831,754

60 SO2 Emission Reduction (ton/yr) 13,930 13,930 13,799 13,799

61 Revised Emission Reduction (ton/yr) 43,428 15,860 46,458 15,989 10

62 S&L Cost Effectiveness ($/ton) 6,724 7,435

63 Revised Cost Effectiveness ($/ton) 1,291 2,048 1,317 2,366

64 Revised (AFUDC, escalation, contingency) 1,670 1,738

65 Cost ($/kw) 513 262 555 268

66 Cost ($/kw) Utility Comparison 351 372

1. This spreadsheet is a modification of "Exhibit 1," prepared by Phyllis Fox as part of her report "Revised BART CostEffectiveness Analysis for Flue Gas Desulfurization at Coal-Fired Electric Generating Units in Oklahoma: Sooner Units 1 & 2, 

Muskogee Units 4 & 5, Northeastern Units 3 & 4," October 2010, RTI Project Number 0209897.004.085. This spreadsheet is 

used to extend her cost analysis as part of EPA's proposed SO2 BART FIP for Units 4 and 5 of the OG&E Muskogee plant, 

Units 1 and 2 of the OG&E Sooner plant, and Units 3 and 4 of the AEP/PSO Northeastern plant. Any errors contained in this 

spreadsheet are solely the fault of EPA.
6. Retained Fox bag and cage correction. This is slightly conservative towards OG&E because the correction in going to the 

80% control case would actually be slightly larger due to the slight decrease in the flow rate through the baghouse OG&E uses 

in their design basis for the 80% control cases vs. the 91% control cases on pdf 76 - 79 of their report. 

7. Retained Fox auxiliary power correction, as the correction as calculated is independent of the size of the scrubber.

3. Zeroed out Fox correction for lime, as the correction was needed to correct a S&L error for assuming lime use based on an 

inlet of 0.509 lbs/MMBtu SO2 at Sooner and 0.507 lbs/MMBtu at Muskogee to an inlet of 1.176 lbs/MMBtu. Since this is an 

extension of the cost evaluation for those lower inlet values, the correction doesn't apply.

4. Zeroed out Fox correction for water for the sake of expediency. This assumption biases the $/ton calculation upward.

5. Zeroed out Fox correction for FGD waste disposal, as the correction was needed to correct a S&L error for assuming FGD 

waste disposal based on an inlet of 0.509 lbs/MMBtu SO2 at Sooner and 0.507 lbs/MMBtu at Muskogee to an inlet of 1.176 

lbs/MMBtu. Since this is an extension of the cost evaluation for those lower inlet values, the correction doesn't apply.

10. The baseline emissions in line 61 are taken from the S&L report, Table 5. These baseline emissions correspond to 

uncontrolled emissions rates of 0.509 lbs/MMBtu for Sooner 1, 0.516 for Sooner 2, 0.507 for Muskogee 4, and 0.514 for 

Muskogee 5 (see Table 9, S&L Report 12/28/09). EPA's reductions in line 61 are based on 0.06 lbs/MMBtu. The post control 

emissions are calculated by multiplying the baseline emissions by (0.06/0.509) for Sooner 1, (0.06/0.516) for Sooner 2, 

(0.06/0.507) for Muskogee 4, and (0.06/0.514) for Muskogee 5. The emissions reductions are then calculated by subtracting the 

post control emissions from the baseline emissions.

2. Modified total project cost by application of the "6/10" rule as per email from Phyllis Fox to Joe Kordzi on 9/30/10 2:15 PM.

9. Modified Fox insurance correction by recalculating the total project cost, since S&L assumed property taxes were a percent 

of that figure.

8. Modified Fox property tax correction by using a recalculated total project cost, since S&L assumed property taxes were a 

percent of that figure. Project cost was recalculated using the "6/10" rule as per email from Phyllis Fox to Joe Kordzi on 9/30/10 

2:15 PM