### 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 Prot ection 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 0209897.004.085iii 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 & Commissi oning Craft Support ...............................................................21 e. Operator Training & Manuals ................................................................................21

f. Other Factored Sums ..............................................................................................22 g. Initial Fabric Filter Replacement Materials ...........................................................22iv 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 FO R NORTHEASTERN DRY SCRUBBER 35

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

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

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

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

1. Water .....................................................................................................................3 7

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 ..................................................................................39v 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 .....................................................................................................................5 0

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 ....................................................................................57vi TABLES

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

Table 2. Option 1 Revised Cost Effectivene ss, Increased Emission Reductions (91.5% SO2 Reduction from Scrubber Inlet of 1.176 lb/MMBtu) ...........................................................6

Table 3. Option 2 Revised Cost Effectivene ss, 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 Effectiv eness Values for Dry Scrubbers & Low Sulfur

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

Table 8. Comparison of Average Cost Eff ectiveness 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 .........................................541 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 st ations: Sooner Units 1 and 2; Muskogee Units 4 and 5; and Northeastern Units 3 and 4. These ar e 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 fo r SO2 for these six units was satisfied by continuing to burn low-sulfur coal and meeti ng 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/MMB tu 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 co al-fired units without citing any unusual

circumstances. This conclusion is based on cost analyses performed by Sargent & Lundy 4 for Oklahoma Gas & Electric (OG&E) Sooner Un its 1 and 2 and Muskogee Units 4 and 5 and by Trinity Consultants 5 for American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Northeastern Units 3 and 4. The focu s of these company analys es 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 collater al 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 Report 6 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 Implem entation Plan ("OK Regional Haze SIP").

2 OK Regional Haze SIP, Ta ble 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, Decemb er 28, 2009 ("12/28/09 S&L Followup Report").

5 Trinity Consultants, Best Available Retrofit Technol ogy (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 Technol ogy (BART) Determination, American Electric Power, Northeastern Power Plant, May 30, 2008 (5/30/08 Trinity Report).2 review, I prepared revised cost analyses, correcti ng some of the errors th at I found. It was not possible to correct all errors as the parties dec lined to provide copies of their spreadsheets disclosing their cost calculat ions 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 highlight ed in blue in these Appendixes. My basis is explained in the following sections.

My analysis indicates the cost to install dry scrubbers at all si x 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 th e 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 correct ed, the average cost effectiven ess 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 overestimate s that I identified due to lack of support and underlying calculations. My revise d cost effectiveness values are within th e range of values

found to be cost effective at othe r 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 f acilities nationwide indicate that the cost

effectiveness of a wet scrubber is about 9% higher than for a dr y scrubber. In cases where an existing electrostatic precipitator can be used in stead of a new fabric f ilter baghouse, the cost effectiveness of wet scrubbing is lower than dry scrubbing and the incremen tal cost effectiveness is zero. This is likely the case for the subjec t units, but this option was not evaluated by the companies.

I revised the wet scrubber co st analyses based on the ratio of my revised dry scrubber cost to the initial company costs. This lo wered 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 eff ectiveness analysis is cont ained in the "12/28/09 S&L FollowUp Report". 8 This report was prepared in respons e to Oklahoma's draft Regional Haze SIP, which required Sooner and Muskogee to in stall dry flue gas de sulfurization systems (scrubbers) to satisfy BART. Oklahoma rej ected Sargent & Lundy's earlier BART cost effectiveness analyses as they were "substant ially 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 st ill substantially higher th an 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 ca lculated according the EPA Air Pollution Control Cost Manual or "Cost Manual", 9 as stipulated in the BART Guid elines. A control technology is

considered to be “cost effectiv e” 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. Seco nd, 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 cost s for the control technology are consistent with

the claimed emission reductions.

In performing its BART analysis, Sargen t & Lundy assumed that the Sooner and Muskogee plants burned coal with a higher sulfur cont ent than they are currently burning. This necessitated costing a much bigge r scrubber than is necessary for the coal they are currently burning. However, Sargent & Lundy also assume d 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 word s, the costed scrubber is much more efficient than the one required to deliver the assumed BART performance level.

The FollowUp Report indicates that two separa te 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 cont aining 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 estim ate 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, Decemb er 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 represen ts a significant increase in the

sulfur content of the coal that is currently burn ed (0.51 lb/MMBtu). 10 The emission reductions that Sargent & Lundy used to calculate cost eff ectiveness, 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 cu rrently burned were costed, which skewed the cost effectiveness in do llars per ton to the high side. When calculating the tonnage removed, a lower scrubbing efficien cy, 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 w ould be needed to minimally satisfy BART.

This mismatch in design causes a dilemma in an alyzing the cost effectiveness that is not completely resolvable within the scope of this wo rk. An ideal analysis w ould be to contrast the cost effectiveness of the larger scrubbers, usi ng a range of coals to the cost effectiveness of smaller scrubbers burning the current coal. Th e basic decision point for EPA, however, is

whether scrubbers are cost effective and what em ission 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 s ections, I revised the Sa rgent & 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 7,4355 The first option, costing the la rger scrubber, as is demonstr ated 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 intend ed as it allows the owner to switch to higher sulfur coals in the future as the supply of lowe r sulfur coals diminishes or to use cheaper higher sulfur coals to reduce oper ating costs. This first option is car ried throughout the balance of this report because Sargent & Lundy assumed a higher su lfur coal would be burned when it costed the scrubbers. The second option, costing a smalle r scrubber, is discusse d 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). T hus, for a given annual cost, the calculated cost effectiveness in dollars per t on declines as emission reductions increase.

Cost effectiveness could be estimated usi ng the cost of the larg er scrubber and the

emission reductions that could be achieved with this larger sc rubber, assuming an outlet of 0.1 lb/MMBtu SO2. The use of higher sulfur co al, 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 effectivene ss 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 scrubbe r 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 incl uded 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 Tabl e 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 revision s, coupled with the increased SO2 emission

reductions shown in Table 2 result in an average cost effectivene ss 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 anal ysis 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 expone nt, which is typically close to 0.6. The capital cost of a process is relate d to capacity by the equation:

C b = C
a (S b /S
a ) n

where C b is the approximate cost ($) of a process or equipment having size S b and C
a is the known cost ($) of a process or equipment having corresponding size S

a. The ratio S b /S
a 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 sc rubber 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

Costs 13 ($/yr) Design

Basis

Reduction 14
(ton/yr) Revised

Cost

Effect. 15

($/ton)

Sooner 93,664,600 43,428 2,157 Muskogee 102,600,400 46,458 2,2087 as the size factor, which is dimensionless. 16 The exponent, n, varies depending upon the type of process unit. This equation indica tes that a log-log plot of capacity versus equipment cost for a given type of equipment should be a straight line with a slope equa l to the exponent n.

The exponent n is typically 0.8 to 0.9 for pro cesses that use a lot of mechanical work or gas compression. For typical petrochemical proce sses, 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 co st-capacity exponent ranges from less than 0.2 to greater than 1.0. I am not aware of any public data sp ecific to dry scrubbe rs. However, it is appropriate here as Sargent & Lundy did not supp ly any cost data for th e smaller scrubber case, the extrapolation is less than a 10-fold capacity range, and the scrubbers are similar with regard to type of construction, material s 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 mate rial balances in the 12/28/09 S&L FollowUp Report. This calculation yi elds a size factor of 0.51. 20 In other words, the fixed capital cost of the smaller scrubber, that can reduce the SO2 fr om 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, Cap ital 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 De sign: 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 summ arized 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 scrubbe r 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/h r 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

Costs 21 ($/yr) S&L

Emission

Reduction 22
(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 smalle r 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 co st 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 im prove 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 Guidelin es 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 scr ubber based on the higher sulfur coal as it is not only more cost effec tive, but it provides greater flexibility in future operations. While this is a good business strate gy, 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 coul d result in inflated cost-effectiveness figures." 24 Cost effectiveness is determ ined 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 effectivenes s for Sooner and Muskogee in Appendix 1.

B. COSTING METHOD

In evaluating cost effectiveness, it is im portant that a consistent set of rules be used. Otherwise, one runs the risk of compar ing apples with oranges when making the cost effectiveness determination. For power plants having a capacity in exces s of 750 MW, as here, Section 169A(b) of the CAA requires that Stat es 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 cont ained 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 e ffectiveness. For cost analyses, the Guidelines stipulate: "In order to maintain and improve c onsistency, 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 us ed for internal project justification or other accounting purposes but are not a ppropriate 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; faile d to optimize costs; dou ble counted costs; and used inflated factors. Oklahoma did not challeng e 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 Manual 28 sets out a generic method to estim ate the cost of pollution control equipment. It also provides specific cost al gorithms to estimate capital and O&M costs for some types of pollution control equipment. The Cost Manual does not include spec ific 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 Manua l, while relying on vendor quotes and other information to estimate scrubber capital a nd 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 de viates in important ways from the Cost Manual. This makes it appear that the cost to cont rol 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 pr ovided for "any unusual circumstances that exist for the source

that would lead to cost-effec tiveness estimates that would ex ceed 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 in terest. In contrast, Sargent & Lundy escalated capital costs from the year of estimate, 2010, to the year of construction; included various future cost s 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 recove ry factor. Revising th ese four factors alone significantly lowers annual costs.

1. Capital Cost: Failure To Follow Cost Manual

One of the factors that is evaluated in a BA RT determination is cost effectiveness of the control options. Cost effectiveness is determin ed 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 unle ss unusual circumstances exist at the source. 31 Thus, cost

effectiveness is a relativ e determination, based on costs borne by other similar facilities. To compare costs among units, a level playing field must be establis hed 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 Po wer 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 Co st 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 Ai r Quality, North Dakota Department of Health, Re: EPA's Comments on the North Dakota Departme nt 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, bo nd cost, and AFUDC; using an excessive contingency; and by annualizing costs using an inflated capital recove ry factor. Cost items such as escalation of costs, bond cost, and AFUDC are not part of th e 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 ty pes of costs create an unlevel playing field for comparison with other BART analyses. 33 The impact of these and ot her factors discussed in this report on the cost effectiveness anal ysis 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% fo r 2011-2015) to the year of expenditure. 34 The Cost Manual approach, recommended by the BA RT Guidance, explicitly excludes future escalation as cost comparisons are made on a current real dollar basis. In flation is not included in cost effectiveness analyses as they rely on the most accurate information available at current prices and do not try to extrapol ate 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 continge ncy and is double counted as discu ssed 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 e qual 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 constr uction 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 to tal capital expended to account for the cost of funding the cash flow during the construction period. AFUDC is an accounting method. Assets under c onstruction do not provide servi ce 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 th em 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, AF UDC 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 co st 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 co st-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 bon d costs estimated as 1% of total project

cost with escalation and con tingency, but without AFUDC. 38 The basis and justification for these costs is not stated. These costs appear to represent a portion of th e cost of financing the project and thus are similar to AFUDC. These cost s 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 ha ve set bond cost equal to zero in my cost analysis in Appendix 1, Line 42.

d. Contingency

The Sargent & Lundy capital cost estima tes 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 ra nge estimating techniques. 40 The details of how this value was calculated are not disclosed. However, it is unpr ecedented 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 compar ed 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 fo r Muskogee 4&5 as 14.085% of tota l 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/tech nical/rps/40R-08.pdf.13 management to estimate costs. Sargent & Lundy cl aims 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 for ecast 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 co sting 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 bu t 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 deliv ery of materials, but their arri val at the job site is not a problem unique to the retrofit. The standard c ontingency 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 us e 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 an d 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 th ese 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 in to a stream of equal annual payments over a given time at a given in terest 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 paymen t is calculated by multiplying the total capital investment by a capital recovery factor calculated from a form ula based on interest rate and equipment lifetime. 45 The longer the service life and the lower the inte rest 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 mentione d 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 re sulted in an annual levelized charge of 10.36%. 46
Thus, total capital costs were annualized by mu ltiplying them by 0.1036. This is equivalent to assuming a 20-year life and an interest rate of 8.23% in the capita l 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 se t 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 th e 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 effectivenes s. 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 co sts by about 30% (0.1036/ 0.0806), a significant amount when dealing with capital cost s of tens of milli ons 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. Th ere 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 handbooks 49 and published papers 50 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 & L undy cost estimate, for example, assumed a 25 year lifetime, which was lo wered to 20 years in the revised 2009 analysis

without comment. The BART determination fo r Big Stone Unit 1, on-line in 1974, assumed a 30 years scrubber life. Thus, I used 30 y ears in my revised cost estimates.

In response to questions from EPA, Sarg ent & 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 Spra y Dryer Absorber Material: Production, Characterization, Utilization Appli cations, 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 op eration 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 esta blished by the Office of Manageme nt and Budget for comparison of public policy issues. 53 Sargent & Lundy's cost estimate assu med an interest rate of 8.23% (when the effect of debt, equity and ta xes are included). It has long be en standard practice to use an interest rate of 7% in regulatory cost effectiv eness analyses, as this is the social cost of borrowing for governmental analyses. 54 In fact, permit applicati ons that AEP, the owner of Northeastern, submitted to the states of Ohio and We st Virginia, use the standard interest rate of

7%. 55 Increasing the interest rate to 8.26% from 7% while hold ing 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 construc t the project, including additional crane rental allowance, mobilization/demobilization, scaffoldi ng, temporary facilities, overtime inefficiency, per deim expense and BOP contractor's general & administrative costs, ar e 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 us ed by Sargent & Lundy are excessive for an open shop project in Oklahoma and the ge neral region, ranging from about $40 to $80/hr. Many public sources demonstrate th ese 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/o mb/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/o mb/circulars_a004_a-4/#d

.

55 Application to the West Virginia Department of En vironmental 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 Southe rn Power Company and Ohio Power Co mpany, 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 in dicates the second quarter 2010 total cost to employer for construction worker s is $31.44/hr. This is a nationa l average, incl uding 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-Bacon 58 prevailing wages on federally funded work in Oklahoma for carpenters, piledrivers, equipment operators, re inforcing steel, etc. is typically $7-11/hr throughout most of the state. The highest wage s I found were in Oklahoma County at $35/hr to $40/hr (including fringe benefits) for electricians, pipefitters, a nd sheetmetal workers. Sooner, Muskogee, and Northeastern are located in Noble, Muskogee, and Rogers counties, respectively. Open shop wages would be less than prevaili ng wages on federally f unded projects.

A 2008 wage survey 59 summarizes union and nonunion wage s by craft within regions. This survey, reproduced in Figure 1, shows that th e highest wage plus benefits in Region 6 (AR, LA, NM, OK, TX) for non-union construction work ers 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 th e wage rates assumed by Sargent & Lundy. Wages have genera lly 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, Availabl e 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 pr ojects are located.

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

Available at: http://www.agc.org/galleries/laborhr/AGC%20Craft%2 0Worker%20Compensation%20Research%20Report%20- %20Final%201-4-08.pdf.17 Figure 1

The wages used in the Sargent & Lundy analys is are factors of two to three times higher than those reported in these sour ces. The files that I reviewed contain no support for these high labor rates. I did not change the labor rates in my revised cost anal ysis as the parties declined to supply the electronic spr eadsheets with embedded calculation s, which would have facilitated such a change. Further, the spec ific craft that is required for th e various tasks is not indicated, but rather only crew names. In addition to the very high wage starti ng point, Sargent & Lundy boosted the cost of labor even more by using hi gh labor escalation rate s 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 pe r diem is included in the wage. 60 However, the cost spreadsheet in Attachment A include certain "oth er 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 ar e about $50/day to $70/day. As the costs are based on six 10 hour days, this amounts of $100 pe r day for per diem, or about $18 million for each plant.

Further, as per diem pays for living expens es, 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 fo r open shop jobs in today's soft labor market. Thus, additionally adding per diem, on top of the hi gh wage rates used to cal culate 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 pa id for a portion of the labor force, as some of the construction worker s will be drawn from the surrounding areas. This factor was not adjusted in my revised cost an alysis as the record c ontains 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 inab ility to attract labor, weather conditions, etc. 61
This is unprecedented in a cost effectiveness an alysis and is another form of contingency, specifically disallowed by the Co st Manual, as discussed above. It also is double counting as a general contingency is included else where in the cost analysis. It is unlikely that there would be any trouble attracting labor in the current and r easonably foreseeable labor market. Further, the Sargent & Lundy Design and Cost Estimate Basi s 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 tota l productivity-adjuste d 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, spec ifically disallowed by the Cost Manual, as discussed above. It also double counts, as a general contingency is in cluded elsewhere in the cost analysis. The new scrubbers would be installed during normal main tenance 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 electroni c 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 Musk ogee, 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 standa rd 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 Sargen t & Lundy's cost estimates are factored from other costs, such as total direct costs, reductions in item s included in these sums

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

costs.

a. Owner's Cost

The Sargent & Lundy cost analyses include ow ner'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 expe nded in other BART analyses. 66 These are reportedly costs incurred by the owner in managing and implementi ng 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 im plement 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 constructio n/field expenses are estimated as 10% of purchased equipment costs). Owner's cost is part of the fact ored estimate for engineering, procurement, and construction management. Owner's costs are not se parately 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 exam ple, EPA rejected the inclusion of "owner's costs" in a cost analysis fo r 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 a nd procurement as 10% of the purchased equipment cost. Sargent & Lundy estimated engin eering 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 & Aux iliary 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 Comme nts on the North Dakota Department of Health's April 2010 Draft BACT Determin ation for NOx for the Milton R. Young Station, May 10,

2010.20 include much more than just the purchas ed 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 estima tes using the Cost Manual approach of 10% of purchased equipment cost. The Cost Manual es timates 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 & L undy engineering/procurement co sts 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 cost s are typically reported on an all-in basis. Thus, because Sargent & Lundy also separately calculated engineering/procurement, the engineering and procurement costs for the vendo r-supplied portion of the capital costs are double
counted. The 6.5% factor should only apply to the balance of pl ant materials and labor, which exclude the scrubber system, fabric filter, a nd the scrubber contractor's scope for the ash recycling system.

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

material and labor costs as revi sed in Appendix 1, Line 34, are $8,371,563 71 for Sooner and $8,840,090 72 for Muskogee, or less than half of th e Sargent & Lundy estimate. This change reduces the engineering and procurement costs by $12,773,100 at Sooner 73 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 ma nagement 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", Sa rgent & 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 remove d 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 12/2 8/09 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 & L undy's analysis for "BOP contractor's general &

admin". 75

The Sargent & Lundy construction management co sts are factored from total direct costs,
calculated as 2% of total di rect 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 cons truction management costs in A ppendix 1, Line 35, to account for

other revisions I made to total direct costs. These revised fees, $5,462,095 at Sooner 76 and $5,685,568 at Muskogee, 77 were estimated as 2% of revised to tal direct costs. This reduces the construction management costs in Appendix 1, Line 35, by $1,043,955 at Sooner 78 and by $1,017,314 at Muskogee. 79

d. Startup & Commi ssioning Craft Support

Sargent & Lundy estimated startup and commi ssioning 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 Soone r). 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 a nd 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 pr oposals 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 av ailable as Sargent & Lundy did not provide an electronic copy of the Excel cost spreadsheets that contained the form ulas. 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 al l 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 f eet), 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, de positing 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 th e 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 ope rating, the vendor's cost estimate for the baghouse includes the cost of these replacement parts. Ho wever, 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 mi nimize 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 f acilities, use of exis ting equipment, and c onsideration of other scrubbing options. If the scrubbers were designed to minimize cap ital 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 & L undy were estimated on a per generating unit basis and doubled for the plant. However, cons iderable 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 a nd 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 pul verized 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 desi gning, procuring, and installing all four

identical OG&E units from the same vendor. Th e 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 s hop 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 re quired information. However, based on my experience, vendors would offer at least a 5% di scount on equipment cost for multiple identical

units. This reduction is incl uded in Appendix 1, Line 24.

b. Common Facilities

Capital and labor costs also could be re duced 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 a nd Muskogee instead of doubling the design of a single unit would reduce equipment, material, a nd 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 pieces24 of equipment. See Section III.A.2. The compan y'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 w ould be cheaper than tw o smaller ones with the same output. The reduction in costs for this fact or is included in the vendor discount adjustment in Appendix 1, Line 24.

d. Other Cost Options

There are more economical options for design ing 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-pas s 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 ch amber or absorber wher e a reagent is sprayed into the gas stream and reacts with SO2. An el ectrostatic 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 thes e 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 co al are collected in a dust collection device and can be recycled to the spray chamber to reduce li me demand. In a recycle system, these solids are collected, mixed with wa ter, and reinjected into the spray ch amber. 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 equi pment required to recycle the solids and more power and water required to operate the recycle syst em. 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 w ith recycle operations are greater than the additional lime and disposal costs without recycle. The Springerville dry scrubber was designed to achieve SO2 removal effi ciencies as high as 9 3.3% without the use of recycle. 86 Other vendors have noted th e 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 Achi eving 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 ne ed 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 (re moved 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 devi ces together are referred to as a dry scrubber or dry flue gas desulfurization unit (DFGD). The costs for th e 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 precipi tators, a dust collection device th at 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 si gnificant difference in an incr emental cost comparison with a wet scrubber, which does not require a downstream baghouse.

Existing electrostatic precipi tators are strong candidates fo r dust collection in retrofit applications. While extra collect ing surface may be needed in so me cases, they generally do not require any upgrade as the resist ivity 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 Re port 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 re move particulate would likely be much less than the cost of new baghouses. This option was not co nsidered 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 fo r Naughton 1 using the existing ESP.

Table 5 Naughton BART Analysis 91

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. Maur in, 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 Gu idelines that "it is important to include control options that involve improvement s to existing controls and not to limit the control options only to those measures that i nvolve a complete replacement of control devices." 93

iii. Fabric Filter Baghouse

The baghouse was designed to achieve a f ilterable particulate emission rate of 0.010 lb/MMBtu. However, the targeted BART filte rable emission limit is 0.10 lb/MMBtu, or ten times higher, met with the exis ting electrostatic precipitators. Thus, the baghouse included in the OG&E dry scrubber costs is over designed fo r its function in the dry scrubber. Baghouse removal efficiency increases in direct proportion to gas filtra tion 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 expens ive 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 Indust rial 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 co mprise the sum of variable O&M, fixed O&M, and indirect O&M. The Sargent & Lund y O&M cost estimates re quire adjustment of

both variable and indi rect 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/MMB tu to 0.100 lb/MMBtu (80% SO2 control or Option 2).

The Sargent & Lundy variable O&M cost s 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 pe r ton of SO2 removed, improving

the cost effectiveness of the dry scrubber. The Sargent & Lundy variable O&M costs also contain other errors, which cance l some of the O&M cost undere stimate. Each component of variable O&M cost that I adjusted to address these issues is di scussed 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 woul d be required to operate a scrubber designed to remove 80% of the SO2 fr om 0.51 lb/MMBtu coal (80% control case) while the capital costs were ba sed on a scrubber designed to re move 91% of the SO2 from a 1.18 lb/MMBtu coal (91% control cas e). As a result, Sargent & L undy 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 estim ated that 2.0 ton/hr of lime w ould 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 De sign 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. Sa rgent & Lundy used this value to estimate lime demand in a study of scrubber technol ogy 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 co st 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/yr 100 or by $4,682,111/yr for the total plant. It

increases the lime costs at Mu skogee from $1,730,600/yr to $3,968,632/yr 101 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 wa ter use are based on th e 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 S ooner 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 uppe r 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, recycl e 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 othe r similar dry scrubbers. 106 The vendor design was based on an average makeup demand within the usual report ed range for other si milar scrubbers.

Using the vendor water demand decreases th e per unit cost of water at Sooner from $95,100/yr to $85,299/yr or by $9,801/yr. At Muskogee, this adjustment d ecreases the per unit annual cost of water from $534,100/yr 107 to $443,735/yr 108 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 F GD waste disposal are based on solids to landfill (stream 12) for the 80% SO2 control opt ion and the unit cost to landfill the solids. 109

These costs assume that the Sooner scrubbe r 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 sc rubber 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 So oner increases from $1,733,500/yr to $4,102,860/yr 111 or by $2,369,360/yr . At Muskogee, this adjustment increas es the per unit cost from $1,849,300/yr to $4,504,643/yr 112 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 F GD solids is high compared to other similar BART cost analyses. The unit disposal co st 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 un it disposal cost as no information was provided about the on-site landf illing 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 agri culture, concrete, concrete products, flowable fill, mining applications, soil stabilization, stru ctural fills and embankments, and synthetic
aggregate. 115 Selling the FGD solids would reduce or el iminate 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 cleani ng. I was unable to re produce Sargent & Lundy's costs with the reported informa tion as it did not include the fl owrate 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 uni t 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 au xiliary power cost, accoun ted 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 decreas es the per unit repl acement cost from $653,300/yr to $544,026/yr 118 or by $109,274/yr . For Muskogee, my costing approach decreases the per unit replacement cost from $675,100/yr to $599,020/yr 119 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 App lications, 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 ]/[(1.07 3 - 1] = 0.3811.

118 Revised Sooner replacement cost s: [(1,724,05 1 ACFM)($3.22/ft 2 )(0.9)(0.3811)/3.5 ACFM/ft 2 = $544,026/yr

.

119 Revised Muskogee replacement cost s: [(1,846,716 ACFM)($3.31/ft 2 )(0.9)(0.3811)/3.5 ACFM/ft 2 = $599,020/yr

.31 The decrease in bag and cage replacement cost is included in my revi sed cost estimate in Appendix 1, Line 54.

v. Auxiliary Power Costs

Auxiliary power is the sum of the dema nd 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 co sts are overestimated for two r easons. 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 th an 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 Do cument from individual motors based on the 91% SO2 control case; 121 (3) assumed by Sargent & Lundy in the National Lime Association Report for simila r plants (1.2% gross output); 122 and (4) estimated by the vendors. The various estimates of auxiliary power, a ssuming 90% capacity factor, are summarized in

Table 6.

Table 6 Auxiliary Power Per Unit (MWh/yr)

Estimate Sooner Muskogee Source S&L Cost Estimate 67,290 123 67,644 12/28/09 S&L Followup Report, pdf 101-104

S&L Cost Estimate Based on Stated Assumptions 67,408 124 67,645 12/28/09 S&L Followup Report, pdf 101-104 S&L Design Document 58,342 125 61,495 12/28/09 S&L Followup Report, pdf 84-87

S&L National L ime Report 53,927 126 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 & L undy's cost estimate is also high compared to other estimates. They assumed $85.93/MW h 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 regul ated 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 wi nter 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 an alyses typically estimate auxiliary power at $50/kW or less. The Northeastern cost effec tiveness 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 aux iliary power costs in the Follo wUp Report indicates the range

for other similar faciliti es 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 analys es 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% (M uscogee) of total capital investment and insurance as 0.0105% of total capital investment. As total capital investment was revised as discussed above, the fact ors that rely on them must also change. This is accommodated in my cost analysis in Appe ndix 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/residen tial-customers/billing-and-pa yment/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 anal yses relied on in Oklahoma's SO2 BART determination significantly overstate the cost of the proposed contro l. My revisions, summarized in Appendix 1, lower the calculated cost effectiveness for Sooner from $6,724/ton 130 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/h r, 1.44 lb SO2/MMBtu) in a March 2007 report prepared for the National Lime Association. In th is study, the calculated co st effectiveness of a 500 MW retrofit dry scrubber on low sulfur PR B coal (1.44 lb/MMB tu) based on 95% SO2 control in 2006 dollars was $1,320/ton. 131 Adjusting to 2009 dollars, th e 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 appl es-to-apples cost effectiveness analysis prepared pursuant to the EPA Cost Manual.

Capital costs are commonly expressed as dollars per kilowatt of capacit y. The total direct capital costs, when reduced to dollars pe r 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 seri ous retrofit issues. The plot plans indicate no retrofit issu es that would justify such hi gh 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) pres ented a graphic of capital cost as a function of generating capacity in 2007 that su mmarizes a wide range of scrubber cost data (2004-2005), reported in year-end 2005 do llars 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 estima te for a ready-to-operate syst em 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, J une 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 da ta, 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-appl es comparison with the Sargent & Lundy data reported in the UARG study, my unit cost woul d increase from $265/kW to $362/kW, at the upper end of the range. The much higher va lues on Figure 2, >$350/kW to $500/kW, are for smaller units on sites with signifi cant retrofit issu es. Sargent & Lundy's capital cost estimates for Sooner and Muskogee correspond to those exp ected for small units, 200 MW to 400 MW on sites with significant retrofit issues, which are no t present at either Sooner or Muskogee.

IV. REVISED COST ANALYSIS FO R NORTHEASTERN DRY SCRUBBER

The Northeastern BART cost effectiveness analysis is contained in the 5/30/08 Trinity Report, Appendix F. It concluded the cost eff ectiveness 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 ca lculations for their modification. Thus, my review is based on the 5/30/08 Trinity Report. The Trinity analys is significantly overestimates the dollars per

ton cost to control SO2 with a dr y scrubber for the reasons discusse d below. The format of my Northeastern review differs from my Sooner an d Muskogee review due to differences in the costing methodologies.

A. CAPITAL COST

The total capital investment and annual capital cost are bot h 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 s upported, but simply state d. It is reported as $555/kW in the Trinity Report 137 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 i ssues. These elevated values correspond to smaller units with significant retrofit issues. AEP, the owner of Northeastern, has pub licly 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 w ould lead to such a high unit capital cost.

The unit capital cost for the tw o coal-fired Northeastern units should be about the same as for Sooner and Muskogee. These six units are sim ilar-sized, tangentially-fi red 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 esti mate using the average capital cost from my revised Sooner and Muskogee analysis in Append ix 1, Line 65. This value is $265/kW, without escalation, AFUDC, bond costs, an d 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 (ODE Q), 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.

138 1/19/10 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). Th e Trinity analysis uses th e correct capital recovery method, but uses incorrect inputs.

The capital recovery factor depends on th e service life of the equipment and the public interest rate, 7%. The higher th e 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 previous ly explained in Section III.B .1.h. The revised Northeastern analysis in Appendix 2, Line 67, is based on capita l 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 a nd 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 omi ssions are discussed below and corrected in Appendix 2.

1. Water

A dry scrubber requires water to prepare th e reagent slurry and to cool the flue gas stream. The cost to supply water was not include d in the Trinity analysis. I added water cost,

scaled from the water demand for Sooner and Mus kogee. See Section III.B.4.a.ii. The average cost of water, based on Sargent & Lundy's tabulati on 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 ei ght 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 furthe r can be optimized. Thus, they w ould be expected to fall at the lower end of the reported range, or $5/ton. Th erefore, in Appendix 2, Line 24, I estimated the cost of on-site landfill dispos al assuming that 5 pounds of solid s would be generated for each pound of SO2 removed and that it would co st $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 th e 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 sa me as those calculated by Sargent & Lundy for Sooner and Muskogee, or an average of about $4 m illion 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 an alysis for Sooner and Muskogee indicates that

insurance rates for similar facili ties are about a factor of ten lower, or 0.0105% of total capital

investment. 143 Thus, I revised the Northeastern insura nce 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 capita l investment, based on the Cost Manual default. The Sargent & Lundy an alysis 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 revi sed cost estimate assume s the upper end of the OG&E range or 0.85% of total capital investme nt. 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 discu ssed for Sooner and Muskogee exist here. The capital and O&M costs for Northeastern were sc aled 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. Th is 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 scr ubber. 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 effec tiveness, 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 dollars 147 or $1,340/ton 148 in 2009 dollars.

V. COST EFFECTIVEN ESS: 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 Bl uff 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 dolla rs 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 Appendi x 1, Line 63 for Sooner and Muskogee and in Appendix 2, Line 47 for Northeastern. A control t echnology is considered to be "cost effective" if it falls within a reasonable range of cost-e ffectiveness estimates. "A reasonable range would be a range that is consistent wi th the range of cost effectivene ss 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 app lications in the utility industry. 150 Thus, dry scrubbing is clearly cost effective, barring an unusual, site specific condi tion. 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 Northeaste rn Units 3 and 4. Oklahoma reported costs far above the usual range for similar fac ilities, 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 analys es 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 misce llaneous 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 effectivene ss values for dry scrubbers on other similar facilities burning low sulfur Powder River Basin co al. Most of these determinations, prepared by engineering firms to estimate actual costs rath er than regulatory costs, incorrectly contain escalation, contingency, and AFUDC deviations from the Cost Manua l, 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 revi sed numbers, I added back in AFUDC, escalation, and contingency to my estimat es 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 Northe astern ($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 App lications, 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 accuracy 152 of the cost estimate (+/-30%). 153 They are also well within the range of

values that have been found to be cost eff ective 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 scr ubbers at Northeastern, projected to be in service by 2012-2014. 154

VI. BART EMISSION LIMIT: DRY SCRUBBER

The Oklahoma Regional Haze SIP concluded th at BART for SO2 for Sooner, Muskogee, and Northeastern is a 30-day ro lling average emission rate (at the stack) of 0.65 lb/MMBtu and a 12-month rolling average of 0.55 lb/MMBt u, achieved using low sulfur coal. 155 These emission limits are higher than the presumptive BART limits and higher than achievabl e with current coal. A dry scrubber was eliminated based on cost effec tiveness. The underlying analysis is not valid as costs were significantly overe stimated, as explained above. Th is section discusses what the BART emission limit should be for a dry scrubber, gi ven that it is cost eff ective. As explained below, a wet scrubber could achieve a lower emi ssion limit and is cost e ffective and otherwise

feasible.

152 Cost estimates that are within the acc uracy 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/to n for a dry scrubber at Northeastern. However, the upper end of this range is in cremental cost effectiveness fo r a wet scrubber, not average cost effectiveness for a dry sc rubber. Incremen tal 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, Tabl es VI-6, VI-7, and VI-10.41 Table 7 Comparison of SO2 BART Co st 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&2 156 2x750 1.88 92 0.15 1,280 Big Stone 1 157 475 0.86 90 0.09 1,462 Nebraska City 1 158 650 0.815 88 0.10 1,636

Boswell 3 159 375 0.947 90 0.09 1,640 Sooner (Ex. 1) 2x570 1.18 91 0.10 1,670 Presumptive Muskogee 160 650 0.02 1,694 Muskogee (Ex. 1) 2x572 1.18 91 0.10 1,738 Naughton 1 161 176 1.18 87 0.15 1,877 Naughton 2 162 234 1.18 87 0.15 1,882

Stanton 1 163 188 1.2 90 0.12 2,006 Northeastern 3&4 2x470 0.91 83 0.15 2,232

White Bluff 1 & 2 164 2x850 0.68 92.5 0.15 2,430

156 ENSR Corporation, BART Analysis for the White Bl uff 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 Generatin g Station Unit 1, Best Available Retrofit Technology Analysis, November 2, 2009, Section 3.0.

158 Nebraska Department of Environm ental 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, D ecember 2009, Appendix 9.2,

Memorandum from Anne Jackson to File Re: BART Dete rmination 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.

160 Technical Support Document for the Best Available Re trofit Technology (BART) Notice of Final Rulemaking, Setting BART SO2 Limits for Electric Generating Units: Co ntrol Technology and Cost-E ffectiveness, 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 H aze 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 Pl an, 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 7 165 142 0.83 85 0.13 2,544

Gerald Gentleman 166 2x750 0.75 80 0.15 2,726

Drake 6 167 85 0.82 85 0.13 2,816

Boardman 168 617 0.61 80 0.12 3,055 Silver Bay 2 169 75 0.60 90 0.06 3,547

The BART analysis must include the maxi mum level of control th at each technology is capable of achieving. 170 In analyzing a technology, "you take into account the most stringent

emission control level that the t echnology is capable of achieving." 171 This is important as "[a]n unrealistically low assessment of the emission reduction potentia l of a certain technology could result in inflated cost-effectiveness figures." 172 This has happened here.

The BART analysis evaluated a control effici ency 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 emi ssion control levels that a dry scrubber is capable of achieving.

In its report for the National Lime Asso ciation, 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, D ecember 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 wate r 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 betw een 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 al so 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 rem oval efficiencies, up to 96%, have been demonstrated at a 600 MW PRB coal fired plan t 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 selec ting coal to assure the limit is met. Similarly, a dry scrubber designed to remove 93% of the SO2 from an in let of 0.91 lb/MMBtu woul d 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 SO 2 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 SO 2 from a 1.18 lb/MMBtu coal would routinely achieve 95% when burning this coal. However, if the sulf ur 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 manuf acturers 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 averag e, when burning coal containing 0.51 to 1.18

lb/MMBtu SO2. The same is true for Northeaster n. The reduction in removal efficiency of the dry scrubber would be offset by th e 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 comparab le levels that are bui lt or being built.

The Nevada Bureau of Air Pollution Contro l, for example, issued a PSD Operating

Permit to Construct to Newmont Nevada Ener gy 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 aver age and 95% minimum SO2 removal efficiency, when combusting coal with a su lfur content equal to or greater than 0.45% (30-day rolling period)

• 0.065 lb/MMBtu on a 24-hour rolling aver age and 91% minimum SO2 removal efficiency, when combustion coal with a sulfur conten t 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 th e 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 Qu ality 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 0.201/1/20083/1/20085/1/20087/1/20089/1/200811/1/20081/1/20093/1/20095/1/20097/1/20099/1/200911/1/20091/1/20103/1/20105/1/20107/1/20109/1/201011/1/2010

TimeSO2 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 supe rcritical boilers that w ill 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. Th e SO2 BACT limits are tiered based on sulfur content as follows:

 0.065 lb/MMBtu on a 30-day rolling aver age when the uncontrolled sulfur

dioxide emission rate is less th an 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/MMB tu but less than 1.25 lb/MMBtu;

 0.105 lb/MMBtu on a 30-day rolling aver age when the uncontrolled sulfur dioxide emission rate is gr eater 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 emi ssion 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.g a.us/gaairpermits/PermitPDF .aspx?id=PDF-PI-18499.46 VII. WET SCRUBBING

There are two general classes of technol ogies that are widely used to control SO 2 emissions: dry flue gas desulfurization (“DF GD” 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 dr y to wet scrubbing was judged unacceptable; and wet scrubbing was alleged to have certain adve rse 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 ha s the same adverse impacts as all other wet scrubbers, none of which are unique or unusual. The BART analysis mu st 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 e fficiency. 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 in flated cost-effectiveness figures." 178 These Guidelines further require that "in analyzing the tec hnology you take into account the most stringent

emission control level that the t echnology 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 achie ve 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 si milar low sulfur PRB co al (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 gu arantees, from the original eq uipment 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 Pr airie 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 Nort heastern. This level of control would yield an emission limit of 0.04 lb/MMBtu, which has b een achieved at Pleasant Prairie (Fig. 4).

B. COST EFFECTIVENESS OF WET SCRUBBING

The companies and ODEQ estimated the averag e and incremental cost effectiveness of both dry and wet scrubbing. In general, the averag e 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 larg e absorber is used for the wet scrubber 183 while two smaller absorbers are required for the dry scrubber or in retrofit applicatio ns that have existing electrostatic precipitato rs. I would expect th is 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 sc rubbing 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 we t scrubber is typically about 9% higher than for a dry scrubber, excep t 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 scrubbi ng 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 analys es 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 effectiven ess for wet scrubbing based on the ratio of my revised value for dry scrubbing to the company estimate for dry scrubbi ng. 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 co llateral impacts including: (1) increased sulfuric acid mist (SAM) in the flue gas; (2) excess pa rticulate emitted due to location of scrubber downstream of particulate control device; (3) uses more reactant, generating more fugitive dust; (4) uses significantly more wate r; (5) generates a wastewater st ream that must be treated; (6) creates higher visibility impairment due to lowe r exit velocity, lower stack temperature, and higher SAM emissions. These claimed adverse imp acts are either wrong or overstated. Further, ODEQ failed to point out the benefits of wet FG D 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 su lfuric 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 leve ls 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. Er ickson, 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 Research49 Further, Sargent & Lundy note: "low-and medium -sulfur coals [which include the PRB coals used by OG&E and AEP/PSO]...typically pr oduce 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 contro l efficiency increases from a dry scrubber, SAM control decreases. A much hi gher SO2 control efficiency can be obtained

with wet scrubbers without the risk of increased SAM emissions.

Further, as discussed below, a dry scrubber mu st be taken off-line pe riodically to change out the atomizer. During these changeout peri ods, 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 or der to meet the SO2 limit, these very high changeout emissions must be averaged out by oper ating the dry scrubber at a higher SO2 control efficiency, up to 98%, for enough time to offset the short-term, uncontro lled 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 emission s, increasing the cost of the dry scrubber

relative to the wet scrubber.

2. Water

The ODEQ alleges that wet scrubbers use "si gnificantly 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 we t scrubber is a small fract ion of the total plant water demand. Typically, about 90% of the freshwat er water is used for wet cooling, 2% for wet scrubbing, and the balance for ash sluicing, bo iler 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, Opera tional Limits on Semi-dry Absorbers, p. 1.

191 1/30/07 Meadows E-mail, p. 2. ("Th ere 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 th e 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 gene rates 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 saleab le gypsum is not produced. This wastewater can be reused elsewhere in the plant.

There are several options for treating FGD wa stewater: (1) eliminate the discharge using a zero liquid discharge system; 192 (2) treat the wastewater wi th the power plant combined wastewater, thus not requ iring a separate wastewater treatment system; (3) treat and discharge the wastewater separately (the only option men tioned); 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 wi ll 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 rem oved by the mist eliminator at the top of the scrubber, which is an integral part of a wet scrubbe r. This mist eliminator is typically specified to require that outle t particulate loading is no higher than inlet particulate load ing. Therefore, by design, the wet scrubber makes no net c ontribution 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 utilizati on of a dry system is poorer compared to a wet system, i.e., it takes more tons of reagent to re move 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 re sult 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 reduc tions 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 a ffect 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 th roughout Europe and could be used with either wet or dry scrubbing to improve plume buoya ncy. This option was not evaluated.

D. BENEFITS OF WET SCRUBBING

The beneficial and adverse impacts of both sc rubbing technologies must be evaluated. The ODEQ only identified advers e impacts of wet scrubbing compared to dry scrubbing. However, wet scrubbing has many beneficial imp acts 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 emissi on rates during atomizer change-out at a dry scrubber, creates a reusable bypr oduct, and does not contaminate th e flyash. Furthermore, some types of wet scrubbers, such as the Chiyoda bubb ling jet reactor and the double contact absorber, have fewer environmental impacts than the c onventional wet scrubber that was evaluated by ODEQ, e.g., uses less power, removes more sulfur ic acid mist, particulate matter, and mercury.

1. Reliability

Wet scrubbers have a much longer and mo re extensive operating history than dry scrubbers. Wet scrubbing systems have demonstrat ed 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 un its, maintained an availability of only 95%. 196

2. Maintenance Emissions

Dry scrubbers have very high short-term emi ssions and typically have permits that allow high 1-hour, 3-hour, and 24-hour emission lim its 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 re moved, 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 Ma nuel 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, reduc ing the control efficiency of the dry scrubber by up to 50%. 198

At the subject plants, two dry scrubber modul es 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 asse mbly. During this time, approxi mately half of the flue gas stream is uncontrolled, although some SO2 removal may still take place with in the filter cake in the baghouse, if a baghouse is us ed to control particulate matt er. The wet scrubber does not require similar routine maintenance and t hus does not have elevated short-term SO 2 emissions, a substantial advantage of the wet scrubbing over the dry system. Mitigating these short-term emissions would require a spare absorber or exce ss 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 scrubbe r as it is capable of greater SO2 removal efficiency, up to 98%. Pleasa nt Prairie Units 1 and 2, similar boilers that burn a low sulfur PRB coal similar, were retr ofit 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 scr ubber easily meets a 365-day rolling average of less than 0.03 lb/MMBtu. Comparably low SO2 em ission limits have been established in BACT analyses and required in PSD permits, achieved w ith 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 0.0501/1/20073/1/20075/1/20077/1/20079/1/200711/1/20071/1/20083/1/20085/1/20087/1/20089/1/200811/1/20081/1/20093/1/20095/1/20097/1/20099/1/200911/1/20091/1/20103/1/20105/1/20107/1/20109/1/201011/1/2010

TimeSO2 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 mo st stringent combination of c ontrol 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 averag e, 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, compar e the blue line (30-day average) with the red line (24-hr average). This comp arison indicates that a 30-day av erage is generally lower than a 24-hour average. The longer averaging time allo ws short-term spikes to be averaged out.

199 U.S. EPA, Region 9, Ambient Air Quality Imp act Report, Desert Rock, p. 18. Available at: http://www.regulations. gov/search/Regs/home.html#docketD etail?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.5455 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 5 203

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 86,859,60 0 86,859,600 86,741,200 86,741,200 13 Fabric Filter 46,335,00 0 46,335,000 45,872,900 45,872,900

14 Ash Recycling System - DFGD Contractor's Scope 11,116,90 0 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 42,463,00 0 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 Co mparison 351 37257 1 

### APPENDIX 2

2 Revised Cost Effectiveness Analysis for
3 Flue Gas Desulfurization at

4 Northeastern Units 3 & 4 204

5

6

7 Trinity a 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, BA RT Economic Analysis for DFGD (SO2). Modified to replace $555/kW with $582/kW, based on 1/19/10 ODEQ BA RT Report, Table 11.