Capital Costs Total Direct Capital

Technology

LNB-OFA

Material Capital Costs1

Total Capital Cost Plus Installation $16,000,000

Annual Costs2

Parameters/Costs Equation Unit 1

Boiler design capacity, mmBtu/hr (C) C 6324

Annual operating hours, hr/yr (H) H = average from 2001-2003 7752

Capital recovery factor

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = 

equipment life 0.11

a. Equipment CRF, 15-yr life, 7% interest

Direct Annual Operating Costs $/yr

Variable O&M Costs

=(0.027 mills/kW-hr/1000) x (1 kW-hr/10,000 Btu) x H x C x 

10^6 Btu/mmBtu $132,364

Indirect Annual Costs, $/yr

1. Fixed O&M Costs (1.5% of capital cost) = 0.015 x TCI $240,000

2. Annualized capital cost = Equipment CRF x TCI $1,756,714

Total Annual Costs ($/yr) $2,129,078

LNB/OFA Capital and O&M Cost Estimate

1

 Public Service Commission Docket 12-008-U.

2

 Annual cost calculation methods for variable costs and fixed costs from Eastern Research Group "Analysis of Combustion Controls for Reducing NOx 

Emissions from Coal-fired EGUs in the WRAP Region" September 6, 2005. Section 4.3.1 and Appendix D. 

Note: The variable rate used for variable O&M costs was 0.027 mills/kW-hr. This is the rate listed in Appendix D
Capital Costs Total Direct Capital

Technology

SCR

Installed Capital Cost1$121,440,000

Annual Costs

Variable

Urea1$2,200,000

Catalyst replacement (per 

year)1$1,500,000

Total Variable O&M1$3,700,000

Fixed

Operating Labor Cost2$530,000

Maintenance Labor3$530,000

Maintenance Material1$500,000

Total Fixed O&M1$1,560,000

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I 

= interest rate, a = equipment life 0.09

a. Equipment CRF, 20-yr life, 7% 

interest

Annualized capital cost = Equipment CRF x TCI $11,463,077

Total Annual Costs ($/yr) $16,723,077

2

 Annual estimates provided by AEP based on 1 person per shift for 5 shifts.

3

 Annual estimates provided by AEP based on 1 person per shift for 5 shifts.

Capital recovery factor

SCR Capital and O&M Cost Estimate

1

 All capital and O&M cost estimates provided by AEP are based on engineering estimates. The engineering 

estimates were informed by AEP's experience with SCR installations at other plants owned by AEP
Capital Costs

Technology

SNCR

Parameters/Costs Equation Unit 1

Boiler design capacity, mmBtu/hr (QB) QB 6324

Total operating time (top, hrs/yr) top = CFtotal × 8760 hrs/yr 7752

Total Capacity Factor (CFtotal) CFtotal = CFplant × CFSNCR 0.92

Plant Capacity Factor (CFplant)

2

0.92

SNCR Capacity Factor (CFSCNR)

3 CFSNCR = tSNCR/365 1

Assumed NOx removal efficiency (ηNOx)

4

35%

Uncontrolled NOx rate (NOxin, lb/MMBtu)50.33

Electricity Cost (Costelect, $/kwh)6$0.05

Water Cost (Costwater, $/gal)7$0.00362

Coal Cost (Costcoal, $/MMBtu)8$2.50

Coal HHV (Btu/lb)99,000

Cost of Ash Disposal (Cash, $/ton)10 $9.0

Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life 0.09

a. Equipment CRF, 20-yr life, 7% interest

Cost Index10

a. 2011 Cost Index 585

b. 1998 Cost Index 389.5

Capital Costs 

Direct Capital Cost (A) DC ($) = ($950/MMBtu) × QB × ((2375 MMBtu/hr/QB)^0.577) × (0.66 + 0.85ηNOx) × (CI2011/CI1998) $5,007,199

Indirect Installation Costs ($)

General Facilities 0.05 × A $250,360

Engineering and Home Office Fees 0.10 × A $500,720

Process Contingency 0.05 × A $250,360

Total Indirect Installation Costs (B) = General Facilities Cost + Engineering and Home Office Fees + Process Contingency $1,001,440

Other Installation Costs ($)

Project Contingency (C) C = 0.15 × (A + B) $901,296

Total Plant Cost (D) D = A + B + C $6,909,934

Allowance for Funds During Construction (E) E = 0 (Assumed for SNCR) $0

Royalty Allowance (F) F = 0 (Assumed for SNCR) $0

Preproduction Cost (G) G = 0.02 × (D + E) $138,199

Inventory Capital (H)11 H = Volreagent (gal) × Costreagent ($/gal) $76,102

Costreag, 50% Urea solution ($/gal)12 1.54

Volume of Reagent Tank (Volreagent (gal)) Volreagent (gal) = qsol x days of reagent supply × 24 hr/day 49,417

Urea solution volumetric flow rate (qsol, gal/hr)13qsol = (msol x 7.481 gal/ft3)/ρreagent 147.07

Mass flow rate of urea solution (msol, lb/hr)14 msol = mreagent/Cureasol 1,395.84

Mass flow rate of reagent (mreagent, lb/hr)15 mreagent = (NOxin x QB x ηNOx × NSR x Mreagent)/(MNOx x SRT) 697.92

Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOxin + 0.7] × ηNOx)/NOxin 1.43

Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no catalyst) $0

Total Capital Investment (TCI) (Capital Cost) TCI = D + E + F + G + H + I $7,124,235

Annual Costs ($)

Annual Maintenance Cost (J) J = 0.015 × TCI $106,864

Annual Reagent Cost (K) K = qsol × Costreag × top $1,755,781

Annual Electricity Cost (L) L = P × Costelect × top $58,064

Power (P, kW) P = (0.47 × NOxin × NSR × QB)/9.5 149.80

Annual Water Cost (M) M = qwater × Costwater × top $18,775

Water flowrate for SNCR system (qwater, gal/hr)16qwater = (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 669.06

Annual ΔCoal Cost (N) N = ΔCoal × Costcoal × top $109,558

Additional coal required (ΔCoal, MMBtu/hr)17 ΔCoal = (Hv × mreagent × [(1/Cureasolinj) - 1])/106

 Btu/MMBtu 5.65

Annual ΔAsh Cost (O) O = (ΔAsh × Costash × top)/2000 lb/ton $1,643

Additional ash generated (ΔAsh , lb/hr)18 ΔAsh = (ΔCoal × ashproduct × 106 Btu/MMBtu)/HHV 47.11

Direct Annual Costs (DAC)/Variable O&M DAC = J + K + L + M + N + O $2,050,684

Indirect Annual Costs (IDAC)/Annualized Capital Cost IDAC = CFR × TCI $672,477

Total Annualized Costs (TAC) TAC = DAC + IDAC $2,723,162

Selective Non-Catalytic Reduction Capital and O&M Cost Estimate1
1

 All SNCR costing equations from EPA Air Pollution Control Cost Manual (APCCM), 6th Edition (January 2002)

2 Plant capacity factor from plant data

3

 tSCNR assumed to be 365 days

4

 ηNOx (NOx removal efficiency) assumed to be 33% for SNCR alone

5 24-hr NOx rate 46,680 lbs/day - from Clean Air Markets Database, with a heat input of 6324 MMBtu/hr

6

 Electricity cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1

7

 Water cost estimate from Bentonville, AR commercial rate of $0.00362/gal, http://www.bentonvillear.com/utbc_rates.html

8 Cost of coal from Lazard's 2009 Levelized Cost of Energy Analysis (LCOE)

10 Cost of ash disposal from BART Analysis for NCS Unit 1, Appendix A

11 From Chemical Engineering Plant Cost Index (CEPCI) 

12 Cost for urea stored on site, i.e., the first fill of the reagent tanks. 

14

 ρreagent = 71.0 lb/ft3

15 Cureasol = urea solution concentration = 50%

18 Approximate heat of vaporization of water at 310°F, Hv = 900 Btu/lb From EPA APCCM, 2002

19 Ashproduct is the fraction of ash produced as a byproduct of burning a given type of coal. Assumed ashproduct = 0.075 from EPA APCCM, 2002 for subbituminous coal.

9

 Coal used at AEP Flint Creek originates from Powder River Basin near Gillette, WY and is considered to be subbituminous (source: http://www.aecc.com/about/generationfacilities/)

HHV for subbituminous coal ranges from 8,000 - 10,000 Btu/lb (EPA APCCM, 2002). 

Using HHV of 9,000 Btu/lb

13 Five-yr average urea cost = $356.11/metric ton, from http://www.indexmundi.com/commodities/?commodity=urea&months=180

Density of 50% urea solution = 9.5 lb/gal (50% urea solution) based on EPA APCCM, 2002

Equates to $1.54/gal

16 Mreagent = 60.6 g/mol (molecular weight of urea)

 MNOx = 46.01 g/mol (molecular weight of NO2)

 SRT = 2 (ratio of equivalent moles NH3 per mole of urea)

17 Concentration of stored urea, Cureasolstored = 50%

 Concentration of urea injected into SNCR system, Cureasolinj = 10%

 From EPA APCCM, 2002
Capital Costs1

NID FGD + FF $ 243,881,264

NID By-Product Handling $ 38,792,582

Balance of Plant (BOP) Construction Total $ 59,656,085

Contingency & Allocations $ 88,119,783

Total Capital Investment (TCI) $ 430,449,714

Annual Costs

Variable O&M2$/year $6,620,000

Auxiliary Power2$/year $4,186,080

Total Fixed O&M2$/year $4,210,000

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I = 

interest rate, a = equipment life 0.08

a. Equipment CRF, 30-yr life, 7% interest

Annualized Capital Cost = Equipment CRF x TCI $34,688,394

Total Annual Costs ($/yr) $49,704,474

2 Total O&M Costs ($/year) from AEP based on information gathered from a detailed estimate developed 

for the simailar study at another AEP facility (Big Sandy FGD Project), scaled to account for the slightly 

smaller unit size at Flint Creek.

NIDS Capital and O&M Cost Estimate

Capital recovery factor

1

 From "FC DFGD & FF Budgetary Cost Estimate Breakdown (Class 4)."
Capital Costs1

WFGD + FF $ 444,439,524

Waste Water Treatment $ 22,685,874

Boiler Modifications $ 3,816,274

Balance of Plant (BOP) Construction Total $ 15,708,422

Contingency & Allocations $ 46,599,533

Total Capital Investment (TCI) $ 533,249,627

Annual Costs

Variable O&M2$/year $5,360,000

Auxiliary Power2$/year $8,023,320

Total Fixed O&M2$/year $4,730,000

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I = 

interest rate, a = equipment life 0.08

a. Equipment CRF, 30-yr life, 7% interest

Annualized Capital Cost = Equipment CRF x TCI $42,972,670

Total Annual Costs ($/yr) $61,085,990

2 Total O&M Costs ($/year) from AEP based on information gathering from a detailed estimate developed 

for the simailar study at another AEP facility (Big Sandy FGD Project), scaled to account for the slightly 

smaller unit size at Flink Creek.

Wet Flue Gas Desulfurization (WFGD) Capital and O&M Cost Estimate

Capital recovery factor

1

 From "Budgetary Cost Estimate Breakdown for FC WFGD & FF."
AEP Flint Creek

Baseline Emissions

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

Caney Creek 21 3 0.668 14 4 0.734 20

Hercules-Glades 24 5 0.730 19 3 0.734 17

Mingo 13 3 0.653 7 0 0.444 4

Upper Buffalo 27 9 1.034 21 10 1.066 28

2001 2002
Total Total Highest

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

No. of Days 

with ∆dv ≥ 

0.5 

No. of Days 

with ∆dv ≥ 

1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

7 0.993 55 14 0.993 1.408

4 0.705 60 12 0.734 2.186

2 0.409 24 5 0.653 1.553

4 0.745 76 23 1.066 2.585

2003
AEP Flint Creek

Post Control Emissions

Scenario 1 - NOx Control (SCR)

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Caney Creek 7 1 0.499 1.105 9 0 0.583

Hercules-Glades 18 3 0.627 1.405 11 1 0.601

Mingo 10 0 0.611 0.913 2 0 0.404

Upper Buffalo 20 4 0.701 1.758 16 8 1.011

Scenario 2 - SO2 Control (Dry Scrubber)

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Caney Creek 1 0 0.346 0.587 3 0 0.309

Hercules-Glades 1 0 0.263 0.656 2 0 0.311

Mingo 3 0 0.216 0.693 0 0 0.189

Upper Buffalo 7 1 0.497 1.121 4 2 0.316

Scenario 3 - NOx Control (LNB + OFA)

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Caney Creek 17 2 0.614 1.286 10 3 0.706

Hercules-Glades 22 5 0.652 1.422 14 3 0.683

Mingo 11 2 0.639 1.224 6 0 0.433

Upper Buffalo 24 5 0.926 1.786 18 8 1.030

Scenario 4 - NOx Control (LNB + OFA + SNCR)

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Caney Creek 16 2 0.594 1.255 10 2 0.679

Hercules-Glades 22 5 0.646 1.419 13 2 0.676

Mingo 11 2 0.634 1.170 5 0 0.431

Upper Buffalo 23 4 0.887 1.781 18 8 1.028

Note: 

Since this is refined modeling (using the refined CALMET dataset), use the 98th percentile or 8th highest value in analyzing visibility.

(Source: Letter from Guy Donaldson at EPA to Anthony Davis at ADEQ, dated 4/26/12)

Scenario 5 - SO2 Control (Wet Scrubber)

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Caney Creek 1 0 0.353 0.616 3 0 0.342

Hercules-Glades 1 0 0.283 0.722 2 0 0.348

2001 2002

2001 2002

2001 2002

2001 2002

2001 2002
Mingo

30 0.225 0.72000 0.201

Upper Buffalo82 0.523 1.23642 0.340
Total Total Highest Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

0.991 17 3 0.784 1.043 33 4 0.784 1.105

1.017 14 3 0.614 1.676 43 7 0.627 1.676

0.836 4 1 0.311 1.167 16 1 0.611 1.167

1.816 19 3 0.621 1.297 55 15 1.011 1.816

Total Total Highest Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

0.749 2 0 0.335 0.673 6 0 0.346 0.749

0.730 2 0 0.269 0.878 5 0 0.311 0.878

0.388 1 0 0.201 0.630 4 0 0.216 0.693

1.469 1 0 0.308 0.512 12 3 0.497 1.469

Total Total Highest Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

1.164 19 5 0.924 1.265 46 10 0.924 1.286

1.285 15 4 0.676 2.023 51 12 0.683 2.023

0.867 4 2 0.375 1.427 21 4 0.639 1.427

2.294 26 4 0.719 1.352 68 17 1.030 2.294

Total Total Highest Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

1.134 19 5 0.900 1.213 45 9 0.900 1.255

1.229 15 4 0.665 1.964 50 11 0.676 1.964

0.862 4 2 0.363 1.382 20 4 0.634 1.382

2.188 26 4 0.712 1.342 67 16 1.028 2.188

value in analyzing visibility.

Total Total Highest Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

0.808 2 0 0.337 0.716 6 0 0.353 0.808

0.749 2 0 0.276 0.885 5 0 0.348 0.885

2003

2003

2003

2003

2003
0.403

10 0.210 0.63740 0.225 0.720

1.52310 0.370 0.509 134 0.523 1.523
max impact 98% #days %vis improvement

1.105 0.784 33 21.0%

1.676 0.627 43 14.6%

1.167 0.611 16 6.4%

1.816 1.011 55 5.2%

0.749 0.346 6 65.2%

0.878 0.311 5 57.6%

0.693 0.216 4 66.9%

1.469 0.497 12 53.4%

1.286 0.924 46 6.9%

2.023 0.683 51 6.9%

1.427 0.639 21 2.1%

2.294 1.030 68 3.4%

1.255 0.900 45 9.4%

1.964 0.676 50 7.9%

1.382 0.634 20 2.9%

2.188 1.028 67 3.6%
Baseline 

Emission 

Rate

Controlled 

Emission 

Level1

Annual Heat 

Input3

Controlled 

Emission 

Rate SO2 Reduced Capital Cost

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($)

NIDS 211,641.00 0.06 37,344,776 1,120.34 10,520.66 430,449,714

Wet Scrubber211,641.00 0.04 37,344,776 746.90 10,894.10 533,249,627

2

 NIDS and Wet Scrubber cost information from vendor communciation/estimates

1

 EPA Basic Concepts in Environmental Sciences, Module 6: Air Pollutants and Control Techniques 

http://www.epa.gov/eogapti1/module6/sulfur/control/control.htm

In conjunction with vendor estimates

3

 Baseline heat input was determined from CAMD, 2001-2003, average daily heat inputs times the average number of operating hours from 2
Annual 

Capital Cost

Annual Fixed 

O&M

Annual 

Variable 

O&M

Total Annual 

Cost

Cost 

Effectiveness

Incremental 

Cost 

($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)

34,688,394 4,210,000 10,806,080 49,704,474 4,724 -

42,972,670 4,730,000 13,383,320 61,085,990 5,607 30,477

e number of operating hours from 2001-2003.
Baseline Emission 

Rate

Controlled 

Emission 

Level

Annual Heat 

Input4

Controlled 

Emission 

Rate

NOx 

Reduced Capital Cost

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($)

LNB/OFA15,120.27 0.23 37,344,776 4294.65 825.62 16,000,000

LNB/OFA/SNCR25,120.27 0.20 37,344,776 3771.82 1348.44 23,124,235

SCR35,120.27 0.07 37,344,776 1251.05 3869.22 121,440,000

3

 SCR Cost information: Please refer to Appendix B.

1

 LNB Cost information: Please refer to Appendix B.

2

 SNCR Cost information: Please refer to Appendix B.

4

 Baseline heat input was determined from CAMD, 2001-2003, average daily heat inputs times the average number of operating hours from 2
Annual 

Capital Cost

Annual 

Fixed O&M

Annualized 

Variable 

O&M

Total 

Annual 

Cost

Cost 

Effectiveness

 Incremental 

Cost 

($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton)

1,756,714 240,000 132,364 2,129,078 2,579 -

2,429,191 240,000 2,183,048 4,852,239 3,598 5,209

11,463,077 1,560,000 3,700,000 16,723,077 4,322 4,795

umber of operating hours from 2001-2003 divided by 24 hours in a day.
SO2 - NIDS

Caney Creek 0.993 0.346 0.647

Hercules-Glades 0.734 0.311 0.423

Mingo 0.653 0.216 0.437

Upper Buffalo 1.066 0.497 0.569

SO2 - WFGD

Caney Creek 0.993 0.353 0.640

Hercules-Glades 0.734 0.348 0.386

Mingo 0.653 0.225 0.428

Upper Buffalo 1.066 0.523 0.543

NOx - LNB/OFA

Caney Creek 0.993 0.924 0.069

Hercules-Glades 0.734 0.683 0.051

Mingo 0.653 0.639 0.014

Upper Buffalo 1.066 1.03 0.036

NOx - LNB/OFA/SNCR

Caney Creek 0.993 0.9 0.093

Hercules-Glades 0.734 0.676 0.058

Mingo 0.653 0.634 0.019

Upper Buffalo 1.066 1.028 0.038

NOx - SCR

Caney Creek 0.993 0.784 0.209

Hercules-Glades 0.734 0.627 0.107

Mingo 0.653 0.611 0.042

Upper Buffalo 1.066 1.011 0.055

Class I Area

Baseline 98th Percentile 

∆dv

NID Controlled 98th Percentile 

∆dv

Improvement in 98th 

Percentile ∆dv

Baseline 98th Percentile 

∆dv

Baseline 98th Percentile 

∆dv

Baseline 98th Percentile 

∆dv

Improvement in 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv

Class I Area

Class I Area

Class I Area

LNB/OFA Controlled 98th 

Percentile ∆dv

LNB/OFA/SNCR 98th 

Percentile ∆dv

SCR Controlled 98th Percentile 

∆dv

Class I Area

Baseline 98th Percentile 

∆dv

WFGD Controlled 98th 

Percentile ∆dv

Improvement in 98th 

Percentile ∆dv
49,704,474 $ 76,822,990

49,704,474 $ 117,504,668

49,704,474 $ 113,740,216

49,704,474 $ 87,354,085 ###########

61,085,990 $ 95,446,859

61,085,990 $ 158,253,859

61,085,990 $ 142,724,275

61,085,990 $ 112,497,218 ###########

2,129,078 $ 30,856,201

2,129,078 $ 41,746,624

2,129,078 $ 152,076,989

2,129,078 $ 59,141,051 ###########

4,852,239 $ 52,174,618

4,852,239 $ 83,659,301

4,852,239 $ 255,381,025

4,852,239 $ 127,690,512 ###########

16,723,077 $ 80,014,722

16,723,077 $ 156,290,438

16,723,077 $ 398,168,498

16,723,077 $ 304,055,944 ###########

$/dv

Total Annual NID 

Cost

$/dv

$/dv

$/dv

Total Annual 

LNB/OFA Cost

Total Annual 

LNB/OFA + SNCR 

Cost

Total Annual SCR 

Cost

$/dv

Total Annual WFGD 

Cost
Misc Data

Design HI (MMBtu/hr) 6324

Average HI (MMBtu/hr) 4817.438

NOx (lb/day) (lb/hr) (lb/MMBtu) tpy

Baseline NOx 46680 1945.00 0.307558507 8519.1

NOX LNB + OFA 34908.48 1454.52 0.23

NOX LNB/OFA/SNCR 30658.75 1277.448 0.202

NOX SCR 10168.99 423.708 0.067

SO2 (lb/day) (lb/hr) (lb/MMBtu)

Baseline SO2 113482 4728.417 0.74769397 20710.465

SO2 control rate 

Dry scrubber - NIDS 9106.56 379.44 0.06

Boiler Emission Inventory Quantities

2001 2002 2003 Average

PM10 125.8 117.3 278.8 173.96667

SO2 14531.2 10962.7 9429.1 11,641.00

NOx 5682.3 5110 4568.5 5,120.27

2009 2010 2011

PM10 327.52 407.81 478.48 404.60333

SO2 6551 8133.5 8618.8 7,767.77

NOx 3619.5 4697.1 5323.6 4,546.73

Average number of operating hours 7752

2001 333

2002 335

2003 301
FGR 0.292181 0.230669

OFA 0.292181 0.276803

LNB 0.261425 0.199913

LNB/OFA 0.246047 0.184535

SN'CR 0.276803 0.184535