OP_YEAR STATE FACILITY_NAME ORISPL_CODE UNITID UNIT_TYPE_INFO

2000 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2001 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2002 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2003 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2004 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2005 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2006 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2007 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2008 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2009 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2010 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2011 ND Leland Olds 2817 1 Dry bottom wall-fired boiler

2000 ND Leland Olds 2817 2 Cyclone boiler

2001 ND Leland Olds 2817 2 Cyclone boiler

2002 ND Leland Olds 2817 2 Cyclone boiler

2003 ND Leland Olds 2817 2 Cyclone boiler

2004 ND Leland Olds 2817 2 Cyclone boiler

2005 ND Leland Olds 2817 2 Cyclone boiler

2006 ND Leland Olds 2817 2 Cyclone boiler

2007 ND Leland Olds 2817 2 Cyclone boiler

2008 ND Leland Olds 2817 2 Cyclone boiler

2009 ND Leland Olds 2817 2 Cyclone boiler

2010 ND Leland Olds 2817 2 Cyclone boiler

2011 ND Leland Olds 2817 2 Cyclone boiler
PRIMARY_FUEL_INFO SO2_CONTROL_INFO NOX_CONTROL_INFO

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal Low NOx Burner Technology (Dry Bottom only) Overfire Air

Coal

Coal

Coal

Coal

Coal

Coal

Coal

Coal

Coal

Coal Overfire Air (Began Nov 01, 2009)

Coal Overfire Air

Coal Overfire Air
PART_CONTROL_INFO

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator

Electrostatic Precipitator
STATE FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

 SUM OP 

TIME 

 NUM 

MONTHS 

REPORTED 

 SO2 

MASS 

SO2 

RATE

ND Leland Olds 2817 Unit 1 2000 8,251 12 16,863 1.811

ND Leland Olds 2817 1 2001 7,100 12 15,237 1.940

ND Leland Olds 2817 1 2002 8,525 12 16,655 1.731

ND Leland Olds 2817 1 2003 8,636 12 19,125 1.816

ND Leland Olds 2817 1 2004 7,209 12 15,448 1.801

ND Leland Olds 2817 1 2005 8,574 12 17,488 1.801

ND Leland Olds 2817 1 2006 8,600 12 17,768 1.886

ND Leland Olds 2817 1 2007 6,788 12 14,562 2.086

ND Leland Olds 2817 1 2008 8,603 12 17,926 2.021

ND Leland Olds 2817 1 2009 8,471 12 17,371 2.023

ND Leland Olds 2817 1 2010 7,733 12 17,203 2.249

Totals 88,489 185,647

Averages 8,044 16,877 1.912

ND Leland Olds 2817 Unit 2 2000 6,894 12 28,587 1.848

ND Leland Olds 2817 2 2001 8,225 12 36,219 1.907

ND Leland Olds 2817 2 2002 8,050 12 30,744 1.728

ND Leland Olds 2817 2 2003 6,632 12 25,598 1.793

ND Leland Olds 2817 2 2004 8,552 12 32,990 1.851

ND Leland Olds 2817 2 2005 8,532 12 30,887 1.727

ND Leland Olds 2817 2 2006 6,305 12 22,259 1.758

ND Leland Olds 2817 2 2007 8,352 12 33,450 1.977

ND Leland Olds 2817 2 2008 7,760 12 30,022 1.940

ND Leland Olds 2817 2 2009 7,120 12 26,782 1.922

ND Leland Olds 2817 2 2010 7,996 12 28,776 2.139
NOX 

RATE NOX MASS CO2 MASS HEAT INPUT

HEAT 

INPUT

0.250 2,344 2,027,259 18,620,905 2,257

0.262 2,062 1,709,710 15,704,164 2,212

0.268 2,581 2,094,645 19,239,865 2,257

0.290 3,051 2,292,600 21,058,116 2,439

0.290 2,510 1,867,410 17,152,685 2,379

0.310 3,017 2,114,422 19,421,524 2,265

0.314 2,965 2,051,707 18,845,504 2,191

0.312 2,177 1,520,252 13,963,931 2,057

0.320 2,855 1,931,403 17,740,432 2,062

0.300 2,584 1,869,945 17,175,940 2,028

0.288 2,188 1,665,414 15,297,310 1,978

 28,334 21,144,768 194,220,375 24,125

0.292 2,576 1,922,252 17,656,398 2,193

0.603 9,472 3,369,076 30,945,842 4,489

0.664 12,718 4,134,522 37,976,687 4,618

0.622 11,184 3,874,640 35,589,576 4,421

0.609 8,813 3,108,955 28,556,587 4,306

0.584 10,379 3,881,215 35,649,975 4,168

0.572 10,241 3,894,585 35,772,845 4,193

0.505 6,463 2,756,498 25,319,177 4,016

0.501 8,452 3,684,722 33,845,154 4,052

0.528 8,210 3,369,894 30,953,377 3,989

0.474 6,635 3,033,690 27,865,279 3,914

0.314 4,237 2,928,952 26,903,299 3,364
0.3

0.4

0.5

0.6

0.7

N

Ox Emissions (lb/m

m

Btu)

Leland Olds NOx Emission Rates

Unit 2

Unit 1

0

0.1

0.2

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (lb/m

m

Btu)

Year
6000

8000

10000

12000

14000

N

Ox Emissions (tpy)

Leland Olds NOx Mass Emissions

Unit 1

Unit 2

0

2000

4000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (tpy)

Year
Leland Olds Station 1

Modified from OAQPS Control Cost Manual Section 4.2, SCR

Given/Assumptions

New or Retrofit? Retrofit

Generation capacity (MW) 216

Override Cost Manual TCC? ($/kW) $ 200

SCR bypass included? Yes

Fuel High Heating Value (Btu/lb) 6,548

Maximum Fuel Consumption Rate (lb/hr) 400,428

Average Annual Fuel Consumption (lb) 2.70E+09

Number of SCR Operating Days 365

Plant Capacity Factor 77%

Uncontrolled NOx Concentration (lb/mmBtu) 0.292

SOFA Total Capital Cost ($/kW) $ 6.3

SOFA Total Annual Cost $ 144,000

LNB outlet = SCR inlet NOx Concentration (lb/mmBtu) 0.230

Required Controlled NOx Concentration (lb/mmBtu) 0.05

Acceptable Ammonia Slip (ppm) 2.0

Fuel Volume Flow Rate (ft3/min/mmBtu/hr) 547

Fuel Sulfur Content 1.13%

Fuel Ash Content 8.45%

Number of SCR reactor chambers 1

Number of spare catalyst layers 2

ASR 1.05

Stored Ammonia Concentration 29%

Reagent Molecular Weight (g/mole) 17.03

Reagent Density (lb/ft3 @ 60F) 56.0

Reagent Specific Volume (gal/ft3) 7.481

NOx Molecular Weight (g/mole) 46.01

Number of Days of Storage for Ammonia 14

Pressure Drop for SCR Ductwork H2O") 3

Pressure Drop for each Catalyst Layer (H2O") 1

Temperature at SCR Inlet (degrees F) 650

Equipment Life (years) 20

Annual Interest Rate 7%

Inflation Since 1998 1.34

Inflation Since 2006 1.04

Catalyst Cost, Initial ($/ft3) $ 213

Catalyst Cost, Replacement ($/ft3) $ 213

Electrical Power Cost ($/kWh) $ 0.050

29% Ammonia Solution Cost ($/lb) $ 0.07

Operating Life of Catalyst (hours) 24,000

Natural gas unit cost ($/mcf) $ 5.50

Natural gas for reheat (mcf) 86

Lost ash sales ($/yr)

Additional Ash Disposal Cost ($/ton)
ND DOH SIP Appendix B.1 report

ND DOH SIP Appendix B.1 report

EPA IPM projection

assumed

company 8/3/06 report Table 1.2-2

calculated from 2,622 mmBtu/hr ND DOH SIP Appendix B.1 report

calcuated from 17,656,398 mmBtu/yr from 2000 - 2010 CAM data

calcuated from 8760 hr/yr 

calcuated

from 2000 - 2010 CAM data

company 8/3/06 report Table 2.4-1

ND DOH SIP Appendix B.1 report

ND DOH SIP Appendix B.1 report

NPS estimate

OAQPS Control Cost Manual

OAQPS Control Cost Manual

company 8/3/06 report Table 1.2-2

company 8/3/06 report Table 1.2-2

assumed

assumed

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual

CEPCI 2009/CEPCI 1998

CEPCI 2009/CEPCI 2006

calculated from $ 7,500 Fox LOS#2 report

calculated from $ 7,500 Fox LOS#2 report

$ 50 company 5/27/09 report

calcuated from $ 475 /ton from Fox LOS#2 report

assumed

Fox report for LOS#2

ratioed from LOS #2 1,549,999 scfm at CCS (company 7/15/11 report Table A-13) vs
 1,199,789 scfm at LOS#2 requiring 66 mmBtu/hr according to Fox
LNB Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc

( 0.29 - 0.23 )/

Boiler Calculations

2.3 QB = HVm-dotfuel

QB = 6,548 Btu/lb * 400,428 lb/hr

QB = 2,622 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 2.70E+09 lb/yr / 8760 hr/yr / 400,428 lb/hr

CFPlant = 77%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

CFTotal = CFPlant x CFSCR

CFTotal = 77% * 100%

CFTotal = 77%

2.12 qfluegas = qfuelQB(460+T)/(460+700o

F)nSCR

qfluegas = 547 ft3/min/(mmBtu/hr)* 2622 mmBtu/hr*( 460 +

qfluegas = 1,372,414 acfm

2.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.23 lb/mmBtu - 0.05 lb/mmBtu)/ 0.23

ηNOx = 78%

Uncontrolled NOx emissions (tpy) 2,576

Overall Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc

( 0.29 - 0.05 )/

NOx removed = 2,134 tpy

Controlled NOx emissions (tpy) = 441 tpy
0.29 = 21%

650 )/( 460 + 700 )/ 1

lb/mmBtu

0.29 = 83%
SCR Reactor Calculations

2.19 Volcatalyst = 2.81 x QB x ηadj x Slipadj x NOxadj x Sadj x Tadj/NSCR

Volcatalyst = 2.81 * 2622 = 7368

2.2 ηadj = 0.2869 + (1.058 x η)

ηadj = 0.2869 +( 1.058 * 0.78 )

ηadj = 1.115

2.22 Slipadj = 1.2835 – (0.0567 x Slip)

Slipadj = 1.2835 - ( 0.057 * 2 )

Slipadj = 1.170

2.21 NOxadj = 0.8524 + (0.3208 x NOxin)

NOxadj = 0.8524 + ( 0.321 * 0.23 )

NOxadj = 0.926

2.23 Sadj = 0.9636 + (0.0455 x S)

Sadj = 0.9636 + ( 0.046 * 1.13 )

Sadj = 1.015

2.24 Tadj = 15.16 – (0.03937 x T) + (2.74 x 10-5 x T2

)

Tadj = 15.16 - ( 0.039 * 650 ) + 2.74E-05 *

Tadj = 1.146

Volcatalyst = 10,355 ft3 each = 293.4 m3 each

2.25 Acatalyst = qfluegas/(16 ft/sec x 60 sec/min)

Acatalyst = 1,372,414 /( 16 * 60 )

Acatalyst = 1,430 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 1430

ASCR = 1,644 ft2

2.27 l = w = ASCR

1/2

l = w = 40.5 ft

2.28 nlayer = Volcatalyst/(h’layer x Acatalyst)

nlayer = 10,355 /( 3.1 * 1430 )

nlayer (calc) = 2.0

nlayer = 2.0

2.29 hlayer = [Volcatalyst/(nlayer x Acatalyst)] + 1

hlayer = 10,355 /( 2.0 * 1430 ) + 1

hlayer = 4.6

2.3 ntotal = nlayer + nempty

ntotal = 2 + 2

ntotal = 4
2.31

hSCR = ntotal(c

1

 + hlayer) + c

2

hSCR =4 * (7+ 4.6 ) +9

hSCR = 55 ft
422500
Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.23 * 2622 * 1.05 * 78% * 17.03 /

m-dotreagent = 183 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 183 / 0.29

m-dotsol = 632 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 632 * 7.481 / 56

qsol = 84 gph

2.35 Tank Volume = qsolt

Tank Volume = 84 * 14 * 24

Tank Volume = 28,390 gal
46.01
Direct Capital Cost

########## DC = QB[($3380/MMBtu/hr) + f(hSCR) +f(NH3

rate) + f(new) + f(bypass)](3500/QB)

0.35 + f(Volcatalyst)

DC = 2622 (( $ 3,380 /mmBtu/hr * inflation = $ 4,529 $ 11,874,880

2.37 f(hSCR) = {[$612/(ft-mmBtu/hr)]hSCR} - $187.9/(mmBtu/hr)

f(hSCR) = 6.12 * 55 - 187.9

f(hSCR) = $ 152 /mmBtu/hr * inflation = $ 203 $ 532,888

2.38 f(NH3

rate) = [($411/lb/hr)(m-dotreagent/QB)] - $47.3/(mmBtu/hr)

f(NH3rate) = 411 * 183 / 2622 - 47.3

f(NH3rate) = $ (19) /mmBtu/hr * inflation = $ (25) $ (65,165)

2.39 f(new) = $0/(mmBtu/hr) for retrofit

f(new) = $ - /mmBtu/hr * inflation = 0 $ -

2.41 f(bypass) = $0/(mmBtu/hr) for no bypass

f(bypass) = $ 127 /mmBtu/hr * inflation = $ 170 $ 446,186

2.43 f(Volcatalyst) = VolcatalystCCinitial

f(Volcatalyst) = 10355 * 213

f(Volcatalyst) = $ 2,200,858 $ 2,200,858

DC = 2622 * ( $ 4,529 + $ 203 + $ (25) + $ - + $ 170 )*( 3500 / 2622 )^ 0.35 + $ 2,200,858

DC = 2622 * ( 4,877 )*( 1.33 )^ 0.35 + $ 2,200,858

DC = 2622 * ( 4,877 )*( 1.11 ) + $ 2,200,858

DC = 2622 * ( 5,396 ) + $ 2,200,858

DC = $ 14,149,198 + $ 2,200,858

DC = $ 16,350,056 for each reactor

DC = $ 16,350,056 for all reactors
Indirect Capital Costs

Total Direct Capital Costs, A

Indirect Installation Costs 

General Facilities 0.05 A

Engineering and Home Office Fees 0.10 A

Process Contingencies 0.05 A

Total Indirect Installation Costs, B 0.20 A =

Project Contingency, C = 0.15 (A+B) =

Total Plant Cost D = A+B+C

Allowance for Funds During Construction, E = 0

Royalty Allowance, F = 0

Preproduction Cost, G = 0.02 (D+E)

Inventory Capital, H =

Initial Catalyst and Chemicals, I = 0.06888 /lb * 632 lb/r * 24 hr/day * 14

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I

Cost/kW =

Total Capital Investment TCI @ 200 $/kW =

Total Capital Investment TCI =
Cost Manual

Cost Cost

$ 16,350,056 ratios

$817,503 5%

$1,635,006 10%

$817,503 5%

$3,270,011 20%

(A+B) = $2,943,010 18%

$22,563,077 138%

$0 0%

$0 0%

$451,262 3%

days = $14,637 0%

+D+E+F+G+H+I $23,028,976 141%

Cost/kW = $107

$ 43,200,000

$ 43,200,000
Annual Costs

2.45 DAC = Annual Maintenance Cost + Annual Reagent Cost + Annual Electricity Cost + Ann

2.46 Annual Maintenance Cost = 0.015 TCI

Annual Maintenance Cost = 0.015 * $ 43,200,000

Annual Maintenance Cost = $ 648,000

2.47 Annual Reagent Cost = qreagentCostreagenttop

2.47a top = CFtotal8760hr/yr

top = 77% * 8760

top = 6734

Annual Reagent Cost = 632 * 6734 *

Annual Reagent Cost = $ 293,353

2.49 Annual Electricity Cost = Power (Costelect)

2.48 Power = 0.105QB[NOxinηNOx + 0.5(ΔP

Power = 0.105 * 2622 *(

Power = 1013 kW

Annual Electricity Cost = 1013 * 6734 *

Annual Electricity Cost = $ 341,122

2.51 Annual Catalyst Replacement Cost = (Catalyst Replacement Cost)

2.5 Catalyst Replacement Cost = nSCRVolcatalyst

Catalyst Replacement Cost = 1 * 10,355 *

Catalyst Replacement Cost = $ 1,100,429

2.52 FWF = i{1/[(1+i)Y

-1]}

2.53 Y = hcatalyst/hyear

Y = 24000 /( 77% *

Y = 3.56

FWF = 0.07 *( 1 /(

FWF = 0.23

Annual Catalyst Cost = $ 247,848

Annual natural gas Cost = 86 mcf/hr *

Annual natural gas Cost = $ 3,177,069

Additional Ash Disposal Cost ($/ton) = $ 2,023,730

Lost Ash Sales = $ -

DAC = $ 6,731,121

2.55 CRF = i(1+i)n

/[(1+i)

n

-1]

CRF = 0.07 *( 1 +

CRF = 0.0944

Indirect Annual Cost = CFR * TCI

Indirect Annual Cost = 0.0944 * $ 43,200,000

Indirect Annual Cost = $ 4,077,774
2.56 Total Annual Cost = Direct Annual Cost + Indirect Annual Cost

SCR Total Annual Cost = $ 6,731,121 + 4,077,774

NOx control Total Annual Cost = $ 10,808,895 + $ 144,000 =

2.57 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.23 * 78% *

SCR NOx Removed = 1,589

Total NOx Removed = 2,134

2.58 Cost effectiveness = TAC/NOx removed

SCR Cost effectiveness = $ 6,802

Total Cost effectiveness = $ 5,132
Cost + Annual Electricity Cost + Annual Water Cost + Annual Catalyst Cost

op

0.068875

elect)top

duct + ntotalΔPcatalyst)]

0.23 * 78% + 0.5 * ( 3 + 4 * 1 ))

0.05

 Cost = (Catalyst Replacement Cost)FWF

catalystCCreplace/Rlayer

212.5 / 2

8760 )

1 + 0.07 )^ 4 - 1 )

 6,734 * $ 5.50 /mcf

0.07 )^ 20 /(( 1 + 0.07 )^ 20 - 1 )
nnual Cost + Indirect Annual Cost

$ 10,952,895

2622 * 6734 / 2000
Operating company Great River Energy

Facility Leland Olds Station

State ND

Contact Tom Bachman

Proposed Controls rejected SCR

Unit 1

Boiler Type dry-bottom, wall-fired

Fuel ND lignite

Rating (MW Gross) each 216

Presumptive BART limit (lb/mmBtu)

Rating (mmBtu/hr) 2,622

Uncontrolled Emissions (tpy) 2,576

Uncontrolled Emissions (lb/mmBtu) 0.292

SOFA/LNB Option 1 Cost-benefit Analysis

Control Efficiency 21.2%

Controlled emissions (lb/mmBtu) 0.230

Controlled Emissions (tpy) 2,030

Emissions Reduction (tpy) 545

Capital Cost $ 1,360,800

Capital Cost ($/kW) $ 6.3

O&M Cost $ 21,000

Annualized Cost $ 149,450

Cost-Effectiveness ($/ton) $ 274

SCR Cost-benefit Analysis

Control Efficiency 78%

Controlled emissions (lb/mmBtu) 0.050

Controlled Emissions (tpy) 441

Emissions Reduction (tpy) 1,589

Capital Cost $ 43,200,000

Capital Cost ($/kW) $ 200

O&M Cost $ 6,731,121

Annualized Cost $ 10,808,895

Cost-Effectiveness ($/ton) $ 6,802

Combustion Controls + SCR Cost-benefit Analysis

Control Efficiency 83%

Controlled emissions (lb/mmBtu) 0.050

Controlled Emissions (tpy) 441

Emissions Reduction (tpy) 2,134

Capital Cost $ 44,560,800

Capital Cost ($/kW) $ 206

O&M Cost $ 6,752,121

Annualized Cost $ 10,952,895

Cost-Effectiveness ($/ton) $ 5,132

Visibility analyses

Visibility Impact before BART (dv at Max Class I)

Visibility Impact after BART (dv at Max Class I)

Visibility Improvement (dv at Max Class I)

Cost-Effectiveness ($/98th % dv at Max Class I)

Visibility Impact before BART (dv at Summed Class I)
Visibility Impact after BART (dv at Summed Class I)

Visibility Improvement (dv at Summed Class I)

Cost-Effectiveness ($/98th % dv at Summed Class I)
tbachman@nd.gov (701) 328-5188

ND DOH SIP Appendix B.1 report

ND DOH SIP Appendix B.1 report

ND DOH SIP Appendix B.1 report

ND DOH SIP Appendix B.1 report

OAQPS Control Cost Manual

from 2000 - 2004 CAM data

calculated

ND DOH SIP Appendix B.1 report

calculated

calculated

calculated

company 8/3/06 report Table 2.4-1

company 1/29/07 report Table 2.4-3

calculated

calculated

OAQPS Control Cost Manual

NPS estimate

calculated

OAQPS Control Cost Manual

company 7/15/11 report Table A-15

EPA IPM projection

hybrid

hybrid

hybrid

calculated

NPS estimate

calculated

calculated

calculated

calculated

calculated

calculated

calculated