### 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 Cy clone 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 PrecipitatorSTATE 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 2.139NOX

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 3,3640.3

0.4 0.5 0.6 0.7**N O** **x E** **m i** **s s** **i o** **n s** **( l** **b /** **m m** **B t** **u )**  

# 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 O** **x E** **m i** **s s** **i o** **n s** **( l** **b /** **m m** **B t** **u )** 

**Year**6000

8000 10000 12000 14000**N O** **x E** **m i** **s s** **i o** **n s** **( t** **p y** **)** 

# Leland **Olds NOx Mass Emissions**

Unit 1

Unit 2

0 2000 4000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010**N O** **x E** **m i** **s s** **i o** **n s** **( t** **p y** **)**

**Year Leland Olds Station**  **1**

**Modified from OA QPS Control Cost Manual Section 4.2, SCR** 

**Given/A ssumptions**  New or Retrofit? Retrofit Generation capacity

(MW ) 216 Override Cost Manual TCC? ($/kW ) 200 $ SCR by pass 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 Day s 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 Volum e 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 cataly st lay ers 2 ASR 1.05 Stored Ammonia Concentration 29% Reagent Molecular W eight (g/mole) 17.03 Reagent Density

(lb/ft3 @ 60F) 56.0 Reagent Specific Volume (gal/ft3) 7.481 NOx Molecular W eight (g/mole) 46.01 Number of Day s of Storage for Ammonia 14 Pressure Drop for SCR Ductwork H2O") 3 Pressure Drop for each Cataly st Lay er (H2O") 1 Temperature at SCR Inlet (degrees F) 650 Equipm ent Life (y ears) 20 Annual Interest Rate 7% Inflation Since 1998 1.34 Inflation Since 2006 1.04 Cataly st Cost, Initial ($/ft3) 213 $ Cataly st Cost, Replacement ($/ft3) 213 $ Electrical Power Cost ($/kW h) 0.050 $ 29% Ammonia Solution Cost ($/lb) 0.07 $ Operating Life of Cataly st (hours) 24,000 Natural gas unit cost ($/mcf) 5.50 $ Natural gas for reheat (mcf) 86 Lost ash sales ($/y r) Additional Ash Disposal Cost ($/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 mmB tu/hr ND DOH SIP Appendix B.1 report calcuated from 17,656,398 mmB tu/y r from 2000 - 2010 CAM data calcuated from 8760 hr/y r 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) vs1,199,789 scfm at LOS#2 requiring 66 mmB tu/hr according to Fox**LNB Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc** ( 0.29

- 0.23 )/

**Boiler Calculations**



### 2.3 Q B 

### = HVm-dot fuel QB = 6,548 Btu/lb * 400,428 lb/hr QB = 2,622 Btu/hr



### 2.7 CF Plant 

### = actual m fuel 

### /maximum m fuel CFPlant = 2.70E+09 lb/y r / 8760 hr/y r / 400,428 lb/hr CFPlant = 77%



### 2.8 CF SCR 

### = t SCR



### /365 day s CFSCR = 365 day s/ 365 day s CFSCR = 100%



### CF Total 

### = CF Plant 

### x CF SCR CFTotal = 77% * 100% CFTotal = 77%



### 2.12 q fluegas 

### = q fuel 

### Q B 

### (460+T)/(460+700 o 

### F)n SCR qfluegas = 547 ft3/min/(mmBtu/hr)* 2622 mmB tu/hr*( 460 + qfluegas = 1,372,414 acfm



### 2.9 η NOx 

### = (NOx in 

### – NOx out 

### ) / NOx in ηNOx = ( 0.23 lb/m mB tu - 0.05 lb/m mB tu)/ 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 tpy0.29 = 21%

650 )/( 460 + 700 )/ 1

lb/m mB tu

0.29 = 83%**SCR Reactor Calculations**



### 2.19 Vol catalyst 

### = 2.81 x Q B 

### x η adj 

### x Slip adj 

### x NOx adj 

### x S adj 

### x T adj 

### /N SCR Volcataly st = 2.81 * 2622 = 7368



### 2.2 η adj 

### = 0.2869 + (1.058 x η) ηadj = 0.2869 +( 1.058 * 0.78 ) ηadj = 1.115 

### 2.22 Slip adj 

### = 1.2835 – (0.0567 x Slip) Slipadj = 1.2835 - ( 0.057 * 2 ) Slipadj = 1.170 

### 2.21 NOx adj 

### = 0.8524 + (0.3208 x NOx in 

### ) NOxadj = 0.8524 + ( 0.321 * 0.23 ) NOxadj = 0.926 

### 2.23 S adj 

### = 0.9636 + (0.0455 x S) Sadj = 0.9636 + ( 0.046 * 1.13 ) Sadj = 1.015 

### 2.24 T adj 

### = 15.16 – (0.03937 x T) + (2.74 x 10 -5 

### x T 2 

### ) Tadj = 15.16 - ( 0.039 * 650 ) + 2.74E-05 * Tadj = 1.146 Volcataly st = 10,355 ft3 each = 293.4 m3 each



### 2.25 A catalyst 

### = q fluegas 

### /(16 ft/sec x 60 sec/min) Acataly st = 1,372,414 /( 16 * 60 ) Acataly st = 1,430 ft2



### 2.26 A SCR



### = 1.15 x A catalyst ASCR = 1.15 * 1430 ASCR = 1,644 ft2



### 2.27 l = w = A SCR 1/2

l = w = 40.5 ft



### 2.28 n layer 

### = Vol catalyst 

### /(h’ layer



### x A catalyst 

### ) nlay er = 10,355 /( 3.1 * 1430 ) nlay er (calc) = 2.0 nlay er = 2.0



### 2.29 h layer 

### = [Vol catalyst 

### /(n layer



### x A catalyst 

### )] + 1 hlay er = 10,355 /( 2.0 * 1430 ) + 1 hlay er = 4.6



### 2.3 n total 

### = n layer



### + n empty ntotal = 2 + 2 ntotal = 4

### 2.31 h SCR 

### = n total 

### (c 1 

### + h laye 

### r) + c 2 hSCR = 4 * ( 7 + 4.6 ) + 9 hSCR = 55 ft422500

### Reagent Calculations



### 2.32 m- dot reagent



### = NOx in 

### Q B 

### ASR

**η NOx**  

### M reagent



### /M NOx 

### m-dotreagent = 0.23 * 2622 * 1.05 * **78%** * 17.03 / m-dotreagent = 183 lb/hr



### 2.33 m- dot sol 

### = m -dot reagent 

### /C sol 

### m-dotsol = 183 / 0.29 m-dotsol = 632 lb/hr



### 2.34 q sol 

### = (m -dot vol 

### /ρ sol 

### )V sol 

### qsol = 632 * 7.481 / 56 qsol = 84 gph



### 2.35 Tank Volume = q sol 

### t Tank Volume = 84 * 14 * 24 Tank Volume = 28,390 gal

### 46.01**Direct Capital Cost**

########## DC = Q B [($3380/MMBtu/hr) + f(h SCR ) +f(NH 3 rate) + f(new) + f(bypass)](3500/Q B ) 0.35 + f(Vol catalyst )

DC = 2622 (( 3,380 $ /mmBtu/hr * inflation = 4,529 $ 11,874,880 $ 2.37 f(h SCR ) = {[$612/(ft-mmBtu/hr)]h SCR } - $187.9/(mmBtu/hr) f(hSCR) = 6.12 * 55

- 187.9 f(hSCR) = 152

$ /mmBtu/hr * inflation = 203 $ 532,888 $

2.38 f(NH 3 rate) = [($411/lb/hr)(m-dot reagent /Q B )] - $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(Vol catalyst ) = Vol catalyst CCinitial 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 $ fo r each reactor DC = 16,350,056 $ fo r all reactors**Indirect Capital Costs**

**Total Direct Capital Costs, A** Indirect Installation Costs

General Facilities 0.05 A Engineering and Hom e 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 Roy alty Allowance, F = 0 Preproduction Cost, G = 0.02 (D+E) Inventory Capital, H = Initial Cataly st 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%

day s = $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 + Annual Water Cost + Annual Catalyst Cost 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 = q reagent 

### Cost reagent 

### t op 

### 2.47a t op 

### = **CF total**  

### 8760hr/yr top = **77%** * 8760 

### top = **6734** Annual Reagent Cost = 632 * **6734** * Annual Reagent Cost = 293,353 $ 

### 2.49 Annual Electricity Cost = Power (Cost elect) 

### 2.48 **Power = 0.105Q B**  

### [NOx **in** 

### ηNOx + 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)FWF 2.5 Catalyst Replacement Cost = n SCR 

### Vol catalyst 

### Catalyst Replacement Cost = 1 * 10,355 * Catalyst Replacement Cost = 1,100,429 $ 

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

### -1]} 2.53 Y = h catalyst



### /h year 

### Y = 24000 /( 77% * Y = 3.56 FW F = 0.07 *( 1 /( FW F = 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 = NOx in 

### η NOx 

### Q B 

### t op 

### 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 $

### DAC = Annual Maintenance Cost + Annual Reagent Cost + Annual Electricity Cost + Annual Water Cost + Annual Catalyst Cost

op



### 0.068875

elect) 

### t op

**duct** 

### + n **total** 

### ΔP **catalyst** 

### )]

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

0.05


### Annual Catalyst Replacement Cost = (Catalyst Replacement Cost)FWF

catalyst 

### CC replace 

### /R layer



### 212.5 / 2

8760 )

1 + 0.07 )^ 4

- 1 )

6,734 * 5.50

$ /mcf

0.07 )^ 20 /(( 1 + 0.07 )^ 20

- 1 )

### Total Annual Cost = Direct Annual 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 Ty pe dry -bottom, wall-fired Fuel ND lignite Rating (MW Gross) each 216 **Presumptive BA RT 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 A**  **nalysis** Control Efficiency 21.2% Controlled emissions (lb/mmBtu) 0.230 Controlled Em issions (tpy ) 2,030 Em issions 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 A nalysis**  Control Efficiency 78% Controlled emissions (lb/mmBtu) 0.050 Controlled Em issions (tpy ) 441 Em issions 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 A nalysis**  Control Efficiency 83% Controlled emissions (lb/mmBtu) 0.050 Controlled Em issions (tpy ) 441 Em issions 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 hy brid hy brid hy brid

calculated NPS estimate calculated calculated calculated calculated calculated calculated calculated