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
CAMD Emissions Data

STATE FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

 SUM OP 

TIME 

 NUM 

MONTHS 

REPORTED 

 SO2 

MASS 

SO2 

RATE

NOX 

RATE NOX MASS CO2 MASS HEAT INPUT

HEAT 

INPUT

ND Leland Olds 2817 Unit 1 2000 8,251 12 16,863 1.811 0.250 2,344 2,027,259 18,620,905 2,257

ND Leland Olds 2817 1 2001 7,100 12 15,237 1.940 0.262 2,062 1,709,710 15,704,164 2,212

ND Leland Olds 2817 1 2002 8,525 12 16,655 1.731 0.268 2,581 2,094,645 19,239,865 2,257

ND Leland Olds 2817 1 2003 8,636 12 19,125 1.816 0.290 3,051 2,292,600 21,058,116 2,439

ND Leland Olds 2817 1 2004 7,209 12 15,448 1.801 0.290 2,510 1,867,410 17,152,685 2,379

ND Leland Olds 2817 1 2005 8,574 12 17,488 1.801 0.310 3,017 2,114,422 19,421,524 2,265

ND Leland Olds 2817 1 2006 8,600 12 17,768 1.886 0.314 2,965 2,051,707 18,845,504 2,191

ND Leland Olds 2817 1 2007 6,788 12 14,562 2.086 0.312 2,177 1,520,252 13,963,931 2,057

ND Leland Olds 2817 1 2008 8,603 12 17,926 2.021 0.320 2,855 1,931,403 17,740,432 2,062

ND Leland Olds 2817 1 2009 8,471 12 17,371 2.023 0.300 2,584 1,869,945 17,175,940 2,028

ND Leland Olds 2817 1 2010 7,733 12 17,203 2.249 0.288 2,188 1,665,414 15,297,310 1,978

ND Leland Olds 2817 Unit 2 2000 6,894 12 28,587 1.848 0.603 9,472 3,369,076 30,945,842 4,489

ND Leland Olds 2817 2 2001 8,225 12 36,219 1.907 0.664 12,718 4,134,522 37,976,687 4,618

ND Leland Olds 2817 2 2002 8,050 12 30,744 1.728 0.622 11,184 3,874,640 35,589,576 4,421

ND Leland Olds 2817 2 2003 6,632 12 25,598 1.793 0.609 8,813 3,108,955 28,556,587 4,306

ND Leland Olds 2817 2 2004 8,552 12 32,990 1.851 0.584 10,379 3,881,215 35,649,975 4,168

ND Leland Olds 2817 2 2005 8,532 12 30,887 1.727 0.572 10,241 3,894,585 35,772,845 4,193

ND Leland Olds 2817 2 2006 6,305 12 22,259 1.758 0.505 6,463 2,756,498 25,319,177 4,016

ND Leland Olds 2817 2 2007 8,352 12 33,450 1.977 0.501 8,452 3,684,722 33,845,154 4,052

ND Leland Olds 2817 2 2008 7,760 12 30,022 1.940 0.528 8,210 3,369,894 30,953,377 3,989

ND Leland Olds 2817 2 2009 7,120 12 26,782 1.922 0.474 6,635 3,033,690 27,865,279 3,914

ND Leland Olds 2817 2 2010 7,996 12 28,776 2.139 0.314 4,237 2,928,952 26,903,299 3,364

Averages 7,674 31,761,618 4,139
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
Basin Electric Power--Leland Olds #2

SNCR from OAQPS Control Cost Manual, Section 4.2

Given/Assumptions

Rating (MW ) 440 ND DOH report

Fuel High Heating Value (Btu/lb) 6,548 Company report (8/06 Table 1.2-2)

Maximum Fuel Consumption Rate (lb/hr) 7.8E+05 calculated from 5,130 ND DOH report (SIP Appendix B.1) (and the Fox report)

Average Annual Fuel Consumption (lb) 5.94E+09 calculated 38,872,062 mmBtu/yr calculated from Fox report 

Number of SNCR Operating Days 365 calculated from 8,760 hr/yr

Total system capacity factor 86.5% Fox report

Uncontrolled NOx Concentration (lb/mmBtu) 0.67 ND DOH report (SIP Appendix B.1) (and the Fox report)

NOx concentration after combustion controls 0.482 ND DOH report (SIP Appendix B.1)

Required Controlled NOx Concentration (lb/mmBtu) 0.305 ND DOH report (SIP Appendix B.1)

Source/State Total Capital Investmant estimate $ 7,800,000 calculated from Table 2.5-2 in the 5/27/09 company report

ash product (Btu/mmBtu) 7.7E+04 OAQPS Control Cost Manual

Stored Urea Concentration 50% OAQPS Control Cost Manual

Injected Urea Concentration 10% OAQPS Control Cost Manual

Reagent Heat of vaporization Hv (lb/Btu) 900 OAQPS Control Cost Manual

Reagent Molecular Weight (g/mole) 60.06 OAQPS Control Cost Manual

SRT 2 OAQPS Control Cost Manual

Reagent Density (lb/ft3 @ 60F) 71.0 OAQPS Control Cost Manual

Reagent Specific Volume (gal/ft3) 7.481 OAQPS Control Cost Manual

NOx Molecular Weight (g/mole) 46.01 OAQPS Control Cost Manual

Number of Days of Storage for Urea 14 OAQPS Control Cost Manual

Equipment Life (years) 20 OAQPS Control Cost Manual

Annual Interest Rate 7% OAQPS Control Cost Manual

Inflation Since 1998 1.34 CEPCI 2009/CEPCI 1998 

Water Consumption Cost ($/gal) 0.0004 OAQPS Control Cost Manual

Electrical Power Cost ($/kWh) $ 0.038 calculated from $ 38.00 /MWhr from previous company report

50% Urea Solution Cost ($/gal) $ 2.25 calculated from $ 475 /ton 50% aqueous solution from Fox report

Coal Cost ($/mmBtu) $ 0.91 Company report

Ash Disposal Cost ($/ton) $ 11.28 OAQPS Control Cost Manual
Boiler Calculations

1.3 QB = HVm-dotfuel

QB = 6548 Btu/lb * 783,445 lb/hr

QB = 5130 mmBtu/hr

1.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 5.94E+09 lb/yr / 8760 hr/yr / 783,445 lb/hr

CFPlant = 86.5%

1.8 CFSNCR = tSNCR/365 days

CFSNCR = 365 days/ 365 days

CFSNCR = 100%

1.6 CFTotal = CFPlant x CFSNCR

CFTotal = 87% * 100%

CFTotal = 86.5%

1.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.482 lb/mmBtu - 0.305 lb/mmBtu)/ 0.482 lb/mmBtu

ηNOx = 37%

Uncontrolled NOx emissions (tpy) 13,022
Reagent Calculations

1.14 NSR = [2NOxin – 0.7] ηNOx/ NOxin

NSR = ( 2 * 0.482 + 0.7 ) * 37% / 0.482

NSR = 1.27

1.13 Utilization = ηNOx/NSR

Utilization = 29%

1.15 m-dotreagent = NOxinQBηNOxNSR Mreagent/MNOx/SRT

m-dotreagent = 0.482 * 5130 * 37% * 127% * 60.06 / 2 / 46.01

m-dotreagent = 751 lb/hr

1.16 m-dotsol = m-dotreagent/Csol

m-dotsol = 751 / 0.50

m-dotsol = 1503 lb/hr

1.17 qsol = m-dotvol/ρsol

qsol = 1503 * 7.481 / 71

qsol = 158 gph

2.35 Tank Volume = qsolt

Tank Volume = 158 * 14 * 24

Tank Volume = 53,198 gal
Direct Capital Cost

1.19 DC = ($950/mmBtu/hr) * QB(mmBtu/hr)[(2375/mmBtu/hr)/QB(mmBtu/hr]0.577 * (0.66 + 0.85* ηNOx)

DC = $ 950 * 5130 *( 2375 / 5130 )^ 0.577 *( 0.66 + 0.85 * 37% )

DC = $ 3,038,006

Inflation Adjustment = 1.34

DC = $ 4,070,928
Indirect Capital Costs

Total Direct Capital Costs, A $ 4,070,928

Indirect Installation Costs 

General Facilities 0.05A $203,546

Engineering and Home Office Fees 0.10A $407,093

Process Contingencies 0.05A $203,546

Total Indirect Installation Costs, B 0.20A $814,186

Project Contingency, C = 0.15 (A+B) $732,767

Total Plant Cost D = A+B+C $5,617,880

Preproduction Cost 0.02D $112,358

Inventory Capital $119,911

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $5,850,149

Company TCI = $ 7,800,000
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 * $ 7,800,000

Annual Maintenance Cost = $ 117,000

1.22 Annual Reagent Cost = qsolCostreagenttop

1.22.a top = CFtotal8760hr/yr

top = 86.5% * 8760

top = 7577

Annual Reagent Cost = 158 * 2.254 * 7577

Annual Reagent Cost = $ 2,704,208

1.24 Annual Electricity Cost = Power (Costelect)top

1.23 Power = 0.47NOxinNSRQB/9.5

Power = 0.47 * 0.482 * 1.27 * 5130 / 9.5

Power = 155 kW

Annual Electricity Cost = 155 * 7577 * 0.038

Annual Electricity Cost = $ 44,656

1.27 Annual Water Cost = qwaterCostwater top

1.25 qwater = m-dotsol/ρwater[Cureastored/Curea sol inj -1]

qwater = 1503 / 8.345 *( 50% / 10% - 1 )

qwater = 720

Annual Water Cost = 720 * 0.0004 * 7577

Annual Water Cost = $ 2,183

1.31 Annual ΔCoal cost = ΔCoal costcoal top

1.28 ΔCoal(Btu/hr) = Hv(Btu/lb)* m-dotreagent(lb/hr)[1/ Curea sol inj -1]

ΔCoal(Btu/hr) = 900 * 1503 *( 1 / 10% - 1 )

ΔCoal(Btu/hr) = 12,171,420

Annual ΔCoal cost = 12.2 * $ 0.91 * 7577

Annual ΔCoal cost = $ 83,927

1.32 Annual ΔAsh cost = ΔAsh costash top

1.30 ΔAsh = ΔCoal ash product/HHV

ΔAsh = 12 * 77000 / 6548

ΔAsh = 143

Annual ΔAsh cost = 143 * $ 11.28 * 7577 / 2000

Annual ΔAsh cost = $ 6,117

Total Variable Cost = $ 2,841,090

Total Direct Annual Cost = $ 117,000 + $ 2,841,090

Total Direct Annual Cost = $ 2,958,090

1.34 CRF = i(1+i)n

/[(1+i)n-1]

CRF = 0.07 *( 1 + 0.07 )^ 20 /(( 1 + 0.07 )^ 20 - 1 )

CRF = 0.0944

1.33 IDAC = CRF*TCI

Indirect Annual Cost = 0.0944 * $ 7,800,000

Indirect Annual Cost = $ 736,265

1.35 Total Annual Cost = Direct Annual Cost + Indirect Annual Cost

Total Annual Cost = $ 2,958,090 + 736,265

Total Annual Cost = $ 3,694,355

1.36 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.482 * 37% * 5130 * 7577 / 2000

NOx Removed = 3440

1.37 Cost effectiveness = TAC/NOx

 removed

Cost effectiveness = $ 1,074
Leland Olds Station Unit 2, EPA's SNCR Cost Analysis Summary

Operating company Basin Electric power

Facility Leland Olds

State ND

Contact Tom Bachman tbachman@nd.gov (701) 328-5188

Proposed Controls proposed ASOFA + SNCR

Unit #2

Boiler Type cyclone ND DOH report (SIP Appendix B.1)

Fuel ND lignite & PRB ND DOH report (SIP Appendix B.1)

Rating (MW Gross) each 440 ND DOH report (SIP Appendix B.1)

Presumptive BART limit (lb/mmBtu) 0.10 presumptive BART for cyclone boiler at facility > 750 MW

Rating (mmBtu/hr) 5,130 ND DOH report (SIP Appendix B.1) (and the Fox report)

Uncontrolled Emissions (tpy) 13,022 calculated

Uncontrolled Emissions (lb/mmBtu) 0.67 ND DOH report (SIP Appendix B.1) (and the Fox report)

ASOFA Cost Analysis

Control Efficiency 28% ND DOH report (SIP Appendix B.1)

Controlled emissions (lb/mmBtu) 0.482 ND DOH report (SIP Appendix B.1)

Controlled Emissions (tpy) 9,329 calculated from Fox report

Emissions Reduction (tpy) 3,693 calculated from Fox report

Capital Cost $ 11,440,000 calculated from Table 2.5-2 in the 5/27/09 company report (and the Fox report "ASOFA+SCR" tab)

Capital Cost ($/kW) $ 26 company report (and the Fox report "ASOFA+SCR" tab)

O&M Cost $ 177,000 from Table 2.5-3 in the 5/27/09 company report

Annualized Cost $ 1,256,855 calculated from Tables 2.5-2 & 2.5-3 in the 5/27/09 company report

Cost-Effectiveness ($/ton) $ 340 calculated

SNCR Cost Analysis

Control Efficiency 37% calculated

Controlled emissions (lb/mmBtu) 0.305 ND DOH report (SIP Appendix B.1)

Controlled Emissions (tpy) 5,889 calculated

Emissions Reduction (tpy) 3,440 OAQPS Control Cost Manual

Capital Cost $ 7,800,000 calculated from Table 2.5-2 in the 5/27/09 company report

Capital Cost ($/kW) $ 18 calculated

O&M Cost $ 2,958,090 hybrid

Annualized Cost $ 3,694,355 hybrid

Cost-Effectiveness ($/ton) $ 1,074 hybrid

ASOFA+SNCR Cost Analysis

Control Efficiency 54% calculated

Controlled emissions (lb/mmBtu) 0.305 calculated

Controlled Emissions (tpy) 5,889 calculated

Emissions Reduction (tpy) 7,133 calculated

Capital Cost $ 19,240,000 calculated

Capital Cost ($/kW) $ 44 calculated

O&M Cost $ 3,135,090 calculated

Annualized Cost $ 4,951,210 calculated

Cost-Effectiveness ($/ton) $ 694 calculated