OP_YEAR STATE FACILITY_NAME ORISPL_CODEUNITID OP_STATUS_INFOUNIT_TYPE_INFO PRIMARY_FUEL_INFO

2000 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2001 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2002 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2003 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2004 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2005 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2006 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2007 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2008 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2009 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2010 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal

2011 ND Milton R Young 2823 B2 Operating Cyclone boiler Coal
SECONDARY_FUEL_INFO SO2_CONTROL_INFO

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali

Dual Alkali Wet Lime FGD (Began Oct 01, 2010)

Dual Alkali Wet Lime FGD
NOX_CONTROL_INFO

Overfire Air (Began Nov 26, 2007)

Overfire Air

Overfire Air

Overfire Air Selective Non-catalytic Reduction (Began Dec 08, 2010)

Overfire Air Selective Non-catalytic Reduction
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
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 

(mmBtu/yr) 

 HEAT INPUT 

(mmBtu/hr) 

ND Milton R Young 2823 Unit B1 2000 7,530 12 18,095 1.914 0.801 7,656 2,055,328 18,912,797 2,512

ND Milton R Young 2823 B1 2001 8,461 12 23,179 1.999 0.784 9,132 2,524,491 23,194,117 2,741

ND Milton R Young 2823 B1 2002 8,304 12 19,858 1.853 0.789 8,510 2,333,523 21,434,050 2,581

ND Milton R Young 2823 B1 2003 7,429 12 18,020 1.757 0.815 8,546 2,233,328 20,513,979 2,761

ND Milton R Young 2823 B1 2004 8,529 12 21,586 1.869 0.843 9,785 2,515,207 23,102,856 2,709

ND Milton R Young 2823 B1 2005 8,355 12 19,450 1.932 0.836 8,458 2,192,181 20,135,772 2,410

ND Milton R Young 2823 B1 2006 7,442 12 16,875 1.908 0.802 7,150 1,925,330 17,684,694 2,376

ND Milton R Young 2823 B1 2007 8,413 12 20,543 1.985 0.838 8,704 2,253,967 20,703,216 2,461

ND Milton R Young 2823 B1 2008 8,297 12 19,608 1.946 0.806 8,193 2,193,430 20,146,954 2,428

ND Milton R Young 2823 B1 2009 7,209 12 16,498 1.891 0.749 6,612 1,899,681 17,449,077 2,421

ND Milton R Young 2823 B1 2010 8,533 12 19,287 1.858 0.540 5,604 2,260,697 20,765,112 2,434

Averages 20,367,511 2,530

ND Milton R Young 2823 Unit B2 2000 8,376 12 21,134 0.987 0.839 18,074 4,658,796 42,819,559 5,112

ND Milton R Young 2823 B2 2001 7,029 12 12,377 0.776 0.833 13,450 3,473,094 31,901,487 4,538

ND Milton R Young 2823 B2 2002 8,171 12 8,707 0.495 0.811 14,335 3,832,125 35,199,243 4,308

ND Milton R Young 2823 B2 2003 8,201 12 10,064 0.519 0.775 15,145 4,224,167 38,800,281 4,731

ND Milton R Young 2823 B2 2004 7,262 12 9,795 0.577 0.806 13,815 3,693,403 33,925,045 4,671

ND Milton R Young 2823 B2 2005 8,120 12 9,957 0.548 0.831 15,223 3,955,523 36,332,357 4,474

ND Milton R Young 2823 B2 2006 8,018 12 10,005 0.553 0.808 14,773 3,937,649 36,167,095 4,511

ND Milton R Young 2823 B2 2007 6,403 12 7,660 0.545 0.856 12,170 3,061,241 28,117,747 4,391

ND Milton R Young 2823 B2 2008 8,385 12 9,302 0.496 0.460 8,599 4,081,707 37,491,532 4,472

ND Milton R Young 2823 B2 2009 8,127 12 9,226 0.503 0.405 7,434 3,995,274 36,697,676 4,516

ND Milton R Young 2823 B2 2010 6,345 12 7,813 0.530 0.409 6,001 3,212,523 29,507,936 4,651

Averages 35,178,178 4,580
0.500

0.600

0.700

0.800

0.900

N

Ox Emissions (lb/m

m

Btu)

MR Young NOx Emission Rates

Unit B1

Unit B2

0.000

0.100

0.200

0.300

0.400

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (lb/m

m

Btu)

Year
12,000 

14,000 

16,000 

18,000 

20,000 

N

Ox Emissions (tpy)

MR Young NOx Mass Emissions

Unit B1

Unit B2

-

2,000 

4,000 

6,000 

8,000 

10,000 

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (tpy)

Year
Minnkota Power--Milton R. Young 2

SNCR from OAQPS Control Cost Manual, Section 4.2

Given/Assumptions

Rating (MW ) 477 ND DOH SIP Appendix B.4 report

Fuel High Heating Value (Btu/lb) 6,662 from table 3-2 in 10/06 BACT analysis

Maximum Fuel Consumption Rate (lb/hr) 7.3E+05 calculated from 4,885 mmBtu/hr from "Summary" cell B3 in ERG report

Average Annual Fuel Consumption (lb) 6.03E+09 calculated 40,182,251 calculated mmBtu/yr

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

Total system capacity factor 93.9% ERG report

Uncontrolled NOx Concentration (lb/mmBtu) 0.786 from Table 3-7 in the October 2006 company BACT report

NOx concentration after combustion controls 0.489 ND DOH SIP Appendix B.4 report

Required Controlled NOx Concentration (lb/mmBtu) 0.330 ND DOH SIP Appendix B.4 report

Source/State Total Capital Investmant estimate $ 7,120,000 calculated from Table 3-10 in the October 2006 company BACT 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 

Inflation Since 2006 1.04 CEPCI 2009/CEPCI 2006

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

Electrical Power Cost ($/kWh) $ 0.035 calculated from $ 35.00 /MWhr from from Table C.1-1 company 10/06 BACT report

50% Urea Solution Cost ($/gal) $ 1.80 calculated from $ 380 /ton 50% aqueous solution from Table C.1-1 company 10/06 BACT report

Coal Cost ($/mmBtu) $ 0.91 from Leland Olds company report

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

1.3 QB = HVm-dotfuel

QB = 6662 Btu/lb * 733,263 lb/hr

QB = 4885 mmBtu/hr

1.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 6.03E+09 lb/yr / 8760 hr/yr / 733,263 lb/hr

CFPlant = 93.9%

1.8 CFSNCR = tSCR/365 days

CFSCR = 0 days/ 365 days

CFSCR = 0%

1.6 CFTotal = CFPlant x CFSNCR

CFTotal = 94% * 0%

CFTotal = 93.9%

1.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.489 lb/mmBtu - 0.33 lb/mmBtu)/ 0.489 lb/mmBtu

ηNOx = 33%

Uncontrolled NOx emissions (tpy) 15,792
Reagent Calculations

1.14 NSR = [2NOxin – 0.7] ηNOx/ NOxin

NSR = ( 2 * 0.489 + 0.7 ) * 33% / 0.489

NSR = 1.12

1.13 Utilization = ηNOx/NSR

Utilization = 29%

1.15 m-dotreagent = NOxinQBηNOxNSR Mreagent/MNOx/SRT

m-dotreagent = 0.489 * 4885 * 33% * 112% * 60.06 / 2 / 46.01

m-dotreagent = 566 lb/hr

1.16 m-dotsol = m-dotreagent/Csol

m-dotsol = 566 / 0.50

m-dotsol = 1131 lb/hr

1.17 qsol = m-dotvol/ρsol

qsol = 1131 * 7.481 / 71

qsol = 119 gph

2.35 Tank Volume = qsolt

Tank Volume = 119 * 14 * 24

Tank Volume = 40,050 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 * 4885 *( 2375 / 4885 )^ 0.577 *( 0.66 + 0.85 * 33% )

DC = $ 2,866,312

Inflation Adjustment = 1.34

DC = $ 3,840,859
Indirect Capital Costs

Total Direct Capital Costs, A $ 3,840,859

Indirect Installation Costs 

General Facilities 0.05A $192,043

Engineering and Home Office Fees 0.10A $384,086

Process Contingencies 0.05A $192,043

Total Indirect Installation Costs, B 0.20A $768,172

Project Contingency, C = 0.15 (A+B) $691,355

Total Plant Cost D = A+B+C $5,300,385

Preproduction Cost 0.02D $106,008

Inventory Capital $72,220

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $5,478,613

Source TCI = $ 7,437,806
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 * $ 7,437,806

Annual Maintenance Cost = $ 111,567

1.22 Annual Reagent Cost = qsolCostreagenttop

1.22.a top = CFtotal8760hr/yr

top = 94% * 8760

top = 8226

Annual Reagent Cost = 119 * 1.803234862 * 8226

Annual Reagent Cost = $ 1,768,029

1.24 Annual Electricity Cost = Power (Costelect)top

1.23 Power = 0.47NOxinNSRQB/9.5

Power = 0.47 * 0.489 * 1.12 * 4885 / 9.5

Power = 132 kW

Annual Electricity Cost = 132 * 8226 * 0.035

Annual Electricity Cost = $ 37,963

1.27 Annual Water Cost = qwaterCostwater top

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

qwater = 1131 / 8.345 *( 50% / 10% - 1 )

qwater = 542

Annual Water Cost = 542 * 0.0004 * 8226

Annual Water Cost = $ 1,784

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 * 1131 *( 1 / 10% - 1 )

ΔCoal(Btu/hr) = 9,163,284

Annual ΔCoal cost = 9.2 * $ 0.91 * 8226

Annual ΔCoal cost = $ 68,590

1.32 Annual ΔAsh cost = ΔAsh costash top

1.30 ΔAsh = ΔCoal ash product/HHV

ΔAsh = 9 * 77000 / 6662

ΔAsh = 106

Annual ΔAsh cost = 106 * $ 11.28 * 8226 / 2000

Annual ΔAsh cost = $ 4,913

Total Variable Cost = $ 1,881,280

Total Direct Annual Cost = $ 111,567 + $ 1,881,280

Total Direct Annual Cost = $ 1,992,847

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 * $ 7,437,806

Indirect Annual Cost = $ 702,076

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

Total Annual Cost = $ 1,992,847 + 702,076

Total Annual Cost = $ 2,694,923

1.36 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.489 * 33% * 4885 * 8226 / 2000

NOx Removed = 3194

1.37 Cost effectiveness = TAC/NOx

 removed

Cost effectiveness = $ 844
Milton R. Young Station Unit 2, EPA's SNCR Cost Analysis Summary

Operating company Minnkota power

Facility MR Young

State ND

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

Proposed Controls proposed ASOFA + SNCR

Unit 2

Boiler Type cyclone

Fuel ND lignite

Rating (MW Gross) each 477 ND DOH SIP Appendix B.4 report

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

Rating (mmBtu/hr) 4,885 ERG report

Uncontrolled Emissions (tpy) 15,792 ERG report

Uncontrolled Emissions (lb/mmBtu) 0.786 from Table 3-7 in the October 2006 company BACT report

ASOFA Cost Analysis

Control Efficiency 37.8% ND DOH SIP Appendix B.4 report

Controlled emissions (lb/mmBtu) 0.489 ND DOH SIP Appendix B.4 report

Controlled Emissions (tpy) 9,825 OAQPS Control Cost Manual

Emissions Reduction (tpy) 5,967 calculated

Capital Cost $ 10,008,000 Table 3-10 in the October 2006 company BACT report

Capital Cost ($/kW) $ 21 Table 3-9 in the October 2006 company BACT report

O&M Cost $ 2,805,000 Table 3-11 in the October 2006 company BACT report

Annualized Cost $ 3,749,684 calculated from Tables 3-10 thru 3-12 in the October 2006 company BACT report

Cost-Effectiveness ($/ton) $ 628 calculated

SNCR Cost Analysis

Control Efficiency 33% OAQPS Control Cost Manual

Controlled emissions (lb/mmBtu) 0.330 ND DOH SIP Appendix B.4 report

Controlled Emissions (tpy) 6,630 calculated

Emissions Reduction (tpy) 3,194 OAQPS Control Cost Manual

Capital Cost $ 7,437,806 calculated form company estimate

Capital Cost ($/kW) $ 16 calculated form company estimate

O&M Cost $ 1,992,847 hybrid

Annualized Cost $ 2,694,923 hybrid

Cost-Effectiveness ($/ton) $ 844 hybrid

ASOFA+SNCR Cost Analysis

Control Efficiency 58% calculated

Controlled emissions (lb/mmBtu) 0.330 ND DOH SIP Appendix B.4 report

Controlled Emissions (tpy) 6,630 calculated

Emissions Reduction (tpy) 9,162 calculated

Capital Cost $ 17,445,806 calculated

Capital Cost ($/kW) $ 37 calculated

O&M Cost $ 4,797,847 calculated

Annualized Cost $ 6,444,608 calculated

Cost-Effectiveness ($/ton) $ 703 calculated