1995 1996

Unit 5 (tons/year) (lb/MMBtu) (tons/year) (lb/MMBtu) tons/yr lb/MMBtu

NOx 768 0.378 864.4 0.835 1133 742 718.141 0.8346 from CAMD

SO2 1269 0.629 567.3 713 474.3 514.717 from CAMD

PM 27 0.013 26906.7 13.499 from APENs

PM10 26.9 0.013 26906.7 13.499 from APENs

Unit 6

NOx 1413 0.415 2578.4 0.881 2738 2255 2742.156 0.8809 from CAMD

SO2 2785 0.820 2091.4 2059 1837.3 2091.376 from CAMD

PM 58 0.020 57606.7 20.256 from APENs

PM10 57.6 0.020 57606.7 20.256 from APENs

Unit 7

NOx 2081.0 0.393 4422.1 0.928 4237 4294 4735.183 0.9281 from CAMD

SO2 4428.7 0.833 3147.5 2930 3079.2 3433.429 from CAMD

PM 54.6 0.011 54573.3 10.505 from APENs

PM10 54.6 0.011 54573.3 10.505 from APENs

Used data from CAMD query

Heat Input (MMBtu/year) 2006 2007 2008 Average (lb/year) (lb/hr)

Unit 5 4123787 3464652 4371282 3986573.667 406,890,110 48893.30809

Unit 6 3446957 7105510 6510699 5687722

Unit 7 10155928 11454052 9559725 10389901.67

Uncontrolled AP-42 Emission Factors NOx SO2 PM PM10

(lb/ton) (lb/ton) (lb/ton) (lb/ton)

22 13.62 81.45 18.73

convert to lb/MMBtu 1.123 0.695 4.156 0.956

Controlled (%) 54.7% n/a 99.7% 98.6%

Uncontrolled AP-42 Emission Factors NOx SO2 PM PM10

(lb/ton) (lb/ton) (lb/ton) (lb/ton)

22 17.898 103.82 23.88

convert to lb/MMBtu 1.023 0.833 4.829 1.111

Controlled (%) 52.8% n/a 99.6% 98.2%

Uncontrolled AP-42 Emission Factors NOx SO2 PM PM10

(lb/ton) (lb/ton) (lb/ton) (lb/ton)

22 18.81 111.43 25.63

convert to lb/MMBtu 0.990 0.846 5.012 1.153

Controlled (%) 57.7% n/a 99.8% 99.1%

Unit 6

Unit 7

1997

Baseline Emissions

Pre-Control

Average 2006 - 2008 Uncontrolled

Unit 5
-0.10

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

NOx_Daily Average (lb/MMBtu) Drake 7

NOx_30-Day Rolling (lb/MMBtu)

Maximum 30-day rolling Emission Rate

'NOx [lb/MMBtu] = 0.5357
(tons/year) Annual 

Average 

(lb/MMBtu)

30-day Rolling 

Average 

(lb/MMBtu)

(tons/year) Annual 

Average 

(lb/MMBtu)

30-day 

Rolling 

Average 

(lb/MMBtu)

(tons/year) Annual 

Average 

(lb/MMBtu)

30-day 

Rolling 

Average 

(lb/MMBtu)

Baseline --- 1,269 0.63 2,785 0.82 4,429 0.83

DSI 60 508 0.25 0.26 1,114 0.33 0.34 1,771 0.33 0.35

Dry FGD (LSD) @ 82% control 82 501 0.15 0.15 797 0.15 0.16

Dry FGD (LSD) @ 85% control 85 418 0.12 0.13 664 0.12 0.13

Dry FGD (LSD) @ 90% control 90 279 0.08 0.09 443 0.08 0.09

FOR SCALING:

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

Unit 5 51 MW

Baseline 0 $0 $0 --- Unit 6 85 MW

DSI 761.5 $1,340,663 $1,760 $1,760 Unit 7 142 MW

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

Baseline 0 $0 $0 ---

DSI 1,671 $2,234,438 $1,337 $1,337

Dry FGD (LSD) @ 82% control (0.15 

lb/MMBtu)

2,284 $6,186,854 $2,709 $6,450

Dry FGD (LSD) @ 85% control (0.12 

lb/MMBtu)

2,367.5 $6,647,835 $2,808 $5,517

Dry FGD (LSD) @ 90% control (0.08 

lb/MMBtu)

2,507 $7,452,788 $2,973 $5,780

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

Baseline 0 $0 $0 ---

DSI 2,657 $3,732,826 $1,405 $1,405

Dry FGD (LSD) @ 82% control (0.15 

lb/MMBtu)

3,632 $8,216,863 $2,263 $4,602

Dry FGD (LSD) @ 85% control (0.12 

lb/MMBtu)

3,764.4 $8,829,321 $2,345 $4,610

Dry FGD (LSD) @ 90% control (0.08 

lb/MMBtu)

3,986 $9,898,382 $2,483 $4,828

Unit 7

Resultant Emissions

CSU DRAKE BART SO2 COST ANALYSIS

UNIT 5

Unit 5 Unit 6

UNIT 7

Alternative Control 

Efficiency (%)

UNIT 6
SCALING SIZE

CEN Boiler 4 35

CEN Boiler 5 65

Drake Unit 5 51

Addition of activated carbon for Hg (mercury) removal

TOTAL CAPITAL COSTS 

Annual Trona Costs

Annual Disposal Costs

Annual Electrical Costs

Operating Labor

Supervisor

Maintenance Labor

Maintenance Materials

Overhead

Property Tax

Insurance

Administration

Mercury removal cost

Capital Recovery

Original Annualized Costs

COMPARISON (Annualized to total) 22%

CAPITAL COSTS 

TOTAL PLANT COST

Annual Capital Recovery Cost (5.5% interest, 20 years)

O&M COSTS 

Maintenance Labor & Materials

Operating Labor

Admin & Support

Prorated Common Maint Labor & Mat'l, Operating Labor, Admin & Support

TOTAL FIXED O&M COSTS

Reagent Costs (1.2 stoic. Ratio)

CSU DSI COSTS (partially based on CENC cost estimates)

CSU semi-dry FGD COSTS

Capital Costs

O&M Costs

Trona - DSI (Unit 5)
All other variable operating costs

TOTAL VARIABLE O&M COSTS

Replacement Energy Cost

Replacement Capacity Cost

TOTAL SCRUBBING COST

Mercury Removal Capital Cost

Annual Mercury Capital Recovery Cost

Mercury Removal O&M Cost

Total Mercury Removal Cost

SO2 Allowance Savings per Ton (estimate of 2013 allowance value)
PROVIDED ON MAY 10, 2010 AT DIVISION'S REQUEST

CAPITAL COSTS

$ 6,111,180

$ 6,111,180

$ 6,000,000 rough estimate based on comparison to similarly sized DSI systems; informal estimate by DSI vendor

$ 850,000 previously provided to APCD in BART analysis for Drake power plant - not included in Division cost a

$ 6,000,000

Trona - DSI (Unit 5)

$ 238,587 (Assumes Trona is $130/ton)

$ 225,000 previously provided to APCD in BART analysis for Drake power plant - not included in Division cost a

$ 502,076 5.5%, 20 years

$ 1,340,663

PROVIDED IN BART UPDATE SUBMITTAL (March 29, 2007)

Unit 6 Unit 7

$ 38,000,000 $ 44,166,000

$ 3,179,815 $ 3,695,781

$ 492,685 $ 638,597

$ 859,047 $ 1,332,970

$ 1,351,732 $ 1,971,567

$ 393,750 $ 612,500

NC cost estimates)

$ 600,000 estimated as 10% of capital cost
$ 525,297 $ 815,095

$ 919,047 $ 1,427,595

$ 643,860 $ 981,120

$ 92,400 $ 140,800

$ 6,186,854 $ 8,216,863

$ 857,500 $ 1,750,000

$ 71,755 $ 146,439

$ 325,000 $ 450,000

$ 396,755 $ 596,439

$ (200) $ (200)

NOT INCLUDED 

IN APCD'S COST 

ANALYSIS
'S REQUEST

s; informal estimate by DSI vendor, order of magnitude estimate for BOP

nt - not included in Division cost analysis

1269 baseline SO2 emissions for Unit 5

60% removal

762 SO2 removed

1835 Trona consumption - 2.41 * SO2 removed (weight ratio 

nt - not included in Division cost analysis

March 29, 2007)

.41 * SO2 removed (weight ratio of Trona to SO2, assumes NSR of 1.0)
y = 1.1856x + 1

$1,500

$2,000

$2,500

$3,000

$0

$500

$1,000

0 500 1,000 1,500 2,000 2,500
y = 0.6228x + 1

$2,263

$2,263

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
Alternative Emissions Reduction 

(tpy)

Annualized Cost 

($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

Annual 

Emissions 

(tons/year)

Annual 

Average 

(lb/MMBtu)

30-day rolling 

(lb/MMBtu)

Baseline 0 $0 $0 ---

Baseline --- 768 0.38 0.44 Overfire air (OFA) 154 $141,844 $923 $923 

Overfire air (OFA) 20 615 0.30 0.35 Ultra-low NOx burners (ULNBs) 200 $147,000 $736 $112 

Ultra-low NOx burners (ULNBs) 26 569 0.280 0.32 Ultra-low NOx burners (ULNBs) + OFA 215.2 $288,844 $1,342 $9,230 

Ultra-low NOx burners (ULNBs) + OFA 28 553 0.272 0.31 Selective Non-Catalytic Reduction (SNCR) 230.5 $1,011,324 $4,387 $47,011 

Selective Non-Catalytic Reduction (SNCR) 30 538 0.26 0.30 ULNB+SCR 626.3 $4,467,000 $7,133 $8,732 

ULNB+SCR 81.5 142 0.070 0.080 Selective Catalytic Reduction (SCR) 626 $4,580,349 $7,314 ---

Selective Catalytic Reduction (SCR) 81.5 142 0.070 0.080

Alternative Emissions Reduction 

(tpy)

Annualized Cost 

($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

(tons/year) Annual 

Average 

(lb/MMBtu)

30-day rolling 

(lb/MMBtu)

Baseline 0 $0 $0 ---

Baseline --- 1,413 0.42 0.48 Overfire air (OFA) 283 $104,951 $371 $371 

Overfire air (OFA) 20 1,130 0.33 0.38 Selective Non-Catalytic Reduction (SNCR) 423.8 $1,208,302 $2,851 $7,810 

Selective Non-Catalytic Reduction (SNCR) 30 989 0.291 0.33 Ultra-low NOx burners (ULNBs) 452 $232,800 $515 ($34,525)

Ultra-low NOx burners (ULNBs) 32 961 0.282 0.32 Ultra-low NOx burners (ULNBs) + OFA 509 $337,751 $664 $1,857 

Ultra-low NOx burners (ULNBs) + OFA 36 904 0.266 0.31 ULNB/SCR layered approach 1,175.4 $6,182,800 $5,260 $8,226 

ULNB+SCR 83.2 237 0.070 0.080 Selective Catalytic Reduction (SCR) 1,175 $6,340,797 $5,395 ---

Selective Catalytic Reduction (SCR) 83.2 237 0.070 0.080

Alternative Emissions Reduction 

(tpy)

Annualized Cost 

($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

(tons/year) Annual 

Average 

(lb/MMBtu)

30-day rolling 

(lb/MMBtu)

Baseline 0 $0 $0 ---

Baseline --- 2,081 0.39 0.45 Overfire air (OFA) 416 $75,217 $181 $181 

Overfire air (OFA) 20 1,665 0.31 0.36 Ultra-low NOx burners (ULNBs) 583 $386,000 $662 $1,867 

Ultra-low NOx burners (ULNBs) 28 1,498 0.283 0.33 Selective Non-Catalytic Reduction (SNCR) 624.3 $2,018,575 $3,233 $39,226 

Selective Non-Catalytic Reduction (SNCR) 30 1,457 0.275 0.32 Ultra-low NOx burners (ULNBs) + OFA 749.1 $461,217 $616 ($12,473)

Ultra-low NOx burners (ULNBs) + OFA 36 1,332 0.251 0.29 ULNB/SCR layered approach 1,708.5 $8,196,000 $4,797 $5,698 

ULNB+SCR 82.1 372 0.070 0.081 Selective Catalytic Reduction (SCR) 1,708 $8,510,067 $4,981 ---

Selective Catalytic Reduction (SCR) 82.1 372 0.070 0.081

Unit 7

UNIT 6

Alternative Control 

Efficiency (%)

Alternative

UNIT 5

Control 

Efficiency (%)

Alternative Control 

Efficiency (%)

UNIT 7

Unit 5

CSU DRAKE BART NOx COST ANALYSIS

Resultant Emissions

Unit 6

Resultant Emissions

Resultant Emissions
PROVIDED IN ORIGINAL BART SUBMITTAL (2006)

OFA - Unit 5 OFA - Unit 6 OFA - Unit 7 Notes

Basic Equipment - NOx Equipment

NOx Equipment Installation

NOx Control Modification

Control Installation & Integration

Lost Revenue - NOx Equip+Control Install

TOTAL CAPITAL COST

Retrofit Factor 1.30 1.40 1.40

Adjusted Retrofit Capital Cost $1,438,895 $1,078,743 $774,738

Capital Cost w/ Inflation Factor (2%) $1,467,672 $1,100,318 $790,232

$/kW $ 29 $ 13 $ 6

Increased Carbon Loss (Loss on Ignition)

Annual Electrical Costs (NOx equipment) Variable O&M Costs

Operating Labor

Supervisor

Maintenance Labor

Maintenance Materials

Overhead

Property Tax

Insuance

Administration Fixed O&M Costs

Capital Recovery $122,814 $92,074 $66,126 5.5%, 20 years

TOTAL ANNUALIZED COST $141,844 $104,951 $75,217

Annual/Total Capital Cost 9.9% 9.7% 9.7%

PROVIDED ON 2/2/2009 - SO2 and NOx Emissions Control Cost & Feasibility Information for Drake and Nixon Plants

ULNBs - Unit 5 ULNBs - Unit 6 ULNBs - Unit 7 Notes

Basic Equipment - NOx Equipment $ 340,000 $ 550,000 $ 930,000

NOx Equipment Installation $ 390,000 $ 630,000 $ 1,070,000

Construction Management $ 50,000 $ 80,000 $ 140,000

Craft Supervision $ 40,000 $ 40,000 $ 40,000

Startup $ 30,000 $ 30,000 $ 30,000

Contigency (@ 20%) $ 170,000 $ 270,000 $ 440,000

Boiler modeling and pulverizer modifications $ 408,000 $ 640,000 $ 1,060,000

TOTAL CAPITAL COST $ 1,428,000 $ 2,240,000 $ 3,710,000

$/kW $ 28 $ 26 $ 26

Increased Carbon Loss (Loss on Ignition) $ 7,000 $ 13,000 $ 22,000

Operating Labor

Supervisor

Maintenance Labor

Maintenance Materials

Overhead

Property Tax

Insuance

Administration

Capital Recovery $ 134,793 $ 211,440 $ 350,198 7%, 20 years

TOTAL ANNUALIZED COST $ 147,000 $ 232,800 $ 386,000

Annual/Total Capital Cost 10.3% 10.4% 10.4%

PROVIDED ON 2/2/2009 - SO2 and NOx Emissions Control Cost & Feasibility Information for Drake and Nixon Plants

SCR - Unit 5 SCR - Unit 6 SCR - Unit 7 Notes

CSU Costs - SCR/ULNB+SCR

Capital Costs

$15,634 $7,935

$ 12,207 $ 8,360 $ 13,802

O&M Costs

Capital Costs

$3,396 $1,938

$770,531

Capital Costs

$10,939

$553,384

$1,156

CSU COSTS - Overfire Air

CSU Costs - Ultra low NOx burners

O&M Costs

$1,106,842

SCR - Unit 5 SCR - Unit 6 SCR - Unit 7 Notes

SCR system including reactor & injection $ 2,230,000 $ 2,950,000 $ 4,680,000

Ammonia Handling and Injection $ 1,318,800 $ 1,160,000 $ 1,760,000 x1.57 for retrofit difficulty (Unit 5 only)

Air Preheater Modifications $ 769,300 $ 1,131,500 $ 1,805,400 x1.57,1.55,1.53 for retrofit difficulty (Unit 5,6,7 respectively)

Miscellaneous equipment capital costs $ 361,100 $ 480,500 $ 780,300 x1.57,1.55,1.53 for retrofit difficulty (Unit 5,6,7 respectively)

ID fan modifications/replacemnt $ 1,148,100 $ 1,478,400 $ 1,976,000 x2.64,2.63,2.6 for retrofit difficulty (Unit 5,6,7 respectively)

Inlet Duct $ 1,540,000 $ 2,000,200 $ 3,070,200 x1.4,1.37,1.29 for retrofit difficulty (Unit 5,6,7 respectively)

Outlet Duct $ 1,554,000 $ 2,027,600 $ 3,096,000 x1.4,1.37,1.29 for retrofit difficulty (Unit 5,6,7 respectively)

Contractor Fees $ 890,000 $ 1,190,000 $ 1,810,000 approximately 10% of direct costs

TOTAL INSTALLED COST W/ RETROFIT $ 17,660,340 $ 22,352,760 $ 26,569,060 x1.8,1.8,1.4 for retrofit difficulty (Unit 5,6,7 respectively)

General Facilities $ 880,000 $ 1,170,000 $ 1,400,000 approximately 5% of total installed cost w/retrofit

Engineering & Project Management $ 1,770,000 $ 2,350,000 $ 2,790,000 approximately 10% of total installed cost w/retrofit

Contingencies $ 3,530,000 $ 4,690,000 $ 5,590,000 approximately 20% of total installed cost w/retrofit

Preproduction Costs $ 640,000 $ 870,000 $ 1,100,000

Inventory Capital $ 70,000 $ 110,000 $ 170,000

Initial Catalyst and Chemicals $ 970,000 $ 1,480,000 $ 2,430,000

Prepaid Royalties (Owner's Cost) $ 349,660 $ 1,567,240 $ 1,870,940

Market Demand Escalation $ 2,590,000 $ 3,460,000 $ 4,190,000

TOTAL CAPITAL COST (SCR) $ 28,460,000 $ 38,050,000 $ 46,110,000

TOTAL CAPITAL COST (ULNB+SCR) $ 29,368,000 $ 39,540,000 $ 48,110,000

$/kW $ 558 $ 448 $ 325

SCR - Unit 5 SCR - Unit 6 SCR - Unit 7

Catalyst replacement $ 320,000 $ 490,000 $810,000

Reagent (Aqueous Ammonia) $ 770,000 $ 1,180,000 $1,940,000

Operating Labor $ 90,000 $ 100,000 $110,000

Maintenance Labor $ 360,000 $ 480,000 $570,000

Maintenance Materials $ 40,000 $ 60,000 $100,000

Electricity $ 150,000 $ 230,000 $370,000

Capital Recovery $ 2,850,349 $ 3,800,797 $ 4,610,067 approx 7.7%, 20 years

TOTAL ANNUALIZED COST $ 4,580,349 $ 6,340,797 $ 8,510,067

ULNB+SCR ANNUALIZED COST $ 4,467,000 $ 6,182,800 $ 8,196,000

SCR only adjusted to 15% $ 4,269,000 $ 5,707,500 $ 6,916,500

Annual/Total Capital Cost (SCR) 16.1% 16.7% 18.5%

Annual/Total Capital Cost (ULNB+SCR) 15.2% 15.6% 17.0%

COST DIFFERENCE to adjust to 15% $ 311,349 $ 633,297 $ 1,593,567

THE DIVISION DID NOT CONDUCT ADDITIONAL ULNB+SCR COST ANALYSIS SINCE THE SCR COSTS WERE DEEMED REASONABLE AND ULNB+SCR WERE CHEAPER THAN SCR

Adjust to $300/kW $ 15,300,000 $ 25,500,000 $ 42,600,000

$/kW $ 300 $ 300 $ 300

Adjusted Capital Recovery $ 1,532,338 $ 2,553,897 $ 4,266,510

Adjust Annualized Cost ($300/kW) $ 3,262,338 $ 5,093,897 $ 8,166,510

SCR $/ton $ 5,209 $ 4,334 $ 4,780

NOTES: CSU DID NOT INCLUDE OVERHEAD (typically 60% of O&M, labor, and maint. Mtl costs OR taxes,insurance, and administration)

Predicted Overead $ 294,000 $ 384,000 $ 468,000

Predicted Taxes, Insurance, and Administration $ 706,414 $ 894,110 $ 1,062,762

total $ 1,000,414 $ 1,278,110 $ 1,530,762

O&M Costs
Fuel Heating Value % Sulfur % Ash Fuel Heating Value

Unit 5 9935 0.368 8.685 9822

Unit 6 10804 0.462 10.628 10515

Unit 7 10858 0.479 11.179 11474

Coal Mine/Region Southern PRB

Coal Rank Classification Sub-bituminous

Year Moisture % Ash % Sulfur % Btu/Lb

2006 27.02 4.65 0.21 8,816.34

2007 27.06 4.66 0.22 8,808.64

2008 27.23 4.61 0.20 8,788.98

2009 27.38 4.63 0.22 8,753.77

Avg. 06 - 08 27.11 4.64 0.21 8,804.65

Coal Mine/Region 20-Mile Foidel Creek

Coal Rank Classification Bituminious

Year % Moisture % Ash % Sulfur Btu/Lb

2006 9.49 12.53 0.54 11,005.58

2007 9.56 12.52 0.53 10,999.92

2008 9.81 10.73 0.50 11,246.92

2009 10.12 10.48 0.49 11,217.42

Avg. 06 - 08 9.62 11.93 0.52 11,084.14

Coal Mine/Region Colowyo

Coal Rank Classification Sub-bituminous, Class A

Year % Moisture % Ash % Sulfur Btu/Lb

2006 Non-Recevied

2007 17.16 5.50 0.35 10,477.00

2008 17.68 5.92 0.39 10,307.00

2009 Non-Recevied

Avg. 06 - 08 17.42 5.71 0.37 10,392.00

Coal Mine/Region West Elk

Coal Rank Classification Bituminous

Year % Moisture % Ash % Sulfur Btu/Lb

2006 Non-Received

2007 7.55 8.71 0.45 12,266.00

2008 Non-Received

2009 11.13 5.15 0.43 11,849.00

2006 2007
Avg. 06 - 08 7.55 8.71 0.45 12,266.00
% Sulfur % Ash Fuel Heating Value % Sulfur % Ash Fuel Heating Value % Sulfur

0.383 8.708 9636 0.324 7.041 9798 0.36

0.47 10.525 10927 0.481 9.993 10749 0.47

0.526 11.9 11018 0.48 10.351 11117 0.50

Nitrogen %

0.73

0.66

0.67

0.69

0.69

% Nitrogen

1.54

1.60

1.58

1.62

1.57

% Nitrogen

1.34

1.35

1.35

% Nitrogen

1.30

1.65

2007 2008 Average
1.30
% Ash

8.14

10.38

11.14
Output (@ 

98th Percentile 

Impact)

98th Percentile 

Impact 

Improvement

98th Percentile 

Improvement 

from Maximum

(dv) (∆ dv) (%)

5 0.943

6 0.997

7 0.994

5 0.251 1.72 0.12 6%

6 0.328 1.65 0.18 10%

7 0.333 1.55 0.29 16%

5 0.120

6 0.120 1.59 0.24 13%

7 0.120 1.45 0.39 21%

6 0.100 1.59 0.25 14%

7 0.100 1.44 0.40 22%

6 0.070 1.58 0.26 14%

7 0.070 1.42 0.41 22%

5 0.321

6 0.120

7 0.120

Pre-Control 

Days >0.5 dv

Post-Control 

Days >0.5 dv

5 0.943

6 0.997

7 0.994

5 0.251 34 32

6 0.328 34 32

7 0.333 34 31

5 0.120 34

6 0.120 34 31

7 0.120 34 28

6 0.100 34 31

7 0.100 34 28

6 0.070 34 31

7 0.070 34 28

5 0.321

6 0.120

7 0.120

dry FGD (LSD)

0.25

n/a

dry FGD (LSD)

dry FGD (LSD)

3-year totals

SO2 BART Control Limit

dry FGD (LSD)

Combo 34 1

Max 24-hr SO2 rates

Max 24-hr SO2 rates

Rocky 

Mountain 

National Park

34

SO2 Emission Rate 

(lb/MMBtu)

DSI 

Combo 

dry FGD (LSD)

---

1.59 86%

---

SO2 Control Scenario Boiler(s)

1.84

---

Unit(s) Class I Area 

Affected

SO2 Emission Rate 

(lb/MMBtu)

dry FGD (LSD)

DSI 
Cost 

Effectiveness

($/dv)

$11,266,076

$12,210,046

$12,871,815

$27,470,391

$22,697,484

 n/a 

 n/a 

$28,999,176

$23,967,026

∆days

Pre-Control 

Days >1.0 

dv

PostControl 

Days >1.0 

dv

∆days

2 17 14 3

2 17 14 3

3 17 13 4

34 17 17

3 17 14 3

6 17 12 5

3 17 14 3

6 17 12 5

3 17 14 3

6 17 12 5

0

17 ---

33 17 17

---

3-year totals

---

 n/a 

---
Output (@ 

98th Percentile 

Impact)

98th Percentile 

Impact 

Improvement

(dv) (∆ dv)

5 0.619

6 0.827

7 0.710

5 0.390 1.79 0.05

6 0.390 1.68 0.16

7 0.390 1.66 0.18

5 0.300* 1.76 0.07

6 0.330* 1.66 0.180

7 0.310* 1.61 0.22

5 0.280* 1.76 0.08

6 0.282* 1.64 0.197

7 0.283* 1.60 0.24

5 0.265* 1.76 0.08

6 0.291* 1.64 0.19

7 0.275* 1.59 0.24

5 0.272* 1.76 0.08

6 0.266* 1.63 0.20

7 0.251* 1.58 0.26

5 0.234 1.75 0.24

6 0.234 1.62 0.24

7 0.234 1.57 0.24

5 0.070 1.71 0.12

6 0.070 1.56 0.27

7 0.070 1.47 0.37

5 0.321

6 0.070

7 0.070

3-year totals

Pre-Control 

Days >0.5 dv

5 0.619

6 0.827

7 0.710

5 0.390 34

6 0.390 34

NOx Control Scenario Boiler(s)

Class I Area 

Affected

NOx Emission Rate (lb/MMBtu)*

34

Max 24-hour NOx rates

NOx Control Scenario

NOx Control Scenario

SNCR

1.59

ULNBs+OFA

OFA

ULNB

NOx Control Scenario

Combo 

SCR 

0.25

---

NOx Control Scenario Boiler(s)

Max 24-hour NOx rates 1.84

NOx Emission Rate (lb/MMBtu)*
7 0.390 34 5 0.300* 6 0.330* 7 0.310* 5 0.280* 6 0.282* 7 0.283* 5 0.265* 6 0.291* 7 0.275* 5 0.272* 6 0.266* 7 0.251* 5 0.234 34 6 0.234 34 7 0.234 34 5 0.070 34 6 0.070 34 7 0.070 34 5 0.321 34 6 0.070 7 0.070

ULNBs+OFA

SCR 

Combo 

Rocky 

Mountain 

National Park

NOx Control Scenario

SNCR

OFA

ULNB
98th Percentile 

Improvement 

from 

Maximum

Cost 

Effectiveness

(%) ($/dv)

---

3% n/a 

9% n/a 

10% n/a 

4% $1,970,053

10% $583,061

12% $335,791

4% $1,934,212

11% $1,181,727

13% $1,615,062

4% $12,641,549

11% $6,260,633

13% $8,272,850

4% $3,703,128

11% $1,663,798

14% $1,794,618

5% n/a 

12% n/a 

15% n/a 

7% $36,024,194

15% $22,647,619

20% $22,091,644

3-year 

totals

Post-Control 

Days >0.5 dv

∆days Pre-Control 

Days >1.0 

dv

PostControl 

Days >1.0 

dv

∆days

--- --- 17 --- ---

34 0 17 15 2

31 3 17 14 3

86% n/a 

---
31

3 17 143

340 17 143

313 17 143

286 17 143

322 17 143

277 17 143

268 17 134

1 33 170 17

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a