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 742 718.1410.8346from CAMD SO2 **1269 0.629**  567.3 713 474.3 514.717 from CAMD PM **27 0.013**  26906.7 13.499from APENs PM10 **26.9 0.013**  26906.7 13.499from APENs
Unit 6 NOx **1413 0.415**  2578.4 0.881 2738 2255 2742.1560.8809from CAMD SO2 **2785 0.820**  2091.4 2059 1837.3 2091.376 from CAMD PM **58 0.020**  57606.7 20.256from APENs PM10 **57.6 0.020**  57606.7 20.256from APENs
Unit 7 NOx **2081.0 0.393**  4422.1 0.928 4237 4294 4735.1830.9281from CAMD SO2 **4428.7 0.833**  3147.5 29303079.2 3433.429 from CAMD PM **54.6 0.011**  54573.3 10.505from APENs PM10 **54.6 0.011**  54573.3 10.505from APENs Used data from CAMD query Heat Input (MMBtu/year) 2006 2007 2008Average (lb/year) (lb/hr) Unit 5 4123787 346465243712823986573.667 406,890,11048893.30809 Unit 6 3446957 71055106510699 5687722 Unit 7 10155928 11454052955972510389901.67

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 

# Dr**ak e 7** 

NOx_Daily Average (lb/MMBtu) NOx_30

-DayRolling (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)**  **Increm ental** 

**Cost ($/ton)** Unit 5 51MW Baseline 0 $0 $0

--- Unit 6 85MW DSI 761.5 $1,340,663 $1,760 $1,760 Unit 7 142MW

**Alternative Emissions**  **Reduction (tpy) Annualized Cost** 

**($) Cost** 

**Effectiveness ($/ton)**  **Increm ental** 

**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)**  **Increm ental** 

**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, order of magnitude estimate for BOP

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

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 analysis

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 $ **CSU DSI COSTS (partially based on CENC 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

# PROVIDED ON MAY 10, 2010 AT DIVISION'S REQUEST

rough estimate based on comparison to similarly sized DSI systems; informal estimate by DSI vendor, order of magnitude estimate for BOP previously provided to APCD in BART analysis for Drake power plant - not included in Division cost analysis

1269baseline SO2 emissions for Unit 5 60%removal 762SO2 removed
1835Trona consumption - 2.41 * SO2 removed (weight ratio of Trona to SO2, assumes NSR of 1.0)

previously provided to APCD in BART analysis for Drake power plant - not included in Division cost analysis

PROVIDED IN BART UPDATE SUBMITTAL (March 29, 2007)

# Trona consumption - 2.41 * 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

$2,2630 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 6OFA - Unit 7Notes 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 $66,1265.5%, 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 6ULNBs - Unit 7Notes 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 6SCR - Unit 7Notes **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 6SCR - Unit 7Notes 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 6SCR - 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 % AshFuel Heating Value

Unit 5 9935 0.3688.685 9822 Unit 6 10804 0.46210.628 10515 Unit 7 10858 0.47911.179 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 ClassificationSub-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% AshFuel Heating Value% Sulfur% AshFuel Heating Value% Sulfur

0.3838.708 96360.3247.041 97980.36 0.4710.525 109270.4819.993 107490.47 0.52611.9 110180.4810.351 111170.50

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

# % Ash8.14

10.38 11.14

## Output (@ 98th 

## Percentile Impact)98th



## Percentile Impact Improvement98th



## 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 dvPost-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 Park34 SO2 Emission Rate (lb/MMBtu)

DSI Combo dry FGD (LSD) ---

86% 1.59 --- SO2 Control ScenarioBoiler(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

∆daysPre-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

17 33 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 ScenarioBoiler(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 ScenarioBoiler(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 14 3

34 0 17 14 3 31 3 17 14 3 28 6 17 14 3 32 2 17 14 3 27 7 17 14 3 26 8 17 13 4 1 33 17 0 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