OP_YEAR STATE FACILITY_NAME ORISPL_CODE

UNITID OP_STATUS_INFO PRG_CODE_INFO

UNIT_TYPE_INFO

PRIMARY_FUEL_INFO

SECONDARY_FUEL_INFO 2000 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2001 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2002 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2003 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2004 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2005 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2006 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2007 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2008 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2009 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler Coal 2010 NE Gerald Gentleman Station 6077 2 Operating ARP Dry bottom wall-fired boiler CoalSO2_CONTROL_INFO NOX_CONTROL_INFO Low NOx Burner Technology (Dry Bottom only ) Other Low NOx Burner Technology (Dry Bottom only ) Other Low NOx Burner Technology (Dry Bottom only ) Other Low NOx Burner Technology (Dry Bottom only ) Other Low NOx Burner Technology (Dry Bottom only ) Other Low NOx Burner Technology (Dry Bottom only ) (Retired Jun 30, 2005) Other Other Other Other Other OtherPART_CONTROL_INFO

Electrostatic Precipitator Baghouse (Began Apr 10, 2001) Electrostatic Precipitator (Retired Mar 31, 2001) Baghouse Baghouse Baghouse Baghouse Baghouse Baghouse Baghouse Baghouse BaghouseSTATE FACILITY _NAME ORISPL

CODE UNIT ID ASSOC

STACKS OP YEAR PRG CODE SUM OP

TIME NUM

MONTHS REPORTED NE Gerald Gentleman Station 6077 2 2000 ARP 8,356 12 NE Gerald Gentleman Station 6077 2 2001 ARP 7,710 12 NE Gerald Gentleman Station 6077 2 2002 ARP 8,424 12 NE Gerald Gentleman Station 6077 2 2003 ARP 7,742 12 NE Gerald Gentleman Station 6077 2 2004 ARP 8,174 12 **Totals** 40,405 **Av erages**  8,081

NE Gerald Gentleman Station 6077 2 2005 ARP 7,800 12

NE Gerald Gentleman Station 6077 2 2006 ARP 8,507 12 NE Gerald Gentleman Station 6077 2 2007 ARP 7,820 12 NE Gerald Gentleman Station 6077 2 2008 ARP 8,652 12 NE Gerald Gentleman Station 6077 2 2009 ARP 8,230 12 **Totals** 33,209 **Av erages**  8,302SO2

MASS SO2

RATE NOX

RATE NOX

MASS CO2 MASS HEAT INPUT HEAT INPUT 12,988 0.496 0.323 8,634 5,375,431 52,392,993 6,270 14,603 0.573 0.313 8,158 5,232,567 50,999,608 6,615 16,471 0.569 0.319 9,440 5,944,663 57,940,211 6,878 14,476 0.537 0.330 9,086 5,532,105 53,919,191 6,964 16,582 0.584 0.344 9,960 5,830,609 56,828,555 6,953 75,120 45,278 27,915,374 272,080,558 15,024 0.552 0.333 9,056 5,583,075 54,416,112 6,734

14,170 0.531 0.346 9,434 5,476,657 53,378,729 6,843

16,281 0.557 0.348 10,361 5,998,117 58,461,168 6,872 13,679 0.540 0.305 7,915 5,200,444 50,686,605 6,482 17,434 0.593 0.338 10,032 6,130,420 58,783,061 6,794 16,125 0.595 0.345 9,540 5,688,946 54,242,446 6,591 63,519 37,848 23,017,927 222,173,281 15,880 0.572 0.341 9,462 5,754,482 55,543,320 6,690**NPPD - Gerald Gentleman 2**  **Modified from OA QPS Control Cost Manual Section 4.2, SCR** 

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

(MW ) 700 Override Cost Manual TCC? ($/kW ) 270 $ SCR by pass included? No Fuel High Heating Value (Btu/lb) 8,900 Maximum Fuel Consumption Rate (lb/hr) 846,966 Average Annual Fuel Consumption (lb) 6.51E+09 Number of SCR Operating Day s 361 Plant Capacity

Factor 88% Uncontrolled NOx Concentration (lb/mmBtu) 0.341 LNB + OFA Total Capital Cost 18,465,000 $ LNB + OFA Total Annual Cost 1,480,000 $ LNB outlet = SCR inlet NOx Concentration (lb/mmBtu) 0.23 Required Controlled NOx Concentration (lb/mmBtu) 0.05 Acceptable Ammonia Slip (ppm) 2.0 Fuel Volum e Flow Rate (ft3/min/mmBtu/hr) 516 Fuel Sulfur Content 0.30% Fuel Ash Content 4.69% Number of SCR reactor chambers 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) 825 Equipm ent Life (y ears) 20 Annual Interest Rate 7% Inflation Since 1998 1.34 Cataly st Cost, Initial ($/ft3) 142 $ Cataly st Cost, Replacement ($/ft3) 142 $ Electrical Power Cost ($/kW h) 0.046 29% Ammonia Solution Cost ($/lb) 0.06 $ Operating Life of Cataly st (hours) 24,000 Natural gas unit cost ($/mcf) 4.98 $ Natural gas for reheat (mcf) NANDEP report

company

report assumed company

report from permit application calculated from 7,538 mmB tu/hr from permit application calcuated from 57,940,211 mmB tu/y r for 2002 from CAMD calculated from 8,652 hours 2008 CAM data calcuated average for 2006 - 2009 from CAMD company

report company

report presumptive BART NPS assumption company

report OAQPS Control Cost Manual from EIA 2001 from EIA 2001 company

report 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 company

report OAQPS Control Cost Manual OAQPS Control Cost Manual CEPCI 2009/CEPCI 1998 calculated from 5,000 $ assumed from other analy ses calculated from 5,000 $ assumed from other analy ses calculated from 46 $ /kW from company report calculated from 400 $ assumed from other analy ses company

report EIA 2010 price forecast**LNB Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc** ( 0.34

- 0.23 )/

**Boiler Calculations**



### 2.3 Q B 

### = HVm-dot fuel QB = 8,900 Btu/lb * 846,966 lb/hr QB = 7,538 Btu/hr



### 2.7 CF Plant 

### = actual m fuel 

### /maximum m fuel CFPlant = 6.51E+09 lb/y r / 8760 hr/y r / 846,966 lb/hr CFPlant = 88%



### 2.8 CF SCR 

### = t SCR



### /365 day s CFSCR = 361 day s/ 365 day s CFSCR = 99%



### CF Total 

### = CF Plant 

### x CF SCR CFTotal = 88% * 99% CFTotal = 87%



### 2.12 q fluegas 

### = q fuel 

### Q B 

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

### F)n SCR qfluegas = 516 ft3/min/(mmBtu/hr)* 7538 mmB tu/hr*( 460 + qfluegas = 8,617,494 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) 9749** 

**Overall Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc** ( 0.34

- 0.05 )/

**NOx removed =** 8318 tpy

**Controlled NOx emissions (tpy) =** 1431 tpy **versus CDPHE report**0.34 = 32%

825 )/( 460 + 700 )* 2

lb/m mB tu

0.34 = 85%

681**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 * 7538 = 21182



### 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 * 0.3 ) Sadj = 0.977 

### 2.24 T adj 

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

### x T 2 

### ) Tadj = 15.16 - ( 0.039 * 825 ) + 2.74E-05 * Tadj = 1.329 Volcataly st = 16,618 ft3 each = 470.9 m3 each



### 2.25 A catalyst 

### = q fluegas 

### /(16 ft/sec x 60 sec/min) Acataly st = 4,308,747 /( 16 * 60 ) Acataly st = 4488 ft2 7,280



### 2.26 A SCR



### = 1.15 x A catalyst ASCR = 1.15 * 4488 ASCR = 5162 ft2



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

l = w = 71.8 ft



### 2.28 n layer 

### = Vol catalyst 

### /(h’ layer



### x A catalyst 

### ) nlay er = 16618 /( 3.1 * 4488 ) nlay er (calc) = 1.0 nlay er = 2.0



### 2.29 h layer 

### = [Vol catalyst 

### /(n layer



### x A catalyst 

### )] + 1 hlay er = 16618 /( 2.0 * 4488 ) + 1 hlay er = 2.9



### 2.3 n total 

### = n layer



### + n empty ntotal = 1 + 1 ntotal = 2

### 2.31 h SCR 

### = n total 

### (c 1 

### + h laye 

### r) + c 2 hSCR = 2 * ( 7 + 2.9 ) + 9 hSCR = 29 ft680625

### Reagent Calculations



### 2.32 m- dot reagent



### = NOx in 

### Q B 

### ASR

**η NOx**  

### M reagent



### /M NOx 

### m-dotreagent = 0.23 * 7538 * 1.05 * **78%** * 17.03 m-dotreagent = 527 lb/hr



### 2.33 m- dot sol 

### = m -dot reagent 

### /C sol 

### m-dotsol = 527 / 0.29 m-dotsol = 1818 lb/hr



### 2.34 q sol 

### = (m -dot vol 

### /ρ sol 

### )V sol 

### qsol = 1818 * 7.481 / 56 qsol = 243 gph



### 2.35 Tank Volume = q sol 

### t Tank Volume = 243 * 14 * 24 Tank Volume = 81,619 gal

### / 46.01

### Direct Capital Cost



### 2.36 DC = Q B 

### [($3380/MMBtu/hr) + f(h SCR 

### ) +f(NH 3 

### rate) + f(new) + f(bypass)](3500/Q
DC = 3769 (( 3,380 $ + 

### 2.37 f(h SCR 

### ) = {[$612/(ft-m mBt u/hr)]h SCR 

### } - $187.9/(m mBt u/hr) f(hSCR) = 6.12 * 29

- 187.9 

### f(hSCR) = (12)

$ /mmBtu/hr



### 2.38 f(NH 3 

### rate) = [($411/l b/hr)(m-dot reagent



### /Q B 

### )] - $47.3/(m

mBt u/hr) f(NH3rate) = 411 * 264 / 3769

- 47.3 

### f(NH3rate) = (19)

$ /mmBtu/hr 

### 2.39 f(new) = $0/(mmBtu/hr) for retrofit f(new) =

-

$ 2.41 f(bypass) = $0/(mmBtu/hr) for no bypass f(bypass) =

-

$ /mmBtu/hr 

### 2.43 f(Vol catalyst 

### ) = Vol catalyst 

### CCinit ial f(Volcatalyst) = 16618 * 142 f(Volcatalyst) = 2,354,653

$

DC = 3769 * ( 3,380 $ + (12)

$ + (19)

$ + DC = 14,654,887 $ for each reactor DC = 29,309,773 $ for all reactors

**Inflation Adjustment =** 1.34

DC = 19,636,419 $

### rate) + f(new) + f(bypass)](3500/Q B 

### ) 0.35 

### + f(Vol catalyst 

### )

)] - $47.3/(m

mBt u/hr)

2,743,832 $

- $

- $ +

-

$ )*( 3500 / 3769 )^ 0.35 + 2,354,653 $**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 = 0.058 /lb * 1818 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 @** 270 $/kW =
**Total Capital Investment TCI =**Cost Manual CDPHE Cost Cost Cost Cost 19,636,419 $ ratios 51,330,000 $ ratios

$981,821 5% $1,963,642 10% $981,821 5% $3,927,284 20% 

### 23,584,000 $ 46% $3,534,555 18% $27,098,259 138%

$0 0% 7,185,000 $ $0 0% $541,965 3%

day s = $35,436 0% +D+E+F+G+H+I $27,675,660 141% 115,527,000 $ 225% Cost/kW = $40 165 $

189,000,000 $ 72,344,739

$ 103 $ 189,000,000 $

### 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 * 189,000,000 $ Annual Maintenance Cost = 2,835,000 $ 

### 2.47 Annual Reagent Cost = q reagent 

### Cost reagent 

### t op 

### 2.47a t op 

### = **CF total**  

### 8760hr/yr top = **87%** * 8760 

### top = **7592** Annual Reagent Cost = 1818 * **7592** * 0.058 Annual Reagent Cost = 800,657 $ 

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

### t op 

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

### [NOx **in** 

### ηNOx + 0.5(ΔP **duct** 

### + n **total** 

### ΔP **catalyst** 

### Power = 0.105 * 7538 *( 0.23 Power = 2121 kW Annual Electricity Cost = 2121 * **7592** * 0.046 Annual Electricity Cost = 740,755 $ 

### 2.51 Annual Catalyst Replacement Cost = (Catalyst Replacement Cost)FWF 2.5 Catalyst Replacement Cost = n SCR 

### Vol catalyst 

### CC replace 

### /R layer 

### Catalyst Replacement Cost = 2 * 16618 * 141.6930253 Catalyst Replacement Cost = 2,354,653 $ 

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

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



### /h year 

### Y = 24000 /( 87% * 8760 Y = 3.16 FW F = 0.07 *( 1 /( 1 FW F = 0.31 Annual Catalyst Cost = 732,419 $

Annual natural gas Cost =

- mcf/yr * Annual natural gas Cost =

- $



### Lost Ash Sales =

DAC = **5,108,831 $** 



### 2.55 CRF = i(1+i) n



### /[(1+i ) n 

### -1] CRF = 0.07 *( 1 + 0.07 CRF = 0.0944

Indirect Annual Cost = CFR * TCI Indirect Annual Cost = 0.0944 * 189,000,000 $ Indirect Annual Cost = 17,840,263 $



### 2.56 Total

Annual Cost = Direct Annual Cost + Indirect Annual Cost

### SCR Total Annual Cost = 5,108,831 $ + 17,840,263 = 22,949,094 $ CC+SCR Total Annual Cost = 22,949,094 $ + 1,480,000 $ = 24,429,094

$



### 2.57 NOx Removed = NOx in 

### η NOx 

### Q B 

### t op 

### NOx Removed = 0.23 * 78% * 7538 NOx Removed by SCR = 5,150

Total NOx Removed = 8,318



### 2.58 Cost effectiveness = TAC/NOx removed SCR Cost effectiveness = 4,456 $ Total Cost effectiveness = 2,937 $

### DAC = Annual Maintenance Cost + Annual Reagent Cost + Annual Electricity Cost + Annual Water Cost + Annual Catalyst Cost 676,000.00 $ NPPD Apndx C 57,000.00 $ NPPD Apndx C 733,000.00 $ NPPD Apndx C

1,776,000 $ NPPD Apndx C

**catalyst** 

### )]

* 78% + 0.5 * ( 3 + 2 * 1 )) 2,163,000 $ NPPD Apndx C 249,000 $ NPPD Apndx C 2,412,000 $ NPPD Apndx C 

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

layer 

### / 2

)

+ 0.07 )^ 3

- 1 )

2,367,000 $ NPPD Apndx C

4.98 $ /mcf

7,288,000 $ calculated

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

- 1 )

19,627,000 $ NPPD Apndx C



### Total Annual Cost = Direct Annual Cost + Indirect Annual Cost

### 27,145,500 $ calculated from NPPD report 28,625,500 $ NPPD report

* **7592** / 2000 4,692 NPPD Apndx C

12,463 calculated from NPPD report

5,445 $ NPPD report

2,297 $ NPPD report

### calculated from NPPD report

calculated from NPPD report**Operating company Nebraska Public Power District** 

**Facility Gerald Gentleman Station**  **State NE**  **Contact**

**Proposed Controls rejected SCR**  Unit 2 Boiler Ty pe wall-fired Fuel PRB sub-bituminous Rating (MW Gross) each 700 company report **Presumptive BA RT limit (lb/mmBtu)**  **0.23 BA**  **RT Guidelines for tangentially-fired boiler > 200 MW firing sub-bituminous coal at facility > 750 MW** Rating (mmBtu/hr) 7,538 mmB tu/hr from permit application Uncontrolled Emissions (tpy ) 9,749 OAQPS Control Cost Manual Uncontrolled Emissions (lb/mmBtu) 0.34 average for 2006 - 2009 from CAMD

**Combustion Controls Cost-benefit A nalysis**  Control Efficiency 32% calculated Controlled emissions (lb/mmBtu) 0.230 presumptive BART Controlled Em issions (tpy ) 6,581 calculated Em issions Reduction (tpy ) 3,168 calculated Capital Cost 18,465,000 $ company report Capital Cost ($/kW ) 26 $ calculated O&M Cost Annualized Cost 1,480,000 $ company report Cost-Effectiveness ($/ton) 467 $ calculated

**SCR Cost-benefit A nalysis**  Control Efficiency 78% OAQPS Control Cost Manual Controlled emissions (lb/mmBtu) 0.05 NPS assumption Controlled Em issions (tpy ) 1,431 calculated Em issions Reduction (tpy ) 5,150 OAQPS Control Cost Manual Capital Cost 189,000,000 $ calculated Capital Cost ($/kW ) 270 $ assumed O&M Cost 5,108,831 $ OAQPS Control Cost Manual Annualized Cost 22,949,094 $ OAQPS Control Cost Manual Cost-Effectiveness ($/ton) 4,456 $ OAQPS Control Cost Manual

**Combustion Controls + SCR Cost-benefit A nalysis**  Control Efficiency 85% calculated Controlled emissions (lb/mmBtu) 0.05 calculated Controlled Em issions (tpy ) 1,431 calculated Em issions Reduction (tpy ) 8,318 calculated Capital Cost 207,465,000 $ calculated Capital Cost ($/kW ) 296 $ calculated O&M Cost 5,108,831 $ calculated Annualized Cost 24,429,094 $ calculated Cost-Effectiveness ($/ton) 2,937 $ calculated

**Visibility analyses** Visibility Impact before BART (dv at Max Class I) 2.931 calculated from NDEQ report for both units Visibility Impact after BART (dv at Max Class I) 1.780 calculated from NDEQ report for both units Visibility Improvement (dv at Max Class I) 1.152 calculated from NDEQ report for both units Cost-Effectiveness ($/98th % dv at Max Class I) 19,926,854 $ calculated

0.00014Visibility 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)**BA RT Guidelines for tangentially-fired boiler > 200 MW firing sub-bituminous coal at facility > 750 MW**  mmB tu/hr from permit application OAQPS Control Cost Manual average for 2006 - 2009 from CAMD

OAQPS Control Cost Manual

OAQPS Control Cost Manual

OAQPS Control Cost Manual OAQPS Control Cost Manual OAQPS Control Cost Manual

calculated from NDEQ report for both units calculated from NDEQ report for both units calculated from NDEQ report for both units