OP_YEAR STATE FACILITY_NAME ORISPL_CODE UNITID OP_STATUS_INFO PRG_CODE_INFO UNIT_TYPE_INFO PRIMARY_FUEL_INFO SECONDARY_FUEL_IN

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 Coal
SO2_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

Other
PART_CONTROL_INFO

Electrostatic Precipitator

Baghouse (Began Apr 10, 2001) Electrostatic Precipitator (Retired Mar 31, 2001)

Baghouse

Baghouse

Baghouse

Baghouse

Baghouse

Baghouse

Baghouse

Baghouse

Baghouse
STATE

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

Averages 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

Averages 8,302
SO2 

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 OAQPS Control Cost Manual Section 4.2, SCR

Given/Assumptions

New or Retrofit? Retrofit

Generation capacity (MW) 700

Override Cost Manual TCC? ($/kW) $ 270

SCR bypass 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 Days 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 Volume 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 Weight (g/mole) 17.03

Reagent Density (lb/ft3 @ 60F) 56.0

Reagent Specific Volume (gal/ft3) 7.481

NOx Molecular Weight (g/mole) 46.01

Number of Days of Storage for Ammonia 14

Pressure Drop for SCR Ductwork H2O") 3

Pressure Drop for each Catalyst Layer (H2O") 1

Temperature at SCR Inlet (degrees F) 825

Equipment Life (years) 20

Annual Interest Rate 7%

Inflation Since 1998 1.34

Catalyst Cost, Initial ($/ft3) $ 142

Catalyst Cost, Replacement ($/ft3) $ 142

Electrical Power Cost ($/kWh) 0.046

29% Ammonia Solution Cost ($/lb) $ 0.06

Operating Life of Catalyst (hours) 24,000

Natural gas unit cost ($/mcf) $ 4.98

Natural gas for reheat (mcf) NA
NDEP report

company report

assumed

company report

from permit application

calculated from 7,538 mmBtu/hr from permit application

calcuated from 57,940,211 mmBtu/yr 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 analyses

calculated from $ 5,000 assumed from other analyses

calculated from $ 46 /kW from company report

calculated from $ 400 assumed from other analyses

company report

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

( 0.34 - 0.23 )/

Boiler Calculations

2.3 QB = HVm-dotfuel

QB = 8,900 Btu/lb * 846,966 lb/hr

QB = 7,538 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 6.51E+09 lb/yr / 8760 hr/yr / 846,966 lb/hr

CFPlant = 88%

2.8 CFSCR = tSCR/365 days

CFSCR = 361 days/ 365 days

CFSCR = 99%

CFTotal = CFPlant x CFSCR

CFTotal = 88% * 99%

CFTotal = 87%

2.12 qfluegas = qfuelQB(460+T)/(460+700o

F)nSCR

qfluegas = 516 ft3/min/(mmBtu/hr)* 7538 mmBtu/hr*( 460 +

qfluegas = 8,617,494 acfm

2.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.23 lb/mmBtu - 0.05 lb/mmBtu)/ 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/mmBtu

0.34 = 85%

681
SCR Reactor Calculations

2.19 Volcatalyst = 2.81 x QB x ηadj x Slipadj x NOxadj x Sadj x Tadj/NSCR

Volcatalyst = 2.81 * 7538 = 21182

2.2 ηadj = 0.2869 + (1.058 x η)

ηadj = 0.2869 +( 1.058 * 0.78 )

ηadj = 1.115

2.22 Slipadj = 1.2835 – (0.0567 x Slip)

Slipadj = 1.2835 - ( 0.057 * 2 )

Slipadj = 1.170

2.21 NOxadj = 0.8524 + (0.3208 x NOxin)

NOxadj = 0.8524 + ( 0.321 * 0.23 )

NOxadj = 0.926

2.23 Sadj = 0.9636 + (0.0455 x S)

Sadj = 0.9636 + ( 0.046 * 0.3 )

Sadj = 0.977

2.24 Tadj = 15.16 – (0.03937 x T) + (2.74 x 10-5 x T2

)

Tadj = 15.16 - ( 0.039 * 825 ) + 2.74E-05 *

Tadj = 1.329

Volcatalyst = 16,618 ft3 each = 470.9 m3 each

2.25 Acatalyst = qfluegas/(16 ft/sec x 60 sec/min)

Acatalyst = 4,308,747 /( 16 * 60 )

Acatalyst = 4488 ft2 7,280

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 4488

ASCR = 5162 ft2

2.27 l = w = ASCR

1/2

l = w = 71.8 ft

2.28 nlayer = Volcatalyst/(h’layer x Acatalyst)

nlayer = 16618 /( 3.1 * 4488 )

nlayer (calc) = 1.0

nlayer = 2.0

2.29 hlayer = [Volcatalyst/(nlayer x Acatalyst)] + 1

hlayer = 16618 /( 2.0 * 4488 ) + 1

hlayer = 2.9

2.3 ntotal = nlayer + nempty

ntotal = 1 + 1

ntotal = 2
2.31

hSCR = ntotal(c

1

 + hlayer) + c

2

hSCR =2 * (7+ 2.9 ) +9

hSCR = 29 ft
680625
Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.23 * 7538 * 1.05 * 78% * 17.03

m-dotreagent = 527 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 527 / 0.29

m-dotsol = 1818 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 1818 * 7.481 / 56

qsol = 243 gph

2.35 Tank Volume = qsolt

Tank Volume = 243 * 14 * 24

Tank Volume = 81,619 gal
/ 46.01
Direct Capital Cost

2.36 DC = QB[($3380/MMBtu/hr) + f(hSCR) +f(NH3

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

DC = 3769 (( $ 3,380 +

2.37 f(hSCR) = {[$612/(ft-mmBtu/hr)]hSCR} - $187.9/(mmBtu/hr)

f(hSCR) = 6.12 * 29 - 187.9

f(hSCR) = $ (12) /mmBtu/hr

2.38 f(NH3

rate) = [($411/lb/hr)(m-dotreagent/QB)] - $47.3/(mmBtu/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(Volcatalyst) = VolcatalystCCinitial

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
ypass)](3500/QB)

0.35 + f(Volcatalyst)

7.3/(mmBtu/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 Home 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

Royalty Allowance, F = 0

Preproduction Cost, G = 0.02 (D+E)

Inventory Capital, H =

Initial Catalyst 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%

days = $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 + Ann

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 = qreagentCostreagenttop

2.47a top = CFtotal8760hr/yr

top = 87% * 8760

top = 7592

Annual Reagent Cost = 1818 * 7592 * 0.058

Annual Reagent Cost = $ 800,657

2.49 Annual Electricity Cost = Power (Costelect)top

2.48 Power = 0.105QB[NOxinηNOx + 0.5(ΔPduct + ntotalΔPcatalyst

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)FW

2.5 Catalyst Replacement Cost = nSCRVolcatalystCCreplace/Rlayer

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 = hcatalyst/hyear

Y = 24000 /( 87% * 8760

Y = 3.16

FWF = 0.07 *( 1 /( 1

FWF = 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 = NOxinηNOxQBtop

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
al 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

yst 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

ndirect 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

m NPPD report

m NPPD report
Operating company Nebraska Public Power District 

Facility Gerald Gentleman Station 

State NE

Contact

Proposed Controls rejected SCR

Unit 2

Boiler Type wall-fired

Fuel PRB sub-bituminous

Rating (MW Gross) each 700 company report

Presumptive BART limit (lb/mmBtu) 0.23 BART Guidelines for tangentially-

Rating (mmBtu/hr) 7,538 mmBtu/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 Analysis

Control Efficiency 32% calculated

Controlled emissions (lb/mmBtu) 0.230 presumptive BART

Controlled Emissions (tpy) 6,581 calculated

Emissions 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 Analysis

Control Efficiency 78% OAQPS Control Cost Manual

Controlled emissions (lb/mmBtu) 0.05 NPS assumption

Controlled Emissions (tpy) 1,431 calculated

Emissions 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 Analysis

Control Efficiency 85% calculated

Controlled emissions (lb/mmBtu) 0.05 calculated

Controlled Emissions (tpy) 1,431 calculated

Emissions 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 bot

Visibility Impact after BART (dv at Max Class I) 1.780 calculated from NDEQ report for bot

Visibility Improvement (dv at Max Class I) 1.152 calculated from NDEQ report for bot

Cost-Effectiveness ($/98th % dv at Max Class I) $ 19,926,854 calculated

 0.00014
Visibility 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)
delines for tangentially-fired boiler > 200 MW firing sub-bituminous coal at facility > 750 MW

from permit application

ontrol Cost Manual

r 2006 - 2009 from CAMD

ontrol Cost Manual

ontrol Cost Manual

ontrol Cost Manual

ontrol Cost Manual

ontrol Cost Manual

from NDEQ report for both units

from NDEQ report for both units

from NDEQ report for both units