CITY OF PHILADELPHIA

Department of Public Health 

Environmental Protection Division 

Air Management Services 

InterOffice Memo 

To: File 

From: Rahel Gebrekidan 

Date: December 01, 2014 

Subject: 1997 8-Hour RACT Analysis for Temple University-Main Campus

Introduction: 

The Clean Air Act (CAA) requires that moderate (or worse) ozone nonattainment areas implement 

reasonably available control technology (RACT) controls on all major sources of Volatile Organic 

Compounds (VOC) and Nitrogen Oxides (NOx). Philadelphia County is part of the PhiladelphiaWilmington-Atlantic City moderate ozone nonattainment area for the 1997 8-hour ozone National 

Ambient Air Quality Standard (NAAQS). This document presents the findings of a RACT evaluation for 

the 1997 8-hour ozone standard for this facility. 

Company Description: 

Temple University – Main Campus (Temple MC) is a multi-building educational institution in the City of 

Philadelphia. In order to provide needed utilities for maintaining heat, power (both backup and 

supplemental), and providing hot water, Temple MC operates a number of steam boilers, hot water 

boilers, and internal combustion engines to produce electricity. The facility’s air emissions sources 

include 16 Boilers and hot water heaters <20 MMBTU/hr, 5 Boilers >= 20 MMBTU/Hr and <50 

MMBTU/Hr, 3 boilers > 50MMBTU/hr boilers, 10 Standby Electric Generating units each 2250 HP, and 

59 emergency generators and fire pumps. Each standby generator is controlled by two oxidation catalysts 

(20 oxidation catalysts total). The 63.9 MMBTU/hr Central Steam Plant Rental boiler currently listed in 

the Title V operating permit has been deactivated and is being removed from the facility. 

Applicability for NOx and VOC RACT: 

Temple Main is a major source of NOx due to having potential NOx emissions greater than 100 tons per 

year, the major source threshold in Philadelphia County that is applicable to NOx RACT. This facility is 

not a major source of VOC having potential VOC emissions less than 50 tons per year, the major source 

threshold in Philadelphia County that is applicable to VOC RACT for the 1997 8-hour ozone NAAQS. 

RACT Evaluation: 

Case-by-case RACT sources: 

The following sections present detailed evaluation of a Case-by-Case RACT for the applicable sources.

Broad Street Main Campus Expansion Project Boilers (BMCEP The three BMCEP Boilers are each 

Victory Energy Models VS-4-68, with a natural gas heat input rating of 91.3 MMBTU/Hr and a #2 fuel 

oil heat input rating of 86.8 MMBTU/Hr. Each unit is an “O-type” watertube boiler and are currently 

equipped with Low NOx burners (LNB) and flue gas recirculation (FGR). These boilers are primarily 

used for heat during cold months and operate well below their annual capacity. These boilers have the 

following requirements per AMS Pre-Construction Plan Approval No. 07132 dated 11/27/2007;
1. NOx Emissions from each boiler shall not exceed the following: 

a) Nitrogen Oxides (NOx) emissions from the three boilers combined shall not exceed 15.5 tons 

per rolling 12-month period. 

b) Emissions from each boiler shall not exceed the following: 

i) NOx: 0.036 lbs/MMBTU while burning natural gas and 

ii) 0.110 lbs/MMBTU while burning No.2 fuel oil 

2. Each boiler shall be equipped with Low NOx burners (LNB) and flue gas recirculation (FGR). 

To comply with the above emission limits, Temple Main is operating the LNB and FGR on each boiler 

and performed initial stack test to show compliance with the 0.036 lbs/MMBTU and 0.110lbs/MMBTU 

NOx emission limit. 

Control Strategies that were considered for NOx RACT are as follows 

 Selective Catalytic Reduction (SCR) 

 Selective Non-Catalytic Reduction (SNCR) 

 Water/Steam Injection 

Selective Catalytic Reduction 

Selective catalytic reduction (SCR) is a technology whereby an ammonia or ammonia-based fluid 

(reducing agent) is injected into the exhaust air stream upstream of a catalyst. Once the mixture comes in 

contact with the catalyst surface, a reduction reaction occurs, breaking down the NOx (NO or NO2) and 

NH3 into N2 and H2O. Selective catalytic reduction is considered technically feasible. 

Selective Non-Catalytic Reduction 

Selective non-catalytic reduction (SCR) is a technology whereby an ammonia or ammonia based fluid 

(reducing agent) is injected into the exhaust air stream. Once the mixture comes in contact with the 

catalyst surface, a reduction reaction occurs, breaking down the NOx (NO or NO2) and NH3 into N2 and 

H2O. Reductions in NOx flue gas concentrations are estimated to be between 20% and 50% for boilers, 

depending on the reducing chemical used and effective control of optimal operating conditions (exhaust 

gas temperature). SNCR systems require relatively high gas operating temperatures. Steady temperatures 

in the range of 1,600 to 2,000°F are required to operate an SNCR system effectively. Selective non 

catalytic reduction is considered technically feasible.

Water/Steam Injection 

The boiler fire box size does not provide sufficient minimum residence time for water injection at the 

combustion temperature for acceptable steam generation. Additionally, the majority of NOx emissions 

from residual oil-fired boilers results from fuel NOx, not thermal NOx, and water/steam injection 

systems are not effective in reducing fuel NOx. Literature also indicates that the use of water/steam 

injection for NOx emissions reduction has a considerable drawback. Fuel and thermal efficiency is 

typically reduced by 10% for boilers (i.e., energy penalty). Water/steam injection has been primarily 

applied to gas-fired turbines. Due to the reasons listed, water/steam injection is not considered 

technically feasible for the boiler. 

The following NOx controls were determined technologically feasible for each boiler: SCR and SNCR. 

A summary of the cost-effectiveness of these controls is provided below. 
For purposes of cost calculations in this evaluation the allowable maximum emission limits of 15.5 tons per rolling 

twelve month period per boiler has been used. This limit is more stringent than the allowable 0.110 lb/MMBTU and 

reflects the maximum enforceable emission limits currently applicable for these boilers. 

Source Control 

Technology 

NOx 

Baseline 

Emissions 

(tpy) 

NOx 

Reduction 

(%) 

NOx 

Reduction 

(tpy) 

Total 

Annualized 

Cost 

($/year) 

Cost 

Effectiveness 

($/Ton) 

Each 

BMCEP

SCR 15.5 85 13.2 210,481 15,976 

SNCR 15.5 20 3.1 59,518 19,199 

The SCR and SNCR are determined economically unreasonable. For more detailed calculations, 

please see the Appendix. 

Conclusion; 

AMS has determined that the following existing emission limits, control technology, and monitoring and 

recordkeeping shall be considered NOx RACT for each boiler as approved on AMS Pre-Construction 

Plan Approval No. 07132 dated 11/27/2007. 

a) Nitrogen Oxides (NOx) emissions from the three boilers combined shall not exceed 15.5 tons per 

rolling 12-month period. 

b) Each boiler shall be installed with low NOx burners and flue gas recirculation. 

c) Emissions from each boiler shall not exceed the following: 

i) NOx: 0.036 lbs/MMBTU while burning natural gas and 

ii) 0.110 lbs/MMBTU while burning No.2 fuel oil 

d) Temple Main shall perform stack test on each boilers every five year.

e) Temple Main shall monitor and record the monthly fuel usage for each boiler, the 

combined NOx emissions for the boilers per rolling 12-month period calculated 

monthly, the combined gas and the combined oil usage for the boilers in MMBTU for a 

rolling 12-month period calculated monthly

Standby Electric Generating Facility (SEGF)

The Standby Electric Generating Facility (SEGF) is a collection of 10 Caterpillar 3516 engines. Each 

engine pair is rated at 2,250 brake-horsepower (bhp) and burns natural gas. Each engine pair is attached to 

a generator that can provide up to 1,600 kilowatts. These units were installed in October 1992. Two 

oxidation catalysts were installed on each standby generator in 2013 in order to comply with 40 CFR 63 

Subpart ZZZZ generator has two oxidation catalysts installed These engines have the following 

requirements per AMS installation permit number 92087, dated October 2, 1992; [25 Pa Code §127.1] 

NOx emissions from the standby electric generator are limited to the following 

a) NOx emission from each standby electric generator shall be less than or equal to 2.00 g/bhp-hr; 

b) Each Standby Electric Generator shall operate at a maximum of 500 hours per rolling 12-

month period 

c) The Combined NOx hourly emission rate of less than or equal to 99 lb/hr 

To show compliance with the 2.00g/bhp-hr emission limits, Temple Main performed initial stack 

test on the engines. 

Control Strategies that were considered for the NOx RACT for each generator are as follows 

- Installation of selective catalytic reduction (SCR) – 80% NOx control 

- Installation of non-selective catalytic reduction (SNCR) – 20% NOx control

Selective Catalytic Reduction 
Selective catalytic reduction is a technology whereby an ammonia or ammonia-based fluid (reducing 

agent) is injected into the exhaust air stream upstream of a catalyst. Once the mixture comes in contact 

with the catalyst surface, a reduction reaction occurs, breaking down the NOx (NO or NO2) and NH3 into 

N2 and H2O. Any ammonia slip is reduced by utilizing an Oxidation Catalyst, which produce NO. 

The estimated overall NOx control efficiency of an SCR system is typically 80% or better. 

In order to comply with the current 40 CFR Part 63, Subpart ZZZZ (RICE MACT) standard, each engine 

(20) is equipped with a Johnson-Matthey Modulex B catalyst designed specifically for CO emission 

reduction. The system can additionally be equipped with additional injection system and SCR catalyst 

downstream of the existing CO catalyst in order to implement an SCR system. 

Based on available information, the SCR system is technically feasible. There are several vendors capable 

of providing the catalyst and injection systems; however, based on the existing catalyst system, a 

Johnson-Matthey injection system with a SINOX high temperature catalyst is the unit under 

consideration. For this system, the reducing agent would be urea. 

Selective Non-Catalytic Reduction 

Selective Non-Catalytic Reduction technology for NOx control on 4-stroke lean burn natural gas fired 

engines has not been installed as a retrofit in many sources; and this technology is not widely available. 

This is likely due to insufficient exhaust temperature to initiate the reduction reaction without the 

assistance of a catalyst. Without the catalyst, this emission control technology would require additional 

heat, resulting in higher operating costs, and potentially more air emissions. As a result, this option is 

technically infeasible.

* The baseline emissions are based on the maximum allowable emission limits of 2.00g/bhp-hr, and 2.47 

tons per rolling twelve month period per engine. 

The cost-effectiveness of the SCR was evaluated. 

Source Control 

Technology 

NOx 

Baseline 

Emissions 

(per rolling 

twelve 

month 

period) 

NOx 

Reduction 

(%) 

NOx 

Reduction 

(tpy) 

Total 

Annualized 

Cost 

($/year) 

Cost 

Effectiveness 

($/Ton) 

Each 

Standby 

Electric 

Generator 

SCR 2.47 80 1.97 80,880 40,931 

The SCR is determined economically unreasonable. For more detailed calculations, please see 

the Appendix. 

Conclusion; 

AMS has determined that the following existing emission rates and monitoring and recordkeeping shall 

be considered RACT for these sources as approved by AMS installation permit 92087 dated 10/02/1992. 

NOx emissions from the standby electric generators are limited to the following: 

a) NOx emission from each standby electric generator shall be less than or equal to 2.00 g/bhp-hr; 

b) Each Standby Electric Generator shall operate at a maximum of 500 hours per rolling 12-

month period 

c) The Combined NOx hourly emission rate shall be less than or equal to 99 lb/hr 

Work practice standard 

a) Each Standby Electric Generating Facility shall operate at a maximum of 500 hours per 

rolling 12-month period 
b) Each standby electric generator shall only burn natural gas 

Testing requirement 

a) Temple Main shall conduct quarterly NOx portable analyzer test on each engine using 

AMS-approved procedure. 

Monitoring and record keeping requirement 

a) The combined NOx emission per rolling 12-month period calculated monthly to demonstrate 

compliance with the above NOx emission limits 

b) Stack test results for each boilers 

c) Operating hours for each Standby Electric Generator per rolling twelve month period 

calculated monthly

d) Combined amount of fuel used for the Standby Electric Generator per month and

e) Portable analyzer test results for each engine

Presumptive RACT Sources 

The following sources meet the various presumptive RACT emission limitations and criteria specified in 

25 Pa. Code 129.93. 

Table 1-1 lists sources that meet the presumptive RACT requirements specified in 25 Pa Code 

129.93(c)(5) [operation and maintenance of engines per manufacturer specifications and use limited to 

500 hours per year or less; 

Table 1-1

Source Description Capacity Fuel/Material Construction 

Date 

Alter Hall 

Emergency Generator 

#1 

350 kW No. 2 Oil 2008 

Anderson Hall 

Emergency Generator 

#1 

125 kW Natural Gas 1974 

Anderson Hall 

Emergency Generator 

#2 

175 kW No. 2 Oil 1998 

Annenberg (Tele) 

Emergency Generator 

100 kW No. 2 Oil 1985 

Barrack Building 

Emergency Generator 

100 kW Natural Gas 2002 

Bell Building 

Emergency Generator 

#1 

1040 kW No. 2 Oil 1986 

Bell Building 

Emergency Generator 

#2 

125 kW No. 2 Oil 1986 

Bio Life 

Emergency Generator 

1,100 kW No. 2 Oil 1985 

CEA Building 

Emergency Generator 

#1 

170 kW Natural Gas 1976 

CEA Building 

Emergency Generator 

#2 

125 kW No. 2 Oil 1998 

Central Heat Plant <50 kW Natural Gas 
Emergency Generator 

Wachman Hall 

Emergency Generator 

140 kW Natural Gas 1977 

Conwell (Bldg) 

Emergency Generator 

150 kW No. 2 Oil 

Conwell(Tele) 

Emergency Generator 

250 kW No. 2 Oil 1985 

Conwell/Carnell Hall 

Emergency Generator 

130 kW No. 2 Oil 1998 

ECEC Building 

Emergency Generator 

125 kW No. 2 Oil 2004 

Gladfelter (Tele) 

Emergency Generator 

100 kW No. 2 Oil 1985 

Gladfelter (Bldg) 

Emergency Generator 

150 kW Natural Gas 1973 

Gladfelter Hall 

Emergency Generator 

175 kW No. 2 Oil 

Johnson/Hardwick Hall 

Emergency Generator 

#2 

100kW 2 oil 2005 

Klein Hall 

Emergency Generator 

#1 

100 kW Natural Gas 1973 

Klein Hall 

Emergency Generator 

#2 

103 kW No. 2 Oil 1998 

Liacouras Center 

Emergency Generator 

1000 kW No. 2 Oil 1997 

Liacouras Garage 

Emergency Generator 

125 kW No. 2 Oil 1997 

Paley 

Emergency Generator 

#2 

100 kW No. 2 Oil 1998 

Peabody 

Emergency Generator 

125 kW No. 2 Oil 1998 

Pearson (Bldg) 

Emergency Generator 

100 kW Natural Gas 

Ritter Annex (Bldg) 

Emergency Generator 

100 kW Natural Gas 1973 

Ritter Annex (Tele) 

Emergency Generator 

100 kW No. 2 Oil 1985 

SAC 

Emergency Generator 

150 kW Natural Gas 2002 

Student Pavillion Center 

Emergency Generator 

30 kW natural gas 1999 

Temple Towers Fire 

Pump 

110 HP Diesel 2009 

1300 C.B. Moore 

Generator 

150 KW No. 2 Oil 2001 

1800 Liacouras Walk 

Emergency Generator 

80 kW No. 2 Oil 2005 

1940 Liacouras Walk 

Emergency Generator 

80 kW No. 2 Oil 1999 
Table 1-2 lists sources that meet the presumptive RACT requirements specified in 25 Pa Code 

129.93(c), operation and maintenance of boilers per manufacturer specifications and maximum heat input 

ratings <20 MMBTU/Hr; and annual combustion adjustment for maximum heat input ratings >=20 

MMBTU/Hr but less than 50 MMBTU/Hr. 

Table 1-2

Source Description Capacity Fuel/Material Construction 

Date

Central Steam Plant 

Boiler #1 

41.24 

MMBtu/hr 

No. 6 oil 

Natural gas 

1962 

Central Steam Plant 

Boiler #2 

41.24 

MMBtu/hr 

No. 6 oil 

Natural gas 

1962 

Central Steam Plant 

Boiler #3 

41.24 

MMBtu/hr 

No. 6 oil 

Natural gas 

1962 

Central Steam Plant 

Boiler #4 

43.84 

MMBtu/hr 

No. 6 oil 

Natural gas 

1969 

Liacouras Center 

Boiler #4 

20.92 

MMBtu/hr 

Natural Gas October 1999 

White Hall Residence 

Boiler #1 

1.9 

MMBTU/hr 

Natural gas After 1970 

White Hall Residence 

Boiler #2 

1.9 

MMBTU/hr 

Natural gas After 1970 

White Hall Residence 

Boiler #3 

1.9 

MMBTU/hr 

Natural gas After 1970 

Liacouras Center 

 Boiler #1 

9.996 

MMBTU/hr 

No. 2 Oil 

Natural gas 

1996 

Liacouras Center 

 Boiler #2 

9.996 

MMBTU/hr 

No. 2 Oil 

Natural gas 

1996 

Liacouras Center 

 Boiler #3 

9.996 

MMBTU/hr 

No. 2 Oil 

Natural gas 

1996 

Edberg-Olsen 

 Boiler 

2.396 

MMBtu/hr 

No. 2 Oil 

Natural Gas 

September 

2000 

Edberg-Olsen 

 Water Heater #1 

0.60 

MMBtu/hr 

Natural Gas September 

2000 

Edberg-Olsen 

 Water Heater #2 

0.60 

MMBtu/hr 

Natural Gas September 

2000 

Edberg-Olsen 

 Water Heater #3 

0.60 

MMBtu/hr 

Natural Gas September 

2000 

Student Pavillion 

Boiler 

2.887 

MMBtu/hr 

No. 2 Oil 

Natural Gas 

September 

2002 

Temple Towers 

Pool Heater 

0.85 

MMBtu/hr 

Natural Gas 

1/9/15

Edward Wiener, Chief of Source Registration Date 
Appendix

Detailed Calculations Summary

The following costs are calculated in order to evaluate the cost effectiveness of each emission 

control technology: 

‐ Total Capital Investment (TCI) 

‐ NOx Emission Reduction (tons/yr) 

‐ Cost Effectiveness ($/ton) 

‐ Capital Recovery = Convert from P (present) to A(Annual amount), A=P(A/P,i%,n), 

(1 ) 1

(1 )

 

  n

n

i

i i CR 15% interest and 20 yrs = A/P=0.1598; Annual Cost = TCI x CRF 

For the Catalyst, The catalyst life is 5 years. The annual cost is given by the sinking fund factor, 

the amount of money the facility will need to set aside each year to be able to replace the catalyst 

at the end of its life, based on the lifespan of the catalyst and the interest rate. 

Sinking Fund Factor (SFF) = Convert from F (Future) to A(Annual amount), A=F(A/F,i%,n), 

(1 ) 1  n i

i SFF 10% interest and 5 yrs = A/F=0.1638 

Where i= Annual interest Rate (10%); n= catalyst system life (5 years); 

Catalyst Annual Cost = SFF x Catalyst Cost 

Cost of the Ammonia in SCR and SNCR (Based on EPA cost manual)

2NH3 + 2NO + 1⁄2 O2 2N2 + 3H2O 

Ammonia Cost = (17/30 * 2moles of NH3/2 moles of NO *1.05 * NOx emission (tpy) 

*$410/ton) 

NH3 = Ammonia, NO = Nitric Oxide; O2 = Oxygen; H2O = Water; 1.05= Ammonia slip and 

excess ammonia 
Appendix

Costs are provided in 2014 US $. SCR 

BMCEP Boiler 91.3 MMBTU/hr 

each 

 

 

Total Capital Investment Cost (TCI)1 $812,363 Based on EPA Cost Control 

Manual of $6000/MMBTU/Hr. 

(section 4, Chapter 2 page 149) 

Escalate 1997 $ using the Marshall 

and swift Index 

Capital Recovery1 $76,687 0.1993 

(A/P) 

CRF*TCI; n=10yrs 

i=15% CFR=0.1993

Electricity Cost1 $45,552 65kw @ $0.08/kwh, 

8760 hrs/yr 

Maintenance1 $12,185.44 1.5%*TCI 

Total catalyst Replacement Cost1 $28,283 0.1638 

(A/F) 

 SFF x Catalyst 

Catalyst Cost= 

$172,667; Cost; 

SFF=0.1638 

Ammonia Cost1 $3,781 NOx 

emission 

15.5 tpy 

= (17/30 * 2moles of 

NH3/2 moles of NO 

*1.05 * NOx emission 

15.5 (tpy) *$410/ton 

Total Direct Annual Cost $89,802 

Indirect Annual Cost 

Overhead1 $11,498 60% of maintenanceOAQPS1

Administrative Charge1 $16,247 2% of TCI1

Property Taxes1 $8,124 1% of TCI-1

Insurance1 $8,124 1% of TCI 

Capital Recovery1 $76,687 0.0966 20 yrs @7% 1 A/p=0.0944

Total Indirect Annual Cost $120,680 

Total Annual Operating Costs $210,481 

NOx Emission Reduction (TPY) 13.2 85 % 

reduction. 

 Based on allowable 

15.5 tons per rolling 12 

month period 

Cost Effectiveness ($/ton NOx 

removed) 

 $15,976 
Costs are provided in 2014 US $.

 BMCEP Boiler 91.3 MMBTU/hr Total 

SNCR 

Total Capital Direct Cost (DCI)1 

(SNCR system equipment, 

instrumentation, sales tax and freight. It 

also includes direct installation costs such 

as auxiliary equipment (e.g., ductwork, 

compressor), foundations and supports, 

handling and erection, electrical, piping, 

insulation and painting)

$369,188 Based on EPA Cost Control Manual Section 

4.2 . Escalate 1998 $ using the Marshall and 

Swift Index 

Total Capital Indirect Cost (CIC) 

(includes costs such as; construction and 

contractor fees, startup and testing, 

inventory capital, and any process and 

project)

$73,838 EPA Cost Manual 

Contingency $66,454 EPA Cost Manual 1.5*TCI 

Total Capital Investment Cost $509,480 DCI+CCI 

1

Electricity Cost $2,102.4 3kw @ $0.08/kwh, 

8760 hrs/yr 

1

Maintenance $7,642 1.5% of TCI 

1

Ammonia Cost $2,139 Based on annual 

NOx emission of 

15.5 tpy 

Ammonia cost =(17/30 

* 1.05 *2 mole of 

Ammonia/2 mole of 

NO *NOx emission 

(tpy)(15.5 tons) 

*$410/ton 

Total Direct Annual Cost 

$11,423 

 

 

Indirect Annual Cost 

Overhead $0 0% of maintenanceOAQPS1

Administrative Charge $0 0 %f TCI-1

Property Taxes $0 0 %f TCI-1

Insurance $0 0 %f TCI-1

1

Capital Recovery $48,095 0.0944 CRF * TCI; 

n=20 yrs 

i=7%A/p=0.0944

Total Indirect Annual Cost $48,095 

 

Total Annual Operating Costs $59,518 

 
 NOx Baseline Emissions (TPY) 15.5 Based on 

maximum 

allowable NOx 

emissions 

 

NOx Emission Reduction (TPY) 3.1 Based on 20 % 

reduction. 

 

Cost Effectiveness ($/ton NOx removed) $19,199/ton 

Costs are provided in 2014 US $.

SCR 

Standby-Engine Generators 2250 HP 

 

 

Total Capital Investment 

Cost (TCI) 

$417,081 Based EPA Cost Control Manual of $125/hp-Hr. 

 Escalate 1997 $ using the Marshall and swift Index 

Annual Operating Costs 

Direct Annual Cost 

Electricity Cost $400 10kw @ $0.08/kwh, 500 hrs/yr 

1

Maintenance $6,256.21 1.5%*TCI 

Total catalyst Replacement 

Cost 

$14,021 0.1638 (A/F) SFF x Catalyst 

Catalyst Cost= $85,000; Cost; 

SFF=0.1638, n=5 i=10% ,

Ammonia Cost $393 NOx emission 

2.47 tpy 

Ammonia cost =(17/30 * 1.05 *2 mole of 

Ammonia/2 mole of NO *NOx emission 

(tpy)(2.47 tons) *$410/ton 

Total Direct Annual Cost $21,070 

 

Indirect Annual Cost 

Overhead3 $656 60% of maintenance-OAQPS1

Administrative Charge $8,342 2% of TCI-1

Property Taxes $4,171 1% of TCI-1

Insurance $4,171 1% of TCI-1

Capital Recovery $39,372 0.0944 CRF * TCI; 

n=20 yrs i=7% 

Total Indirect Annual 

Cost 

$59,809 

 

Total Annual Operating 

Costs 

$80,880 

 

NOx Emission Reduction 

(TPY) 

1.97 80% reduction Based on Maximum allowable NOx 

emissions of 2.47 tons per rolling twelve 

months 

Cost Effectiveness ($/ton 

NOx removed) 

$40,931 

References: 

1

Office of Air Quality Planning and standards (OAQPS) Environmental Protection Agency (EPA) Air Pollution 

Control Manual, Six Edition, EPA/452/B-02-001, January 2002.