CITY OF PHILADELPHIA

Department of Public Health 

Environmental Protection Division 

Air Management Services 

InterOffice Memo 

To: File 

From: Kassahun Sellassie 

Date: January 9, 2015 

Subject: 1997 8-Hour RACT Analysis for Grays Ferry Cogeneration Partnership 

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 Philadelphia-Wilmington-Atlantic City moderate ozone 

nonattainment area for the 1997 8-hour ozone NAAQS. This document presents the findings of a RACT evaluation 

for the 1997 8-hour ozone standard for this facility. 

Company Description: 

Grays Ferry Cogeneration Partnership owns and operates an electric generating unit facility at 2600 Christian Street, 

Philadelphia, PA 19146. Equipment used at the facility includes one (1) front wall fired boiler, and one (1) 

combined cycle combustion turbine (CT). 

Applicability for NOx and VOC RACT: 

Grays Ferry Cogeneration Partnership has been determined a single source with Veolia Schuylkill and Veolia 

Energy efficiency. Veolia – Schuylkill Station, GFCP, and Veolia Energy Efficiency are 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 for the 1997 8-hour ozone NAAQS. They are not a major source of VOC, due to 

having potential VOC emissions not greater than 50 tons per year, the major source threshold in Philadelphia 

County that is applicable to NOx RACT for the 1997 8-hour ozone. 

In addition to the above, the station also includes Veolia Schuylkill’s three boilers, Boiler #23, #24, and 26, are 

subject to 1-hour RACT, per the 1-hour RACT determination, issued by AMS as RACT plan approval with PA 

Permit Number 51-04942 on December 1, 1999, and approved into the SIP by EPA on December 15, 2000 (65 FR 

78418). Sources under Veolia Energy Efficiency (PA) LLC that include the two new 297.92 MMBTU/hr boilers. 

The facility is not subject to 1-hour ozone RACT. 

Process Descriptions: 

Grays Ferry Cogeneration Partnership currently has one (1) front wall fired boilers (Boiler # 25) rated 1119 

MMBTU/hr and one (1) combined cycle combustion turbine (CT) rated 1515 MMBTU/hr (135 MW). The CT can 

run with a Heat Recovery Steam Generator (HRSG) The boiler and the CT both burn Natural Gas (NG) and/or #2 

oil. 

Boiler #25 is equipped with low NOx burner and flue gas recirculation (LNB + FGR). Per Plan Approval 97019, 

Boiler #25 has NOx emission limits of 0.10 pounds per MMBTU when firing gas and 0.15 pounds per MMBTU 

when firing oil. The potential to emit (PTE) for boiler #25 based on capacity and lbs/MMBTU NOx emission limits 

is 490 tons per year when burning gas (1119 MMBTU/hr * 0.1 lb/MMBTU *8760 hr/yr * 1 ton/2000 lb= 490 tpy) 

and 735 tons per year when burning #2 oil (1119 MMBTU/hr * 0.15 lb/MMBTU *8760 hr/yr * 1 ton/2000 lb= 735 

tpy). Boiler #25 and the CT, with and without HRSG, have a combined NOx limit of 540 tons per year in Plan 

Approval # 97019, dated on 3/8/2001, making the actual PTE for Boiler #25 540 tons per year. 
The CT is equipped with Selective Catalytic Reduction (SCR) and Dry Low NOx (DLN) when firing gas; SCR and 

water injection (WI) when firing oil. Per Plan Approval # 97019, dated on 3/8/2001, the CT has NOx emission 

limits of 0.0344 pounds per MMBTU (9 ppm) when firing gas and 0.1683 pounds per MMBTU (42 ppm) when 

firing #2 oil; the CT with HRSG has emission limit of 0.09 pounds per MMBTU when firing gas and 0.1683 pounds 

per MMBTU when firing oil; these limits don’t apply during startup and shutdown. These limits were determined to 

be Best Available Technology (BAT) for the plan approval, but could not be guaranteed during startup and 

shutdown, and therefore alternative limits were determined during these periods of time. The CT alone (without 

HRSG) has a NOx limit of 255 pounds per hour at all times, including startup and shutdown. The CT with HRSG 

has a NOx limit of 298.8 pounds per hour at all times, including startup and shutdown. The pounds per hour limit is 

based on the rated capacity and the pounds per MMBTU limit for #2 oil for the CT, and is slightly lower than this 

calculation for the CT/HRSG. The theoretical PTE based on the pounds per hour NOx limits is 1,116.9 tons per 

year for the CT and 1,309.2 tons per year for the CT with HRSG. As mention above, Boiler #25 and the CT, with 

and without HRSG, have a combined NOx limit of 540 tons per year in Plan Approval # 97019, dated on 3/8/2001, 

making the actual PTE of the CT, with and without HRSG, 540 tons per year. 

NOx RACT Evaluation:

Boiler #25: 

The following were considered possible additional NOx controls as RACT for Boiler #25: (1) Selective Catalytic 

Reduction (SCR), (2) Ultra Low-NOx Burners (ULNB) and Overfire Air (ULNB with OFA), (3) Selective NonCatalytic Reduction (SNCR), and (4) Ultra Low NOx Burners (ULNB), 

ULNB are burners designed to create a larger, lower temperature flame. They would reduce NOx emissions by 

around 25% for Boiler #25 

ULNB with OFA reduce NOx emissions by around 35% for Boiler #25 

SCR injects ammonia upstream of a catalyst. NOx, ammonia (NH3), and oxygen (O2) react on the surface of the 

catalyst to form nitrogen (N2) and water (H2O). NOx emissions are reduced by around 80%. 

SNCR reduce NOx emissions by around 25% for Boiler #25 

The NOx emissions for Boiler No. 25 were determined based on the combined limit of 540 tons per year for Boiler 

No. 25 and the CT/HRSG. This is lower than the PTE based on capacity and lbs/MMBTU NOx emission limits, as 

detailed above. 

The following NOx controls were determined technologically feasible for Boiler No.25. 

Source Control Technology Baseline NOx 

Emissions 

(tpy) 

NOx 

Reduction 

(%) 

NOx 

Reduction 

(tpy) 

Total 

Annualized 

Cost ($/year) 

Cost 

Effectiveness 

($/Ton) 

Schuylkill 

Boiler #25 

SCR 540 80 432 3,125,445 7,235 

ULNB + OFA 540 35 189 788,409 4,171 

SNCR 540 25 135 1,195,847 8,858 

ULNB 540 25 135 498,135 3,690 

All of these control options have been determined economically unreasonable. Thus, the existing control for Boiler 

#25 (LNB + FGR) represents NOx RACT for the 1997 8-hour ozone standard 

Combustion Turbine: 

The Combustion Turbine (CT) with and without the HRSG already have the most stringent NOx control option for 

this unit, SCR + WI, which AMS has determined to be RACT. SCR + WI have an efficiency of 90-98% emission 

reduction. AMS has determined only the lbs/hr emission limits to be RACT for the CT, as these are the lowest 

achievable emissions rates resulting from existing technologies, and are applicable at all times. 

Conclusions and Recommendations: 

AMS has determined that the existing control for CT (SCR + WI) and the existing control for Boiler #25 (LNB + 

FGR) represent NOx RACT for the 1997 8-hour ozone standard for Grays Ferry Cogeneration, LLC. 
AMS requests these requirements to be approved as RACT in the SIP. 

Thus, AMS determines the following as RACT: 

- Boiler #25- NOx emissions shall not exceed 0.10 pounds per MMBTU when firing gas and 0.15 pounds per 

MMBTU when firing oil. The emission for boiler #25 is 490 tons per year when burning gas and 735 tons 

per year when burning #2 oil. 

- The Combustion Turbine NOx emissions shall not 255 pounds per hour. 

- The Combustion Turbine with HRSG NOx emissions shall not exceed 298.9 pounds per hour. 

- The facility shall monitor and record compliance based on NOX CEMs for Boiler #25 and CT. 

1/9/15

Edward Wiener, Chief of Source Registration Date 

References: 

1

Manufacturers of Emission Controls Association (MECA) states SCR Control 90% NOX and the most 

effective emission control www.meca.org 2

Minnesota Power vendor and EPA’s Clean Air Markets (CAM) data: SCR is expected to achieve a 

NOX emission rate of 0.05 lb/mmBtu guarantees offered by SCR system suppliers 3

Northeast States for Coordinated Air Use Management (NESCAUM). Status Report 

on NOx Control Technologies and Cost Effectiveness for Utility Boilers. June 1998 and 2008 4

EPA Air Pollution Control Cost Manual (EPA 452/B-02-001) 

http://epa.gov/ttn/catc/products.html#cccinfo 5

http://www.4cleanair.org/Documents/ATTACHMENTNOXFINALASFILED.pdf 6

 EPA Air Pollution Control Technology Fact Sheet, SCR Achievable emission limits 

7

ACT document, NOx Emission from ICI Boilers, March 1994, USEP 
 

GRAYS FERRY COGENERATION PARTNERSHIP BOILER #25 

Table 1 Detail Calculations for BOILER # 25- SCR

 Total capital Cost

Total Capital 

Investment Cost 

(TCI) 

$9,956,557 Based EPA Cost Control Manual of $6000/MMBTU/Hr. Escalate 

1997 $ using the Marshall and swift Index1

Capital 

Recovery 

$1,082,033 0.1598 20 yrs @15% -OAQPS1 A/p=0.1598

 

Annual 

Operating 

Costs 

 

Direct Annual 

Cost 

 

Electricity 

Cost2 

$70,080 100kw @ $0.08/kwh, 8760 hrs/yr 

Maintenance3 $101,567.56 1.5% * TCI 

Ammonia3 $277,920 17/30 * 2moles of NH3/2 moles of NO *1.05 * NOx emission (tpy) 

*$410/ton*1.55 

Catalyst Cost3 190,000 0.1638 Sinking Fund Factor n=5 years, i=10% 

Annual Catalyst 

Replacement 

Cost 

 

31,122 

Total Direct 

Annual Cost 

$480,690 

 

Indirect 

Annual Cost 

$1,082,033 Capital Recovery 

 

Total Annual 

Cost 

$1,562,723 

 

Total Annual 

Operating 

Costs 

$3,125,445 

 

NOx Emission 

Reduction 

(TPY) 

432 Based on the combined limit with the CT/HRSG of 540 tons/yr 

NOx, which is lower than the PTE based on rated capacity and 

lbs/MMBTU NOx emission limits. 

Cost 

Effectiveness 

($/ton NOx 

removed) 

$7,235 
Table 2 Detail Calculations for Boiler # 25- ULNB + OFA 

Total capital Cost

 

Total Capital Investment 

Cost (TCI) 

$3,251,339 TCI includes equipment cost estimates from 

NESCAUM 2002 Status Report on NOx 

Control for Boilers3

Capital Recovery $519,564 0.1598 20 yrs @15% -OAQPS1 A/p=0.1598

Annual Operating Costs

Direct Annual Cost 

Electricity Cost $70,080 100kw @ $0.08/kwh, 8760 hrs/yr 

Operator $16,425 0.5hr/shift, 3 shift/day, $30/hr 

Supervisor $2,463.75 15% of Operator 

Maintenance $19,162.50 0.5hr/shift, 3 shift/day, $35/hr 

Material $19,162.50 100% of Maintenance 

Total Direct Annual Cost $127,294 

 

Indirect Annual Cost 

Overhead1 $11,498 60% of maintenance 

Administrative Charge1 $65,027 2% of TCI 

Property Taxes1 $32,513 1% of TCI 

Insurance1 $32,513 1% of TCI 

Total Indirect Annual Cost $141,551 

 

Total Annual Operating 

Costs 

$788,409 

 NOx Baseline Emissions 

(TPY) 

540 Based on the combined limit with the 

CT/HRSG of 540 tons/yr NOx, which is 

lower than the PTE based on rated capacity 

and lbs/MMBTU NOx emission limits. 

NOx Emission Reduction 

(TPY) 

135 Based on 35 % of NOx removed. 

Cost Effectiveness ($/ton 

NOx removed) 

$4,171 
Table 3 Detail Calculations for Boiler # 25 ULNB 

Total capital Cost

Total Capital Investment Cost 

(TCI) 

$1,798,514 TCI includes equipment cost estimates from 

NESCAUM 2002 Status Report on NOx 

Control for Boilers3

Capital Recovery $287,403 0.1598 20 yrs @15% -OAQPS1 A/p=0.1598

 

Annual Operating Costs

Direct Annual Cost 

Electricity Cost $70,080 100kw @ $0.08/kwh, 8760 hrs/yr 

Operator $16,425 0.5hr/shift, 3 shift/day, $30/hr 

Supervisor $2,463.75 15% of Operator 

Maintenance $19,162.50 0.5hr/shift, 3 shift/day, $35/hr 

Material $19,162.50 100% of Maintenance 

Total Direct Annual Cost $127,294 

 

Indirect Annual Cost 

Overhead1 $11,498 60% of maintenanceAdministrative Charge1

 $35,970 2% of TCI 

Property Taxes1 $17,985 1% of TCI 

Insurance1 $17,985 1% of TCI 

Total Indirect Annual Cost $83,438 

 

Total Annual Operating 

Costs 

$498,135 

 NOx Baseline Emissions 

(TPY) 

540 Based on the rated capacity of 1119 

MMBTU/hr, 8,760 hours per year, and a 

0.15 lbs/MMBTU NOx emission limit. 

NOx Emission Reduction 

(TPY) 

135 Based on 25% of NOx removed. 

Cost Effectiveness ($/ton 

NOx removed) 

$3,690 
Table 4 Detail Calculations for Boiler # 25 SNCR 

Total Capital Cost

Direct Capital Cost 

 

$2,111,593 Based EPA’s Cost Control Manual of 

(($950/MMBTU)* 

Qb(MMMBTU/hr)(2375 

mmbtu/hr/Qb)*(0.66+0.85 nNOx) 

Qb= boiler size(mmbtu/hr); nnox= nox 

removal efficiency; 1

Indirect Capital Cost $422,319 Based EPA’s Cost Manual 

Total Capital Investment Cost 

(TCI) 

$2,533,912 

Capital Recovery $404,919 0.1598 20 yrs @15% -OAQPS1 A/p=0.1598

 

Annual Operating Costs 

Direct Annual Cost 

Electricity Cost $70,080 100kw @ $0.08/kwh, 8760 hrs/yr 

Maintenance $38,009 1.5% x TCI 

 

Ammonia1 $277,920 17/30 * 2 moles of NH3/2 moles of NO 

*1.05 * NOx emission (tpy) x 735 tpy 

*$410/ton*1.55(cost from 1999 to 2014) 

Total Direct Annual Cost $386,009 

 

Total Indirect Annual Cost $404,919 CFR x TCI 

 

Total Annual Operating 

Costs 

$1,195,847 

 NOx Baseline Emissions 

(TPY) 

 540 Based on the rated capacity of 1119 

MMBTU/hr, 8,760 hours per year, and a 

0.15 lbs/MMBTU NOx emission limit. 

NOx Emission Reduction 

(TPY) 

135 Based on 25 % of NOx removed. 

Cost Effectiveness ($/ton 

NOx removed) 

$8,858 
References

1. Office of Air Quality Planning and standards (OAQPS), Environmental Protection 

Agency (EPA) Air Pollution Control Manual, Sixth Edition, EPA/452/B-02-001, January 

2002. 

2. Electricity cost: EPA cost manual, Appendix A-NOx Control Analysis 

3. North East States for Coordinated Air Use Management (NESCAUM) 2002 Status 

Report on NOx Control for Boilers 

4. 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 CFR 

5. Catalyst Cost of SCR: The catalyst life is 5 years. The annual cost is given by the 

sinking fund factor (SFF). The SFF is 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. 

6. 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 

7. Ammonia Cost: 

2NH3 + 2NO + 1/2O2 2N2 + 3H2O 

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

(tpy) *$410/ton yrs x 1.55 from 1999 to 2014 price) 

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

and excess ammonia