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MEMORANDUM

TO: Bob Kelly, U.S. Environmental Protection Agency

FROM: Eastern Research Group, Inc.

DATE: March 28, 2012

SUBJECT: BART Control Cost and Emission Reduction Estimates for the Virgin Islands

BACKGROUND

Section 169A of the Clean Air Act requires sources affecting areas designated as Class I areas to reduce 

emissions to eliminate all anthropogenic obscuration of visibility, with the goal of reaching natural 

background levels of visibility by 2064. The Virgin Islands National Park on the island of St. John is a 

designated Class I area. Therefore, a Regional Haze State Implementation Plan (SIP) is being developed 

by EPA to address the need to reduce emissions to provide reasonable progress toward reducing regional 

haze in the Virgin Islands National Park. 

As part of the analysis needed to develop the SIP, the costs of applying Best Available Retrofit 

Technology (BART) to BART-eligible sources have been estimated using information provided by EPA 

and the VIDPNR. This analysis has been conducted to estimate control costs and emissions reduction 

potential for controlling NOx, SO2, and PM. The results of this effort are presented in this memo, 

including the estimated control costs, emissions reductions, and cost effectiveness of each evaluated 

control technology for each pollutant.

This memo is organized as follows:

I. Selected Controls and Control Efficiency Assumptions

II. Emission Reductions

III. Emission Control Costs

A. Filling Data Gaps for Control Cost Inputs

B. Cost Summary

IV. Cost Effectiveness 

V. References

I. SELECTED CONTROLS AND CONTROL EFFICIENCY ASSUMPTIONS

For SO2 and PM control, a duct sorbent injection and fabric filter (DIFF) combination was prescribed. 

Duct sorbent injection is a control technique for SO2 control where a sorbent such as lime is injected into 

the duct upstream from the particulate matter control device. The SO2 is absorbed, neutralized and/or 

oxidized by the alkaline reagent into a sold compound, either calcium or sodium sulfate. The solid is then 

removed from the waste gas stream using the downstream particulate control equipment. DIFF is a semiwet flue gas desulfurization (FGD) process, with additional water added due to quench demand. The

water is used to humidify and cool the gas stream to the desired reaction temperature. In this instance, we 

have assumed a fabric filter is the particulate matter control device that collects the sorbent medium (and 

any particulate formed directly from the combustion process). 
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According to the Clean Air Technology Center (CATC) Flue Gas Desulfurization fact sheet1, dry sorbent 

injection is 50% to 60% efficient for SO2 removal when using calcium-based sorbent. For our emission 

reduction estimates, we have assumed a 55% removal efficiency.

For PM removal, fabric filter efficiencies typically range from 95% to 99.9%, with newer equipment 

ranging from 99% to 99.9%2. We have therefore assumed a 99% PM removal efficiency for installed 

fabric filters.

For NOX control, selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR) were 

considered. In an SNCR system, a nitrogen-based reducing agent, or reagent, such as ammonia or urea, is 

injected into the post-combustion flue gas through nozzles mounted on the wall of the combustion unit. 

In an SCR system, the nitrogen-based reagent is injected downstream of the combustion unit, then the gas

enters a reactor containing a catalyst, through which the hot flue gas and reagent diffuse. In the presence 

of the catalyst, the reagent reacts selectively with NOX. SNCR is used on a wide range of boiler 

configurations; for large gas turbines, however, SCR is most commonly used.

In conjunction with combustion controls, SNCR NOX removal efficiencies range from 65% to 75%.3For 

the purposes of estimating control costs and emission reductions, we have conservatively assumed a 65% 

removal rate in case combustion controls are not in place or are not feasible in some cases.

SCR system removal efficiencies for NOX typically range from 70% to 90%4, so we have assumed an 

efficiency of 80% for our calculations.

II. EMISSION REDUCTIONS 

Table 1 shows the emission reductions resulting from the installation of controls discussed above. 

Baseline emissions are based on potential to emit and design data as provided by EPA Region II. Total 

reduction estimates, based on efficiencies described above, can be summarized as follows:

Installing DIFF on all units would result in approximately 4,600 tons per year of SO2 removal and 780

tons per year of PM removed. 

Installing SNCR on all boilers would result in a NOX reduction of approximately 4,000 tons per year.

Installing SCR on all turbines would result in a NOX reduction of approximately 7,400 tons per year.

III. EMISSION CONTROL COSTS

This section presents the costs that were estimated for DIFF, SNCR, and SCR.

A. Filling Data Gaps for Control Cost Inputs

Costs were calculated using algorithms based on those presented in the OAQPS Control Cost Manual5as 

well as algorithms previously developed for regulatory development. In order to use these algorithms, 

input values for heat input, flow rate, operational hours, and other parameters were required for each unit. 

Unit-specific data were limited, so data gaps were filled based on the assumptions described below. 

Resulting input values are presented in Appendix A.

Stack data including temperature, velocity, and diameter, were provided for all units except for those at 

the WAPA St. Thomas facility. For the WAPA St. Thomas boilers, we assumed the same values as those 

provided for the two boilers at the WAPA St. Croix facility. For the WAPA St. Thomas turbines, we used 

data from Hovensa unit GT1(G-1101E), since these appeared to be similar units.
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Stack velocity, diameter, and temperature were then used to calculate actual flow rate (acfm) where no 

flow rate data were available. 

Average moisture and oxygen values were based on moisture and oxygen values assigned to specific fuel 

categories in the boiler database. 6,7 Data pulled from the boiler database is listed in Appendix B. Fuel 

categories were assigned to the Hovensa and WAPA units based on reported fuel types. Because several 

units reported multiple fuel types, an average of the corresponding moisture and/or oxygen values was 

calculated for each unit.

Average pollutant concentrations at 7% O2 were based on the emissions data and the oxygen value 

determined as discussed above. Average dry flow rates were calculated using the moisture values 

obtained as discussed above.

For the Hovensa units, operational hours were based on data for the same units in the boiler database. For 

the WAPA units, averages from comparable units in the boiler database were used.

 

B. Emission Control Costs

The capital and annual costs for the emission controls were estimated in dollars ($) on a 2008 basis, and

annualized costs assumed an interest rate of 7 percent. Downtime costs for the retrofits were assumed to 

be negligible. Each unit is assumed to have adequate space to install an emission control system. 

Appendix A contains a summary of the parameters used for each unit (e.g., heat input rate, stack gas flow 

rate, incinerator operating hours, and concentrations). 

Capital and annual control costs for each unit are provided in Table 2. Total capital and annual control 

costs for all BART-eligible units are summarized in Table 3. The total capital cost to install DIFF for all 

boilers and turbines is estimated at approximately $750 million, and the total annual cost for DIFF is 

approximately $203 million per year. The cost for applying SNCR at all boilers is estimated at $29.1 

million in capital costs and $3.3 million annually. For SCR, the capital cost to install for all turbines is 

estimated at $83.0 million, and the total annual cost is estimated at $13.0 million per year. Cost details are 

discussed below.

1. Adding duct sorbent injection/fabric filter (DIFF).

Calculations were based on an algorithm consistent with that used for the boiler NESHAP.8

Calculations are presented in Appendix C. DIFF capital costs per unit range from approximately $4.8 

million to $55.4 million, and annual costs range from approximately $1.1 million/yr to $15.3

million/yr.

2. Adding a selective non-catalytic reduction (SNCR) system.

The cost algorithm for installing an SNCR system is presented in Appendix D and is based on 

algorithms in the OAQPS Control Cost Manual.

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 The SNCR capital costs range from approximately 

$2.1 million to $3.0 million, and annual costs range from approximately $234,000/yr to $330,000/yr. 

3. Adding a selective catalytic reduction (SCR) system.

The cost algorithm for installing an SCR system is presented in Appendix E and is based on 

algorithms in the OAQPS Control Cost Manual.

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 The SCR capital costs range from approximately 

$7.0 million to $8.7 million, and annual costs range from approximately $1.1 million/yr to $1.4 

million/yr. 
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IV. COST EFFECTIVENESS

Table 2 summarizes the pollution control cost effectiveness for each unit for each control type (DIFF for 

all units, SNCR for the boilers and SCR for the turbines). Appendix F contains details on how these data 

were derived.

Table 3 summarizes the overall pollution control cost effectiveness. The cost effectiveness for each 

control was calculated based on the total annual control costs for all units for which the control was 

assigned and the estimated annual emission reductions resulting from the application of those controls. 

For NOX control using SNCR for boilers, the overall cost effectiveness was estimated at $834 per ton of 

pollutant removed.

For NOX control using SCR for turbines, the overall cost effectiveness was estimated at $1,734 per ton of 

pollutant removed.

For PM and SO2 control using DIFF for all units, the overall cost effectiveness was estimated at $38,064

per ton of pollutant removed.

The overall cost effectiveness of using these three controls to reduce NOx, PM, and SO2 emissions from 

all units is $13,153 per ton of pollutant removed.

V. REFERENCES

1. “Air Pollution Control Technology Fact Sheet: Flue Gas Desulfurization (FGD) - Wet, Spray Dry, 

and Dry Scrubbers.” http://www.epa.gov/ttn/catc/dir1/ffdg.pdf.

2. “Air Pollution Control Technology Fact Sheet: Fabric Filter” http://www.epa.gov/ttn/catc/dir1/ffshaker.pdf, http://www.epa.gov/ttn/catc/dir1/ff-pulse.pdf, http://www.epa.gov/ttn/catc/dir1/ffrevar.pdf. 

3. “Air Pollution Control Technology Fact Sheet: Selective Non-Catalytic Reduction (SNCR).” 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf.

4. “Air Pollution Control Technology Fact Sheet: Selective Catalytic Reduction (SCR).” 

http://www.epa.gov/ttn/catc/dir1/fscr.pdf.

5. U.S. Environmental Protection Agency. January 2002. OAQPS Control Cost Manual, Sixth Edition. 

Publication Number EPA/452/B-02-001.

6. Survey Database containing Results of the 2008 Questionnaire for Boilers, Process Heaters, & Other 

Combustion Units (ICR No. 2286.01) (Version 3)

7. Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis 

Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (Version 7).

8. 40 CFR 63, subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters.
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Table 1. Emission Reductions for Selected Controls

Facility Location

Unit 

Type Unit No.

Baseline Emissions (TPY) Reductions* (TPY) Resulting Emissions (TPY)

PM10 SO2 NOX PM10 SO2 NOX PM10 SO2 NOX

Hovensa St Croix Boiler 1 (B-1151) 40.6 330.1 450.6 40.2 181.5 292.9 0.41 148.5 157.7

Hovensa St Croix Boiler 3 (B-1153) 40.6 330.1 450.6 40.2 181.5 292.9 0.41 148.5 157.7

Hovensa St Croix Boiler 4 (B-1154) 39.7 322.5 443.5 39.3 177.4 288.3 0.40 145.1 155.2

Hovensa St Croix Boiler 5 (B-1155) 60.7 484.9 676.9 60.1 266.7 440.0 0.61 218.2 236.9

Hovensa St Croix Boiler 6 (B-3301) 40.6 330.8 435.3 40.2 182.0 282.9 0.41 148.9 152.3

Hovensa St Croix Boiler 7 (B-3302) 40.6 330.8 435.3 40.2 182.0 282.9 0.41 148.9 152.3

Hovensa St Croix Boiler 8 (B-3303) 78.6 640.1 559.8 77.8 352.1 363.9 0.79 288.0 195.9

Hovensa St Croix Boiler 9 (B-3304) 78.6 640.1 559.8 77.8 352.1 363.9 0.79 288.0 195.9

Hovensa St Croix Turbine GT1 (G-1101E) 12.2 135.5 805.7 12.0 74.5 644.6 0.12 61.0 161.1

Hovensa St Croix Turbine GT2 (G-1101F) 12.2 135.5 805.7 12.0 74.5 644.6 0.12 61.0 161.1

Hovensa St Croix Turbine GT3 (G-1101G) 12.2 135.5 805.7 12.0 74.5 644.6 0.12 61.0 161.1

Hovensa St Croix Turbine GT4 (G-3404) 12.9 161.0 809.5 12.8 88.5 647.6 0.13 72.4 161.9

Hovensa St Croix Turbine GT5 (G-3405) 12.9 161.0 766.5 12.8 88.5 613.2 0.13 72.4 153.3

Hovensa St Croix Turbine GT6 (G-3406) 12.9 161.0 766.5 12.8 88.5 613.2 0.13 72.4 153.3

Hovensa St Croix Turbine GT7 (G-3407) 12.9 161.0 766.5 12.8 88.5 613.2 0.13 72.4 153.3

Hovensa St Croix Turbine GT8 (G-3408) 15.1 167.6 1002.1 14.9 92.2 801.7 0.15 75.4 200.4

Hovensa St Croix Turbine GT9 (G-3409) 14.0 52.2 150.2 13.9 28.7 120.2 0.14 23.5 30.0

VI WAPA St Thomas Boiler 11 60.0 646.0 371.0 59.4 355.3 241.2 0.60 290.7 129.9

VI WAPA St Thomas Boiler 13 28.0 1116.0 670.0 27.7 613.8 435.5 0.28 502.2 234.5

VI WAPA St Thomas Turbine 12 15.0 381.0 1288.0 14.9 209.6 1030.4 0.15 171.5 257.6

VI WAPA St Thomas Turbine 14 16.0 392.0 1326.0 15.8 215.6 1060.8 0.16 176.4 265.2

VI WAPA St Croix Boiler 10 45.0 396.0 359.0 44.6 217.8 233.4 0.45 178.2 125.7

VI WAPA St Croix Boiler 11 81.0 712.0 646.0 80.2 391.6 419.9 0.81 320.4 226.1

Total 782.2 8322.6 15350.1 774.4 4577.4 11371.4 7.8 3745.2 3978.7

* Control Efficiencies are based on typical efficiencies listed in EPA Clean Air Technology Center fact sheets for dry sorbent injection, fabric filters, selective 

non-catalytic reduction, and selective catalytic reduction. See Section I of this memorandum for details.
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Table 2. Cost Effectiveness for Selected Controls

Facility Location

Unit 

Type Unit No.

Reductions* (TPY) Annual Control Cost ($/yr)

Cost Effectiveness ($/ton 

reduced)

PM10 SO2 NOX DIFF SNCR SCR DIFF SNCR SCR

Hovensa St Croix Boiler 1 (B-1151) 40.2 181.5 292.9 $8,591,292 $235,848 $38,749 $805

Hovensa St Croix Boiler 3 (B-1153) 40.2 181.5 292.9 $8,591,292 $235,848 $38,749 $805

Hovensa St Croix Boiler 4 (B-1154) 39.3 177.4 288.3 $8,588,093 $234,532 $39,640 $814

Hovensa St Croix Boiler 5 (B-1155) 60.1 266.7 440.0 $6,253,161 $313,100 $19,136 $712

Hovensa St Croix Boiler 6 (B-3301) 40.2 182.0 282.9 $5,819,344 $234,477 $26,197 $829

Hovensa St Croix Boiler 7 (B-3302) 40.2 182.0 282.9 $5,819,344 $234,477 $26,197 $829

Hovensa St Croix Boiler 8 (B-3303) 77.8 352.1 363.9 $11,589,590 $312,326 $26,959 $858

Hovensa St Croix Boiler 9 (B-3304) 77.8 352.1 363.9 $11,589,590 $312,326 $26,959 $858

Hovensa St Croix Turbine GT1 (G-1101E) 12.0 74.5 644.6 $12,389,903 $1,172,745 $143,149 $1,819

Hovensa St Croix Turbine GT2 (G-1101F) 12.0 74.5 644.6 $12,389,903 $1,172,745 $143,149 $1,819

Hovensa St Croix Turbine GT3 (G-1101G) 12.0 74.5 644.6 $12,389,903 $1,172,745 $143,149 $1,819

Hovensa St Croix Turbine GT4 (G-3404) 12.8 88.5 647.6 $12,395,811 $1,173,950 $122,333 $1,813

Hovensa St Croix Turbine GT5 (G-3405) 12.8 88.5 613.2 $12,395,811 $1,160,377 $122,333 $1,892

Hovensa St Croix Turbine GT6 (G-3406) 12.8 88.5 613.2 $12,395,811 $1,160,377 $122,333 $1,892

Hovensa St Croix Turbine GT7 (G-3407) 12.8 88.5 613.2 $12,395,811 $1,160,377 $122,333 $1,892

Hovensa St Croix Turbine GT8 (G-3408) 14.9 92.2 801.7 $15,316,917 $1,402,611 $142,990 $1,750

Hovensa St Croix Turbine GT9 (G-3409) 13.9 28.7 120.2 $15,295,348 $1,135,171 $359,186 $9,447

VI WAPA St Thomas Boiler 11 59.4 355.3 241.2 $1,168,675 $256,705 $2,818 $1,065

VI WAPA St Thomas Boiler 13 27.7 613.8 435.5 $2,416,194 $330,397 $3,766 $759

VI WAPA St Thomas Turbine 12 14.9 209.6 1030.4 $6,217,806 $1,117,227 $27,709 $1,084

VI WAPA St Thomas Turbine 14 15.8 215.6 1060.8 $6,219,588 $1,132,200 $26,873 $1,067

VI WAPA St Croix Boiler 10 44.6 217.8 233.4 $1,128,352 $254,743 $4,301 $1,092

VI WAPA St Croix Boiler 11 80.2 391.6 419.9 $2,353,506 $327,269 $4,988 $779

Total 774.4 4577.4 11371.4 $203,711,047 $3,282,047 $12,960,525 $38,064 $834 $1,743

* Reductions are based on typical efficiencies listed in EPA Clean Air Technology Center fact sheets for dry sorbent injection, fabric filters, selective noncatalytic reduction, and selective catalytic reduction. See Section I of this memorandum for details.
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Table 3. Total Control Costs and Cost Effectiveness

Control Total Capital Cost 

($)

Total Annual 

Cost ($/yr)

Total Emission 

Reductions (tpy)

Cost Effectiveness 

($/tpy pollutant reduced)

DIFF $750,566,946 $203,711,047 5,352 $38,064

SNCR $29,146,033 $3,282,047 3,937 $834

SCR $82,692,433 $12,960,525 7,434 $1,743

Overall $862,405,412 $219,953,619 16,723 $13,153