Prevention of Significant Deterioration Permit 

for 

Pioneer Valley Energy Center 

Ampad Road 

Westfield, MA 

431 MW Combustion Turbine 

Combined Cycle Generating Unit 

EPA Final PSD Permit Number 

052-042-MA15 

 Pursuant to the provisions of the Clean Air Act, Subchapter I, Part C (42 U.S.C. Section 

7470, et. seq) and the regulations found at the Code of Federal Regulations Title 40, Section 

52.21, the United States Environmental Protection Agency New England (EPA) is issuing a 

Prevention of Significant Deterioration (PSD) air quality permit to Pioneer Valley Energy 

Center, Ampad Road, Westfield, MA (PVEC) to install and operate a new 431 megawatt (MW) 

combined cycle generating facility at this location. 

 The design, construction and operation of the Facility shall be subject to the attached 

permit conditions and permit limitations. This Permit is valid only for the equipment described 

herein and as submitted to EPA in the November 8, 2008 application for a New Source Review 

(NSR)/Prevention of Significant Deterioration (PSD) permit under 40 CFR 52.21 and subsequent 

application submittals. This permit shall become effective 33 days after the date of signature 

unless review is requested on the permit under 40 C.F.R. § 124.19, in which case the permit shall 

be effective when provided by 40 C.F.R. § 124.19(f). The permit shall remain in effect until it is 

surrendered to EPA. This permit becomes invalid if PVEC does not commence construction 

within 18 months after the date of signature. EPA may extend the 18-month period upon a 

satisfactory showing that an extension is justified. 

 This permit does not relieve PVEC from the obligation to comply with applicable state 

and federal air pollution control rules and regulations. 

__________________________ _________________ 

Stephen S. Perkins, Director Date of Issuance 
Pioneer Valley Energy Center 

Prevention of Significant Deterioration Air Permit 

Final PSD Permit Number 052-042-MA15

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Office of Ecosystem Protection 

Table of Contents 

 Definitions 3

I. Emission Limits 4

II. Operational Conditions 7

III. Monitoring Requirements 9

IV. Testing Requirements 11

V. Recordkeeping Requirements 12

VI. Reporting 14

VII. Right of Entry 15

VIII. Transfer of Ownership 15

IX. Severability 15

X. Credible Evidence 15

XI. Other Applicable Regulations 16

XII. Agency Address 16
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Definitions 

1. ASTM: This reference means a monitoring device that meets American Society for Testing 

and Materials (ASTM) standards for the specific measuring activity. 

2. Carbon dioxide equivalent (CO2e): This represents an amount of GHGs emitted, and shall be 

computed as follows: 

a. Multiply the mass amount of emissions (tpy) for each of the six greenhouse gases in the 

pollutant GHGs by the gas's associated global warming potential published at Table A–1 

to subpart A of 40 C.F.R. part 98. 

b. Sum the resultant value from the above paragraph for each gas to compute a tpy CO2e.

3. Combined cycle turbine (CCT): This term includes the combustion turbine and heat recovery 

steam generator. 

4. GHGs: The aggregate group of six greenhouse gases: carbon dioxide, nitrous oxide, methane, 

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 

5. MWhgrid: Amount of electricity delivered to the grid in one hour. 

6. Startup: Unit startup commences when fuel is first ignited. Cold startups are defined as 

occurring after a period of greater than 24 hours of turbine shutdown, and warm startups are 

defined as occurring 24 hours or less since turbine shutdown. The time period for a warm 

startup is limited to 2.0 hours. The time period for a cold startup is limited to 5.0 hours. 

7. Shutdown: Shutdown is defined as the time when the turbine operation is between minimum 

sustained operating load and flame-out in the turbine combustor occurs. The time period for 

a shutdown is limited to 1.0 hour. 

8. ULSD: Transportation diesel or biodiesel (containing no more than 20 % non fossil fuel) with a 

sulfur content of 15 ppm by weight or less. 
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Project Description (For Informational Purposes) 

Pioneer Valley Energy Center (PVEC) is proposing to construct and operate a 431 MW electrical 

generating facility (the Facility) at a site on Ampad Road in Westfield, Massachusetts. The 

major system components will consist of a combined cycle turbine, an auxiliary boiler, an 

emergency diesel engine/generator, a diesel engine/fire pump, and a mechanical draft wet 

cooling tower. 

On April 11, 2011, EPA and the Massachusetts Department of Environmental Protection 

(MassDEP) entered into an “Agreement for Delegation of the Federal Prevention of Significant 

Deterioration (PSD) Program by the United States Environmental Protection Agency, Region 1 

to the Massachusetts Department of Environmental Protection” (Delegation Agreement). 

Pursuant to the Delegation Agreement and to 40 CFR 52.21(u), EPA delegated to MassDEP full 

responsibility for implementing and enforcing the federal PSD regulations for sources located in 

the Commonwealth of Massachusetts. Under Section IV.K of that Delegation Agreement, 

however, EPA retained responsibility for issuance and, if necessary, defense on appeal of the 

PSD permit for PVEC. After this permit has taken final effect, MassDEP may implement the 

PSD program with respect to this permit and this facility to the same extent as any other facility 

in Massachusetts, and where this permit refers to communications to or approval by EPA, 

MassDEP may act on EPA’s behalf. 

Permit Terms and Conditions 

I. Emission Limits

1. The owner/operator shall not discharge or cause to discharge into the atmosphere emissions 

from the combined cycle turbine (CCT) in excess of any of the emission limits in Tables I-IV. 

The emission limits contained in Tables I and II shall apply at all times, except that for CO 

and NOx only, the alternate emission limits contained in Tables III and Table IV shall apply 

during startup and shutdown, after which the limits in Tables I and II shall apply. The 

emission limits for ULSD shall apply when transitioning between natural gas and ULSD. 

Table I 

Emission Limits – Natural Gas 

Pollutant Concentration Limit Mass Limit

Nitrogen Oxides (averaged 

over 1 hr) 2.0 ppmvd @ 15%O2 20.2 lb/hr

Sulfuric Acid Mist 0.0019 lb/MMBtu 4.9 lb/hr

PM10

0.0040 lb/MMBtu

filterable + condensables

9.8 lb/hr

filterable + condensables

PM2.5

0.0040 lb/MMBtu

filterable + condensables

9.8 lb/hr

filterable + condensables

Carbon Monoxide

(averaged over 1 hr) 2.0 ppmvd @ 15%O2 12.3 lb/hr
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Table II 

Emission Limits – ULSD 

Pollutant Concentration Limit Mass Limit

Nitrogen Oxides (averaged 

over 1 hr)

5.0 ppmvd @ 15%O2 43.0 lb/hr

Sulfuric Acid Mist 0.0018 lb/MMBtu 3.6 lb/hr

PM10

0.014 lb/MMBtu

filterable + condensables

26.8 lb/hr

filterable + condensables

PM2.5

0.014 lb/MMBtu

filterable + condensables

26.8 lb/hr

filterable + condensables

Carbon Monoxide

(averaged over 1 hr)

6.0 ppmvd @ 15%O2

31.5 lb/hr

Table III 

Startup and Shutdown Emission Limits – Natural Gas 

(Averaging time is 1 hour) 

Pollutant Concentration Limit Mass Limit 

Nitrogen Oxides 40 ppmvd @ 15%O2 62.0 lb/hr

Carbon Monoxide

1,100 ppmvd @ 15%O2

for first 60 minutes of 

startup and for shutdowns

2000 lb/hr

Carbon Monoxide

100 ppmvd @ 15%O2

after first 60 minutes of 

startup 

400 lb/hr

Table IV 

Startup and Shutdown Emission Limits – ULSD 

(Averaging time is 1 hour) 

Pollutant Concentration Limit Mass Limit 

Nitrogen Oxides 60 ppmvd @ 15%O2 99 lb/hr

Carbon Monoxide

4,000 ppmvd @ 15%O2

for first 60 minutes of 

startup and for shutdowns

6000 lb/hr

Carbon Monoxide

250 ppmvd @ 15%O2

after first 60 minutes of 

startup 

800 lb/hr

2. To ensure the owner/operator has designed and installed an energy efficient CCT, the 

owner/operator shall conduct an initial emission test for CO2 and use emission factors from 

40 CFR part 98 for all other components of greenhouse gases, within 180 days from initial 

startup. The owner/operator shall ensure that GHG emissions from the CCT do not exceed 

825 lbs of CO2e MWhgrid (the “design emissions limit”) during the test. The test shall be 

conducted when the CCT is operating above 90 % of its design capacity on natural gas and 

the results shall be corrected to ISO conditions (59 oF, 14.7 psia, and 60% humidity). If the 

CCT does not meet the design emissions limit, then the owner/operator shall remedy the 

CCT’s failure to meet the design emissions limit, and shall not combust any fuel in the CCT 
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until the owner/operator has shown compliance with that limit during a subsequent emission 

test. 

3. Starting 365 calendar days after initial startup, the owner/operator shall not discharge or 

cause to discharge into the atmosphere GHG emissions from the combined cycle turbine 

(CCT) in excess of 895 lbs of CO2e/MWhgrid on a 365-day rolling average. A new 365-day 

rolling average emission rate is calculated each day by calculating the arithmetic average of 

all hourly emission rates (sum of measured lbs CO2/MWhgrid with the emission factors from 

40 CFR part 98 for all other all components of greenhouse gases and excluding hours in 

which the CCT was not operating) for the 365 preceding days. 

4. The owner/operator shall not discharge or cause to discharge into the atmosphere emissions 

from the 270 hp fire pump in excess of any of the following emission limits: 

a. 4.0 g/KW-hour of nitrogen oxides and non-methane hydrocarbon combined 

b. 0.20 g/KW-hour of PM10

c. 0.20 g/KW-hour of PM2.5

5. The owner/operator shall not discharge or cause to discharge into the atmosphere emissions 

from the 1500 KW emergency generator in excess of any of the following emission limits: 

a. 6.4 g/KW-hour of nitrogen oxides and non-methane hydrocarbon combined 

b. 3.5 g/KW-hour of carbon monoxide 

c. 0.20 g/KW-hour of PM10

d. 0.20 g/KW-hour of PM2.5

6. The owner/operator shall not discharge or cause to discharge into the atmosphere emissions 

from the auxiliary boiler in excess of any of the following emission limits: 

Table V 

Emission Limits – Natural Gas 

Pollutant Concentration Limit Mass Limit

Nitrogen Oxides 0.029 lbs/MMBtu 0.58 lb/hr

Sulfuric Acid Mist 0.0005 lb/MMBtu n/a

PM10

0.0048 lb/MMBtu

filterable + condensables

0.1 lb/hr

filterable + condensables

PM2.5

0.0048 lb/MMBtu

filterable + condensables

0.1 lb/hr

filterable + condensables

Carbon Monoxide 0.037 lbs/MMBtu 0.74 lb/hr
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II. Operational Conditions 

A. Emergency Generator and Fire Pump

1. The owner/operator shall only burn ULSD in the emergency generator and fire pump. The 

owner/operator shall limit the operating hours of each of these emission units to 300 hours in 

any 12 consecutive month period. The owner/operator shall only operate the emergency 

generator during power loss from the electrical grid or as needed for required monitoring, 

testing, or maintenance. The owner/operator shall not operate the emergency generator 

during combustion turbine startup or shutdown. 

2. The owner/operator shall only conduct readiness testing on the emergency generator and fire 

pump between 12:00 pm and 3:00 pm. 

3. The owner/operator shall not conduct readiness testing on the emergency generator and fire 

pump during days when the hourly ambient NO2 level measured just before testing at the 

nearest ambient NO2 air quality monitor in Hampden County operated by the MassDEP and 

available at http://public.dep.state.ma.us/MassAir (or its successor) is 54 ppb or higher. 

Notwithstanding the preceding, the owner/operator may conduct readiness testing if the 

scheduled testing has been delayed due to previous NO2 measurements for five consecutive 

calendar days. 

4. The owner/operator shall install, maintain, and operate the emergency generator and fire 

pump in accordance with the manufacturer’s specification.

B. Combined Cycle Turbine 

1. The owner or operator shall only burn either natural gas or ULSD in the combined cycle 

turbine. 

2. The owner/operator shall not burn ULSD in the combined cycle turbine for more than 1440 

hours in any 12 consecutive month period. Note: Any fractional hour burning ULSD will be 

rounded up to 1 hour. For example, 1 hour and 20 minutes on ULSD will be considered 2 

hours using ULSD. 

3. In addition to the ULSD combustion limitations imposed by Condition II.B.2, the 

owner/operator shall only burn ULSD in the combined cycle turbine during hours when one 

or more of the conditions in subparagraphs (a)-(f) below is true. 

a. The interruptible natural gas supply is curtailed at the Tennessee No. 6 gas terminal hub. 

A curtailment begins when the owner/operator receives a communication from the owner 

of the hub stating the natural gas supply will be curtailed, and ends when the 

owner/operator receives a communication from the owner of the hub stating that the 
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curtailment has ended. 

b. A blockage or breakage in the gas line delivery system limits or prohibits the use of 

natural gas. 

c. The owner/operator is commissioning the combined cycle turbine and, pursuant to the 

turbine manufacturer’s written instructions, the owner/operator is required by the 

manufacturer to fire ULSD during the commissioning process. 

d. The firing of ULSD is required for emission testing purposes as specified in Section IV 

of this permit or as required by the Commonwealth of Massachusetts. 

e. Routine maintenance of any equipment requires the owner/operator to fire ULSD. 

 

f. In order to maintain an appropriate turnover of the on-site fuel oil inventory, the 

owner/operator can fire ULSD when the last delivery of the oil to the tank was more than 

six months ago. 

4. In addition to the ULSD combustion limitations imposed by Condition II.B.3, the 

owner/operator may not burn ULSD under subparagraphs Condition II.B.3.d-f on any day 

when the Air Quality Index (AQI) for the area that includes Westfield, MA, as made 

available through the AIRNow web site at 

http://airnow.gov/index.cfm?action=airnow.local_city&cityid=74 (or its successor) is, or is 

forecasted to be, 101 or more (or, if the AQI is re-scaled, to an equivalent value indicating air 

quality Unhealthy for Sensitive Groups or worse). This provision does not apply to 

Conditions II.B.3.a-c. 

5. For purposes of Conditions II.B.3.a and V.2.o, the owner/operator may designate an alternate 

gas terminal hub in lieu of the Tennessee No. 6 hub. Such an alternate designation will 

become effective when EPA receives the owner/operator’s written communication specifying 

the owner/operator’s alternate hub designation and shall remain effective until replaced by 

another alternate hub designation. 

6. The owner/operator shall not discharge or cause to discharge into the atmosphere from the 

combined cycle turbine any gases, excluding water vapor, that exhibit greater than 10 percent 

opacity (6-minute average). This operational restriction shall apply at all times, except when 

firing ULSD during periods of startup or shutdown.

C. Auxiliary Boiler 

1. The owner/operator shall not operate the auxiliary boiler for more than 1100 hours in any 12 

consecutive month period. 

2. The owner/operator shall only burn natural gas in the auxiliary boiler. 
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3. The owner/operator shall tune-up the auxiliary boiler within 14 days after commencement of 

operations, and at least once every year thereafter, including the following: 

a. Inspect the burner, and clean or replace any components of the burner as necessary. 

b. Inspect the flame pattern, and adjust the burner as necessary to optimize the flame 

pattern. The adjustment should be consistent with the manufacturer’s specifications.

c. Inspect the system controlling the air-to-fuel ratio, and ensure that it is correctly 

calibrated and functioning properly. 

d. Optimize total emissions of carbon monoxide, consistent with the manufacturer’s 

specifications. 

e. Measure the concentrations in the effluent stream of carbon monoxide in parts per 

million, by volume, and oxygen in volume percent, before and after the adjustments are 

made (measurements may be either on a dry or wet basis, as long as it is the same basis 

before and after the adjustments are made). 

D. Cooling Tower

1. The owner/operator shall install high efficiency drift eliminators in accordance with 

manufacturer’s specifications and limit the amount of escaped water droplets to 0.0005 % of 

the total recirculating water. 

III. Monitoring Requirements 

1. The owner/operator shall install, operate, and maintain a continuous emission monitoring 

system (CEMS) to monitor carbon monoxide (CO), carbon dioxide (CO2), oxygen (O2), and 

nitrogen oxides (NOx) emissions, and a continuous opacity monitoring system (COMS) for 

the combined cycle turbine. The systems shall be operational prior to the initial stack testing 

required by Section IV.1 of this permit. 

2. Except as specified in paragraphs a and b, the installation of the CO monitor shall meet the 

performance specifications of 40 CFR Part 60 Appendix B, Performance Specifications 4 and 

4A. After installation, the owner/operator shall conduct quality assurance procedures in 

accordance with 40 CFR Part 60, Appendix F. 

a. The CO monitoring system will have two ranges for measuring CO emissions: 

i. 0-12 ppm for steady state operations 

ii. 0-10,000 ppm for startup/shutdown operations 

b. The relative accuracy of the CO monitoring system shall be: 

i. For the 0-12 ppm range, the relative accuracy must be within +/-0.5 ppm. 

ii. For the 0-10,000 ppm range, the relative accuracy must be within +/- 125 ppm. 
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3. Except as specified in paragraphs a and b, the installation of the NOx monitor shall meet the 

performance specifications of 40 CFR Part 75. After the installation the owner/operator shall 

conduct quality assurance procedures in accordance with 40 CFR Part 75. 

a. The NOx monitoring system will have two ranges for measuring NOx: 

i. 0-10 ppm for steady state operations 

ii. 0-120 ppm for startup/shutdown operations 

b. The relative accuracy of the NOx monitoring system shall be 

i. For the 0-10 ppm range, the relative accuracy must be within +/-0.5 ppm. 

ii. For the 0-120 ppm range, the relative accuracy must be within +/- 6 ppm. 

4. The installation of the CO2 and O2 monitors shall meet the performance specifications of 40 

CFR Part 60, Appendix B, Performance Specification No. 3. 

5. The installation of the continuous opacity monitoring system shall meet the performance 

specifications of 40 CFR Part 60, Appendix B, Performance Specification No. 1. 

6. The owner/operator shall install and operate a single, dedicated ASTM certified natural gas 

flow meter for the combined cycle turbine. 

7. The owner/operator shall install and operate a single, dedicated ASTM certified ULSD flow 

meter for the combined cycle turbine. 

8. The owner/operator shall calculate the heat input to the combined cycle turbine for each hour 

of operation by using the fuel flow meters and the corresponding fuel’s heat content.

9. The owner/operator shall provide fuel supplier certifications for each fuel delivery that 

documents the sulfur content of the ULSD is 15 ppm sulfur by weight or less. Fuel supplier 

certification shall include the following information: 

a. The name of the oil supplier; 

b. The sulfur content of the oil; 

c. The method used to determine the sulfur content of the oil; 

d. The location of the oil when the sample was drawn for analysis to determine the sulfur 

content of the oil; specifically including whether the oil was sampled as delivered to PVEC, 

or whether the sample was drawn from oil in storage at the oil supplier’s or oil refiner’s 

facility or another location; 

e. If the oil was not sampled as delivered, a statement that the sampling was performed 

according to either the single tank composite sampling procedure or the all-levels sampling 

procedure in ASTM D4057-88, “Standard Practice for Manual Sampling of Petroleum and 

Petroleum Products” and that no additions have been made to the supplier’s tank since 

sampling. 
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10. As an alternative to fuel supplier certification, the owner/operator may elect to take a manual 

sample after each addition of oil to the storage tank in accordance with the sampling 

procedure in ASTM D4057–88, “Standard Practice for Manual Sampling of Petroleum and 

Petroleum Products.”

11. The owner/operator shall install and maintain a non-resettable operating hour meter or the 

equivalent software to accurately indicate the elapsed operating time of the turbine, including 

periods of when the unit is in startup and shutdown operations.

12. For the emergency generator, the owner/operator shall install and maintain a non-resettable 

operating hour meter or the equivalent software to accurately indicate the elapsed operating 

time. 

13. For the fire pump, the owner/operator shall install and maintain a non-resettable operating 

hour meter or the equivalent software to accurately indicate the elapsed operating time. 

14. For the auxiliary boiler, the owner/operator shall install and maintain a non-resettable 

operating hour meter or the equivalent software to accurately indicate the elapsed operating 

time. 

IV. Testing Requirements 

The owner/operator shall: 

1. Ensure that all emissions tests are completed within 180 days after initial “startup,” as that 

term is defined in 40 C.F.R. § 60.2, of the CCT.

2. Submit a proposed emission test protocol(s) (including testing for startup and shutdown 

emissions) for EPA review and approval at least 60 days prior to the date of actual testing. 

EPA may revise the proposed emission test protocol or request that the owner/operator revise 

and re-submit. 

3. Submit the final emission test report(s) to the EPA within 60 days after the completion of 

each of the tests. 

4. Ensure that all stacks are constructed so as to accommodate the emissions testing 

requirements as stipulated in 40 CFR Part 60, Appendix A. 

5. Ensure that all emissions testing is conducted in accordance with the Environmental 

Protection Agency test requirements as specified in the 40 CFR Part 60, Appendix A, or by a 

methodology approved by the EPA. 

6. Conduct volumetric flow rate and velocity testing in accordance with 40 CFR Part 60, 

Appendix A, Method 1 and 2 and either Method 2F (3 dimensional probe) or Method 2G 

(two dimensional probe). 
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7. Measure PM10/PM2.5 emissions using 40 CFR 51, Appendix M, Test Method 201 or 201a, 

and Test Method 202, or another test method approved by EPA. 

8. Conduct initial compliance emission tests at maximum load to determine compliance with 

the emission limits (lb/hr, lb/MMBtu, and ppmvd) established in Section I for the CCT for 

the following: 

a. ULSD: NOx, CO, PM10/PM2.5, Sulfuric Acid Mist 

b. Natural Gas: NOx , CO, PM10/PM2.5, Sulfuric Acid Mist, GHG 

c. Conduct initial compliance tests for the duration of start-up and shut down periods for the 

CCT for NOx, and CO. Testing shall be done for both ULSD and natural gas. 

V. Recordkeeping Requirements 

1. The owner/operator shall maintain records of emergency engine operation that show it operated 

according to the allowable operating conditions listed in Conditions II.A.1-4 of this permit. 

2. The owner/operator shall maintain records of all information used to show compliance with the 

terms and conditions of this permit. The owner/operator shall maintain the records for five years 

in a location accessible to staff personnel from EPA and MassDEP. At a minimum, the records 

shall contain in either paper or electronic format, the following information: 

a. Date and hours of operation of the combined cycle turbine. 

b. Amount of electricity delivered to the grid for each operating hour. 

c. Date and hours of operation of the emergency generator. 

d. Date and hours of operation of the fire pump. 

e. Date and hours of operation of the auxiliary boiler. 

f. Date and time of start-up and shutdown of the combined cycle turbine. 

g. Date, time and specifications of all maintenance performed on the combined cycle 

turbine and continuous monitoring devices and the type or a description of the 

maintenance performed and the date and time the work was completed. 

h. Date, time and specifications of all maintenance performed on all pollution control 

equipment including dry low NOx combustors, water injection, and selective catalyst 

reduction for controlling NOx and the catalytic oxidation system for controlling CO. 
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i. Date, time and specifications of all maintenance performed on the CEM system. In 

addition when calibrating any of the CEM monitoring devices, a record of the date, time 

and the name of contractor who performed the calibrations. 

j. Combustion equipment, emission control or monitoring device malfunctions, time and 

date of malfunction, description of event, time and date of corrective action taken and 

description of said action. 

k. On an hourly basis, the total fuel consumption of natural gas in cubic feet and total fuel 

consumption of ULSD in gallons for each permitted fuel burning piece of equipment. 

l. For each fuel fired in the combined cycle turbine, the method to determine the fuel’s heat 

value and the actual value used to determine the heat input on an hourly basis. 

m. Hourly NOx, CO, and CO2 emissions, on a ppm and lb/hr basis for the combined cycle 

turbine. Hourly lb/hr emissions for CO shall be calculated using method 19 in 40 CFR 

part 60, Appendix A and the ppm measurement. Hourly lb/hr emissions for NOx shall be 

calculated using 40 CFR part 75. Emission data for ppm shall include both the actual ppm 

reading and the ppm reading adjusted to 15% O2. 

n. To determine the mass amount of CO2 emitted in one hour use the following equation: 

 

 

 

E = CO2 in lb/hr 

K = 1.14 x 10-3 lb/scf/%CO2

%CO2 is the average percent CO2 in the gas stream for the hour, dry basis 

F8710 is the F-factor for natural gas, dscf/MMBtu 

GCV is the gross calorific value, Btu/dscf 

 is the natural gas fuel flow rate, dscf/hr 

o. Communication from owner of the gas terminal Tennessee No. 6 to the owner/operator 

that demonstrates when natural gas to the owner/operator was curtailed and when each

curtailment ended. 

p. Documentation when an equipment failure necessitates the owner/operator to switch to 

ULSD. This includes, but is not limited to, communication from the gas supplier that a 

disruption in the gas supply has occurred. 

q. Date(s) and operating hours when the commissioning of the combined cycle turbine 

required the owner/operator to fire ULSD. 

r. Date(s) and operating hours when ULSD was fired in the combined cycle turbine due to 

emission testing. 
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s. Date(s), operating hours, and maintenance logs when routine maintenance of any 

equipment required the owner/operator to fire ULSD. 

t. The date and amount in gallons when ULSD was delivered to the storage tank that is used 

for the combined cycle turbine. Sum the deliveries for each calendar month. 

u. Date(s) and operating hours when ULSD was fired in the combined cycle turbine in 

accordance with permit Condition II.B.3. Sum the usage for each calendar month. 

3. The owner/operator shall display copies of this permit in reasonably accessible locations as 

near to the subject equipment as is practical. 

4. The owner/operator shall establish a maintenance procedure for ensuring the integrity of the 

drift eliminators. 

5. The owner/operator shall keep a record of all hourly ambient NO2 levels used by the 

owner/operator in determining readiness testing of the fire pump and/or emergency generator 

could proceed. 

VI. Reporting Requirements 

1. The owner/operator shall notify EPA in writing within 30 days after construction has been 

“commenced” as that term is defined in 40 C.F.R. § 52.21(b)(9), and, if construction is 

discontinued, then within 30 days after construction has been discontinued and again within 

30 days after construction has been re-commenced. 

2. The owner/operator shall notify EPA in writing within 15 days after the actual date of initial 

“startup” as that term is defined in 40 C.F.R. § 60.2.

3. The owner/operator shall submit quarterly CEMS and COMS reports in writing to EPA and 

MassDEP. The reports will be submitted by January 30th, April 30th, July 30th and October 

30th of each year and will contain at least the following information: 

a. The reports from the facility CEMS and COMS shall identify any periods of excess 

emissions; and 

b. For each period of excess emissions or excursions from allowable operating conditions, 

PVEC shall list the duration, cause, the response taken, and the amount of excess 

emissions. Periods of excess emissions shall include periods of start-up, shutdown, 

malfunction, emergency, equipment cleaning, and upsets or failures associated with the 

emission control system or CEMS and COMS. 

4. Within 48 hours of receiving a shipment of ULSD with a sulfur content by weight in excess of 15 

ppm, the owner/operator shall notify EPA and MassDEP in writing of such receipt, including the 

information in Condition III.9 above, and shall not combust that fuel. 
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5. After the occurrence of any violation of any emission limitation, the owner/operator must notify 

EPA New England, Office of Environmental Stewardship, attention Compliance and Enforcement 

Chief, by FAX at (617) 918-1810 within two business days, and subsequently in writing to the 

address listed in Section XII below within seven calendar days. 

6. Compliance with Condition VI.5 or any other condition of this permit requiring the 

owner/operator to notify EPA of excess emissions or of any other violation of the permit shall 

not excuse or otherwise constitute a defense to any violation of the permit or of any 

applicable law or regulation. 

VII. Right of Entry 

The owner/operator shall allow all authorized representatives of EPA, upon presentation of 

credentials, to enter upon or through the facility where records required under this permit are 

kept. The owner/operator shall allow such authorized representatives, at reasonable times: 

1. To access and copy any records that must be kept under this permit 

2. To inspect any facilities, equipment (including monitoring and air pollution control 

equipment), practices, or operations regulated or required under this permit; and 

3. To monitor substances or parameters for purposes of assuring compliance with this permit. 

VIII. Transfer of Ownership 

In the event of any changes in control or ownership of the PVEC facility, this permit shall be 

binding on all subsequent owners and operators. The owner/operator shall notify the succeeding 

owner and operator of the existence of this permit and its conditions before such change if 

possible, but in no case later than 14 days after such change. Notification shall be sent by letter 

with a copy forwarded within 5 days to EPA. 

IX. Severability 

The provisions of this permit are severable, and if any provision of the permit is held invalid, the 

remainder of this permit will not be affected thereby. 

X. Credible Evidence 

For the purpose of submitting compliance certifications or establishing whether or not the 

owner/operator has violated or is in violation of any provision of this permit, the methods used in 

this permit shall be used, as applicable. However, nothing in this permit shall preclude the use, 

including the exclusive use, of any credible evidence or information, relevant to whether the 

owner/operator would have been in compliance with applicable requirements if the appropriate 

performance or compliance test procedures or methods had been performed. 
Pioneer Valley Energy Center 

Prevention of Significant Deterioration Air Permit 

Final PSD Permit Number 052-042-MA15

16

XI. Other Applicable Regulations 

The owner/operator shall construct and operate all equipment regulated herein in compliance 

with all other applicable provisions of federal and state air regulations.

XII. Agency Address 

Subject to change, all correspondence required by this permit shall be forwarded to: 

Air Compliance Clerk 

U.S. EPA New England 

5 Post Office Square 

Suite 100, OES04-2

Boston MA 02109-3912 
1 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION 1 

5 POST OFFICE SQUARE, SUITE 100 

BOSTON, MA 02109-3912

FACT SHEET 

Pioneer Valley Energy Center 

Ampad Road 

Westfield, MA 

EPA Draft Permit (Revised) 

Permit Number 052-042-MA14
2 

Table of Contents

I. General Information 3

II. Project Location 4

III. Proposed Project 5

IV. PSD Program Applicability and Review 6

V. PSD Applicability 7

VI. BACT Analysis 9

VII. Monitoring and Testing 30

VIII. Endangered Species Act/ESA 30

IX. Impact Analysis Based on Modeling 31

X. Mass Based Emission Limits 37

XI. Environmental Justice (EJ) 38

XII. National Historic Preservation Act 46

XIII. Comment Period, Hearings and Procedures for Final Decisions 46

XIV. EPA Contacts 47
3 

I. General Information 

 Name of source: Pioneer Valley Energy Center 

Location: Westfield, Massachusetts 

Applicant’s name and address: Ampad Road 

 Westfield, MA 01803 

 Application Prepared by: ESS Group, Inc. 

 888 Worcester Street, Suite 240 

 Wellesley, MA 02482 

 Draft PSD permit number: 052-042-MA14 

 EPA contact: Donald Dahl 

 Air Permits, Toxics, and Indoor Air Program Unit 

 EPA-New England 

5 Post Office Square 

Suite 100 (OEP05-2) 

Boston, MA 02109-3912 

 Telephone: (617) 9188-1657 

 Dahl.Donald@epa.gov

In November 2008, Pioneer Valley Energy Center (PVEC) submitted an initial application to 

EPA-New England (EPA) requesting a prevention of significant deterioration (PSD) permit for a 

new 431 MW combined cycle electric generating facility in Westfield, Massachusetts 

(―Facility‖). PVEC submitted additional information on March 10, 2010, July 12, 2010, and 

October 27, 2010. On November 5, 2010, EPA issued a draft PSD permit for a 30 day public 

comment period. 

As of January 2, 2011, any source required to obtain a PSD permit must assess greenhouse gas 

(GHG) emissions to determine if GHG emissions are subject to regulation under the PSD 

permitting program. Since greenhouse gas emissions for this project are estimated to be over 

75,000 tons per year on a carbon dioxide equivalent basis (CO2e), PVEC determined the 

project’s GHG emissions would be subject to PSD. On March 9, 2011 and July 12, 2011, PVEC 

submitted additional information to support its request for a PSD permit, including a BACT 

analyses for GHG emissions. On September 22, 2011 and October 14, 2011, PVEC submitted 

modeling analysis using meteorological data from Barnes Airport. EPA considers the receipt of 

the additional information on October 14, 2011 as completing the application for this draft 

permit. 

After reviewing the November 2008 PSD application and additional information, EPA prepared 

this Fact Sheet and draft PSD permit for the proposed PVEC project as required by 40 CFR Part 

124-Procedures for Decision Making. 
4 

EPA’s permit decisions are based on the information and analysis provided by the applicant and 

EPA’s own technical expertise. This Fact Sheet documents the information and analysis EPA 

used to support the PSD permit decisions. It includes a description of the proposed facility, the 

applicable PSD regulations, and an analysis demonstrating how the applicant complied with the 

requirements. 

Based on all submittals, EPA has concluded PVEC’s application is complete and provides the 

necessary information showing the project meets federal PSD regulations. EPA is making 

PVEC’s submitted information part of the official record for this Fact Sheet and PSD permit. 

The initial application and supplemental information for this permit are available on-line at EPA 

New England’s Web Site http://www.epa.gov/ne/communities/nsemissions.html. 

Please note this project is also subject to the Massachusetts Department of Environmental 

Protection’s (MassDEP) Comprehensive Plan Approval (CPA) requirements under the 

Commonwealth’s regulations at 310 Code of Massachusetts Regulations (CMR) 7.02. On 

December 31, 2010, the Commonwealth issued the CPA. The CPA regulates all pollutants 

affected by the proposed project, including the pollutants regulated under the PSD permit,1and 

also implements MassDEP’s nonattainment New Source Review (NSR) program regulations at 

310 CMR 7.00: Appendix A. PVEC must comply with both the federal PSD permit and the 

MassDEP’s CPA, as well as other applicable federal and state requirements. 2

II. Project Location 

The proposed plant site is located in an industrial land-use area of Westfield, Massachusetts 

bounded by Servistar Industrial Way toward the south and east, Ampad Road toward the west, 

and an undeveloped wooded area toward the north. 

This new facility will be located in an area which is classified as either ―attainment‖ or 

―unclassifiable‖ for sulfur dioxide (SO2), nitrogen dioxide (NO2), carbon monoxide (CO), 

particulate matter with diameters less than 10 microns (PM10) and 2.5 microns (PM2.5), and lead. 

Therefore, the facility is located in a PSD area for these pollutants. EPA has also designated 

western Massachusetts as a moderate non-attainment area under the 8-hour ground level ozone 

NAAQS. See 40 CFR 81.322. 

 

1

 For greenhouse gases, the CPA only regulates carbon dioxide (CO2), not the full suite of GHGs regulated by this 

PSD permit.

2

It is also possible that the facility may become subject to Section 112(r) of the Clean Air Act. Section 112(r) 

provides in relevant part: 

It shall be the objective of the regulations and programs authorized under this subs ection to prevent the 

accidental release and to minimize the consequences of any such release of any substance listed [under 

CAA 112(r)(3)] or any other extremely hazardous substance. The owners and operators of stationary 

sources producing, processing, handling or storing such substances have a general duty ... to identify 

hazards which may result from such releases using appropriate hazard assessment techniques, to design and 

maintain a safe facility taking such steps as are necessary to prevent releases, and to minimize the 

consequences of accidental releases which do occur. 

42 USC 7412(r)(1). For more information regarding Section 112(r) requirements, see 

http://www.epa.gov/osweroe1/docs/chem/gdc-fact.pdf. 
5 

III. Proposed Project 

PVEC proposes to construct a 431 MW (gross) electrical generating facility located on an 

undeveloped site off of Ampad Road in Westfield, Massachusetts. The major system 

components will consist of a Mitsubishi M501G air-cooled combined cycle turbine, an auxiliary 

boiler, an emergency diesel engine/generator and emergency diesel engine/fire pump, a 

mechanical draft wet cooling tower, and tanks for the storage of ultra low sulfur distillate oil 

(ULSD) or a blend of 20% biodiesel oil and 80% ULSD (B20). 

The combustion turbine will fire natural gas as a primary fuel and ULSD/B20 oil as a backup 

fuel. The combustion turbine will have a maximum heat input rate of 2,542 million British 

thermal units per hour (MMBtu/hr) at ISO conditions and a maximum gross power output 

(including the steam turbine) of 431 MW while firing natural gas. The maximum heat input rate 

and gross power output will be 2,016 MMBtu/hr and 306 MW, respectively, when firing 

ULSD/B20 oil. 

The heat recovery steam generator (HRSG) will house a Selective Catalytic Reduction (SCR) 

emissions control system to minimize emissions of nitrogen oxides (NOx) and an oxidation 

catalyst to minimize emissions of carbon monoxide (CO) and volatile organic compounds 

(VOC). Exhaust gases from the combustion turbine/HRSG will be discharged through an 

exhaust stack 23 feet in diameter and 180 feet tall. 

The auxiliary boiler and emergency diesel engine/generator will be housed within the main plant 

building. The auxiliary boiler will have a maximum heat input rate of approximately 21 

MMBtu/hr and will be fired by natural gas. The emergency diesel engine/generator will have a 

power output of approximately 2,174 horsepower (hp) and 1500 KWe-shaft. The emergency 

diesel fire pump is a 270 hp engine that will be housed in a separate, small building located to the 

north of the main plant building. Both diesel engines will be fueled with ULSD/B20. 

PVEC has requested the combined cycle turbine be permitted for unrestricted operation on 

natural gas and for the usage of up to 1440 hours (equivalent to 60 days) per 12-month period on 

ULSD/B20. Assuming an ULSD/B20 oil heating value of 138,000 Btu/gallon, this is equivalent 

to approximately 14,609 gallons per hour fuel use rate or 21.0 million gallons per 12-month 

period. 

The auxiliary boiler will be limited to the equivalent of no more than 1,100 hours of operation 

per rolling 12-month period. The emergency diesel engine/generator and fire pump will each be 

limited to no more than 300 hours of operation per rolling 12-month period. The emergency 

diesel engine/generator and fire pump will not operate concurrently with the combustion 

turbine/HRSG except for sometime between the hours of 12:00 pm and 3:00 pm for maintenance 

and testing. 
6 

IV. PSD Program Applicability and Review 

As stated earlier, EPA currently classifies Western Massachusetts as a moderate nonattainment 

area for ground level ozone and attainment/unclassifiable for all other criteria pollutants. Under 

these classifications, MassDEP administers the nonattainment NSR program to regulate 

emissions of Volatile Organic Compounds (VOC) and Nitrogen Oxides as a precursor to ground 

level ozone. EPA administers the PSD program that applies to the emissions of all other 

regulated criteria pollutants, including NO2. NO2 is a constituent of NOx. 

Before March 2003, under a delegation agreement with the EPA, Massachusetts administered the 

federal PSD program at 40 CFR 52.21 and issued PSD permits to sources in Massachusetts. 

However, in March 2003, Massachusetts returned the PSD program to EPA. In April 2011, 

Massachusetts once again became the PSD permitting authority under a new delegation 

agreement with EPA. However, Section IV.K. of the delegation agreement specifies that EPA 

would retain the responsibility in issuing the PSD permit for PVEC. After this permit has taken 

final effect, MassDEP may implement the PSD program with respect to this permit and this 

facility to the same extent as any other facility in Massachusetts, and where this permit refers to 

communications to or approval by EPA, MassDEP may act on EPA’s behalf. 

The MassDEP continues to administer its state permitting regulations and to issue 

comprehensive plan approvals to sources in Massachusetts. Typically, sources that are subject to 

the federal PSD program are also subject to the state permitting program. 

The PSD regulations require major new stationary sources or major modifications to an existing 

major stationary source to undergo a PSD review and to receive a PSD permit before 

commencement of construction. 

40 CFR 52.21 (b)(1) of the federal PSD regulations defines a ―major stationary source‖ as either 

(a) any of 28 designated stationary source categories with potential emissions of 100 tons per 

year or more of any regulated NSR pollutant, or (b) any other stationary source with potential 

emissions of 250 tons per year or more of any regulated NSR pollutant. Combined cycle 

generating facilities like PVEC are part of the 28 designated stationary source categories for 

which 100 tons per year of potential emissions qualifies the source as ―major.‖

3

In addition, once a new stationary source has been determined to be a ―major‖ source, it is 

subject to PSD review for each regulated NSR pollutant that the source would have the potential 

to emit in ―significant‖ amounts, which in some cases are lower than the ―major‖ thresholds. 

Forty CFR 52.21(b)(50)(iv) includes pollutants ―subject to regulation‖ as defined in 40 CFR 

52.21(b)(49) as regulated NSR pollutants. For this project, GHG emissions become a regulated 

NSR pollutant if the project’s total GHG emissions on a CO2e basis equal or exceed 75,000 tons 

per year. 

 

3

“Determining Prevention of Significant Deterioration (PSD) Applicability Thresholds for Gas Turbine Based 

Facilities,‖ memo from Edward J, Lillis, dated February 2, 1993. 
7 

If EPA determines a new stationary source or new modification is subject to the PSD program, 

the source must apply for and obtain a PSD permit that meets regulatory requirements including: 

Best Available Control Technology (BACT) requiring sources to minimize emissions to 

the greatest extent possible; 

An ambient air quality analysis to ensure all the emission increases do not cause or 

contribute to a violation of any applicable PSD increments or NAAQS; 

An additional impact analysis to determine direct and indirect effects of the proposed 

source on industrial growth in the area, soil, vegetation and visibility; and 

Public comment including an opportunity for a public hearing. 

V. PSD Applicability 

The Facility is considered a major source of air pollution as defined by EPA’s PSD program. 

Potential emissions from the new turbine are significant for six different pollutants; PM10, PM2.5, 

CO, NOx, sulfuric acid mist and GHG. Table 1 lists the significance level threshold for several 

pollutants and the potential emissions from the proposed new equipment at the site.
8 

Table 1 

Facility Potential Emissions (tons per year) 

Pollutant

Combustion 

Turbine

(8,215 

hr/yr)

Auxiliary

Boiler

(1,100 

hr/yr)

Emergency

Generator

(300 hr/yr)

Fire

Pump

(300 hr/yr)

PTE - Normal 

Operation(1)

CT Startup/

Shutdown(2)

(545 hr/yr)

Facility

PTE(3)

PSD Sig. 

Emission Rates

(TPY)

PSD?

NOx 91.9 0.3 5.6 0.5 98.4 12.6 110.9 40 yes

CO 59.9 0.4 1.8 0.3 62.5 487.4 549.9 100 yes

SO2 16.7 0.0 0.5 0.1 17.2 0.8 18.0 40 no

H2SO4 mist 17.2 0.0 0.0 0.0 17.2 0.8 18.0 7.0 yes

PM10/PM2.5 

(Total) 49.1 0.1 0.1 0.0 49.4 1.7 51.0 15 PM1010 PM.25

yes

PM10/PM2.5 

(Filterable) 24.6 0.0 0.1 0.0 24.7 0.8 25.5 – –

PM/PM10/PM2.5 

(Condensible) 24.6 0.0 0.1 0.0 24.7 0.8 25.5 – –

VOC 23.8 0.0 0.3 0.1 24.2 0.6 24.8 40 no

Lead 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.6 no

GHG (CO2e 

basis)41,480,786 1,394 383 47 1,482,610

75,000 CO2e and 

any amount of 

GHG yes

1. Total emissions represent maximum potential of all equipment operating independently in normal operation, and are based on the 

operation of the combustion turbine for 8,215 hr/yr, the auxiliary boiler for 1,100 hr/yr, the emergency generator and fire pump for 300 

hr/yr each, and on 545 hr/yr spent in startup or shutdown. 

 

 The combustion turbine may operate in excess of 8,215 hours per year which would result in decreased startup and shutdown hours and 

decreased overall emissions. 

2. Startup/shutdown emissions are estimated based on 141 warm starts (2 hrs each), 35 cold starts (5 hours each) and 176 shutdowns per 

year. 

3. The Facility PTE is the sum of the PTE during normal operation and during startup/shutdown of the combustion turbine. 

4. GHG emissions are calculated assuming 7,320 hours on natural gas and 1440 hours on ULSD. The value of 75,000 TPY CO2e under ―PSD 

Sig. Emission Rate(s)‖ represents the ―subject to regulation‖ threshold for GHG, per 40 CFR 52.21 (b)(49).
9 

VI. BACT Analysis 

As required by the federal PSD program at 40 CFR 52.21(j)(2) and (3), PVEC is required to 

apply BACT to the NOx, PM10, PM2.5, CO, GHG, and H2SO4 mist emissions from the new 

turbine and other emission units. BACT is defined as, an emissions limitation ... based on the 

maximum degree of reduction for each pollutant subject to regulation under [the Clean Air] Act 

which would be emitted from any proposed major stationary source or major modification which 

the Administrator, on a case-by-case basis, taking into account energy, environmental, and 

economic impacts and other costs, determines is achievable for such source or modification 

through application of production processes or available methods, systems and techniques ... for 

control of such pollutant. 40 CFR 52.21(b)(12); Clean Air Act (CAA) 169(3). 

In making its BACT determinations, EPA follows the following five step ―top-down‖ 

methodology as outlined in several EPA policy memoranda. 

1. Identify all control technologies. Identify all possible control options, including 

inherently lower emitting processes and practices, add-on control equipment, or 

combination of inherently lower emitting processes and practices and add-on control 

equipment. 

2. Eliminate technically infeasible options. Eliminate technically infeasible options based 

on physical, chemical, and engineering principles. 

3. Rank remaining control technologies by control effectiveness. Rank the remaining 

control options by control effectiveness, expected emission reduction, energy impacts, 

environmental impacts, and economic impacts. 

4. Evaluate most effective controls and document results. Determine the economic, 

energy, and environmental impacts of the control technology on a case-by-case basis. 

5. Select the BACT. Select the most effective option not rejected as the BACT. 

Combined Cycle Turbine 

Clean Fuels 

Background

For the turbine, a major element of the BACT analysis is the use of clean fuels. This Fact Sheet 

discusses the BACT analysis for fuels here, rather than repeating it for each individual pollutant. 

PVEC has proposed to burn primarily natural gas, which is a clean-burning fuel. However, as an 

alternate fuel, PVEC has requested permission to burn ultra low sulfur distillate oil (ULSD) or a 
10

blend of ULSD and 20% biodiesel oil (B20) for up to 1440 hours per year.4 While ULSD and 

B20 are the cleanest-burning fossil fuels other than natural gas, for several regulated NSR 

pollutants, air emissions from burning ULSD/B20 are higher than from burning natural gas. 

Step 1: Identify all control technologies. 

Since this section is focusing on fuels, the identified control technologies are: 

1. use of natural gas only 

2. primarily natural gas with ULSD as a backup fuel 

3. primarily natural gas with B20 as a backup fuel 

4. primarily natural gas with either ULSD or B20 as a backup fuel 

Step 2: Eliminate technically infeasible options 

None of the above fuel options are technically infeasible. 

Step 3: Rank remaining control technologies by control effectiveness. 

With respect to pollutant emissions, natural gas is the cleanest fuel identified. ULSD and B20 

have higher emissions than natural gas, but their emissions are essentially identical. The 

additional daily emissions from burning ULSD/B20 are 0.27 tons of NOx, 0.23 tons of CO, 0.20 

tons of PM10/2.5 (totaling 0.7 tons/day, or 42 tons/year), and 962 tons/year of GHGs (measured in 

CO2e). 

Since natural gas is a cleaner fuel than ULSD/B20, it ranks higher in terms of control 

effectiveness. However, as noted above, in determining the BACT, EPA is required to consider 

energy impacts, environmental impacts, and economic impacts. This section discusses the 

energy, environmental, and economic impacts of natural gas as opposed to ULSD/B20. 5

 

Step 4: Evaluate most effective controls and document results.

1. Energy impacts- In order to understand the energy impacts associated with natural gas, a 

brief background on the New England energy market is helpful. Under extreme 

conditions, the Independent System Operator-New England (―ISO-NE‖), which regulates 

the New England electricity market, may declare an ―Energy Emergency‖ if there may be 

sustained national or regional shortages in fuel availability or deliverability to the New 

England region’s generation resources. Such shortages of fuel may come in many forms, 

including, but not limited to: severe drought, or interruption to availability or 

transportation of natural gas, liquefied natural gas, oil, or coal. 6 In such circumstances, 

 

4

 On October 19, 2009, the Commonwealth of Massachusetts Energy Facilities Siting Board (EFSB) issued its ruling 

limiting the amount of ULSD that PVEC can burn to this amount.

5

 As noted above, the emissions of ULSD and B20 are essentially identical, and EPA is unaware of any significant 

differences between ULSD and B20 with respect to energy, economic, or environmental impacts. Consequently, 

having no reason to prefer ULSD or B20, the rest of this analysis focuses on ULSD/B20 vs. natural gas.

6

See ISO New England Operating Procedure No. 21, ―Action During an Energy Emergency‖ (June 1, 2010), at 

http://www.iso-ne.com/rules_proceds/operating/isone/op21/op21_rto_final.pdf.
11

ISO-NE may ask dual-fuel units to voluntarily switch to operation on the fuel source that 

is not in short supply. While the natural gas transportation capacity in New England has 

improved in recent years, the possibility of a temporary gas shortage has not been 

completely eliminated. 

Short of a declared energy emergency, there may also be practical constraints on a power 

plant’s ability to obtain natural gas on a given day. It is important to distinguish two 

different types of natural gas service. ―Firm‖ or ―non-interruptible‖ service customers 

purchase, in advance, a right to a guaranteed supply. Pipeline companies must be 

prepared to provide daily service up to the maximum specified volume or service level 

under firm contracts or tariffs even though the firm customers may not actually purchase 

or request transportation of that volume of gas on any given day. In return for this service 

guarantee, firm customers pay rates that allow pipeline companies to recover most of the 

fixed costs associated with the firm load, e.g., constructing, maintaining, and operating 

the pipeline system. By contrast, ―interruptible‖ gas service, which is generally priced 

substantially lower than firm service, does not guarantee supply, and the availability of 

capacity to serve interruptible customers is often limited during periods of peak gas 

demand.7

 Due to bottlenecks in distribution, there may be days when interruptible 

service customers simply cannot obtain sufficient natural gas at any price. There may 

also be extremely local disruptions where, for various reasons, natural gas is generally 

available in New England, but it cannot be delivered to a specific site due to a local 

system failure. 

2. Economic impacts - Even when natural gas is available, under certain market conditions, 

natural gas may be so much more expensive than ULSD that natural gas becomes costineffective as a means of pollution control, or, put another way, the economic impacts of 

natural gas make it no longer BACT. To the best of EPA’s knowledge, this is determined 

by two factors: (1) whether the facility uses an interruptible or firm contract, and (2) 

whether there is a natural gas shortage. In simple terms, with a firm contract, the price of 

natural gas is always high but always available; with an interruptible contract, the price of 

gas is almost always lower than under a firm contract, but in rare events the spot market 

price could exceed the firm contract price. Since the primary reason that the spot market 

price could exceed the firm price is a curtailment, the economic impact analysis begins 

with a discussion of contract mechanisms. On March 10, 2010, PVEC supplemented its 

BACT analysis by including the cost differential between the two types of natural gas 

contracts. A non-interruptible contract for PVEC (which would enable it to burn 100% 

natural gas) would cost an additional $13,900,000 dollars per year. As noted above, this 

facility is already subject to an EFSB limitation that prevents it from burning more than 

1440 hours of ULSD/B20. Since the total pollution (all non-GHG pollutants combined) 

avoided by burning 100% natural gas as opposed to 1440 hours’ ULSD/B20 is 42 

tons/year, use of 100% natural gas via a non-interruptible contract would involve a cost 

per ton of criteria pollutants avoided of $330,952/ton and $14,499/ton of GHG (measured 

in CO2e). This is well outside the range of controls or fuels determined to be costeffective in previous BACT determinations. 

 

7

For more background information, see http://www1.eere.energy.gov/cleancities/pdfs/glossary_ng_purchasing.pdf.
12

One final possibility deserves discussion. Since EPA (through BACT) regulates control 

technologies (including available clean fuels), not market mechanisms for purchasing 

such technologies, it is conceivable that an appropriate BACT determination would still 

be to require 100% natural gas, but to leave the facility to purchase natural gas on the 

spot market (if it so desired) through interruptible contracts, rather than commit to a noninterruptible contract. However, if PVEC were only authorized to burn natural gas and it 

proceeded with interruptible contracts, then there could be times when a curtailment in 

natural gas supply would sufficiently affect the cost and availability in such a manner that 

requiring natural gas only would have unacceptable energy impacts (because gas is not 

available to interruptible customers) or unacceptable economic impacts (because the spot 

market price of gas is not cost-effective as a means of pollution control). As a practical 

matter, the occasions on which gas is not available to interruptible customers or the spot 

market price of gas is not cost-effective as a means of pollution control are only likely to 

occur when there is a curtailment of supply. This means that the economic impacts of 

this option (i.e., the permit allowing only natural gas, but the facility pursuing 

interruptible contracts) are largely the same as the energy impacts (discussed on page 11). 

3. Environmental impacts - When the turbine burns ULSD, water is injected into the 

combustion area to control the formation of thermal NOx. This increase in water usage is 

approximately 410,000 gallons per day. Over a 60-day period, this would mean 

24,600,000 excess gallons of water for burning ULSD/B20 as opposed to gas. The water 

used to control NOx emissions represents 18% of the facility’s water needs. Pioneer 

Valley will obtain its water from two municipal water sources, Westfield and Holyoke. 

According to EPA’s Water Sense program, an average family of four can use 400 gallons 

of water per day.8 This means the water used to control NOx emissions when burning 

ULSD is the equivalent of how much water 1025 households would use on a daily basis. 

As previously discussed, EPA has limited Pioneer Valley’s ability to burn ULSD to 

circumstances when the ability to burn natural gas is curtailed. During these times, 

PVEC may not be able to generate electricity if it is not capable of burning ULSD. The 

shutdown of PVEC would result in a loss of 306 MW per hour, or a total of 7344 

MW/day. According to data obtained from the Massachusetts Department of Energy and 

Environmental Affairs,9the average household in Massachusetts uses 700 kw per month 

which equates to about 23 kw per day. Based on these numbers, preventing PVEC from 

generating electricity would remove enough electricity to power over 300,000 homes. 

Within this step of the BACT analysis, EPA weighs the all of the environmental, energy, 

and economic impacts. Since the energy impact of requiring 100% natural gas (loss of 

electricity) outweighs the collateral environmental impact of allowing ULSD/B20 

(additional water usage) by a factor of 300 on a per household basis, EPA concludes that 

the burning of ULSD under restricted circumstances is allowable even though the burning 

of ULSD uses more water. 

 

8

See http://www.epa.gov/WaterSense/pubs/indoor.html.

9

See http://www.mass.gov/eea/energy-utilities-clean-tech/electric-power/electric-market-info/electric-customermigration-data.html.
13

As noted above, natural gas is the most effective fuel for pollution reduction and also has 

lower collateral environmental impacts (water usage), but on the other hand, allowing 

only natural gas combustion could have adverse energy and/or economic impacts. 

EPA finds that allowing only natural gas would not be BACT because of these potential 

adverse impacts. Rather, BACT includes burning ULSD/B20 as a backup fuel. 

However, EPA also finds that allowing unrestricted burning of ULSD/B20 for 1440 hours 

per year (as PVEC has requested) is not BACT, because it would allow the facility to 

burn the dirtier fuel beyond the point that may be justified by the need to avoid 

unacceptable energy and/or economic impacts. 

Step 5: Select BACT 

EPA is proposing to allow PVEC to burn ULSD/B20 as a backup fuel, but only under 

specifically defined circumstances that constrain its usage to those situations where not allowing 

ULSD/B20 would impair the facility’s ability to generate at all. These situations include: a 

curtailment in the natural gas supply; commissioning the turbine (which may require firing with 

oil); government-required emissions testing; equipment maintenance; and maintaining 

appropriate turnover of the on-site oil inventory.10 

To address these events, EPA is limiting the use of ULSD to the following circumstances: 

1. The interruptible natural gas supply is curtailed at the Tennessee No. 6 gas terminal hub. 

A curtailment begins when the owner/operator receives a communication from the owner 

of the hub informing the owner/operator stating that the natural gas supply will be 

curtailed, and ends when the owner/operator receives a communication from the owner of 

the hub stating that the curtailment has ended. 

2. Any equipment (whether on-site or off-site) required to allow the turbine to utilize natural 

gas has failed; 

3. The owner/operator is commissioning the combined cycle turbine and, pursuant to the 

turbine manufacturer’s written instructions, the owner/operator is required by the 

manufacturer to fire ULSD during the commissioning process; 

4. The firing of ULSD is required for emission testing purposes as specified in the PSD 

permit or as required by the Commonwealth of Massachusetts; 

5. Routine maintenance of any equipment requires the owner/operator to fire ULSD; 

 

6. In order to maintain an appropriate turnover of the on-site fuel oil inventory, the 

owner/operator can fire ULSD when the age of the oil in the tank is greater than six 

 

10 Stored oil becomes less usable with time, and thus the facility may wish to combust oil at a certain point to avoid 

wastage.
14

months. A new waiting period for when oil can be used pursuant to this condition will 

commence once oil firing is stopped. 

Finally, the total number of hours (including partial hours) of firing ULSD/B20 cannot exceed 

1440 per year. 

NOx

NOx emissions from the combustion of fossil fuels are largely the result of fuel-bound nitrogen 

content of the fuel and high combustion temperatures. 

Natural gas has negligible fuel-bound nitrogen, and ULSD has lower levels of fuel bound 

nitrogen than other liquid fossil fuel. The majority of the NOx emitted from the turbine is 

thermal. 

Several design and add-on technologies have been developed to minimize NOx emissions, and 

have been identified in Step 1 of the BACT analysis: 

Step 1

1. Dry Low-NOx Combustors 

In dry low-NOx (DLN) burners, air and fuel are mixed before entering the combustor to 

provide more homogeneous charge. To achieve low NOx emission levels, the mixture of 

fuel and air should be near the lean flammability limit of the mixture. However, at 

reduced load conditions, lean premixed combustors may lead to some combustion 

instability and increased CO emissions (which, as discussed below, will be controlled by 

an oxidation catalyst as part of the BACT for CO). 

PVEC proposed using DLN burners as part of its BACT determination for controlling NOx

emissions when burning natural gas. 

2. Water Injection 

Water injection involves injection of water or steam into the immediate vicinity of the 

combustor burner flame. Instantaneous cooling reduces the NOx formation in the 

combustion chamber. However water or steam injection may also lead to increases in 

emissions of CO and hydrocarbons (HC) resulting from incomplete fuel combustion. There 

is also a decrease in efficiency due to heat loss, resulting in an increase in greenhouse gases 

per megawatt of electricity. 

The technology of using water injection was proposed by PVEC as part of its BACT 

determination for controlling NOx emissions when burning ULSD/B20. 
15

3. Catalytic Combustion/XONON

Instead of burning the fuel with an open flame, a catalyst bed is first used to oxidize the fuel 

mixture. The use of the catalyst lowers the combustion temperature helping to minimize the 

formation of thermal NOx during combustion. 

4. SCONOx

11

SCONOxTM uses a potassium carbonate (K2CO3) coated catalyst to reduce oxide of 

nitrogen emissions from natural gas fired, water injected, turbines. The catalyst oxidizes 

carbon-monoxide (CO) to carbon-dioxide (CO2), and nitric oxide (NO) to nitrogendioxide (NO2). The CO2 is exhausted while the NO2 absorbs onto the catalyst to form 

potassium nitrites (KNO2) and potassium nitrates (KNO3). Dilute hydrogen gas is passed 

periodically across the surface of the catalyst to regenerate the K2CO3 coating. The 

regeneration cycle converts the KNO2 and KNO3 to K2CO3, water, and elemental 

nitrogen. The K2CO3 is thereby made available for further absorption and the water and 

nitrogen are exhausted.12

5. Selective Catalytic Reduction (SCR) 

An SCR control system is a method for converting NOx generated from the combustion 

turbine to nitrogen (N2) and water by reaction with ammonia (NH3) in the presence of a 

catalyst. NH3 is vaporized and injected in the flue gas upstream of the catalyst, which, when 

passing over the catalyst, results in the following dominant chemical reactions. 

4NO + 4NH3 + O2 → 4N2 + 6H2O 

2NO2 + 4NH3 + O2 → 3N2 + 6H2O 

NH3 is added in slight excess in order to minimize the NOx emissions. The excess NH3 that 

remains unreacted is emitted from the stack and is referred to as ―ammonia slip.‖ In this 

application, NH3 slip is expected to be ≤ 2 ppm at 15% O2 while firing either natural gas or 

ULSD/B20. 

Step 2

Under this step, EPA reviews all of the technologies identified in step 1 and eliminates any 

technology the Agency determines is technologically infeasible for this project. 

1. Catalytic Combustion/XONON

EPA conducted a search to determine if this technology can be used for this project. The 

only literature the Agency was able to find in its search is the application of this technology 

on a 1.4 MW gas turbine. The literature further states multiple combustors would be 

 

11 SCONOx has since been renamed EMx by its manufacturer. We use the more widely known name for consistency 

with earlier documents. 

12 Excerpt from the California Environmental Technology Certification Program 
16

needed for larger turbines such as a 6.5 MW unit. The Agency did not find any evidence 

this technology is technically feasible for this project and we concur with the Applicant’s 

findings which eliminated this technology in step 2. EPA is eliminating this technology 

from further analysis. 

2. SCONOx 

In its November 24, 2008 letter, PVEC states SCONOx is not technically feasible for this 

project since the technology has not been demonstrated for a turbine source as large as this 

project. On December 20, 1999, the Regional Administrator for EPA Region I sent a letter 

to the Connecticut DEP Commissioner stating SCONOx is technically feasible for large 

combined-cycle turbine projects and therefore is subject to a full BACT evaluation. 

Although PVEC’s position regarding the technical feasibility of SCONOx has not changed, 

PVEC submitted additional information regarding this technology in its July 12, 2011 letter 

to EPA. For purposes of Step 2 of this BACT analysis, EPA views SCONOx as technically 

feasible at this project. 

3. Use of DLN when burning ULSD

In its July 12, 2011 letter, PVEC submitted information indicating that the DLN technology 

cannot be used for liquid fuels due to flame instability. EPA concurs with this statement 

and has eliminated using DLN when burning ULSD from further analysis. (However, DLN 

remains an option when burning natural gas.) 

4. Use of water/steam injection when burning natural gas

The purpose of water/steam injection and DLN is the lowering of the combustion 

temperature to minimize formation of NOx. The combination of using both DLN and 

water/steam injection is not feasible since the technologies use different mechanisms for 

reducing the combustion temperature, thereby reducing NOx emissions. EPA concurs with 

PVEC that the use of water/steam injection in combination of DLN when burning natural 

gas is technically infeasible and has eliminated using water injection when burning natural 

gas from further analysis.. 

Step 3

Under this step, technologies, both individual and combination, are listed in order of the most 

effective to least effective. 

1. SCR, in combination with DLN when burning natural gas and water injection when burning 

ULSD, is effective in reducing NOx emission to 2 ppm at 15% O2.

2. SCONOx

There appears to be only one BACT analysis that determined that SCONOx was BACT for 

a large combined cycle turbine. However, the accompanying permit for the facility, Elk 
17

Hills Power in California, allowed the use of SCR or SCONOx to meet a permit limit of 2.5 

ppm, and the actual technology that was installed in that case was SCR. 

A much smaller unit (43 MWh) at Redding Power Plant in California, was permitted with a 

2.0 ppmdemonstration limit using SCONOx. In a letter dated June 23, 2005 from the 

Shasta County Air Quality Management District (Shasta County AQMD) to the Redding 

Electric Utility, however, it was determined that the unit could not meet the demonstration 

limit and, as a result, the limit was revised to 2.5 ppm. Based on these two examples, it 

appears SCONOx has been demonstrated to achieve only 2.5 ppm and we are therefore 

evaluating it at this limit. 

Step 4

EPA must consider the economic, environmental, and energy impacts between the technologies. 

1. Energy Impact – The parasitic load (i.e., energy wasted operating the control technology 

itself) between SCONOx and SCR is virtually the same and therefore has no impact on the 

BACT selection. DLN and water injection were not analyzed since these technologies 

would be used in conjunction with either control technology. 

2. Environmental Impact - SCONOx has an environmental benefit when compared to SCR 

because ammonia is not used in the process. In the SCR, ammonia reacts with NOx to 

create nitrogen. However, as with most chemical reactions, there could be byproducts, 

including ammonia sulfate and ammonia, due to injecting slightly more ammonia than is 

required for the chemical reaction. In the July 12, 2011 letter, PVEC estimated ammonium 

sulfates and ammonium nitrates will contribute to 57 % of the PM2.5 emissions when firing 

natural gas and 15 % of the PM2.5 emissions when firing ULSD with an SCR. SCONOx

avoids this problem. Therefore, EPA determines SCONOx has a smaller environmental 

impact than SCR. 

Even with SCR, however, the creation of ammonia sulfate can be limited through the use of 

low sulfur containing fuels. Excess ammonia is limited through the use of automatic 

process controllers which inject the rate of ammonia based on the amount of NOx in the 

exhaust. PVEC will minimize the sulfur content in the fuels by using only natural gas and 

ULSD. As explained further in the BACT discussion regarding PM10/PM2.5 emissions, 

ULSD contains the lowest amount of sulfur in commercially available fuel oils. EP A has 

concluded PVEC has minimized the environmental impact from using SCR by using fuels 

with low sulfur content and the use of controllers to minimize ammonia emissions. 

3. Economic Impact – In this section, EPA takes into account cost differences between 

technologies. A technology can be eliminated in this section if EPA determines the cost, 

usually based on a dollar per ton of pollutant removed, is determined to be outside the 

normal cost for controls meeting BACT. 

In the July 12, 2011 letter, PVEC stated the installation of SCONOx is at least five times 

higher than SCR. For a similar size project in Florida, it was determined the incremental 
18

cost of SCONOx was 21 million dollars. Operational costs are also significantly higher 

because SCONOx uses a catalyst made from platinum versus a base metal catalyst in the 

SCR system. These statements were supported by the only vendor of the SCONOx

technology, EmeraChem. Since SCONOx has not been proven to remove additional NOx

versus SCR, the additional cost for installation and operation of SCONOx results in an 

infinite incremental cost since the denominator in such a calculation is zero. 

Step 5

At this step EPA determines which controls or methods identified through the first 4 steps 

constitute BACT for this project. Further, EPA develops the appropriate permit terms and 

conditions to ensure BACT is meet during all operational times. 

EPA has determined SCR with the use of dry low NOx burners when firing natural gas and the use 

of SCR with water injection when firing ULSD meet BACT for minimizing NOx emissions for this 

project. The costs for applying SCONOx to reduce the environmental impact of the SCR system is 

well outside the range of controls determined to be cost-effective in previous BACT 

determinations. Furthermore, the adverse environmental impact of SCR (from excess ammonia 

byproduct emissions) will be minimized by use of low sulfur fuels and automatic process 

controllers. With the use of SCR and thermal reducing NOx formation technology, EPA is 

proposing setting the NOx BACT emission limit at the stack at 2.0 ppm @ 15% O2 when firing 

natural gas and 5.0 ppm @ 15% O2 when firing ULSD/B20 (except during startup and shutdown 

operations which are addressed later in this document). 

CO

CO emissions are formed due to incomplete combustion of the fuel. These emissions are 

typically higher during transient and low load operating conditions. Control technologies used to 

minimize CO emissions include state-of-the-art combustion technology, add-on oxidation 

catalyst systems, and establishing minimum load restrictions. 

Step 1

1. SCONOx: In addition to removing NOx, this control also removes CO by converting it 

into CO2 through the oxidation process. 

2. Optimize combustor design and configuration to minimize the creation of CO. 

3. Oxidation catalyst: Located in the HRSG, PVEC proposes to install a catalyst which is 

expected to remove greater than 90% of the CO in the exhaust stream. 
19

Step 2

 All technologies identified in step 1 were deemed technically feasible for this project. 

Step 3

The effectiveness in removing CO emissions is the same for SCONOx and the CO 

catalyst. Optimizing combustor design and configuration will apply regardless of which 

add-on pollution control technology is determined as BACT. 

Step 4 

1. Environmental Impact – For this facility, there is no difference in collateral adverse 

impact on the environment between a CO catalyst and SCONOx technology. 

2. Energy Impact - The parasitic load between SCONOx and the CO catalyst is virtually 

the same and therefore has no impact on the BACT selection. 

3. Economic Impact – PVEC estimated the cost of SCONOx for removing CO emissions 

was $60,000/ton on average and is considered well outside the range of controls 

determined to be cost-effective in previous BACT determinations. 

Step 5

EPA has determined the use of a CO catalyst and optimizing the unit’s design and operations, 

meets BACT for minimizing CO for this project. With these emission controls, EPA is proposing 

setting the CO BACT emission limit at the stack at 2.0 ppm @ 15% O2 when firing natural gas 

and 6.0 ppm @ 15% O2 when firing ULSD/B20 (except during startup and shutdown operations 

which are addressed later in this document). 

PM10/PM2.5

PM10 and PM2.5 from fuel combustion is primarily the result of non-combustible constituents 

(ash) in the fuel and sulfates. For combustion turbines, all PM is typically less than 10 microns 

in diameter (PM10). The emissions of fine particulate matter (PM2.5) from the turbine have been 

conservatively assumed to be equal to the emissions of PM10.

This discussion forgoes specifically identifying each individual step of the BACT process since 

add-on controls to minimize PM10/PM2.5 emissions are not available. Add-on Control devices 

for controlling PM10/PM2.5 emissions from stationary sources, such as fabric filters, wet 

scrubbers, or electrostatic precipitators, create back pressure which adversely affects the 

turbine’s operations. 

Particulate emission control is achieved at the source by efficiently burning low ash and low sulfur 

fuel. PVEC proposed using natural gas and being allowed to burn ULSD/B20 for up to 1440 hours at 

their discretion. The use of these fuels would be combined with state-of-the-art combustion 
20

technology and operating controls, to provide the most stringent degree of particulate emissions 

control available for combustion turbines. As previously discussed in the section ULSD versus natural 

gas, EPA has determined to limit PVEC’s ability to burn ULSD to a specific list of conditions and to 

never use ULSD for more than 1440 hours in any 365 consecutive day period. 

The use of natural gas as the primary fuel, limited use of ULSD/B20 as the back-up fuel for 

periods when natural gas in unavailable or too expensive, and proper combustion are the 

proposed controls for PM10 and PM2.5 BACT. With these emission controls, EPA is proposing 

setting the PM10 and PM2.5 BACT emission limit at 0.0040 lb/MMBtu heat input firing natural gas 

and 0.014 lb/MMBtu while firing ULSD/B20. To further control emissions, EPA is limiting the 

amount of ULSD combustion as discussed above. All of these PM10 and PM2.5 emission limits 

are based on the applicable stack test since the proposed permit is not requiring a continuous 

emission monitor for measuring PM10 and PM2.5 emissions. PM10 and PM2.5 emissions are fairly 

consistent when operating a combined cycle turbine. Operators of turbines are very conscious 

about particulate emissions since these emissions cause damage to the turbine blades. 

Sulfuric Acid Mist

Sulfuric acid mist is formed from oxidation of sulfur in fuel. The only means for controlling sulfuric 

acid mist emissions from PVEC is to limit the sulfur content of the fuel. Because this is the only 

method to minimize sulfuric acid mist, EPA is not specifically identifying each step of the BACT 

analysis. 

Natural gas as the primary fuel, with its natural low sulfur content, is the cleanest, naturally occurring 

fossil fuel. To minimize sulfuric acid mist emissions during fuel oil combustion, EPA is proposing 

to require PVEC to use ULSD/B20 with a sulfur content of 15 ppm by weight or less. These fuels 

have the lowest sulfur content commercially available for fuel oil. As stated earlier, EPA is also 

proposing to limit the amount of ULSD PVEC can burn. The use of these fuels result in an 

emission limit of 0.0018 lb/MMBtu when burning ULSD and 0.0019 lbs/MMBtu when burning 

natural gas. 

Greenhouse Gases

Greenhouse gases for PSD permitting is the aggregate of six pollutants: carbon dioxide, 

methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. Since 

each pollutant has a different effect on global warming, PSD applicability is based on a carbon 

dioxide equivalent (CO2e), determined by multiplying each pollutant by its global warming 

potential. Like other combustion sources, the main constituent of greenhouse gases for a 

combined cycle turbine is carbon dioxide. For this combined cycle turbine, carbon dioxide 

constitutes 98.5% of greenhouse gases on a CO2e basis. Nitrous oxide and methane make up the 

other 1.5 % of greenhouse gases from the combined cycle turbine on a CO2e basis. 
21

Step 1

1. Carbon capture and storage: This technology is available for large fossil-fuel fired power 

plants13 and has been identified in Step 1 as an add-on control for reducing greenhouse 

gas emissions. 

2. Energy efficiency: PVEC has proposed the use of a combined cycle gas turbine, which is 

more energy efficient than a simple cycle turbine. PVEC’s letter dated March 9, 2011 

identified combined cycle turbines from three of the major vendors. In its July 12, 2011 

letter, PVEC clarified the turbines identified in the March letter are the most energy 

efficient models commercially available for a 430 MW size facility at this time from 

these vendors. For combustion units, efficiency can be measured by the heat rate, which 

for an electric generating unit can be expressed as Btu of the fuel combusted divided by 

kWh of electricity produced (Btu/kWh). The lower the overall numbers the less heat 

needed to produce a unit of electricity. PVEC identified the following models: 

a. GE model no. MS7001FB, lower heat rate14 of 5,950 Btu/kWh. 

b. GE model no. MS7001FA, lower heat rate of 6,090 Btu/kWh. 

c. Siemens model no. SCC6-5000F, lower heat rate of 5,990 Btu/kWh. 

d. Proposed project using a Mitsubishi model no. 501G and water cooling, lower 

heat rate of 5,948 Btu/kWh. 

e. EPA identified Mitsubishi model no. MHI501J. This turbine is expected to have a 

heat rate lower than the 501G model. 

Since age and ambient conditions will affect efficiency, the heat rate numbers presented 

above are used to compare the efficiency between turbine models and do not translate 

directly into permit limitations. 

Step 2

1. Carbon capture and storage: In its letters dated March 9, 2011 and July 12, 2011, PVEC 

states this control option is not technically feasible due to a number of factors including 

the lack of a nearby storage facility for captured CO2. According to the US Department 

of Energy, the nearest storage site to PVEC’s plant is in New York15. The terrain between 

PVEC and a potential storage site is also problematic due to a pipeline having to traverse 

the Berkshire Mountains, and probably the Hudson River. The offsite logistical barriers 

of constructing such a pipeline (e.g., land acquisition, permitting, liability, etc.) 

enormously complicates the technology of CCS and may arguably eliminate the 

technology because it is technically infeasible for this project. Putting aside the technical 

infeasibility issue, EPA and PVEC continued to include CCS in the GHG BACT analysis. 

 

13 ―PSD and Title V Permitting Guidance for Greenhouse Gases‖, March 2011, available at 

http://www.epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf, page 32.

14 Lower heat rate is determined by subtracting the heat of vaporization of the water from the higher heating value.

15 Although the map of the Saline formation contained in the docket does not identify specific formations, the state 

border is approximately 40 miles away.
22

2. Energy efficiency: PVEC did not identify any technical feasibility issues between the 

different turbine models since all identified models are currently available for purchase 

within the United States. In response to EPA’s queries regarding another turbine model 

from Mitsubishi, MHI501J, PVEC determined that this model is under development and 

currently unavailable in this country, and therefore is not technically feasible. EPA agrees 

with PVEC’s statement regarding Mitsubishi MHI501J availability and has eliminated 

this turbine from further analysis. 

Step 3

1. Capture and storage of CO2 emissions is the most effective technology for reducing 

greenhouse gas emissions for this project. 

2. Regarding energy efficiency, PVEC is requesting a permit for the turbine with the lowest 

heat rate (the Mitsubishi 501G), and therefore most energy efficient, among 

commercially available turbines in its class. The GE MS7001FB turbine’s heat rate is 

only slightly less than the Mitsubishi 501G’s and can be ranked equivalently for control 

effectiveness. The GE MS7001FA and Siemens SCC6-5000F turbine models are notably 

less energy efficient. 

Step 4

1. Energy and environmental impact - The capture, control, and storage of CO2 emissions 

would increase the environmental impact for this project due to the control equipment. In 

order to capture CO2 emissions from a combustion source, a facility in West Virginia 

used a chilled ammonium carbonate system to absorb CO2 and create ammonium 

bicarbonate. The resulting ammonium bicarbonate is then converted back to ammonium 

carbonate in a regenerator and is reused to repeat the process. The flue gas, cleaned of 

CO2, flows back to the stack and the captured CO2 is sent for storage in an underground 

reservoir. 

The energy requirement to operate such a system – often referred to as ―parasitic load‖ –

is very large. In a June 2010 report, the General Accounting Office estimated the 

parasitic load to capture and store CO2 emissions is between 21-32%. Electrical 

generating plants similar to PVEC in New England operate on an intermittent basis and 

usually are not base-loaded. Under the current power structure in New England, it is 

likely that the electricity used by the CCS system would need to be created by other fossil 

fuel fired electric generating plants, many of which are less energy efficient (and may 

emit higher amounts of conventional pollutants and GHG/MWh) than PVEC’s proposed 

project. 

The installation of a new pipeline from PVEC to the nearest CO2 storage site would also 

have an environmental impact as the pipeline installation tries to avoid ecologically 

sensitive areas. Neither EPA nor PVEC quantified the additional environmental impact 

from the increase of electric generating facilities to power the parasitic load or from the 

construction and operation of a new pipeline to transfer CO2 emissions to a storage site. 
23

2. Economic impact - PVEC estimated the cost to construct a pipeline to carry the captured 

CO2 emissions to a storage site at one to three million dollars per mile. PVEC did not 

estimate any potential economic penalty due to projects delays caused while PVEC 

obtains the rights and land to build a CO2 pipeline. As stated in step 2, the nearest storage 

site to PVEC’s plant is somewhere in New York which is approximately 40 miles away. 

Due to the terrain between PVEC’s facility and New York State, the cost of the pipeline 

would probably be on the higher end of the estimate At $3 million/mile, the cost just to 

construct a pipeline would be at least $120 million dollars, and probably much higher 

because it is very unlikely a storage site is right at the state border. Because PVEC 

contends that the cost of just the pipeline exceeds what is a reasonable cost for BACT, 

PVEC did not estimate the cost for the carbon capture system. 

 

In a fact sheet, updated in February 2011, the Department of Energy estimated the cost of 

capturing CO2 at $150/ton of carbon. In another study by the National Energy 

Technology Laboratory, the cost to capture CO2 and compress it is $240 million dollars 

for a combined cycle turbine with a gross electrical output of 564 MWh. Based on this 

later study, it is reasonable to assume the capital cost of installing a system for capturing 

and compressing CO2 emissions is $183 million 

Due to the energy, environmental and economic impacts of installing and operating CCS for 

PVEC’s proposed project, EPA has eliminated this technology as greenhouse gas BACT for this 

project. 

Step 5

EPA has determined the installation and operation of PVEC’s proposed combined cycle turbine 

project as meeting BACT for greenhouse gases. 

With determining BACT as an energy efficient model for the combined cycle turbine, permit 

conditions must be developed to ensure PVEC installs an energy efficient turbine and will 

continue to operate the turbine in an energy efficient manner. To ensure these two goals are met, 

EPA is proposing two emission limits for greenhouse gases, along with appropriate monitoring 

recordkeeping, and reporting. 

First, to determine an efficient combined cycle turbine is installed, EPA has developed an 

emission limit in lbs of GHG/MWh going to the electrical grid that must be met during the initial 

stack test. Since weather conditions, which affect efficiency during a stack test, cannot be 

predicted at this time, the emission limit is being set using International Organization for 

Standardization (ISO) conditions. ISO 3977-2 sets the standard conditions at 59 oF, 14.7 psia, 

and 60 % humidity. The weather conditions during the stack test will be corrected to these ISO 

values. 
24

Based on the design low heat release rate of 5,948 Btu/kWhgrid, a CO2 emission factor of 116 

lb/MMBtu, and the fact that 98.5 % of all GHG emissions on a CO2e basis are CO2,

16 EPA 

calculated an emission rate of 776 lbs CO2e/MWhgrid. To determine the emission limit which 

must be demonstrated during PVEC’s initial stack test, accuracy in measuring CO2 and the 

correction curves used to convert stack tests results to ISO conditions must be taken into account. 

Based on these factors, which are outside of PVEC’s control, EPA has calculated an emission 

limit of 825 lbs CO2e/MWhgrid. Since a turbine’s efficiency will degrade with time and fluctuate 

due to ambient conditions, the emission limit of 825 lbs CO2e/MWhgrid will only apply during 

the initial stack test. 

The greenhouse gas emission limit established for installation cannot feasibly be used for 

continuous operations due to a number of factors such as partial load, startups, shutdowns, and 

weather conditions which all affect the turbine’s efficiency. To ensure PVEC operates its facility 

to minimize greenhouse gases, EPA is proposing to establish an ongoing CO2e emission 

limit/MWh to the electric grid. Due to the factors previously listed affecting efficiency, the 

emission limit shall be determined by averaging the emissions for each day and averaging the 

day’s emissions with the previous 364 days of emissions. These factors, along with system 

degradation, will also cause fluctuations with the combined cycle turbine efficiency. 

EPA expects a decrease in efficiency of 2.5% over time even for a well-operated turbine.17 In its 

March 9, 2011 application supplement, PVEC claimed a performance margin of 6%. EPA 

understands the performance margin addresses factors affecting the efficiency which cannot be 

controlled by PVEC such as ambient temperature. The actual effect of temperature on a 

combined cycle turbine will vary depending on the turbine’s design. The variation can be as 

much as 10%.18 Based on the information PVEC provided and on EPA’s own research regarding 

unavoidable decreases in efficiency and variability of performance under a reasonable range of 

conditions, EPA has determined that BACT is met by an emissions limit that is 8.5% higher than 

the corrected value which must be met during the initial test. EPA is proposing an ongoing 

emission limit of 895 lbs CO2e/MWhgrid averaged over each 365 consecutive day period. 

Turbine’s startup and shutdown operations

During startup and shutdown operations,19 gas turbines experience operational fluctuations 

resulting in increases of NOx and CO emissions. In addition, minimum operating temperature 

for the SCR catalyst must be obtained before ammonia can be injected to control NOx emissions. 

 

16 EPA used emission factors for N2O and CH4 supplied by PVEC instead of AP-42 because the vendor specific 

emission factors are usually better for estimating emissions. Note, emission factors for these pollutants provided by 

PVEC are higher than the presumptive emission factors in 40 CFR part 98, subpart C. 

17 ―Combined-cycle gas & steam turbine power plants ‖ by Rolf Kehlhofer, Bert Rukes, Frank Hannemann, Franz 

Stirnimann, page 242.

18 ―Thermodynamic performance analysis of gas-turbine power-plant‖ by M. M. Rahman, Thamir K. Ibrahim, and 

Ahmed N. Abdalla available at http://www.academicjournals.org/IJPS/PDF/pdf2011/18Jul/Rahman%20et%20al.pdf

19 Unit startup commences when fuel is first ignited and shall not exceed 2.0 hours for a warm start and 5.0 hours for 

a cold start. Cold startups are defined as occurring after a period of greater than 24 hours of turbine shutdown, and 

warm startups are defined as occurring 24 hours or less since turbine shutdown. Shutdown is defined as the time 
25

BACT for NOx and CO during these transient operations is determined to be good engineering 

practices to minimize emissions and in accordance with manufacturer’s recommendations. 

Emission reductions due to add-on controls do not occur since the controls do not function until a 

minimum exhaust temperature is maintained. The emission rates in the draft permit will be 

higher for both CO and NOx on a concentration and mass basis. See Tables II and III. Emission 

rates are also higher when burning ULSD instead of natural gas. The attached permit has been 

drafted to take these facts into account. 

The emission limits for all other pollutants regulated under the permit (i.e., besides NOx and CO) 

apply at all times, including during startup and shutdown. 

Table II 

Startup and Shutdown Emission Limits – Natural Gas 

(Averaging time is 1 hour) 

Pollutant Concentration Limit Mass Limit 

Nitrogen Oxides 40 ppmvd @ 15%O2

62.0 lb/hr

Carbon Monoxide

1100 ppmvd @ 15%O2 for 

first 60 minutes of startup 

and for shutdowns

2000 lb/hr

Carbon Monoxide

100 ppmvd @ 15%O2

after first 60 minutes of 

startup and shutdown

400 lb/hr

Table III

Startup and Shutdown Emission Limits – ULSD 

(Averaging time is 1 hour) 

Pollutant Concentration Limit Mass Limit 

Nitrogen Oxides 60 ppmvd @ 15%O2

99 lb/hr

Carbon Monoxide

4000 ppmvd @ 15%O2 for 

first 60 minutes of startup 

and for shutdowns

6000 lb/hr

Carbon Monoxide

250 ppmvd @ 15%O2

after first 60 minutes of 

startup and shutdown

800 lb/hr

Although CO emissions during these transient operations are higher than other similar sources 

that have recently been issued a PSD permit, the NOx emissions for PVEC are lower than the 

other permits. To control emissions during transient times, a facility can only rely on good 

combustion practices to minimize emissions. Pollution control equipment that removes CO and 

NOx emissions from the gas stream is not operational during startup and shutdown due to the low 

exhaust temperature. When good combustion practices are relied on, there is a trade-off between 

 

when the turbine operation is between minimum sustained operating load and flame-out in the turbine combustor 

occurs. Shutdown shall not exceed 1.0 hour. 
26

CO and NOx emissions. A decrease in one pollutant is usually offset by an increase in the other 

pollutant. As noted earlier, PVEC’s proposed location is in a nonattainment area for ozone and 

attainment for CO. Since NOx contributes to ozone formation, it is more important to control 

NOx emissions than CO emissions. 

In an e-mail to EPA dated February 8, 2010, PVEC’s consultant proposed CO and NOx emission 

limits for startup and shutdown. The emission limits proposed by PVEC for CO are higher than 

what EPA has proposed in the PSD permit. PVEC proposed CO emission rates when firing 

natural gas of 3,700 ppmvd at 15% O2 and 7410 lbs/hr. When firing ULSD, PVEC proposed CO 

emission limits of 10,000 ppmvd at 15% O2 and 13,341 lbs/hr. PVEC did not supply supporting 

information for the proposed emission limits other than stating the limits are based on data from 

the manufacturer.20

 EPA reviewed the RBLC clearinghouse and a database on combined cycle 

turbines maintained by Region IV and found scant information regarding short term emission 

limits during startup and shutdown. 

EPA has based its determination for the proposed CO emission limits on two applications for 

modifications to existing PSD permits. The applications were submitted to EP A on March 31, 

2009 by Boston Generating, LLC. EPA determined it is appropriate to use the information from 

these applications because the turbines operated by Boston Generating, LLC are similar to the 

model proposed for the PVEC facility (different versions of Mitsubishi Heavy Industries Model 

501G).21 EPA was informed by Boston Generating, LLC, that the proposed emission limits for 

Mystic and Fore River Stations are based on actual operations of its six turbines from 2007 and 

2008. EPA has determined that given the information on the record, the emission limits in 

Tables II and III meet BACT during startup and shut down operations. 

Cooling Water Tower 

Out of the five pollutants regulated by this proposed PSD permit, only PM10/PM2.5 are emitted 

from the cooling water tower. A cooling water tower emits PM10 and PM2.5 due to the particle 

entrainment within escaped water droplets. Therefore, to control PM10 and PM2.5 emissions, 

PVEC will install high efficiency drift eliminators that limit the amount of escaped water 

droplets to 0.0005 % of the total recirculating water. These eliminators will limit the PM10 and 

 

20 Regarding vendor guarantees, In re Masonite Corp., 5 E.A.D. 551, 562 n.12 (1994), the Environmental Appeals 

Board, citing the 1990 Draft NSR Workshop Manual, has explained: 

On the subject of vendor guarantees, EPA's New Source Review Workshop Manual at B-20 states: 

Vendor guarantees may provide an indication of commercial availability and the technical 

feasibility of a control technique and could contribute to a determination of technical feasibility or 

technical infeasibility, depending on circumstances. However, EPA does not consider a vendor 

guarantee alone to be sufficient justification that a control option will work. Conversely, lack of a 

vendor guarantee by itself does not present sufficient justification that a control option or 

emissions limit is technically infeasible. Generally, decisions about technical feasibility will be 

based on chemical and engineering analyses (as discussed above) in conjunction with information 

about vendor guarantees. 

21 In an e-mail dated October 27, 2010 from ESS to Donald Dahl, ESS stated the proposed turbine for the Facility 

has been modified by Mitsubishi. ESS stated that the new model is more efficient and lowers NOx and PM 

emissions. However, no evidence was provided about the effects these modifications would have on startup and 

shutdown emissions for CO compared to the turbines installed by Boston Generating LLC.
27

PM2.5 emissions to 0.01 lbs/hr. This emission rate is consistent with other recent BACT 

determinations.22

Auxiliary Boiler

As part of this project, PVEC is installing a 21 MMBtu boiler, known as the auxiliary boiler. 

Since this is also a combustion unit, this unit will emit all of the 5 pollutants regulated by this 

permit. To minimize emissions, PVEC proposed limiting the boiler’s operation to 1100 

operating hours in any 12 month period and only combust natural gas. Add-on controls for 

reducing NOx, H2SO4, PM10/PM2.5, and CO for such an emission unit are not economical since 

the boiler is limited to 0.8 tons per year of all of these CAA pollutants based on the limit on 

operations. Given these facts, EPA has not listed out the five step BACT analysis for these 

pollutants. EPA is proposing the following emission limits for the auxiliary boiler: 

Table IV

Emission Limits – Natural Gas 

Pollutant Concentration Limit

Nitrogen Oxide 0.029 lbs/MMBtu

Sulfuric Acid Mist 0.0005 lb/MMBtu

PM10/PM2.5

0.0048 lb/MMBtu

filterable + 

condensables

Carbon Monoxide 0.037 lbs/MMBtu

To ensure compliance with the modeling assumptions that PVEC used as part of its 

demonstration that the NAAQS will be attained, EPA is also proposing to limit the heat 

input to the auxiliary boiler to 21 MMBtu/hr. 

Finally, with respect to GHGs, PVEC researched the feasibility of adding energy 

efficiency measures to the auxiliary boiler such as an air preheater. As discussed above, 

CCS is not cost-effective for this facility. Since the auxiliary boiler is only used during 

startups until the HRSG can produce steam, the exhaust gas temperature would not be 

significant enough to adequately transfer lost heat to the combustion air system. Air 

preheaters are mainly installed on boilers that are intended to be used in a steady-state 

mode. The auxiliary boiler for this project is not designed nor intended to be operated in 

a steady state mode. EPA concurs with PVEC and has determined efficient combustion 

controls installed on the auxiliary boiler meets BACT for greenhouse gases. 

Consequently, EPA is proposing that BACT for GHGs from the auxiliary boiler be the 

heat and hours-of-operation limits identified above, and an annual boiler tune-up. 

 

22 See PSD permit for the construction of new Cooling Towers at Dominion Energy, Brayton Point Facility, April 2, 

2009. URL: http://www.epa.gov/region1/communities/pdf/braytonpoint/CoolingTowerPermit.pdf
28

Emergency Generator and Fire Pump

PVEC has applied to install a 2,174 KWh diesel generator to be used in case of a power outage at 

the plant and a 270 hp fire pump. 

Unlike other combustion equipment (e.g., CTs and boilers), new engines are required to be 

certified in compliance with NSPS requirements, including emission limits, upon purchase. 

Different types of engines have different emission requirements based on the type of engine 

being purchased (emergency engine, emergency fire pump engine, or non-emergency engine). 

Engine manufacturers may need to employ some of the control technologies identified above in 

order to comply with the NSPS emission limits, depending on the type of engine and the 

applicable limits. The applicant is proposing to construct an emergency engine and an 

emergency fire pump engine. As a result, to comply with NSPS the applicant must purchase 

engines that meet the emission requirements for emergency engines and emergency fire pump 

engines. 

PVEC proposed the requirements of 40 CFR part 60, subpart IIII, the NSPS standard for internal 

combustion engines, as BACT. Forty CFR 60.4202(a)(2) requires emergency engines to meet 

the model year 2007’s emission requirements in 40 CFR 89.112 and 40 CFR 89.113. Table I of 

40 CFR 89.112 requires the engines to meet Tier 2 requirements which are: 

a. 6.4 g/KWhour of NOx and Non-methane Hydrocarbon (NMHC) combined 

b. 0.20 g/KWhour of PM10/PM2.5

c. 3.6 g/KWhour of CO

However, EPA has identified the use of a Tier 4 generator set (also known as an engine) as being 

commercially available in 2011. As such the BACT analysis must include a comparison 

between a TIER 2 and a TIER 4 engine for PVEC intended use. 

Emissions are significantly reduced when using a Tier 4 engine versus a Tier 2 engine. The 

reduction is almost 90% for NOx and 50 % for fine particulates. To achieve these emission 

limits, a TIER 4 engine must add post combustion controls, such as urea injection. In order for 

the post controls to be fully functional, a minimum temperature must be maintained (usually 

around 650 oF). PVEC is installing its engine for emergency purposes only so it can safely bring 

the facility off line in case the plant loses electricity. On most occasions, the emergency 

generator will only be operated for a short period of time for maintenance checks and readiness 

testing. These short operating periods are not conducive to achieving optimum operation of a 

urea injected control system since the minimum temperature is not achieved. 

It is plausible that if the plant loses electricity, the emergency engine is operated for a period 

long enough to reach minimum temperature for the urea injection system to work. Even in this 

case, the urea system will only operate for a short period of time because the purpose of the 

generator is to safely shutdown the plant, which usually takes several hours, not days. Based on 

information from Caterpillar, the cost difference between a Tier 2 engine and a Tier 4 engine is 

between $350,000-400,000. Amortizing the cost over 20 years, assuming an 8 % interest rate, 
29

results in an annual cost of $40,000. Although emissions are significantly reduced on a 

percentage basis when using a Tier 4 engine, the amount of NOx and PM10/2.5 reduced will 

probably be less than one ton per year given the purpose of the emergency generator. Even 

without estimating the additional operating costs of a Tier 4 engine, costs of using a Tier 4 engine 

to reduce NOx and PM10/2.5 is well outside the range of controls determined to be cost-effective in 

previous BACT determinations. EPA is determining that BACT for the emergency generator is 

to meet EPA’s Tier 2 emission standards for CO, NMHC + NOx, and PM10/2.5, listed above. 

The Fire Pump will be required to meet the emission limits in Table IV of 40 CFR part 60, 

subpart IIII. 

a. 4.0 g/KWhour of NOx and NMHC combined 

b. 0.20 g/KWhour of PM10/PM2.5

Although NMHC (non methane hydrocarbon) is not a pollutant required to be reviewed for 

BACT, the Part 60 standard for emergency generators combines NOx with NMHC into one 

emission limit. A BACT emission limit must be at least as stringent as a 40 CFR parts 60 or 61 

standard. See the definition of Best Available Control Technology at 40 CFR 52.21(b)(12). It 

should be noted Table IV does not specify a specific emission limit for CO for fire pump engines 

of model year 2009 or later with a horsepower between 175 and 300. EPA has determined 

BACT for minimizing CO emissions from the fire pump is implementing the manufacturer’s 

operating specifications. 

A review of EPA’s BACT/LAER Clearinghouse determined that recently permitted emergency 

generators were required to meet emission rates similar to the emission standards found at 40 

CFR part 60. Since the permitted emission limits are the same as the requirements in 40 CFR 

parts 60 and part 63, and these emission limits are similar to other BACT determinations, EPA 

has concluded the proposed emission limits meet BACT requirements. Furthermore, operation 

of the emergency generator is limited to 300 hours in any 12-consecutive month period. 

Since only new engines can meet these emissions limits, and these new engines are more 

efficient than older models, BACT for GHG emissions is met. 

Finally, after considering the environmental impact, EPA is proposing operational limits on the 

emergency generator and fire pump engine: 

Prohibiting operating the emergency generator or fire pump during startup or shutdown. 23

Prohibiting scheduled testing of the emergency generator or fire pump outside of the 

hours of 12:00pm-3:00pm. 

 

23 See page 36, footnote 32.
30

Prohibiting scheduled testing of the emergency generator or fire pump during days when 

the most recent (before scheduled testing) hourly value for NO2 at the nearest ambient 

NO2 air quality monitor in Hampden County operated by the MassDEP exceeds 54 ppb. 24

VII. Monitoring and Testing 

PVEC will install, calibrate, and operate a dedicated continuous emission monitoring system for 

measuring CO, CO2 and NOx emissions from the combined cycle turbine. The system will 

consist of a probe, analyzer, and data acquisition system. The NOx monitoring system shall meet 

the specifications and quality assurance procedures of 40 CFR Part 75. The CO and CO2

monitoring systems will meet the specifications and quality assurance procedures of 40 CFR Part 

60 Appendix B, Performance Specifications 4 and 4A (for CO) and Performance Specification 3 

for CO2. Emission data for CO and NOx will be measured by the analyzer in ppmvd (parts per 

million on a volume and dry basis). This ppmvd data can be directly compared to the permit 

emission limits to determine compliance. 

To obtain NOx, CO2 and CO mass emissions on an hourly basis, PVEC will use EPA methods 

contained in 40 CFR part 75 for NOx and 40 CFR part 60, appendix A, method 19 for CO. 

PVEC will need to measure heat input on an hourly basis and moisture content to convert the 

measured ppmvd data to lbs/hr. 

For determining CO2 mass emissions, PVEC shall use the following equation: 

E = CO2 in lb/hr 

K = 1.14 x 10-3 lb/scf/%CO2

%CO2 is the average percent CO2 in the gas stream for the hour, dry basis 

F8710 is the F-factor for natural gas, dscf/MMBtu 

GCV is the gross calorific value, Btu/dscf 

is the natural gas fuel flow rate, dscf/hr 

PVEC is also required to monitor or keep records of the amount of sulfur in the fuel that is used 

in the combined cycle turbine. 

PVEC is also required to conduct stack tests for PM10 and PM2.5 emissions for both oil and 

natural gas within 180 days after initial start-up of the combined cycle turbine. 

VIII. Endangered Species Act/ESA 

Section 7 of the ESA requires that certain federal actions such as federal PSD permits address the 

protection of endangered species in accordance with the ESA. To comply with the ESA, Region 

1 consulted with the United States Fish and Wildlife Department (FWS)-New England Field 

 

24 See Section XI below.
31

Office web site http://www.fws.gov/newengland/EndangeredSpec-Consultation.htm to determine 

if the proposed permit for PVEC posed any risk to endangered species. Our consultation is 

consistent with the direction EPA received from the FWS in an e-mail on another PSD permit 

EPA drafted. See the file for an e-mail from Anthony Tur of FWS to Phyllis Nelson of EPA 

dated November 20, 2007. 

The website instructs EPA to review a list of endangered species by county and determine if an 

endangered species is located in the county for the permitted facility. PVEC is in Hampden 

County. According to the table on the web site, the only listed endangered species (Small 

Whorled Pogonia) in Hampden County is located in the Town of Southwick. Therefore, it has 

been concluded that the proposed permit revisions do not pose a threat to any endangered or 

proposed endangered species or their habitat in the area subject to FWS jurisdiction, and that no 

further ESA impact analysis is required. The web site directed EPA to print a letter dated January 

3, 2011 and signed by Thomas R. Chapman, Supervisor, New England field Office of the FWS. 

The letter states that no further review is warranted. The file contains a copy of this letter. 

IX. Impact Analysis Based on Modeling 

As part of its application, PVEC submitted a modeling analysis that met the requirements of 40 

CFR part 51, Appendix W. 

In determining a project’s impact, a source usually conducts a screening model to determine if 

there is a significant ambient impact from the proposed project outside the fence line. For most 

NAAQS, EPA has published pollutant levels called significant impact levels (SILs) where 

impacts below the SIL are considered de minimis. The facility’s screening modeling (assuming 

worse case meteorological conditions) from the 2008 application showed all pollutants, except 

CO, were above the SIL at the facility fence line. 25 Therefore, PVEC conducted refined 

modeling for NO2, PM10, and PM2.5. Because CO was below the SIL at the fence line, no 

further modeling was required for CO. 

 

25 PVEC did not submit results from a screening analysis for NO2, instead opting to proceed directly to a refined 

modeling analysis.
32

Table V 

Screening Model Results 

Pollutant Result from screening 

modeling

SIL

NO2 (annual) 32.9 ppb 1 ppb

NO2 (1 hour) Not ascertained 4 ppb26

CO (1 hour) 461 μg/m32000 μg/m3

CO (8 hour) 195 μg/m3500 μg/m3

PM10 24 hour 63.5 μg/m35.0 μg/m3

PM10 annual 16.7 μg/m31.0 μg/m3

PM2.5 24 hour 63.5 μg/m31.2 μg/m3

PM2.5 annual 16.7 μg/m30.3 μg/m3

In order to conduct a refined modeling analysis, the applicant is required to input meteorological 

data relevant to the project area. An applicant can either establish an on-site meteorological 

station to gather one year’s worth of data prior to the application or propose to use five years’ 

worth of meteorological data from a source where the applicant believes data is representative to 

its proposed site. Proximity and terrain are the two main elements taken into account when 

making this determination. In its original application in 2008, PVEC used 1991-1995 

meteorological data from Westover Air Force Base. At the time of the original application this 

was acceptable because in 1996, changes were made to the gathering and coding of 

meteorological data which raised several issues with air dispersion models. Since these changes 

were made, EPA has been identifying and solving issues with the new methods for gathering and 

entering meteorological data. In February 28, 2011, EPA issued a model change bulletin 

(MCB#4) which addressed the remaining issues. As a result, PVEC has submitted a new air 

quality impact analysis, using data from years 2006-2010 and from a different site (Barnes 

Airport in Westfield) which is approximately one mile away from the proposed site. 

Terrain is another factor impacting the selection of representative meteorological data. Based on 

figure 2-1 (USGS Locus Map containing elevation information) in the 2008 application, EPA has 

determined the use of meteorological data from Barnes Airport is acceptable since the terrain is 

similar to the proposed project site. 

At the time of the original application in 2008, EPA had not developed a SIL for PM2.5 so PVEC 

conducted refined modeling for both the 24-hour and annual PM2.5 standard. The 24-hour and 

annual SILs EPA promulgated on October 20, 2010 (75 FR 64864) continue the need for PVEC 

to conduct refined modeling. EPA published SILs for both the 24 hour PM2.5 (1.2 μg/m3) and 

annual PM2.5 (0.3 μg/m3

) which still requires PVEC to conduct a refined modeling analysis that 

is provided below 

 

26 SIL is from EPA Guidance titled ―Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the 

Prevention of Significant Deterioration Program‖ dated June 29, 2010 and is used by EPA until the agency 

formalizes a SIL through rulemaking. 
33

Results from Refined Modeling

Table VI contains the results from the refined modeling. All modeled pollutants, except for 24-

hour PM2.5 and 1-hour NO2 emissions, were below the SIL at the fence line. Since PM2.5 24 hour 

and one hour NO2 emissions were above the SIL, further analysis is required to determine if this 

project would cause or contribute to a NAAQS or increment violation. 

Table VI 

Refined Model Results27

Pollutant Result from refined

modeling

SIL

NO2 (annual) 0.68 ppb 1 ppb

NO2 (1 hour) 57.4 ppb 4 ppb28

PM10 24 hour 3.05 μg/m35.0 μg/m3

PM10 annual 0.106 μg/m31.0 μg/m3

PM2.5 24 hour 2.07 μg/m31.2 μg/m3

PM2.5 annual 0.11 μg/m30.3 μg/m3

PM2.5 

Background concentration

When using results from refined modeling for NAAQS compliance, background concentration 

for the pollutant of concern must be determined either by modeling other sources or monitoring 

representative pollutant levels. There are two ways of determining the background 

concentration. First, the applicant can install an EPA approved ambient monitor to gather 

emission data at the site prior to the application. A second method is to use data from an existing 

ambient monitor which is representative of the ambient conditions for the proposed project. To 

guide applicants, EPA has published significant monitoring concentration (SMC) values for 

different pollutants. For PM2.5 averaged over 24 hours the SMC is 4 μg/m3

. Forty CFR 

52.21(i)(5) allows EPA to exempt a stationary source or modification from the requirement to 

gather site specific data [40 CFR 52.21(m)] if the emission increase from the project is less than 

the SMC value listed at 40 CFR 52.21(i)(5). Given the results from refined monitoring of 2.07 

μg/m3 for PM2.5 averaged over 24 hours and PM10, EPA has determined to exempt this project 

from preconstruction on-site monitoring for PM2.5 emissions. Forty CFR 52.21(m)(2) allows 

EPA to require post construction monitoring as necessary. Since it has been established the 

 

27 The term ―refined model‖ does not apply to the modeling for NO2. The differences between Tables V and VI for 

NO2, besides the more updated meteorological data, is Table VI represents model results using hour-by-hour 

meteorological data.

28 SIL is from EPA Guidance titled ―Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the 

Prevention of Significant Deterioration Program‖ dated June 29, 2010 and is considered to be used by EPA until the 

agency formalizes a SIL through rulemaking. 
34

highest modeled impact from this project is less than the SMC for PM2.5, EPA has determined not 

to require post construction ambient monitoring of PM2.5 emissions.29

Now that it has been established that site specific ambient monitoring is not required, 

background levels of PM2.5 must be determined and a decision must be made whether to require 

PVEC to include emissions from nearby sources. Nearby sources are described in 40 CFR part 

51, Appendix W as follows: 

―Nearby Sources: All sources expected to cause a significant concentration gradient in 

the vicinity of the source or sources under consideration for emission limit(s) should be 

explicitly modeled. The number of such sources is expected to be small except in unusual 

situations. Owing to both the uniqueness of each modeling situation and the large number 

of variables involved in identifying nearby sources, no attempt is made here to 

comprehensively define this term. Rather, identification of nearby sources calls for the 

exercise of professional judgement by the appropriate reviewing authority (paragraph 

3.0(b)). This guidance is not intended to alter the exercise of that judgement or to 

comprehensively define which sources are nearby sources. ‖

The term ―sources‖ in EPA’s modeling guidance refers to point sources of air emissions. Air 

emissions from mobile sources are addressed through the use of ambient air monitors. EPA 

reviewed the latest compilation (2008) of Massachusetts’ emission inventory for all point sources 

of PM2.5 emissions in Hampden County. When determining whether a ―nearby source‖ may 

cause a ―significant concentration gradient‖ for PM2.5, EPA’s modeling reviewer determined it 

would be appropriate to look at 100 tpy sources within one mile of the proposed project and 

1,000 tpy sources within 10 miles. 

The largest source of PM2.5 emissions in Hampden County is Mount Tom Generating Station in 

Holyoke. Mount Tom emitted 44 tons of PM2.5 and 92 tons of PM10 emissions and is 

approximately 9 miles away. There is also John S Lane and Son Company located 

approximately 5 miles away in Westfield which had 12 tons of PM2.5 emissions and 18 tons of 

PM10. There are only 8 sources in Hampden County with PM2.5 emissions above 10 tpy and 10 

sources in Hampden County with PM10 emissions above 10 tons. Based on the emission 

inventory EPA has determined there are no nearby sources expected to cause a significant 

concentration gradient in the area of the proposed project. Therefore, interactive modeling using 

PM2.5 emissions from other sources is not required for this project. 

In determining background levels of PM2.5 emissions, PVEC proposed using ambient monitoring 

data gathered at the Chicopee site (monitor ID 250130008). In EPA’s analysis, the agency 

identified two other ambient monitoring stations, Springfield Liberty Street (monitor ID 

250130016), Springfield 1860 Main Street (monitor ID 250132009)30, within the vicinity of the 

project and based our analysis using emission data from all three ambient monitoring stations. 

 

29 EPA also compared the model impact of 0.68 ppb NO2 on an annual basis to the SMC of 7.5 ppb and determined 

not to require on-site monitoring. The annual standard is used because there is no SMC for the 1-hour NO2 standard 

at this time. See 40 CFR 52.21(i)(5)(iii).

30 Data from an additional continuous emission monitor in Springfield can be obtained from AirNowTech.Org. This 

monitor is not recognized by EPA for determining compliance with the NAAQS. A cursory review in comparing the 
35

The results from the refined modeling (using the average of the maximum modeled 24-hour 

averages across 2006-2010) were added to the most recent design value (years 2008-2010) for 

each ambient monitoring station to determine if the emissions from PVEC would contribute to a 

violation of the PM2.5 NAAQS averaged over 24 hours (35 μg/m3)

31. The background level for 

both of the Springfield monitoring stations is 27 μg/m3, while the design value for the Chicopee 

monitoring station is 25 μg/m3. When the background levels are added to the results from the 

modeling, the highest level is 29.07 μg/m3 which is below the NAAQS level of 35.0 μg/m3. 

In addition to demonstrating compliance with the NAAQS, PVEC is required to demonstrate its 

emissions will not exceed available increment. States have the flexibility in how their state is 

divided geographically for determining and tracking PSD increment. For PM2.5, increment is 

tracked on the county wide basis in Massachusetts. On October 20, 2010, EPA published an 

increment standard for PM2.5, averaged over both annual and 24-hour basis. In this rulemaking, 

EPA established the major source baseline date of October 20, 2010 and a requirement that all 

PSD sources required to address PM2.5 emissions demonstrate they will not consume more than 

the available increment. PVEC will be the first major source permitted after these dates and 

therefore will consume PM2.5 increment and will need to demonstrate its modeled impact is less 

than the available increment. Because there are no other PSD permitted sources within 

Hampden County after October 20, 2010, and the minor source baseline date is triggered when 

EPA deems PVEC’s PSD application is complete, 100 % of the increment is available to PVEC. 

The increment for a Class II area (which is the Class Hampden County is currently designated) is 

9 μg/m3. PVEC’s maximum modeled impact is 2.07 μg/m

3

, consuming 23% of the available 

increment. EPA has determined there is sufficient available increment for this project. 

When analyzing the impact of PM2.5 emissions, secondary formation of the pollutant should be 

addressed. Secondary emissions are formed when pollutants emitted by the source react with 

other ambient air pollutants. The model used by PVEC to demonstrate impacts from PM2.5

emissions cannot address precursor emissions and secondary PM2.5 formation and impacts. At 

this time, no Appendix W point source model can provide this data. EPA does not have a model 

which can adequately address these complex chemical reactions. That said, secondary PM2.5

emissions from PVEC will form well away from the source, not locally, because time is required 

for the secondary PM2.5 to form. As the plume of direct PM2.5 and precursor emissions from 

PVEC moves away from the facility, dispersion results in diluting the pollutants even as they 

form. 

The impact these secondary emissions would have within the vicinity of the proposed site is de 

minimis. These particles, if they impact an area within the United States, will be part of the 

background levels measured by existing downwind monitors. In lieu of an available method in 

calculating the impact of secondary emissions from this facility and the fact that once secondary 

PM2.5 emissions do impact the surface, such impacts will be at a considerable distance from the 

facility, EPA reviewed the design values of monitors possibly downwind of the proposed project. 

The highest such value was 25 μg/m3 in Suffolk County, Massachusetts. Given this information, 

 

data between the EPA reference monitor and the continuous emission monitor showed the continuous emission 

monitor reading 20-30% higher than the EPA reference monitor. 

31 ―Modeling Procedures for Demonstrating Compliance with PM2.5 NAAQS,‖ March 23, 2010
36

EPA believes the secondary formation of PM2.5 emissions will not cause or contribute to a 

violation of the PM2.5 NAAQS. 

NO2 

In ―Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the Prevention of 

Significant Deterioration Program‖ issued on June 29, 2010, EPA explains procedures an 

applicant can follow when preliminary model estimates suggest potential violation of the 1-hour 

NO2 standard. Additional guidance relating to modeling demonstration for the 1–hour NO2

standard ―Additional Clarification Regarding Application of Appendix W Modeling Guidance 

for the 1-hour NO2 National Ambient Air Quality Standard‖ was issued on March 1, 2011. These 

documents were used in determining whether the project would cause or contribute to a violation 

of the 1-hour NO2 NAAQS. There is no increment for the 1-hour NO2 standard at this time. 

As allowed by the aforementioned guidance documents, the following assumptions were used in 

deriving the project’s impact from the air model. 

1. Assumption that 80% of NOx exiting the stack is in the form of NO2. 

2. Use the results from the controlling receptor. The location of the maximum reading in 

each year can vary between receptors. In accordance with our guidance, PVEC 

calculated maximum impact based on the individual receptor with the highest reading 

averaged over 5 years. 

3. Use design value of each model year (8th highest reading) and averaging the numbers 

over a five year period. 

The largest impact from NO2 emissions occur when the combined cycle turbine, auxiliary boiler, 

and firepump are simultaneously operated32. Although the operating hours are limited for both 

the auxiliary boiler and firepump, operation of these devices were assumed to be 8760 hours per 

year for modeling purposes. Although EPA guidance does allow for different treatment of 

intermittent operations such as the auxiliary boiler and firepump,33 PVEC chose the more 

conservative approach in estimating the project’s impact. 

Based on this acceptable approach, PVEC calculated the maximum ambient impact to be 48 ppb. 

The next step is to make a determination whether a ―nearby source‖ may cause a ―significant 

concentration gradient‖ for NO2. Using the latest emission data in NEI (2008), PVEC plotted 

 

32 Although allowable CCT NOx emissions are higher during startup and shutdown operations, PVEC modeling 

demonstration showed a smaller impact because they assumed the neither the firepump or emergency generator 

would be operated during these scenarios. EPA has included a permit condition prohibiting PVEC from operating 

the firepump and emergency generator for readiness testing when the combined cycle turbine is in startup or 

shutdown mode.

33 See ―Additional Clarification Regarding Applicability of Appendix W Modeling Guidance for the 1 -hour NO2 

NAAQS‖ (Mar. 1, 2011), available at 

http://www.epa.gov/ttn/scram/Additional_Clarifications_AppendixW_Hourly-NO2-NAAQS_FINAL_03-01-

2011.pdf, at 8-11. 
37

sources of NOx emissions within Hampden County on a map which included a wind rose and 

topography. In its October 14, 2011 supplemental application, PVEC articulated several reasons 

why interactive modeling was not done, including using the information contained in the map. 

EPA has reviewed PVEC’s submittal and concurs with their judgment there are no sources 

within the project’s vicinity to include in the modeling demonstration. 

When interactive modeling is not done, an applicant relies on ambient monitoring data in 

determining background levels. To determine if emissions from this project would violate the 

NAAQS, the modeled impact was added to the highest design value (from years 2008-2010) of 

any EPA approved ambient monitor in the vicinity. The highest monitor design value, 49 ppb, 

was from a monitor located at Liberty St. in Springfield. When this background level is added to 

the results from the modeling, the highest level is 97 ppb which is below the NAAQS level of 

100 ppb. Therefore, EPA has determined the NO2 emissions from this project will not cause or 

contribute to a violation of the NO2 NAAQS. 

Impairment to Visibility, Soils, and Vegetation

Forty CFR 52.21(o) requires the applicant to conduct an analysis of the air quality impact and 

impairment to visibility, soils, and vegetation that would occur as a result of as a result of the 

project and general commercial, residential, industrial and other growth associated with the 

project. EPA reviewed the analysis and agrees with PVEC that CO, NOx, PM10, PM2.5, and 

sulfuric acid mist emission increases from this new project and associated commercial, 

residential, industrial, and other growth will not result in an impairment to visibility, soils, or 

vegetation, nor a model exceedance of the National Ambient Air Quality Standards for these 

pollutants or increments. In addition, the modeling analysis demonstrated the project’s emissions 

would not have an adverse visibility impact at the closest Class I area (Lye Brook Wilderness 

Area near Manchester, Vermont). 

X. Mass Based Emission Limits 

To ensure the NAAQS and increment are not violated, a PSD permit must contain enforceable 

permit terms and conditions which ensure the mass flow rates for each modeled pollutant are not 

exceeded. This is accomplished by establishing mass-based emission limits for each modeled 

pollutant with or without the use of a CEMS. When a CEMS is used, the PSD permit must 

establish the averaging time for each mass-based emission limit that ensures compliance with the 

NAAQS. Without a CEMS, the applicable stack test method establishes the averaging time by 

default. PVEC is required to install CEMSs for both CO and NOx, therefore averaging times for 

these pollutants are specified in the permit. 

The following table contains the mass-based emission limits PVEC used in demonstrating 

compliance with the NAAQS and increment and therefore become emission limits in the PSD 

permit. 
38

NOx CO PM10/PM2.5

Combined Cycle Turbine (maximum capacity)

20.2 lbs/hr gas, 43 lbs/hr 

ULSD, one hr average

12.3 lbs/hr gas, 31.5 lbs/hr ULSD, 

one hr average

9.8 lbs/hr gas, 26.8 lbs/hr oil

Combined Cycle Turbine (startup/shutdown)

See tables II and III See tables II and III Not applicable34

Auxiliary Boiler 

0.58 lbs/hr 0.74 lbs/hr 0.1 lbs/hr

Note: There are no mass-based emission limits for sulfuric acid mist or GHGs since there is no 

NAAQS or increment to protect. There are no mass-based emission limits for the emergency 

generator because the permit condition limiting maximum size of the generator combined with 

the BACT limit is in effect a limit on mass emissions. 

XI. Environmental Justice (EJ) 

Executive Order 12898, entitled ―Federal Actions To Address Environmental Justice in

Minority Populations and Low-Income Populations,‖ states in relevant part that ―each Federal

agency shall make achieving environmental justice part of its mission by identifying and 

addressing, as appropriate, disproportionately high and adverse human health or environmental 

effects of its programs, policies, and activities on minority populations and low-income 

populations.‖ Exec. Order 12898, § 1-101, 59 Fed. Reg. 7,629 (Feb. 16, 1994). 

―Federal agencies are required to implement this order consistent with, and to the extent 

permitted by, existing law.‖ Id. at 7,632. EPA policy further defines environmental justice as 

the fair treatment and meaningful involvement of all people regardless of race, color, national 

origin, or income with respect to the development, implementation and enforcement of 

environmental laws, regulations and policies. 35 

The fact sheet for EPA’s November 2010 draft permit included the Agency’s analysis of 

environmental justice issues and the basis for the Agency’s conclusion that the facility's 

emissions would not have disproportionately high and adverse human health or environmental 

effects on minority or low-income populations. During the public comment period on last year’s

draft permit, EPA received written comments from Alternatives for Community and the 

Environment (ACE) on behalf of Westfield Concerned Citizens. These comments stated that the 

environmental justice analysis supporting the draft permit was inadequate. EPA also met with 

ACE representatives in EPA’s Boston office on August 8, 2011 to discuss these concerns. EPA 

has considered the comments it received last year and in the August 8 meeting, and is providing 

additional analysis and process for today’s draft permit. 

 

34 Due to issues with cyclonic flow, stack testing results for PM10 and PM2.5 are not representative of actual 

emissions.

35 See http://www.epa.gov/environmentaljustice/ for more information.
39

1. Public Participation

In response to the level of public interest and issues regarding public participation raised in the 

comments, EPA has agreed to conduct enhanced public outreach and communication. For this 

revised draft permit, EPA is undertaking the following actions: 

Conducting enhanced outreach to notify the public of the draft permit, i.e., beyond the 

minimum required by EPA regulations. 

Providing an extended comment period that is longer than the 30 days’ minimum 

required by EPA regulations. 

Conducting an informal public informational meeting and formal public hearing. At the 

public hearing, people may submit comments on the record orally. 

Providing Spanish, Russian, French, and Polish interpreters at the informational meeting 

and public hearing.36

Providing a simplified short-form summary of the permit action (available in English, 

Spanish, Russian, French, and Polish). 

These steps will ensure an opportunity for meaningful involvement for all communities. For 

more details on these issues, see the public notice and associated documents. 

2. NAAQS Compliance

As noted above, the PSD permitting program applies to pollutants for which western 

Massachusetts is classified as attainment or unclassifiable. 37 The facility’s modeled air impact 

will not result in exceedance of the NAAQS for any PSD pollutant. The Agency sets the 

NAAQS using technical and scientific expertise, ensuring that the NAAQS protects the public 

health with an adequate margin of safety. See CAA § 109(b), 42 U.S.C. § 7409(b). 

In general, for a PSD permit, compliance with the NAAQS is sufficient to demonstrate that 

emissions from a proposed facility will not have disproportionately high and adverse human 

health or environmental effects on a minority or low-income population. This is because the 

Executive Order concerns itself with effects that are ―adverse,‖ and air emissions that do not 

cause an exceedance of the NAAQS do not lead to an adverse impact cognizable under the PSD 

permit program. ―In the context of an environmental justice analysis, compliance with the 

NAAQS is emblematic of achieving a level of public health protection that, based on the level of 

protection afforded by a primary NAAQS, demonstrates that minority or low-income populations 

will not experience disproportionately high and adverse human health or environmental effects 

due to exposure to relevant criteria pollutants.‖ In re Shell Gulf of Mexico, Inc., OCS Appeal 

Nos. 10-01 through 10-04 [hereafter ―Shell II‖], slip op. at 74 (EAB Dec. 30, 2010); see also In 

re Shell Offshore Inc., 13 E.A.D. 357, 404-05 (2007); In re Knauf Fiber Glass, GmbH, 9 E.A.D. 

 

36 The commenters requested Spanish and Russian translators. We added Polish and French on our own initiative 

because our analysis shows that the area surrounding the facility has a number of Polish and French speakers.

37 Western Massachusetts is designated nonattainment for 8-hour ozone. The nonattainment New Source Review 

(NANSR) permit for this facility’s ozone precursor emissions was issued by MassDEP. MassDEP’s NANSR 

analysis is beyond the scope of this PSD permit. 
40

1, 16-17 (EAB 2000); In re Sutter Power Plant, 8 E.A.D. 680, 692 (EAB 1999) (describing the 

NAAQS as the ―bellwether of health protection‖).

It is true that, by using a conservative methodology, NO2 levels at one site (Liberty St. in 

Springfield) are modeled to be 97 ppb, or 97% of the NAAQS of 100 ppb. See Section IX. 

However, this is not cause for concern. As noted above, NAAQS are set with ―an adequate 

margin of safety.‖ CAA § 109(b)(1). Moreover, in determining the NAAQS, EPA considers the 

impact of the pollutant on sensitive subpopulations, such as children, the elderly, and asthmatics. 

Shell II, slip op. at 64 n.72; see also Coalition of Battery Recyclers Ass’n v. EPA, 604 F.3d 613, 

617-18 (D.C. Cir. 2010); Lead Indus. Ass’n v. EPA, 647 F.2d 1130, 1152-53 (D.C.Cir.1980). 

Thus, compliance with the NAAQS by any margin means that public health, including that of 

sensitive subpopulations, will be protected with an adequate margin of safety. For this reason, 

emissions from the proposed facility will not have disproportionately high and adverse human 

health or environmental effects on minority or low-income populations. 

3. Additional Analysis of Surrounding Areas

As noted above, the facility’s modeled air impact complies with the NAAQS at all points, and 

therefore there are no ―adverse human health or environmental effects‖ cognizable under the 

PSD permit program. Nevertheless, in light of the public interest and comment regarding 

environmental justice issues, EPA further examined the local demographics to determine whether 

the facility’s emissions, even at below-NAAQS (i.e. non-―adverse‖) levels, would 

disproportionately affect minority or low-income populations. In parallel, and as discussed in 

Section IX above, PVEC has conducted new air quality modeling: revised PM2.5 (annual and 24-

hour) air quality modeling using more up-to-date data, and 1-hour NO2 modeling. 

To analyze the communities potentially affected by these emissions, EPA examined an area 

known as the Significant Impact Area (SIA). The SIA is the area in which the facility’s modeled 

impact exceeds the Significant Impact Level (SIL). The SIL, in turn, is a threshold value that, in 

PSD permitting, is used for modeling screening purposes: impacts below the SIL are not 

―significant‖ and do not need to undergo refined modeling. 38 It is important to emphasize that 

modeled impacts above the SIL do not necessarily mean a project’s emissions would be 

unhealthy, or would have an ―adverse‖ effect on any population. To the contrary, the SIL is 

typically set at a very small percentage of the NAAQS. For example, the 1-hour NO2 SIL is set 

at 4 ppb, which is only 4 % of the NAAQS (100 ppb), which EPA recently promulgated in 2010 

to protect human health with an adequate margin of safety. Thus, modeled impacts that exceed 

the SIL, but are below the NAAQS, do not present health risks. EPA is using the SIA as a basis 

for analysis not because of any concern that emissions impacts inside the SIA are adverse—since 

they are below the NAAQS, they are by definition not adverse—but rather because impacts 

outside the SIA are so insignificant as to be ―de minimis.‖ 

 

38 It also defines the level at which a facility’s modeled exceedance of the NAAQS is considered to be ―causing or 

contributing‖ to a violation of the NAAQS. See 40 C.F.R. § 51.165(a)(2)(D)(i). That is not an issue here since the 

NAAQS will not be exceeded.
41

A. Additional PM2.5 Analysis

With respect to PM2.5, EPA considered the revised modeled SIA for PM2.5 , and examined the 

demographics of two areas: (1) a circle around the facility site tightly drawn around the SIA 

(with a radius of 0.63 miles), and (2) a 1.0-mile circle around the facility site. 39 See Figures EJ-1 

(map for PM2.5 SIA with 0.63-mile and 1.0-mile circles), EJ-2 (demographic analysis of 0.63-

mile circle), and EJ-3 (demographic analysis of 1.0-mile circle). These analyses reveal the 

following: 

The SIA itself contains no dwellings. In other words, no persons of any race or income 

are modeled to be exposed to PM2.5 emissions from the facility at significant levels. 

Neither the 0.63-mile circle nor the 1.0-mile circle contains any Census block groups 

with high minority or low-income populations.40 

The 0.63-mile circle contains 0.4% percent persons of minority race (below the 

Massachusetts average of 15.5%) and 5.5% percent persons below the federal poverty 

line (below the Massachusetts average of 6.7%). 

The 1.0-mile circle contains 0.5% persons of minority race and 5.7% persons below the 

federal poverty line. Again, these values are well below the Massachusetts averages. 

The facility’s maximum modeled contribution to ambient PM2.5 levels in an area with a 

substantial minority or low-income population is 0.298 μg/m3(Area 2). This is 25% of 

the SIL and just 1% of the NAAQS. 

EPA therefore concludes that the facility’s PM2.5 emissions will not have disproportionately high 

human health or environmental effects on minority or low-income populations.

B. Additional NO2 Analysis

EPA also examined the impact from increased NO2 emissions since the impact of this pollutant 

is also above the SIL. Current scientific evidence links short-term NO2 exposures, ranging from 

30 minutes to 24 hours, with adverse respiratory effects including airway inflammation in 

healthy people and increased respiratory symptoms in people with asthma. 

 

39 EPA used a one-mile circle because ACE suggested this as a radius of concern in its December 2010 comment.

40 For the purpose of this analysis, EPA mapped both EPA Region 1’s Potential Environmental Justice (EJ) Areas 

and the Massachusetts Environmental Justice Populations. EPA’s Potential EJ Areas are based on the 2000 Census 

Block Group Boundary layer. The methodology used to determine how the areas are coded involved identifying 

those block groups with percentages in the top 15% of the six-state New England region for low-income residents 

and/or minorities. Low-income is defined as twice the Federal Poverty Level. The Massachusetts EJ Populations 

are defined by having one or more of the following attributes: a minority population of 25% or more; an average 

household income of less than 65% the Massachusetts state median income; a foreign-born population of 25% or 

more; and/or a non-English-proficient population of 25% or more.
42

As with other pollutants, PVEC modeled several different operating scenarios to determine 

which scenario represented the project’s most significant impact from NO2 emissions. At EPA’s 

request, PVEC analyzed the potential impacts of its NO2 emissions on minority and low-income 

communities. See PVEC October 14, 2011 submission (―Supplemental Information - 1 hour 

NO2 Impact Analysis‖) [hereafter ―PVEC NO2 Analysis‖]. PVEC submitted two very detailed 

maps which provide information regarding topography, wind direction, other NOx emitting 

sources in the area, and ―Areas-of Concern‖ communities. As the PVEC NO2 Analysis 

explained, PVEC used EPA’s ―Toolkit for Assessing Potential Allegations of Environmental 

Injustice‖ to define Areas-of-Concern communities as meeting either of the following two 

criteria: 

1. The community’s minority population percentage is above the statewide minority 

population percentage (15.5%), and/or 

2. The community’s percentage of population below the poverty level exceeds the 

statewide average population percentage below the poverty level (6.7%). 

PVEC’s conclusions, and EPA’s further analyses, are discussed below separately for two different 

operating scenarios. 

1. Normal Operations 

The first map, Attachment 1 to this Fact Sheet, shows PVEC’s modeled analysis of the impact of 

NO2 emissions when PVEC is operating the gas turbine on ULSD. Although the use of ULSD is 

strictly limited by the permit, for these purposes PVEC mapped the 1-hour NO2 impacts of 

ULSD rather than natural gas because burning ULSD has a higher impact than burning natural 

gas. Attachment 1 demonstrates that NO2 emissions above the SIL occur only in areas which are 

not considered Areas-of-Concern communities. Indeed, the SIA for NO2 from normal turbine 

operations is almost entirely west of the facility, whereas the Areas-of-Concern communities are 

north, south, and east of the facility. 

Based on Attachment 1, EPA concludes that the facility’s normal operations (turbine operating at 

steady state) will not have will not have disproportionately high human health or environmental 

effects on minority or low-income populations.

2. Weekly testing 

At EPA’s request, PVEC also modeled NO2 emissions when the turbine is fully operational and 

when PVEC is conducting its weekly maintenance and safety checks on the emergency engine 

and fire pump. Although the permit limits the operation of the emergency engine and fire pump 

to 300 hours per year, and although EPA guidance allows facilities to ignore such ―intermittent‖ 

sources when conducting modeling,41 EPA asked PVEC to analyze this operating scenario 

 

41 See ―Additional Clarification Regarding Applicability of Appendix W Modeling Guidance for the 1-hour NO2 

NAAQS‖ (Mar. 1, 2011), available at 

http://www.epa.gov/ttn/scram/Additional_Clarifications_AppendixW_Hourly-NO2-NAAQS_FINAL_03-01-

2011.pdf, at 8-11.
43

because it has the highest modeled impact from NO2 emissions. Impacts during these times are 

greater than the impact occurring when the turbine is in startup or shutdown mode, even though 

the NOx emission rate is higher during startup and shutdown, because of the smaller volumetric 

flow from the stack during startup and shutdown. At EPA’s suggestion, PVEC further 

investigated whether confining the weekly testing of the emergency engine and fire pump to a 

particular time of day would limit the spatial extent of the NO2 plume (due to meteorological 

variability), and determined that the extent of the NO2 plume would be minimized if the testing 

was limited to 12:00-3:00pm. 

Attachment 2 to this Fact Sheet shows PVEC’s modeled analysis of the impact of NO2 emissions 

when PVEC is operating the gas turbine and also conducting its required weekly maintenance 

and safety checks on the emergency engine and fire pump. This map does indicate three 

different Areas-of-Concern communities in which the model results predict the impact of 

PVEC’s NO2 emissions to be higher than the SIL in at least part of the community. 

Based on PVEC’s analysis, EPA decided to further examine the demographics of the modeled 

SIA for NO2 under the scenario of PVEC operating the gas turbine and also conducting its 

weekly testing of the emergency engine and fire pump. These analyses reveal the following: 

The SIA does include two Census block groups in Westfield that are both EPA Region 1 

Potential EJ Areas and Massachusetts EJ Populations. These correspond to Area 1 and 

Area 2 in PVEC’s maps.

The SIA overlaps a Census block group in West Springfield that is a Massachusetts EJ 

Population but not an EPA Region 1 Potential EJ Area. This corresponds in part to Area 

3 in PVEC’s map. 

Because of the extremely irregular shape of the modeled Significant Impact Area for 1-hour 

NO2, EPA does not believe that a demographic analysis based on a circular region is an ideal 

method of evaluating the population affected by the NO2 plume from emergency equipment 

testing. However, in the interest of completeness, EPA generated demographic analyses for 

circles of three different radii around the facility: 3.5 miles, 6 miles, and 8 miles. 

The first two radii were selected so as to include the above-identified block groups. The 3.5-mile 

circle includes the two identified Westfield block groups (i.e., all of the Census block groups that 

have modeled NO2 impacts above the SIL and meet the threshold of EPA Region 1 Potential EJ 

Areas) and has been expanded slightly beyond those block groups so as to ensure inclusion of 

three schools just south and west of these two areas. See Figures EJ-4 (map with 3.5-mile circle, 

NO2 SIA, and locations of interest), EJ-5 (demographic analysis of 3.5-mile circle). The 6-mile 

circle includes the West Springfield block group as well. Thus, it includes all of Census block 

groups that have modeled NO2 impacts above the SIL and meet the threshold of EPA Region 1 

Potential EJ Areas or Massachusetts EJ Populations, and has been expanded to include the 

entirety of the West Springfield block group in question, not just the portion within the SIA. See 

Figures EJ-6 (map with 6-mile circle, NO2 SIA, and locations of interest), EJ-7 (demographic 

analysis of 6-mile circle). The third radius (8 miles) was selected because it includes most 
44

(though not all) of the SIA. See Figure EJ-8 (map with 8-mile circle, NO2 SIA, and locations of 

interest), EJ-9 (demographic analysis of 8-mile circle). 

EPA’s demographic analysis of these areas reveals that these circles contain higher-than-stateaverage percent of persons below poverty level, and, for the 8-mile circle, above-average 

minority residents as well.42 However, as noted above, EPA does not believe that these circles 

accurately characterize the population affected by the NO2 plume, for several reasons: 

1. Because the SIA is extremely irregular in shape, demographic analysis of circular regions 

necessarily includes areas for which the facility’s predicted NO2 impact is in fact below 

the significant impact level. 

2. The population density increases with distance from the facility, whereas emissions 

(generally, if not uniformly) decrease with distance from the facility. Specifically, the 

population densities in the 0.63-mile and 1-mile circles are 394 and 386 persons per 

square mile, respectively; the population densities in the 3.5-mile and 6-mile circles 

discussed below are 673 and 674 persons per square mile, respectively; and the 

population density in the 8-mile circle is 852 persons per square mile. Looking at this 

issue another way, the 8-mile circle includes 166,413 persons, the 6-mile circle includes 

74,361 persons, the 3.5-mile circle includes 25,204 persons, and the 1-mile circle 

includes only 1,214 persons. Thus, 95.2% of the population of the 3.5-mile circle lives 

more than a mile away from the facility, 98.4% of the population of the 6-mile circle lives 

more than a mile away from the facility, and 99.3% of the population of the 8-mile circle 

lives more than a mile away from the facility (indeed, more than half of the pop ulation of 

the 8-mile circle lives between 6 and 8 miles away from the facility). Yet the NO2

impacts are generally greatest closer to the facility. See Attachments 1 and 2. Thus, as 

circles are drawn with greater radii, they contain more and more people who (generally) 

will experience less and less NO2 impact from the facility. 

3. This trend is further exacerbated by the fact that the larger circles include more dense, 

lower-income populations east of the facility, whereas the 1-hour NO2 plume generally 

extends further west of the facility. This is readily apparent from Figure EJ-8, which 

shows how the 8-mile circle is heavily influenced by minority and low-income 

neighborhoods of Holyoke, Chicopee, and Springfield that are not in fact within the SIA, 

but are included in the circle solely because they happen to be at the same distance (albeit 

opposite direction) from the facility as regions of Russell, Granville, and Westhampton 

that are in the SIA. 

 

For these reasons, while EPA has provided the demographics for the 3.5-mile, 6-mile, and 8-mile 

circles in the interest of completeness, we believe they are not the most useful means of 

evaluating whether the impacts of the NO2 plume during scheduled testing disproportionately 

affect minority or low-income populations. 

 

42 Specifically, the 3.5-mile circle contains 6.1% minority residents (below the state average of 15.5%) and 14.1% 

persons below the poverty level (above the state average of 6.7%). The 6-mile circle contains 8.2% minority 

residents and 10.3% persons below the poverty level. The 8-mile circle contains 21.9% minority residents and 

15.7% persons below the poverty level. 
45

Instead, EPA examined the facility’s modeled NO2 impact in the three identified Areas-ofConcern communities that are within or overlap the SIA, and compared it to the modeled NO2

impact in other, non-Areas of Concern communities. The impacts in the three identified Areasof-Concern communities are: 

Area 1 (Westfield): 4.45 ppb 

Area 2 (Westfield): 4.66 ppb 

Area 3 (West Springfield): between 3.66 ppb and 4.12 ppb 

Of these three Areas-of-Concern communities, the highest NO2 impact from PVEC occurs in 

Area 2 with a modeled impact of 4.66 ppb, i.e., very slightly exceeding the SIL of 4.00 ppb. 

These impacts are in fact quite low, not just in absolute terms but also relative to other 

communities in the Significant Impact Area. EPA confirmed that there are other communities 

within the SIA that are not Areas-of-Concern communities and which have higher impacts from 

NO2 emissions than Area 2. For example, the modeling analysis predicts an impact of 20 ppb 

(i.e., 20 % of the health-based standard of 100 ppb) in a neighborhood just north of the Victoria 

Estates Conservation Area that does not have high percentages of minority or low-income 

residents. 

Since the project’s maximum modeled air impact does not occur in Areas-of-Concern 

communities, it actually affects low-income communities less than other communities. 

Furthermore, as noted above, the project’s maximum modeled air impact is not ―adverse‖ 

because it is well below the NAAQS. For these reasons, EPA concludes that the project’s air 

emissions will not cause disproportionately high and adverse human health or environmental 

effects on minority or low-income populations. See, e.g., In re EcoEléctrica, L.P., 7. E.A.D. 56, 

68 (1997). 

C. Actions taken

While the facility’s impacts will not cause disproportionately high and adverse human health or 

environmental effects on minority or low-income populations, EPA has decided, out of an 

abundance of caution, to implement several common-sense measures given the presence of 

potentially sensitive communities near the facility: 

1. As discussed above, EPA is providing enhanced public participation to ensure that all 

members of the public have an opportunity for meaningful involvement. 

2. Because PVEC’s NO2 modeling indicates that the plume from scheduled emergency 

testing would have the least impact if conducted between 12:00-3:00pm, the draft permit 

requires that testing be conducted only during this window. 

3. Finally, to account for any remaining uncertainties in this analysis and for the potential 

sensitivity of vulnerable groups to cumulative impacts, the draft permit prohibits the 

facility from conducting scheduled testing of the emergency generator and fire pump 

during days when the hourly ambient NO2 level measured just before testing at the 

nearest ambient NO2 air quality monitor within Hampden County operated by the 

MassDEP and available at http://public.dep.state.ma.us/MassAir is 54 ppb or higher, the 
46

starting point for the ―moderate‖ air quality index for NO2.

43

 This prohibition shall apply 

except for the rare circumstance when this condition would prevent emergency 

equipment testing for more than five consecutive days and thereby pose a potential safety 

hazard.

The above-discussed analyses and actions fulfill EPA’s obligations under Executive Order 12898 

and EPA environmental justice policy. 44

XII. National Historic Preservation Act 

On November 5, 2010, EPA sent a letter to Brona Simon, Executive Director for the 

Massachusetts State Historic Preservation Office, notifying her of the earlier draft permit for 

PVEC and requesting consultation under Section 106 of the National Historic Preservation Act 

of 1966, as amended. Ms. Simon responded to EPA by a letter recommending that EPA make a 

finding of ―no historic properties affected‖ under 36 CFR 800.4(d)(1) for this project. Today’s 

draft permit does not change the scope of the previous draft permitted project; therefore, EPA is 

making a finding that our action does not affect any historic properties. 

XIII. Comment Period, Hearings and Procedures for Final Decisions 

All persons, including applicants, who believe any condition of the Draft Permit is inappropriate 

must raise all issues and submit all available arguments and all supporting material for their 

arguments in full by the close of the public comment period, to Donald Dahl (OEP 05-2) 

U.S. Environmental Protection Agency 5 Post Office Square - Suite 100 Boston MA 02109 - 

3912. Please note that this new Draft Permit completely replaces and supersedes the November 

5, 2010 draft permit. Even if you commented on the November 2010 draft permit, if you believe 

that a condition of this new Draft Permit is inappropriate, you must, during the new public 

comment period, submit a comment raising all available issues. 

A public hearing will be held during the public comment period. See the public notice for 

details. EPA will consider requests for extending the public comment period for good cause. In 

reaching a final decision on the Draft Permit, the EPA will respond to all significant comments 

and make these responses available to the public at EPA' s Boston Office. 

Following the close of the public comment period, and after the public hearing, the EPA will 

issue a Final Permit decision and forward a copy of the final decision to the applicant and each 

person who has submitted written comments or requested notice. Within 30 days following the 

notice of the permit decision, any interested parties may submit a petition for review of the 

permit to EPA's Environmental Appeals Board consistent with 40 CFR 124.19. 

 

43 An air quality index of ―moderate‖ is defined as: ―Air quality is acceptable; however, for some pollutants there 

may be a moderate health concern for a very s mall number of people. Unusually sensitive people sh ould consider 

reducing prolonged or heavy exertion outdoors.‖ http://www.mass.gov/dep/air/aqi/aqi.htm#How_AQI_Works. 

44 EPA’s conclusion that this particular PSD permit action will not cause disproportionately high and adverse human 

health or environmental effects on minority or low-income populations is based on the location and modeled 

environmental impact of this particular facility. Outside of the scope of this PSD permit, EPA has invested in a 

variety of environmental justice-related activities in Holyoke, Chicopee, and Springfield. See document entitled 

―EPA Community Initiative Supporting the Pioneer Valley Knowledge Corridor‖ in the permit file. 
47

XIV. EPA Contacts 

Additional information concerning the draft permit may be obtained between the hours of 9:00 

a.m. and 5:00 p.m., Monday through Friday, excluding holidays from: 

Donald Dahl (OEP 05-2) 

U.S. Environmental Protection Agency 

5 Post Office Square - Suite 100 

Boston MA 02109 - 3912 

Telephone: (617) 918-1657

Dahl.Donald@epa.gov
48

Attachment 1 
49

Attachment 2 

Area 1

Area 2 Area 3
50

Figure EJ-1 (map for PM2.5 SIA with 0.63-mile and 1.0-mile circles) 
51

EJ-2: Demographics analysis of 0.63 mile circle 

Overview

Total Persons: 492 Land Area: 99.2% Households in Area: 201

Population 

Density:

393.97 /sq 

mi Water Area: 0.8% Housing Units in Area: 209

Percent Minority: .4% Persons Below Poverty 

Level: 27 (5.5%) Households on Public Assistance:

5

Percent

Urban: 95% Housing Units Built <1970:

21% Housing Units Built <1950: 7%

Race and Age*

(* Columns that add up to 100% are highlighted) 

Race Breakdown Persons (%) Age Breakdown Persons(%)

White: 490 (99.6%) Child 5 years or less: 29 (5.9%)

African-American: 0 (0.0%) Minors 17 years and younger: 89 (18.1%)

Hispanic-Origin: 2 (0.4%) Adults 18 years and older: 403 (81.9%)

Asian/Pacific Islander: 0 (0.0%) Seniors 65 years and older: 118 (24.0%)

American Indian: 0 (0.0%)

Other Race: 2 (0.4%) This space intentionally left blank

Multiracial: 0 (0.0%)

Gender

Gender Breakdown Persons (%)

Males: 240 (48.8%)

Females: 252 (51.2%)

Education

Education Level (Persons 25 & older) Persons (%)

Less than 9th grade: 38 (10.9%)

9th -12th grade: 52 (15.0%)

High School Diploma: 123 (35.6%)

Some College/2 yr: 31 (8.9%)

B.S./B.A. or more: 102 (29.6%)
52

Language

Ability to Speak English Persons (%)

Population Age 5 and Over: 465

Speak only English: 437 (94.0%)

Non-English at Home: 27 (5.9%)

Speak English very well: 24 (5.1%)

Speak English well: 4 (0.8%)

Speak English not well: 0 (0.0%)

Speak English not at all: 0 (0.0%)

Speak English less than well: 0 (0.0%)

Language Spoken

Language Spoken Persons (%)

Speak only English: 429 (89.2%)

Spanish or Spanish Creole: 12 (2.5%)

French (incl. Patois, Cajun): 6 (1.3%)

French Creole: 1 (0.1%)

German: 2 (0.4%)

Greek: 1 (0.1%)

Russian: 8 (1.7%)

Polish: 15 (3.1%)

Other Slavic Languages: 1 (0.2%)

Other Indo-European Lanugages: 3 (0.7%)

Non-English Speaking: 52 (10.8%)
53

Place of Birth for the Foreign-Born

Country Persons

Foreign-Born Population: 34

Europe: 23 (67.6%)

Asia: 6 (18.5%)

Americas: 5 (13.8%)

United Kingdom: 4 (11.3%)

Ireland: 1 (2.6%)

France: 1 (1.9%)

Italy: 2 (5.6%)

Poland: 8 (23.2%)

Russia: 1 (1.6%)

Ukraine: 4 (11.5%)

Other Eastern Europe: 3 (9.9%)

Other Central Eastern Asia: 6 (18.5%)

El Salvador: 1 (4%)

Guatemala: 1 (1.9%)

Chile: 0 (1.2%)

Other South America: 0 (1.4%)

Canada: 2 (5.4%)

Income

Income Breakdown Households (%)

Less than $15,000: 37 (18.3%)

$15,000 - $25,000: 13 (6.4%)

$25,000 - $50,000: 61 (30.6%)

$50,000 - $75,000: 44 (21.9%)

Greater than $75,000: 58 (28.8%)

Tenure

Tenure Breakdown Households (%)

Occupied Housing Units: 201 (100.0%)

Owner Occupied: 183 (91.4%)

Renter Occupied 17 (8.6%)
54

EJ-3 Demographic Analysis of 1 mile circle 

Overview

Total Persons: 1214 Land Area: 99.2% Households in Area: 494

Population 

Density:

386.2 /sq 

mi Water Area: 0.8% Housing Units in Area: 515

Percent Minority: .5% Persons Below Poverty 

Level: 69 (5.7%) Households on Public Assistance:

11

Percent

Urban: 94% Housing Units Built <1970:

23% Housing Units Built <1950: 8%

Race and Age*

(* Columns that add up to 100% are highlighted) 

Race Breakdown Persons (%) Age Breakdown Persons(%)

White: 1208 (99.5%) Child 5 years or less: 72 (5.9%)

African-American: 0 (0.0%) Minors 17 years and younger: 224 (18.5%)

Hispanic-Origin: 5 (0.4%) Adults 18 years and older: 990 (81.5%)

Asian/Pacific Islander: 0 (0.0%) Seniors 65 years and older: 286 (23.5%)

American Indian: 1 (0.1%)

Other Race: 5 (0.4%) This space intentionally left blank

Multiracial: 0 (0.0%)

Gender

Gender Breakdown Persons (%)

Males: 594 (48.9%)

Females: 620 (51.1%)

Education

Education Level (Persons 25 & older) Persons (%)

Less than 9th grade: 89 (10.6%)

9th -12th grade: 125 (14.8%)

High School Diploma: 304 (35.9%)

Some College/2 yr: 82 (9.7%)

B.S./B.A. or more: 245 (29.0%)
55

Language

Ability to Speak English Persons (%)

Population Age 5 and Over: 1147

Speak only English: 1080 (94.2%)

Non-English at Home: 67 (5.8%)

Speak English very well: 58 (5.1%)

Speak English well: 9 (0.8%)

Speak English not well: 0 (0.0%)

Speak English not at all: 0 (0.0%)

Speak English less than well: 0 (0.0%)

Language Spoken

Language Spoken Persons (%)

Speak only English: 1103 (88.9%)

Spanish or Spanish Creole: 33 (2.7%)

French (incl. Patois, Cajun): 15 (1.2%)

French Creole: 2 (0.1%)

Portuguese or Portuguese Creole: 0 (0.0%)

German: 4 (0.4%)

Greek: 2 (0.1%)

Russian: 24 (1.9%)

Polish: 37 (3.0%)

Other Slavic Languages: 3 (0.2%)

Hindi: 1 (0.0%)

Other Indo-European Lanugages: 8 (0.6%)

Japanese: 0 (0.0%)

Korean: 0 (0.0%)

Arabic: 0 (0.0%)

Non-English Speaking: 138 (11.1%)
56

Place of Birth for the Foreign-Born

Country Persons

Foreign-Born Population: 90

Europe: 61 (67.4%)

Asia: 17 (18.7%)

Americas: 13 (13.9%)

United Kingdom: 9 (10.4%)

Ireland: 2 (2.3%)

Austria: 0 (.1%)

France: 2 (1.7%)

Germany: 0 (.1%)

Greece: 0 (.1%)

Italy: 5 (5.5%)

Portugal: 0 (.1%)

Poland: 20 (21.9%)

Belarus: 0 (.1%)

Russia: 3 (2.9%)

Ukraine: 11 (12.3%)

Other Eastern Europe: 9 (10%)

Japan: 0 (.1%)

Korea: 0 (.1%)

India: 0 (.5%)

Other Central Eastern Asia: 16 (17.8%)

Lebanon: 0 (.1%)

Barbados: 0 (.1%)

Dominican Republic: 0 (.3%)

El Salvador: 3 (3.6%)

Guatemala: 2 (1.7%)

Chile: 1 (1.1%)

Other South America: 1 (1.3%)

Canada: 5 (5.9%)

Income

Income Breakdown Households (%)

Less than $15,000: 90 (18.1%)

$15,000 - $25,000: 32 (6.5%)

$25,000 - $50,000: 151 (30.7%)

$50,000 - $75,000: 109 (22.0%)

Greater than $75,000: 140 (28.4%)
57

Tenure

Tenure Breakdown Households (%)

Occupied Housing Units: 494 (100.0%)

Owner Occupied: 449 (90.9%)

Renter Occupied 45 (9.1%)
58

EJ-4: Map with 3.5-mile circle, NO2 SIA, and locations of interest 
59

Overview

Total Persons: 25204 Land Area: 97.2% Households in Area: 9518

Population 

Density:

673.37 /sq 

mi Water Area: 2.8% Housing Units in Area: 9994

Percent 

Minority:

9.2% Persons Below 

Poverty Level: 3398 (14.1%) Households on Public Assistance:

466

Percent

Urban: 83% Housing Units Built <1970:

63% Housing Units Built 

<1950:

38%

Race and Age*

(* Columns that add up to 100% are highlighted) 

Race Breakdown Persons (%) Age Breakdown Persons(%)

White: 23678 (93.9%) Child 5 years or less: 1957 (7.8%)

African-American: 274 (1.1%) Minors 17 years and younger: 6190 (24.6%)

Hispanic-Origin: 1689 (6.7%) Adults 18 years and older: 19014 (75.4%)

Asian/Pacific Islander: 114 (0.5%) Seniors 65 years and older: 3406 (13.5%)

American Indian: 45 (0.2%)

Other Race: 750 (3.0%) This space intentionally left blank

Multiracial: 343 (1.4%)

Gender

Gender Breakdown Persons (%)

Males: 12323 (48.9%)

Females: 12881 (51.1%)

Education

Education Level (Persons 25 & older) Persons (%)

Less than 9th grade: 1047 (7.2%)

9th -12th grade: 1780 (12.2%)

High School Diploma: 5597 (38.5%)

Some College/2 yr: 2798 (19.2%)

B.S./B.A. or more: 3322 (22.8%)

EJ-5 (demographic analysis of 3.5-mile circle
60

Language

Ability to Speak English Persons (%)

Population Age 5 and Over: 23495

Speak only English: 20016 (85.2%)

Non-English at Home: 3479 (14.8%)

Speak English very well: 1651 (7.0%)

Speak English well: 874 (3.7%)

Speak English not well: 777 (3.3%)

Speak English not at all: 176 (0.8%)

Speak English less than well: 954 (4.1%)

Language Spoken

Language Spoken Persons (%)

Speak only English: 19766 (85.8%)

Spanish or Spanish Creole: 1033 (4.5%)

French (incl. Patois, Cajun): 230 (1.0%)

French Creole: 19 (0.1%)

Portuguese or Portuguese Creole: 33 (0.1%)

German: 57 (0.2%)

Other West Germanic Languages: 11 (0.0%)

Scandinavian Languages: 2 (0.0%)

Greek: 62 (0.3%)

Russian: 659 (2.9%)

Polish: 428 (1.9%)

Serbo-Croatian: 90 (0.4%)

Other Slavic Languages: 317 (1.4%)

Armenian: 2 (0.0%)

Persian: 1 (0.0%)

Hindi: 36 (0.2%)

Other Indo-European Lanugages: 51 (0.2%)

Chinese: 8 (0.0%)

Japanese: 22 (0.1%)

Korean: 6 (0.0%)

Mon-Khmer, Cambodian: 10 (0.0%)

Vietnamese: 6 (0.0%)

Tagalog: 9 (0.0%)
61

Other Native North American Languages: 5 (0.0%)

Arabic: 23 (0.1%)

Hebrew: 2 (0.0%)

Non-English Speaking: 3271 (14.2%)

Place of Birth for the Foreign-Born

Country Persons

Foreign-Born Population: 1989

Europe: 1512 (76%)

Asia: 260 (13.1%)

Africa: 5 (.2%)

Oceania: 0 (0%)

Americas: 213 (10.7%)

United Kingdom: 78 (3.9%)

Ireland: 20 (1%)

Sweden: 0 (0%)

Other Northern Europe: 1 (0%)

Austria: 8 (.4%)

France: 14 (.7%)

Germany: 42 (2.1%)

Netherlands: 3 (.1%)

Greece: 27 (1.3%)

Italy: 91 (4.6%)

Portugal: 9 (.4%)

Spain: 3 (.1%)

Czechoslavakia: 0 (0%)

Poland: 262 (13.2%)

Belarus: 8 (.4%)

Russia: 252 (12.7%)

Ukraine: 473 (23.8%)

Yugoslavia: 15 (.7%)

Other Eastern Europe: 209 (10.5%)

Mainland China: 3 (.2%)

Taiwan: 0 (0%)

Japan: 6 (.3%)

Korea: 11 (.5%)

India: 35 (1.8%)

Iran: 1 (0%)

Pakistan: 0 (0%)

Other Central Eastern Asia: 153 (7.7%)

Cambodia: 6 (.3%)
62

Indonesia: 11 (.6%)

Philippines: 10 (.5%)

Vietnam: 10 (.5%)

Lebanon: 11 (.6%)

Other Eastern Africa: 0 (0%)

Egypt: 0 (0%)

South Africa: 0 (0%)

Other Western Africa: 2 (.1%)

Australia: 0 (0%)

Other Australian and New Zealand Subregion: 0 (0%)

Micronesia: 0 (0%)

Barbados: 7 (.3%)

Dominican Republic: 16 (.8%)

Jamaica: 14 (.7%)

Mexico: 0 (0%)

Costa Rica: 0 (0%)

El Salvador: 17 (.8%)

Guatemala: 8 (.4%)

Argentina: 0 (0%)

Brazil: 6 (.3%)

Chile: 5 (.2%)

Colombia: 2 (.1%)

Ecuador: 2 (.1%)

Venezuela: 1 (0%)

Other South America: 6 (.3%)

Canada: 129 (6.5%)

Income

Income Breakdown Households (%)

Less than $15,000: 1788 (18.8%)

$15,000 - $25,000: 1092 (11.5%)

$25,000 - $50,000: 2810 (29.5%)

$50,000 - $75,000: 2065 (21.7%)

Greater than $75,000: 1808 (19.0%)

Tenure

Tenure Breakdown Households (%)

Occupied Housing Units: 9518 (100.0%)

Owner Occupied: 5864 (61.6%)

Renter Occupied 3655 (38.4%)
63

EJ-6 (map with 6-mile circle, NO2 SIA, and locations of interest) 
64

EJ-7 (demographic analysis of 6-mile circle) 

Overview

Total Persons: 74361 Land Area: 97.5% Households in Area: 28320

Population 

Density:

674.24 /sq 

mi Water Area: 2.5% Housing Units in Area: 29518

Percent 

Minority:

11.1% Persons Below 

Poverty Level: 7308 (10.3%) Households on Public Assistance:

1111

Percent

Urban: 85% Housing Units Built <1970:

64% Housing Units Built 

<1950:

33%

Race and Age*

(* Columns that add up to 100% are highlighted) 

Race Breakdown Persons (%) Age Breakdown Persons(%)

White: 68269 (91.8%) Child 5 years or less: 5377 (7.2%)

African-American: 1076 (1.4%) Minors 17 years and younger: 17616 (23.7%)

Hispanic-Origin: 5943 (8.0%) Adults 18 years and older: 56744 (76.3%)

Asian/Pacific Islander: 580 (0.8%) Seniors 65 years and older: 11291 (15.2%)

American Indian: 84 (0.1%)

Other Race: 3313 (4.5%) This space intentionally left blank

Multiracial: 1040 (1.4%)

Gender

Gender Breakdown Persons (%)

Males: 36015 (48.4%)

Females: 38346 (51.6%)

Education

Education Level (Persons 25 & older) Persons (%)

Less than 9th grade: 2774 (6.3%)

9th -12th grade: 5071 (11.4%)

High School Diploma: 15823 (35.6%)

Some College/2 yr: 9133 (20.6%)

B.S./B.A. or more: 11586 (26.1%)
65

Language

Ability to Speak English Persons (%)

Population Age 5 and Over: 69850

Speak only English: 59452 (85.1%)

Non-English at Home: 10398 (14.9%)

Speak English very well: 6082 (8.7%)

Speak English well: 2212 (3.2%)

Speak English not well: 1544 (2.2%)

Speak English not at all: 560 (0.8%)

Speak English less than well: 2104 (3.0%)

Language Spoken

Language Spoken Persons (%)

Speak only English: 59452 (85.1%)

Spanish or Spanish Creole: 4811 (6.9%)

French (incl. Patois, Cajun): 940 (1.3%)

French Creole: 25 (0.0%)

Portuguese or Portuguese Creole: 242 (0.3%)

German: 152 (0.2%)

Other West Germanic Languages: 20 (0.0%)

Scandinavian Languages: 9 (0.0%)

Greek: 143 (0.2%)

Russian: 1037 (1.5%)

Polish: 1274 (1.8%)

Serbo-Croatian: 159 (0.2%)

Other Slavic Languages: 435 (0.6%)

Armenian: 6 (0.0%)

Persian: 15 (0.0%)

Hindi: 55 (0.1%)

Urdu: 21 (0.0%)

Other Indic Languages: 0 (0.0%)

Other Indo-European Lanugages: 130 (0.2%)

Chinese: 76 (0.1%)

Japanese: 51 (0.1%)

Korean: 24 (0.0%)

Mon-Khmer, Cambodian: 59 (0.1%)
66

Miao, Hmong: 8 (0.0%)

Vietnamese: 60 (0.1%)

Other Asian Languages: 16 (0.0%)

Tagalog: 42 (0.1%)

Other Native North American Languages: 12 (0.0%)

Hungarian: 10 (0.0%)

Arabic: 168 (0.2%)

Hebrew: 6 (0.0%)

African Languages: 25 (0.0%)

Non-English Speaking: 10398 (14.9%)

Place of Birth for the Foreign-Born

Country Persons

Foreign-Born Population: 4670

Europe: 3046 (65.2%)

Asia: 804 (17.2%)

Africa: 83 (1.8%)

Oceania: 6 (.1%)

Americas: 730 (15.6%)

United Kingdom: 196 (4.2%)

Ireland: 85 (1.8%)

Sweden: 1 (0%)

Other Northern Europe: 7 (.2%)

Austria: 18 (.4%)

France: 33 (.7%)

Germany: 213 (4.6%)

Netherlands: 7 (.1%)

Other Western Europe: 13 (.3%)

Greece: 51 (1.1%)

Italy: 182 (3.9%)

Portugal: 115 (2.5%)

Spain: 8 (.2%)

Czechoslavakia: 8 (.2%)

Hungary: 10 (.2%)

Poland: 695 (14.9%)

Belarus: 23 (.5%)

Russia: 359 (7.7%)

Ukraine: 693 (14.8%)

Bosnia and Herzegovina: 24 (.5%)

Yugoslavia: 23 (.5%)
67

Other Eastern Europe: 283 (6.1%)

Mainland China: 33 (.7%)

Hong Kong: 11 (.2%)

Taiwan: 8 (.2%)

Japan: 23 (.5%)

Korea: 73 (1.6%)

India: 65 (1.4%)

Iran: 22 (.5%)

Pakistan: 21 (.5%)

Other Central Eastern Asia: 247 (5.3%)

Cambodia: 31 (.7%)

Indonesia: 16 (.4%)

Laos: 8 (.2%)

Philippines: 58 (1.2%)

Vietnam: 76 (1.6%)

Jordan: 22 (.5%)

Lebanon: 39 (.8%)

Syria: 5 (.1%)

Turkey: 9 (.2%)

Other Western Asia: 10 (.2%)

Other Eastern Africa: 22 (.5%)

Egypt: 11 (.2%)

South Africa: 0 (0%)

Ghana: 2 (.1%)

Nigeria: 24 (.5%)

Other Western Africa: 6 (.1%)

Australia: 0 (0%)

Other Australian and New Zealand Subregion: 6 (.1%)

Micronesia: 0 (0%)

Barbados: 13 (.3%)

Cuba: 8 (.2%)

Dominican Republic: 37 (.8%)

Jamaica: 47 (1%)

Trinidad Tobago: 4 (.1%)

Other Caribbean: 3 (.1%)

Mexico: 8 (.2%)

Costa Rica: 0 (0%)

El Salvador: 28 (.6%)

Guatemala: 28 (.6%)

Panama: 3 (.1%)

Argentina: 30 (.6%)

Brazil: 32 (.7%)

Chile: 5 (.1%)
68

Colombia: 41 (.9%)

Ecuador: 10 (.2%)

Guyana: 4 (.1%)

Venezuela: 15 (.3%)

Other South America: 32 (.7%)

Canada: 383 (8.2%)

Income

Income Breakdown Households (%)

Less than $15,000: 4337 (15.3%)

$15,000 - $25,000: 3208 (11.3%)

$25,000 - $50,000: 8001 (28.3%)

$50,000 - $75,000: 6450 (22.8%)

Greater than $75,000: 6351 (22.4%)

Tenure

Tenure Breakdown Households (%)

Occupied Housing Units: 28320 (100.0%)

Owner Occupied: 19158 (67.6%)

Renter Occupied 9163 (32.4%)

Jum p t o m ain cont ent.
69

EJ-8 (map with 8-mile circle, NO2 SIA, and locations of interest) 
70

EJ-9 (demographic analysis of 8-mile circle) 

Overview

Total Persons: 166413 Land Area: 97.1% Households in Area: 64551

Population 

Density:

852.08 /sq 

mi Water Area: 2.9% Housing Units in Area: 68010

Percent 

Minority:

21.9% Persons Below 

Poverty Level: 25252 (15.7%) Households on Public Assistance:

3913

Percent

Urban: 91% Housing Units Built <1970:

69% Housing Units Built 

<1950:

39%

Race and Age*

(* Columns that add up to 100% are highlighted) 

Race Breakdown Persons (%) Age Breakdown Persons(%)

White: 138703 (83.3%) Child 5 years or less: 13137 (7.9%)

African-American: 4048 (2.4%) Minors 17 years and younger: 42796 (25.7%)

Hispanic-Origin: 29700 (17.8%) Adults 18 years and older: 123617 (74.3%)

Asian/Pacific Islander: 1648 (1.0%) Seniors 65 years and older: 23964 (14.4%)

American Indian: 246 (0.1%)

Other Race: 18319 (11.0%) This space intentionally left blank

Multiracial: 3449 (2.1%)

Gender

Gender Breakdown Persons (%)

Males: 79740 (47.9%)

Females: 86673 (52.1%)

Education

Education Level (Persons 25 & older) Persons (%)

Less than 9th grade: 8877 (9.0%)

9th -12th grade: 14279 (14.4%)

High School Diploma: 35607 (36.0%)

Some College/2 yr: 19293 (19.5%)

B.S./B.A. or more: 20797 (21.0%)
71

Language

Ability to Speak English Persons (%)

Population Age 5 and Over: 155611

Speak only English: 118547 (76.2%)

Non-English at Home: 37064 (23.8%)

Speak English very well: 20883 (13.4%)

Speak English well: 8046 (5.2%)

Speak English not well: 5610 (3.6%)

Speak English not at all: 2525 (1.6%)

Speak English less than well: 8135 (5.2%)

Language Spoken

Language Spoken Persons (%)

Speak only English: 118547 (76.2%)

Spanish or Spanish Creole: 23763 (15.3%)

French (incl. Patois, Cajun): 2817 (1.8%)

French Creole: 45 (0.0%)

Portuguese or Portuguese Creole: 984 (0.6%)

German: 372 (0.2%)

Yiddish: 1 (0.0%)

Other West Germanic Languages: 43 (0.0%)

Scandinavian Languages: 16 (0.0%)

Greek: 265 (0.2%)

Russian: 1869 (1.2%)

Polish: 3456 (2.2%)

Serbo-Croatian: 198 (0.1%)

Other Slavic Languages: 556 (0.4%)

Armenian: 16 (0.0%)

Persian: 21 (0.0%)

Gujarathi: 16 (0.0%)

Hindi: 73 (0.0%)

Urdu: 101 (0.1%)

Other Indic Languages: 30 (0.0%)

Other Indo-European Lanugages: 222 (0.1%)

Chinese: 324 (0.2%)

Japanese: 135 (0.1%)
72

Korean: 79 (0.1%)

Mon-Khmer, Cambodian: 101 (0.1%)

Miao, Hmong: 12 (0.0%)

Thai: 9 (0.0%)

Laotian: 12 (0.0%)

Vietnamese: 235 (0.2%)

Other Asian Languages: 80 (0.1%)

Tagalog: 104 (0.1%)

Other Pacific Island Languages: 1 (0.0%)

Other Native North American Languages: 28 (0.0%)

Hungarian: 18 (0.0%)

Arabic: 277 (0.2%)

Hebrew: 15 (0.0%)

African Languages: 65 (0.0%)

Non-English Speaking: 37064 (23.8%)

Place of Birth for the Foreign-Born

Country Persons

Foreign-Born Population: 10509

Europe: 6083 (57.9%)

Asia: 1923 (18.3%)

Africa: 149 (1.4%)

Oceania: 10 (.1%)

Americas: 2343 (22.3%)

United Kingdom: 310 (3%)

Ireland: 163 (1.5%)

Sweden: 7 (.1%)

Other Northern Europe: 15 (.1%)

Austria: 33 (.3%)

France: 67 (.6%)

Germany: 407 (3.9%)

Netherlands: 14 (.1%)

Other Western Europe: 35 (.3%)

Greece: 93 (.9%)

Italy: 334 (3.2%)

Portugal: 645 (6.1%)

Spain: 20 (.2%)

Czechoslavakia: 19 (.2%)

Hungary: 18 (.2%)
73

Poland: 1674 (15.9%)

Belarus: 95 (.9%)

Russia: 667 (6.3%)

Ukraine: 1006 (9.6%)

Bosnia and Herzegovina: 52 (.5%)

Yugoslavia: 42 (.4%)

Other Eastern Europe: 368 (3.5%)

Mainland China: 139 (1.3%)

Hong Kong: 44 (.4%)

Taiwan: 19 (.2%)

Japan: 96 (.9%)

Korea: 135 (1.3%)

India: 170 (1.6%)

Iran: 32 (.3%)

Pakistan: 73 (.7%)

Other Central Eastern Asia: 416 (4%)

Cambodia: 69 (.7%)

Indonesia: 29 (.3%)

Laos: 32 (.3%)

Philippines: 126 (1.2%)

Thailand: 4 (0%)

Vietnam: 256 (2.4%)

Israel: 0 (0%)

Jordan: 50 (.5%)

Lebanon: 62 (.6%)

Syria: 19 (.2%)

Turkey: 37 (.4%)

Other Western Asia: 57 (.5%)

Other Eastern Africa: 43 (.4%)

Egypt: 11 (.1%)

South Africa: 1 (0%)

Ghana: 5 (0%)

Nigeria: 49 (.5%)

Sierra Leone: 5 (0%)

Other Western Africa: 6 (.1%)

Australia: 4 (0%)

Other Australian and New Zealand Subregion: 6 (.1%)

Micronesia: 0 (0%)

Barbados: 34 (.3%)

Cuba: 32 (.3%)

Dominican Republic: 286 (2.7%)

Jamaica: 95 (.9%)

Trinidad Tobago: 25 (.2%)
74

Other Caribbean: 13 (.1%)

Mexico: 152 (1.5%)

Costa Rica: 8 (.1%)

El Salvador: 54 (.5%)

Guatemala: 43 (.4%)

Honduras: 2 (0%)

Panama: 18 (.2%)

Other Central America: 6 (.1%)

Argentina: 59 (.6%)

Brazil: 58 (.6%)

Chile: 5 (0%)

Colombia: 260 (2.5%)

Ecuador: 42 (.4%)

Guyana: 15 (.1%)

Peru: 12 (.1%)

Venezuela: 52 (.5%)

Other South America: 71 (.7%)

Canada: 1000 (9.5%)

Other North America: 0 (0%)

Income

Income Breakdown Households (%)

Less than $15,000: 13092 (20.3%)

$15,000 - $25,000: 8221 (12.7%)

$25,000 - $50,000: 18658 (28.9%)

$50,000 - $75,000: 12977 (20.1%)

Greater than $75,000: 11691 (18.1%)

Tenure

Tenure Breakdown Households (%)

Occupied Housing Units: 64551 (100.0%)

Owner Occupied: 37422 (58.0%)

Renter Occupied 27129 (42.0%)