VERMONT AGENCY OF NATURAL RESOURCES

Department of Environmental Conservation

Air Pollution Control Division

TECHNICAL SUPPORT DOCUMENT 

FOR

PERMIT TO CONSTRUCT

#AP-11-038

Permit Date: April 19, 2013

North Springfield Sustainable Energy Project, LLC

North Springfield, VT

Prepared By: Steven K. Snook

Air Pollution Control Division

This Technical Support Document details the Agency of Natural Resources, Department of 

Environmental Conservation, Air Pollution Control Division review for the Air Pollution Control 

Permit to Construct and is intended to provide additional technical information, discussion and 

clarification in support of the Permit. It is not intended to provide a comprehensive review of the 

Facility or permit process or duplicate the information contained in the Permit.
North Springfield Sustainable Energy Project, LLC AP-11-038

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Facility:

North Springfield Sustainable Energy 

Project, LLC

36 Precision Drive

North Springfield, VT 05150

Application Contact Person:

Dale Raczynski

Epsilon Associates, Inc.

3 Clock Tower Place, Suite 250

Maynard, MA 01754

Phone - (978)-897-7100

Facility Contact Person:

Daniel Ingold

36 Precision Drive, 

North Springfield, VT 05150-9706

Phone - 802-886-6100

1.0 INTRODUCTION

North Springfield Sustainable Energy Project, LLC (hereinafter “Permittee”) has proposed to 

construct/install and operate wood fired electrical generating station, with an electrical 

generation rate of approximately 37 MW (net), at 36 Precision Drive in North Springfield, 

Vermont (also referred to herein as “Facility”). The parent corporation for North Springfield 

Sustainable Energy Project, LLC is Winstanley Enterprises, LLC.

Administrative Milestones:

Table 1-1: Administrative Summary

Administrative Item Result or Date

Date Application Received: 12/29/2011

Date Administratively Complete: 12/29/2011

Date Draft Decision: 8/9/2012

Date & Location Draft Decision/Comment Period 

Noticed: 8/9/2012 Claremont Eagle Times

Date & Location Public Meeting Noticed: 8/9/2012 Claremont Eagle Times

Date & Location of Public Meeting: 8/29/2012 at Springfield High School

Deadline for Public Comments: 9/10/2012

Date Final Decision: 4/19/2013

Classification of Source Under §5-401: §5-401(3): Electric power generation facilities

Classification of Application: New Source Review/ Prevention of Significant 

Deterioration Construction Permit

New Source Review Designation of Source: Major Stationary Source

Facility SIC Code(s) & Descriptions: 4911 – Electrical Services
North Springfield Sustainable Energy Project, LLC AP-11-038

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The allowable emissions for the Facility are summarized below:

Table 1-2: Estimated Air Contaminant Emissions (tons/year)1

PM/PM10 /PM2.5 SO2 NOx CO VOC HAPs 2 CO2e 3

38.6 40.6 62.4 153.3 10.2 <10/25 448,714

1 PM/PM10/PM2.5 - particulate matter, SO2 - sulfur dioxide, NOx - oxides of nitrogen, CO - carbon monoxide, VOC –

volatile organic compounds, HAPs - hazardous air pollutants. 2

 Emissions of individual HAPs each < 10 tpy and emissions of total HAPs combined <25 tpy. 3

 CO2e ‘at the stack’ – includes emissions from biogenic sources. See section 3.3 for details. This is not a facility 

limit.

Total PM emissions from the Facility, including both filterable and condensable components, are 

conservatively assumed to also be categorized as PM2.5 and thus also PM10. Filterable PM 

represents the PM that is in solid form in the heated exhaust gas at the point of sampling. 

Condensable PM represents pollutants that are in gaseous form in the heated exhaust at the 

point of sampling but will become PM upon cooling and condensing and includes high molecular 

weight organics. 

2.0 FACILITY DESCRIPTION AND LOCATION

2.1 Facility Locations and Surrounding Area

North Springfield Sustainable Energy Project, LLC will be located at 36 Precision Drive 

in North Springfield, Vermont. The areas surrounding the Facility include mixed 

industrial, commercial, forested, and suburban residential land uses. The Facility is 

approximately 0.9 km from the western bank of the Black River. The Jeld-Wen door 

company is immediately to the west of the Project site. A gravel pit operation is 

immediately to the north and east of the project site. A non-operating gravel pit and 

concrete block plant is immediately to the south of the project site. A number of other 

small industrial firms are located immediately northwest of the Facility. To the north, 

south, and east of the Facility, the land use is mixed residential, farmland and forested 

areas. The Facility is located less than 1 km south of the center of North Springfield, 

and approximately 5 km to the northwest of Springfield, VT. 

The Lye Brook Wilderness Area is approximately 41 km to the southwest of the Facility. 

The nearest Vermont designated sensitive area (elevation at or above 2500 ft elevation): 

is Mount Ascutney, with an elevation of 3,143 feet, located approximately 14.5 km

northeast of the Facility.

2.2 Facility Description

Operations performed at the Facility are classified within the Standard Industrial 

Classification Code / North American Industrial Classification System Code 4911 -

Electrical services (other electrical power generation) / 221119 - Other Electric Power

Generation. Regulated sources of air contaminant emissions at the Facility are listed in 

Table 2-1, and Table 2-2 lists information on air pollution control equipment at the 

Facility.
North Springfield Sustainable Energy Project, LLC AP-11-038

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TABLE 2-1: Equipment and Stack Information

Equipment/Make/Model Capacity/ Size Fuel or 

input 

material

Air Pollution 

Control 

Equipment

Stack 

Height 

(feet)

Boiler: wood fired advanced 

fluidized bed boiler

Four (4) auxiliary/start-up burners 

for the boiler

Maximum annual 

average heat input 

(45%moisture 

content wood): 

464 MMBtu/hr 1

Maximum short

term 6 heat input 

(55%moisture 

content wood): 

502 MMBtu/hr 1

Natural 

Wood Fabric filter

and

Selective Catalytic 

Reduction (SCR)

140

40 MMBtu/hr 

(each)

160 MMBtu/hr 1

(total)

ULSD 2

One (1): Emergency Diesel Engine 

Generator 3,000 kW 4

ULSD 2

Tier 2 

per 40 CFR

Part 89

-

Diesel Engine Fire Pump 450 bhp 5 Tier 3 

per 40 CFR

Part 89

-

1

 MMBtu/hr – million British Thermal Units of heat input per hour 2

 ULSD – ultra low sulfur diesel (0.0015% or 15 ppm sulfur content). 3

 gpm – gallons per minute 4

 kW – rated kilowatt output 5

 bhp – rated brake horse power output 6 Maximum short term heat input has been used to establish pollutant emission rates for review of short 

term NAAQS (≤24-hr standards).

Table 2-2: Air Pollution Control Equipment

Boiler –

Pulse-jet fabric filter dust collector

Inlet Temperature: 430 oF

Maximum design flue gas rate: 260,000 acfm

6 compartments, each with 340 filter bags

Nominal bag dimensions: 6” x 26.33’ (39.77 ft2/bag)

Total cloth filtering area: 81,130 ft2, Air/Cloth = 3.2 (gross)

22 oz./yd2 woven fiberglass with Teflon and ePTFE coating

Pressure drop – typical range: 4.5 – 6.5” w.c.

Boiler - Selective Catalytic 

Reduction for NOx.

Inlet Temperature: 425 oF

Details not available at this time.

In series, following boiler fabric filter dust collector. 1

 The term fabric filter is synonymous with the term bag house for this document.
North Springfield Sustainable Energy Project, LLC AP-11-038

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2.3 Description of Compliance Monitoring Devices 

The Facility will be equipped with continuous emission monitoring systems (CEMS) 

which measures exhaust flow and the emission rates of NOx, CO, NH3, and CO2 from 

the Boiler exhaust stack to the ambient air. In addition, the Facility will operate and 

maintain a continuous opacity monitoring system (COMS) which measures the opacity of 

the exhaust gas from the Boiler. If required by the Acid Rain Program, an SO2 CEMS 

will also be used.

2.4 Identification of Sources with Insignificant or Negligible Emissions

Although not required for determining applicability with Subchapter X, quantifiable 

emissions from “insignificant activities” must be included for the purposes of establishing 

whether or not a source is subject to other air pollution control requirements, including, 

but not limited to: reasonably available control technology, major source status, and Title 

V operating permit applicability.

Additionally, guidance provided by the U.S. EPA (entitled “White Paper for Streamlined 

Development of Part 70 Permit Applications”) lists activities which are considered as 

“trivial” sources of air contaminants, and may be presumptively omitted from operating 

permit applications.

Table 2-3 lists activities at the Facility which were considered trivial, negligible or exempt 

sources of air contaminant emissions, and therefore were not considered as emission 

sources as part of the Permit review. 

Table 2-3: Negligible Sources of Contaminant Emissions

Fuel storage tanks: Diesel fuel storage tanks.

Fly ash storage silo

The Permittee has proposed to utilize a sealed fly ash handling system that 

conditions the ash with water before discharging the ash from the system as a 

wetted cake.

It should be noted that a process or piece of equipment which is considered a “negligible 

activity” does not relieve the owner or operator from the responsibility of complying with 

any applicable requirements associated with said process or equipment.

2.5 Proposed Limitations

 

The Permittee has not proposed any operating limits for the Boiler. However, the annual 

potential to emit calculations are based on an average heat input of 464 MMBtu/hr (vs. 

the maximum design heat input of 502 MMBtu/hr), for 365 days per year, so the permit 

will have an annual heat input limit of 4,064,640 MMBtu/yr. Assuming 4,500 Btus per 

pound of 45% moisture wood, this equates to approximately 451,627 tons/yr of wet 

wood fuel. 
North Springfield Sustainable Energy Project, LLC AP-11-038

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In their application, the Permittee used 65 hours of operation to estimate the potential 

emissions from the diesel powered emergency generator and the diesel engine fire 

pump during routine testing and maintenance. The permit will include 65 hours as a 

limitation for the routine testing and maintenance of these diesel engines. Actual 

emergency hours of operation are not limited.

Short term emission limits are determined by MSER and/or HMSER determinations 

below.

3.0 QUANTIFICATION OF POLLUTANTS

The quantification of emissions from a stationary source is necessary in order to establish the 

appropriate regulatory review process for the operating permit application and to determine 

applicability of various air pollution control requirements. These determinations are normally 

based upon allowable emissions. Allowable emission is defined as the emission rate calculated 

using the maximum rated capacity of the source and, if applicable, either: (a) the applicable 

emission standard contained in the Regulations, if any, or (b) the emission rate or design, 

operational or equipment standard specified in any order or agreement issued under the 

Regulations that is state and federally enforceable. An applicant may impose in its application 

an emission rate or design, or an operational or equipment limitation which may be incorporated 

in the Permit to restrict operation to a lower level. Such limitations may include fuel restrictions 

or production limits.

3.1 Estimating Potential Emission of Criteria Pollutants from the Proposed 

Stationary Source

For the Boiler, the calculated allowable annual emissions of SO2, NOX, PM, CO and 

VOCs are based on the established emission limits expressed in lbs/MMBtu and an 

annual average maximum heat input of 464 MMBtu/hr. Short term emission rates (for air 

dispersion modeling) will be based on the maximum design heat input of 502 MMBtu/hr. 

Since firing with ULSD only occurs at startup there are no separate emission limits 

established specifically for oil firing. The Facility is expected to comply with the long 

term emission limits (>24 hours) at all times (including startup) regardless of fuel. The 

short term limits for NOx, CO and VOC do not apply during the startup of the boiler. 

Start up emission limits for NOx, CO and VOC will be established from operating data, 

CEMS data as well as stack test data and will be included in the Facility’s Title V 

Operating Permit.

Potential HAP emissions are based on a combination of emission factors from the U.S. 

EPA document, A Compilation of Air Pollutant Emission Factors (AP-42), emission data 

from the National Council for Air and Stream Improvement (NCASI) Technical Bulletin 

No. 858 and stack testing conducted at other biomass boilers in New England; additional 

details regarding this data is available in Section 3.2 of this document. 
North Springfield Sustainable Energy Project, LLC AP-11-038

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Table 3-1: Boiler - Allowable Emissions

464 MMBtu/hr heat input x 8760 hours = 4,064,640 MMBtu/yr annual heat input

Emission Factor Allowable Emissions

Factor Units tons per year 1 Source

SO2 0.020 lb/MMBtu MSER 40.6

NOx – Annual 0.03 lb/MMBtu MSER 61.0

NOx – hourly 0.06 lb/MMBtu MSER -

PM10/PM2.5/PM 2 0.019 lb/MMBtu MSER / HMSER 38.6

CO 0.075 lb/MMBtu MSER / HMSER 152.4

VOC 0.005 lb/MMBtu HMSER 10.2

HAPs 0.0075 lb/MMBtu

AP-42, Wood Residue Combustion in 

Boilers, Tables 1.6-3 and 1.6-4 (9/03), 

NCASI Technical Bulletin No. 858, 

representative stack tests.

15.33

1

 lb/MMBtu: pounds of pollutant emitted per million British Thermal Units (HHV) of energy input to the boiler. 2

 PM: total PM including filterable and condensable fractions. 3 No individual HAP exceeds 10 tons per year and combined HAPs are less than 25 tons per year.

Table 3-2: Diesel Generators – Allowable Emissions

Emission estimate 

based on 65 hours 

3000 kW Tier 2 Engine

Emission Factor Allowable Emissions, 

tons/yr Factor Units Source

SO2 0.0015 lb/MMBtu 15 ppm sulfur content in fuel 0.0015

PM 0.2

g/kW-hr

EPA Tier 2 Engine

0.04

NOX 6.4 1.37

CO 3.5 0.75

VOC - - -

Table 3-3: Fire Pump/Diesel Engine – Estimated Emissions

Emission estimate 

based on 65 hours

450 hp Tier 3 Engine

23.5 gph

Emission Factor

Allowable Emissions, 

tons/yr Factor Units Source

SO2 0.0015 lb/MMBtu 15 ppm sulfur content in fuel 0.0002

PM 0.15

g/BHP-hr

EPA Tier 3 Engine

0.005

NOX 3.0 0.10

CO 2.6 0.09

VOC - - -
North Springfield Sustainable Energy Project, LLC AP-11-038

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Table 3-4: Summary of Allowable Air Contaminant Emissions by Source (tons/year)

Source PM/PM10 SO2 NOX CO VOC Total 

HAPs

Boiler 38.6 40.6 61.0 152.4 10.2 15.3

Diesel generators (1@3000kW) 0.04 - 1.37 0.75 - -

Diesel fire pump - - 0.1 0.08 - -

Facility Totals 38.64 40.6 62.4 153.3 10.2 15.3

Significance Levels 25/15 40 40 50 40 -

As summarized in Table 3-4 above:

• The Facility has allowable emissions of all air contaminants in the aggregate of ten (10) 

or more tons per year and has allowable emissions of carbon monoxide in excess of 100 

tons per year: the Facility is therefore subject to Subchapter X of the Regulations and is 

designated as a Title V Subject Source. The Facility will be required to file an 

application for a Title V Permit to Operate within one year of commencing operation.

• The Facility has allowable emissions of NOX and CO greater than 50 ton/year which 

classifies the source as a “Major Source” and therefore is subject to the new source 

review requirements of §5-502 of the Regulations. In addition, for a Major Source, the 

allowable emissions of the other criteria pollutants are reviewed to determine if they 

exceed their respective ‘significant emission rate.’ PM10 and SO2 exceed their significant 

emission rates and will also be subject to §-502 of the Regulations. See section 5.0 for 

the review of the Most Stringent Emission Rate for the affected pollutants.

• The Facility is an electrical generating unit which uses fossil fuel (ULSD startup burners) 

and has a rating of > 25 MW; therefore the Facility is subject to the Acid Rain Program 

and the Permittee must file an Acid Rain permit application at least 24 months before 

commencing operation.

3.2 Estimating Emissions of Hazardous Air Contaminants.

The potential emissions of Vermont Hazardous Air Contaminants are estimated based 

on the maximum operating load for the Boiler and an appropriate emission factor. For 

this review the emission factors are based on a combination of sources that best 

represent the expected emissions from the respective sources: U.S. EPA AP-42, the 

National Council for Air and Stream Improvements (NCASI) and stack testing of similar 

wood fired boilers located in Vermont and the rest of New England.
North Springfield Sustainable Energy Project, LLC AP-11-038

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Table 3-5 Quantification of HAC Emissions

Hazardous Air 

Contaminant CAS#

Toxic 

Category

Boiler 

Emission 

Factor

Boiler EF 

Source 1

Facility 

Emission 

Rate

Action 

Level

Above 

Action 

Level?

(lb/mmbtu) (lb/8-hrs) (lb/8-hrs)

1,1,1-Trichloroethane 71556 II 3.10E-05 AP-42 1.15E-01 8.30E+01

1,2-Dichloroethane 

(ethylene dichloride) 107062 I 2.90E-05 AP-42 1.08E-01 3.20E-03 Yes

1,2-Dichloropropane 

(propylene dichloride) 78875 I 3.30E-05 AP-42 1.22E-01 4.20E-03 Yes

2,4,6-Trichlorophenol 88062 I 2.20E-07 NCASI 8.17E-04 2.70E-02

Acetaldehyde 75070 I 1.90E-04 NCASI 7.05E-01 3.80E-02 Yes

Acetone 67641 II 2.20E-04 NCASI 8.17E-01 2.61E+01

Acrolein 107028 II 2.40E-04

AP-42 

(LO) 8.91E-01 2.00E-03 Yes

Ammonia II 6.00E-03 HMSER 2.23E+01 8.30E+00 Yes

Antimony II 7.90E-06 AP-42 2.93E-02 3.00E-01

Arsenic I 4.00E-06

AP-42 

(LO) 1.48E-02 1.90E-05 Yes

Barium II 1.70E-04 AP-42 6.31E-01 4.00E-02 Yes

Benzene 71432 I 8.50E-04

AP-42 

(LO) 3.16E+00 1.10E-02 Yes

Benzo(a)pyrene 50328 I 2.67E-06 NCASI 9.91E-03 4.00E-05 Yes

Beryllium I 1.90E-06 NCASI 7.05E-03 3.50E-05 Yes

Bromodichloromethane 75274 I 3.00E-03 NCASI 1.11E+01 4.60E-03 Yes

Bromomethane (methyl 

bromide) 74839 II 1.50E-05 AP-42 5.57E-02 4.00E-01

Cadmium I 4.10E-06 AP-42 1.52E-02 4.60E-05 Yes

Carbon disulfide 75150 II 1.30E-04 NCASI 4.83E-01 5.45E+01

Carbon tetrachloride 56235 I 8.90E-07 NCASI 3.30E-03 5.50E-03

Chlorine 7782505 III 7.90E-04 AP-42 2.93E+00 1.00E-02 Yes

Chlorobenzene 108907 II 3.30E-05 AP-42 1.22E-01 2.00E-01

Chloroform 67663 I 3.10E-05 NCASI 1.15E-01 3.60E-03 Yes

Chloromethane (methyl 

chloride) 74873 II 4.00E-05 NCASI 1.48E-01 7.50E+00

Chromium (total) II 2.10E-05 AP-42 7.80E-02 1.00E-02 Yes

Chromium, hexavalent I 2.00E-06

AP-42 

(LO) 7.42E-03 6.90E-06 Yes
North Springfield Sustainable Energy Project, LLC AP-11-038

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Table 3-5 Quantification of HAC Emissions

Hazardous Air 

Contaminant CAS#

Toxic 

Category

Boiler 

Emission 

Factor

Boiler EF 

Source 1

Facility 

Emission 

Rate

Action 

Level

Above 

Action 

Level?

(lb/mmbtu) (lb/8-hrs) (lb/8-hrs)

Cobalt I 6.50E-06 AP-42 2.41E-02 8.30E-04 Yes

Copper (dusts & mists) II 4.90E-05 AP-42 1.82E-01 2.00E-02 Yes

Cumene 98828 II 1.80E-05 NCASI 6.68E-02 3.32E+01

Di-butyl phthalate 84742 II 3.30E-05 NCASI 1.22E-01 2.50E-01

Dichloromethane 

(methylene chloride) 75092 I 5.40E-04 NCASI 2.00E+00 1.70E-01 Yes

Dinitrotoluene-2,4 121142 I 9.40E-07 NCASI 3.49E-03 4.20E-04 Yes

Ethanol 64175 II 6.80E-05 NCASI 2.52E-01 3.72E+01

Ethylbenzene 100414 I 3.10E-05 AP-42 1.15E-01 8.30E+00

Fluoranthene 206440 II 1.64E-06 NCASI 6.09E-03 1.20E+00

Formaldehyde 50000 I 1.20E-03

AP-42 

(LO) 4.45E+00 6.50E-03 Yes

Hexachlorobenzene 118741 I 1.00E-06 NCASI 3.71E-03 1.80E-04 Yes

Hexane 110543 II 2.90E-04 NCASI 1.08E+00 5.81E+02

Hydrogen Chloride 7647010 II 8.34E-04 Test 3.10E+00 1.70E+00 Yes

Iron oxides - dusts & 

fumes II 9.90E-04 AP-42 3.67E+00 1.00E+00 Yes

Isopropanol 67630 II 3.90E-03 NCASI 1.45E+01 1.84E+02

Lead compounds I 4.80E-05 AP-42 1.78E-01 8.30E-04 Yes

Manganese II 8.60E-05

AP-42 

(LO) 3.19E-01 4.00E-03 Yes

Mercury II 3.50E-06 NCASI 1.30E-02 2.00E-02

Methanol 67561 II 8.30E-04 NCASI 3.08E+00 9.70E+01

Methyl ethyl ketone 78933 II 9.10E-06 NCASI 3.38E-02 4.15E+02

Methyl Isobutyl Ketone 108101 II 2.30E-05 NCASI 8.54E-02 2.49E+02

Molybdenum 

compounds (metal & 

insoluble) II 2.10E-06 AP-42 7.80E-03 2.00E-01

Naphthalene 91203 I 1.60E-04 NCASI 5.94E-01 2.00E-02 Yes

Nickel compounds I 3.30E-05 AP-42 1.22E-01 1.70E-04 Yes

PCDD/PCDF (VT 

APCD Memo 2/7/2011) - I 1.38E-10 NCASI 5.12E-07 1.93E-09 Yes
North Springfield Sustainable Energy Project, LLC AP-11-038

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Table 3-5 Quantification of HAC Emissions

Hazardous Air 

Contaminant CAS#

Toxic 

Category

Boiler 

Emission 

Factor

Boiler EF 

Source 1

Facility 

Emission 

Rate

Action 

Level

Above 

Action 

Level?

(lb/mmbtu) (lb/8-hrs) (lb/8-hrs)

Pentachlorophenol 87865 I 5.10E-08 AP-42 1.89E-04 2.40E-03

Phenanthrene 85018 II 7.21E-06 NCASI 2.68E-02 8.70E+00

Phenol 108952 II 5.10E-05 AP-42 1.89E-01 5.30E+00

Pyrene 129000 II 3.79E-06 AP-42 1.41E-02 8.70E-01

Selenium II 3.00E-06 NCASI 1.11E-02 1.50E-01

Silver compounds 

(metal) II 1.40E-04 NCASI 5.20E-01 6.60E-01

Styrene 100425 I 6.40E-04 NCASI 2.38E+00 8.30E+00

Sulfuric Acid Mist II 9.19E-04 APCD 3.41E+00 2.70E-02 Yes

Tetrachloroethylene 

(perchloroethylene) 127184 I 3.82E-05 AP-42 1.42E-01 1.50E-02 Yes

Tin compounds (metal 

and inorganic) II 3.90E-05 NCASI 1.45E-01 4.00E-01

Toluene 108883 II 2.90E-05 NCASI 1.08E-01 2.49E+01

Trichloroethylene 79016 I 3.00E-05 AP-42 1.11E-01 4.00E-02 Yes

Trichlorofluoromethane 75694 II 4.10E-05 AP-42 1.52E-01 4.66E+01

Vanadium pentoxide I 9.80E-07 AP-42 3.64E-03 8.30E-04 Yes

Vinyl Chloride 75014 I 1.80E-05 AP-42 6.68E-02 9.10E-03 Yes

Xylenes (includes 

o,m,p) - II 2.80E-05 NCASI 1.04E-01 8.30E+00

Zinc oxide II 4.20E-04 AP-42 1.56E+00 8.30E-02 Yes

1

 Sources of Emission Factors: 

AP-42 = U.S. EPA document, A Compilation of Air Pollutant Emission Factors, 5th Edition.

AP-42 (LO) = An adjusted emission factor after auditing AP-42 for outlier data. Refer to the NSSEP permit 

application, Appendix A, Table A-2 for further details.

NCASI = National Council for Air and Stream Improvement (NCASI) Technical Bulletin No. 858.

Test = stack testing conducted at other biomass boilers in New England.

APCD = Based on Babcock & Wilcox technical paper: A System Approach to SO3 Mitigation, and Motobec 

USA technical paper: Reducing SO2 Emissions at Coal Fired Power Plants.

HMSER = Hazardous Most Stringent Emission Rate – see section 7.4 of this document.
North Springfield Sustainable Energy Project, LLC AP-11-038

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3.3 – Estimating Potential Greenhouse Gas Emissions

The estimate for potential GHG emissions includes the distillate fuel oil that would be used for 4 cold startups of the boiler. Each cold 

startup is expected to take 11 hours and consume an estimated 9,000 gallons of distillate fuel. The estimate does not ‘back-out’ the 

reduced wood fuel usage during these startups, so the estimate for GHG is conservatively high.

Section 3.3 Estimation of CO2e Emissions

Source Source

Estimated 

wood 

usage 

ID Description Units (raw tons)

Main Boiler 275,994 tons 451627 45.0%

Auxilliary burners 36,000 gallons 0 0.0%

Emergency engines 15,386 gallons 0 0.0%

Table 2. Total Company-Wide Stationary Source Fuel Combustion

Quantity

Fuel Type Combusted Units

51,386 gallons

275,994 tons

Table 3. Total Company-wide CO2, CH4 and N2O Emissions from Stationary Source Fuel Combustion

CO2 CO2 CH4 CH4 N2O N2O

(kg) (lb) (kg) (lb) (kg) (lb)

Distillate Fuel Oil #2 524,465 1,156,246 21.3 46.9 4.3 9.4

Total Fossil Fuel Emissions 524,465 1,156,246 21.3 46.9 4.3 9.4

Wood Fuel 398,161,195 877,794,134 135,833 299,461 17,828 39,304

Total Non-Fossil Fuel Emissions 398,161,195 877,794,134 135,833 299,461 17,828 39,304

Total Emissions for all Fuels 398,685,660 878,950,380 135,855 299,508 17,832 39,314

Global Warming Potential CO2 CH4 N2O

1.0 21.0 310.0 metric ton short ton

Total CO2 Emissions - Equivalent (Fossil CO2e + Biogenic CH4 & N2O) 8,905 9,817

All CO2e emissions at stack (Fossil CO2e + Biogenic CO2e) - for APCD Permit info 407,067 448,714

CO2e

Wood Fuel

Distillate Fuel Oil #2

Fuel Type

The wood fuel emission factors are based on wood with 10% moisture content, so 451,627 tons @ 45% MC is 

converted to 275,994 tons @ 10% MC

Potential/ 

Allowable 

Quantity 

Combusted

Estimated 

%MC for 

raw wood 

fuel

Wood Fuel

Distillate Fuel Oil #2

Distillate Fuel Oil #2

Fuel Combusted
North Springfield Sustainable Energy Project, LLC AP-11-038

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4.0 DISCUSSION OF SELECT APPLICABLE AND NON-APPLICABLE REQUIREMENTS

The Agency will assess compliance with these regulations during any inspections of the Facility. 

The inspections will include confirmation of the proper operation and maintenance of equipment 

and air pollution control devices, visual observations of emission points, and review of any 

records required by the Permit.

4.1 Vermont Air Pollution Control Regulations and Statutes

§5-201 and §5-202 - Open Burning Prohibited and Permissible Opening 

Burning

Open burning of materials is prohibited except in conformance with the 

requirements of this section. 

§5-211(2) - Prohibition of Visible Air Contaminants - Installations 

constructed subsequent to April 30, 1970

This emission standard applies to all point sources of air emissions at the 

Facility.

§5-221(1) - Prohibition of Potentially Polluting Materials in Fuel; Sulfur 

Limitation in Fuel

This prohibition applies to all stationary fuel burning equipment used on-site. 

Based on the application submittal the Permittee is expected to comply with this 

regulation based on the use of Ultra Low Sulfur Diesel fuel oil certified by the 

supplier to contain no more 0.0015% (15 ppm) sulfur by weight and natural 

wood.

§5-231(3) - Prohibition of Particulate Matter; Combustion Contaminants

Based on the application submitted and information available to the Agency, this 

Facility has applicable fuel burning equipment subject to this regulation. The 

allowable particulate emissions based on minimum standards of 5-231(3) are 

shown in Table 4-1, however the Facility is limited to a more stringent emission 

standard under the MSER requirements of 5-502(3). 

Table 4-1: Equipment Subject to §5-231(3)

Equipment ID Size/Capacity Emission Standard, 

lbs/MMBtu

Allowable Emissions, 

lbs/hr

Boiler 502 MMBtu/hr 0.1 50.2

§5-231(4) - Prohibition of Particulate Matter; Fugitive Particulate Matter

This section requires the use of fugitive PM control equipment on all process 

operations and the application of reasonable precautions to prevent PM from 

becoming airborne during the handling, transportation, and storage of materials, 

or use of roads. This requirement applies to the entire Facility.

§5-241(1) & (2) - Prohibition of Nuisance and Odor 

This requirement applies to the entire Facility and prohibits the discharge of air 
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contaminants that would be a nuisance to the public or the discharge of 

objectionable odors beyond the property-line of the Facility.

§5-251 - Control of Nitrogen Oxide Emissions

Based on the application submittal and information available to the Agency, the 

boiler is greater than 250 MMBtu/hr and is subject to this regulation 5-251(1) 

while burning fossil fuel. However the boiler is being held to a more stringent 

emission standard under the MSER requirements of 5-502(3). The Facility does 

not have allowable emissions of NOX in excess of 100 tons per year and is 

therefore not subject to subsection 5-251(3). 

§5-252 - Control of Sulfur Dioxide Emissions

Based on the application submittal and information available to the Agency, the 

boiler is greater than 250 MMBtu/hr and is subject to this regulation while burning 

fossil fuel. However the boiler is being held to a more stringent emission standard 

under the MSER requirements of 5-502(3).

§5-253.1 – 5-253.20 - Control of Volatile Organic Compounds

Based on the application submittal and information available to the Agency, this 

Facility currently has no applicable operations subject to this regulation.

§5-261 - Control of Hazardous Air Contaminants 

See Section 7.0 below.

§5-271 – Control of Air Contaminants from Stationary Reciprocating 

Internal Combustion Engines

This emission standard applies to all stationary reciprocating internal combustion 

engines with a brake horsepower output rating of 450 hp or greater. This section 

applies to the emergency generator and fire pump engine at the Facility. 

4.2 Regional Greenhouse Gas Initiative Vermont CO2 Budget Trading Program -

The Regional Greenhouse Gas Initiative (RGGI) is a cooperative, market-based 

regulatory CO2 emission trading program among nine Northeast and Mid-Atlantic 

states (States). Participating states include Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and 

Vermont. RGGI is intended to stabilize and then reduce emissions of CO2 from 

fossil fuel-fired electrical generating systems with a nameplate capacity equal to 

or greater than 25 MWe. Sources subject to RGGI are required to purchase and 

hold allowances equivalent to their actual emissions of CO2 over each three year 

control period and certify compliance at the end of each respective control 

period. Emission allowances are primarily auctioned by the States, which, in 

turn, invest the auction proceeds in energy-related consumer benefit programs.

Compliance with RGGI is defined and administered under the Vermont CO2

Budget Trading Program Regulations (Program Regulations)
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A “fossil fuel-fired electrical generating system” is defined under §22-102 of the 

Program Regulations as a unit where “...the combustion of fossil fuel, alone or in 

combination with any other fuel, where the fossil fuel combusted comprises, or is 

projected to comprise, more than 50 percent of the annual heat input on a Btu 

basis during any year “. 

Although the generation capacity at the Facility has a nameplate rating of greater 

than 25 MWe, the Facility is not intended or projected to use greater than 50 

percent fossil fuel for its annual heat input. As such, it is not subject to the 

requirements of RGGI or the Program Regulations. 

4.3 Federal Air Pollution Control Regulations and the Clean Air Act

40 C.F.R. Part 60 Subpart Db – Standards of Performance for Small 

Industrial-Commercial-Institutional Steam Generating Units

“The affected facility to which this Subpart applies is each steam generating unit 

for which construction, modification, or reconstruction is commenced after June 

19, 1984 and that has a maximum design heat input capacity of greater than 29 

megawatts (MW) (100 million BTU per hour).

The Boiler is subject to this regulation. However the boiler is held to more 

stringent emission standards through MSER.

40 C.F.R. Part 60 Subpart IIII – Standards of Performance for Stationary 

Compression Ignition Internal Combustion Engines

Applies to CI RICE model year 2007 and newer. This regulation establishes

emission rates for affected engines, requires routine engine maintenance and 

sets maximum sulfur content for the diesel fuel. Beginning October 1, 2010 

applicable engines shall only use diesel fuel with a maximum sulfur content of 15 

ppm (ULSD). 

This regulation applies to the diesel engines that power the emergency generator 

and the fire pump at the Facility.

40 C.F.R. Part 63 Subpart JJJJJJ – National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial and Institutional 

Boilers – area sources.

This regulation has requirements for emission limits (PM <0.03 lb/MMBtu heat 

input), work practice standards, operating limits for the PM control device, 

performance stack testing, and demonstrating continuous compliance (similar to 

Compliance Assurance Monitoring discussed below).

Since the Facility has HAP emissions less than 10 tons for each individual HAP 

and less than 25 tons for all HAPs combined it is classified as an area source of 

HAPs, not a major HAP source, and therefore this regulation applies to the Boiler

rather than the major source regulation Subpart DDDDD.
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40 C.F.R. Part 63 Subpart ZZZZ – National Emission Standards for

Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. 

Applies to new engines installed after June 12, 2006 at area sources of HAPs. 

Requires such engines to meet the emission standards of NSPS Subpart IIII and 

JJJJ, imposes ULSD fuel limitations, and imposes maintenance requirements. 

Separate provisions of ZZZZ also apply to existing engines installed prior to June 

12, 2006. 

Subpart ZZZZ applies to the diesel engines that power the emergency generator 

and the fire pump at the Facility requiring them to meet NSPS Subpart IIII.

Clean Air Act §§114(a)(3), 502(b), and 504(a)-(c); 40 CFR Part 70 

§§70.6(a)(3)(i)(B) and 70.6(c)(1); and 40 CFR Part 64 - Compliance 

Assurance Monitoring. 

This Facility will be subject to CAM. The emissions of PM and NOx from the 

Boiler are subject to CAM because: 

• the Facility is a Title V Subject Source;

• the uncontrolled emission rates of PM and NOx exceed their respective 

Title V major source thresholds (100 ton/yr); 

• the emissions of PM (NSPS, MSER and HMSER) and NOx (MSER) are 

subject to an applicable rule;

• the Boiler is equipped with emissions control devices for each of these 

pollutants. Note that CO is controlled based on the bubbling fluidized bed 

boiler design which is not considered an emission control device for CAM, 

so CAM does not apply to CO for this Facility. Considering that the 

Facility is otherwise required to have a CO CEMS, CAM does not offer 

any additional significant monitoring benefits for CO.

The CAM Plan for this Facility will be included in the Title V Operating permit. 

The Facility is required to file an application for a Title V Operating permit within 

one year of commencing operation. The Facility is expected to establish the 

parameters of the CAM plan during the initial operating period of the Facility so 

they can be included in the CAM plan portion of the Title V operating permit 

application.

40 C.F.R. Parts 72-78 – Acid Rain Program

The Permittee is required to operate the Facility under a permit that includes the 

Acid Rain Program requirements. This regulation requires that the Facility be 

equipped with a CEMS for opacity, exhaust flow, diluents, NOX and SO2

emissions, although the Permittee may petition EPA to use a default SO2

emission factor pursuant to 75.11(e)(1) and (f). This regulation also requires the 

Permittee meet additional recordkeeping and reporting requirements. Pursuant 

to §72 the Facility is required to file an application for an Acid Rain permit at least 

24 months prior to commencing operation.
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40 C.F.R. Part 98 – Mandatory Greenhouse Gas Reporting

Pursuant to §98.2(a)(1)(i) the Permittee is required to report the Facility’s 

greenhouse gas emissions from the Boiler.

4.4 Non-Applicable Requirements for Which a Permit Shield Provision Has 

Been Requested

Pursuant to §5-1015(a)(14) of the Regulations, an owner/operator may request to 

be shielded from potentially applicable state or federal requirements. The Facility 

has not requested a permit shield from any specific, potentially applicable 

requirement. Accordingly, the Agency has not granted any permit shields for the 

Facility.

5.0 CONTROL TECHNOLOGY REVIEW FOR MAJOR SOURCES AND MAJOR 

MODIFICATIONS

Pursuant to §5-502 of the Regulations each new major source and major modification must 

apply control technology adequate to achieve the Most Stringent Emission Rate (“MSER”) with 

respect to those air contaminants for which there would be a major or significant emission 

increase, respectively. For those unfamiliar with Vermont’s term MSER, it can be thought of as 

a functional equivalent to the federal Best Available Control Technology.

As shown in Tables 3-4 above, the Facility must achieve MSER for PM/PM10/PM2.5, SO2, CO, 

and NOx. Note that the emission rate of beryllium using available wood burning emission factor 

data also is estimated to exceed its significant emission rate of 0.0004 ton/yr. Since beryllium is 

also a HAC, it will be reviewed under §5-261 of the Regulations which establishes the 

Hazardous Most Stringent Emission Rate for HACs that are expected to be emitted at a rate 

that exceeds their Action Level.

MSER is established following the procedures identified in the Agency’s “Air Pollution Control 

Permitting Handbook”, NESCAUM’s “BACT Guideline”, and the U.S. EPA’s “New Source 

Review Workshop Manual”. The process of determining MSER is to first list all available 

options for reducing emissions and then rank the alternatives in order of effectiveness from top 

to bottom (top being the most effective). One of the sources for information on emission limits 

and control technologies for permitted facilities is the U.S. EPA’s “RACT, BACT, LAER 

Clearinghouse (RLBC).” MSER requires the application of the top option unless it can be 

demonstrated based upon costs (economic, energy, and environmental) or technical constraints 

that such an option is not achievable for the proposed project. If the Agency concurs with the 

applicant that an option is not achievable, then the next most effective option is evaluated. This 

process may take several iterations before MSER is established. 

MSER will be established for the following sources: Boiler and the emergency engines. 
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Wood Fired Boiler – MSER Determination:

5.1 Boiler - NOX MSER Review

The NOx control alternatives identified in the permit application for the proposed Boiler, 

listed in order of effectiveness:

1. Selective catalytic reduction (SCR): Use of a catalyst to reduce NOx to N2. There 

are several approaches to using a catalyst for NOx reduction. One is hot side, 

conventional SCR, where the exhaust gases pass straight through the catalyst and 

out the stack. To achieve the necessary inlet temperatures, the SCR is placed 

immediately after the boiler on the “hot side” of the other emission control devices. 

In cases where the exhaust gases are too cool for the catalyst to function properly, 

additional heat is necessary to bring the exhaust gases up in temperature. In these 

systems, the added heat energy is often recovered by cycling back and forth over 

heat recovery media beds. This is referred to as a regenerative SCR (RSCR). 

Conventional SCR systems can achieve very high levels of emission reductions 

depending on the volume of catalyst and amount of ammonia used. RSCR systems 

have slightly lower performance due primarily to the cycling back and forth across 

the heat recovery beds. SCR had not been applied to wood-fired units until about 

2004, having been considered technically infeasible due to the adverse impacts of 

alkaline materials in the wood ash that rapidly deactivate the catalyst. However, 

vendors of this technology have begun to overcome these issues by physical catalyst 

configuration, and by placing the catalyst downstream of the particulate removal 

device, thus avoiding the worst effects of fouling and degradation. This lower 

temperature zone also required reformulation of the catalyst material to obtain 

adequate reaction at temperatures 200 to 300o F lower than the 600-750o F that was 

the previous norm for SCR applications.

2. Selective non-catalytic reduction (SNCR): Reducing NOx to N2 by injection of 

ammonia or urea into the boiler exhaust gases at high temperature (1600 to 2100°F). 

This can achieve NOx reduction levels ranging from 30 – 50%. When combined with 

combustion controls, the overall NOx reduction can be in the range of 65 – 75%. 

3. Combustion controls: Controlling the fuel/air mixing, excess air levels, and other 

combustion parameters to achieve efficient combustion and to control the 

stoichiometry in the combustion zone to minimize the formation of thermal NOx. 

Combustion controls also include flue gas recirculation to lower combustion 

temperature and thermal NOx formation. To varying degrees, these have become 

integral components in modern boiler design. The bubbling fluidized bed proposed 

herein varies FGR rates to compensate for variations in fuel moisture content to 

maintain the bed temperature of 1,300 to 1,600o F. NOx formation increases 

exponentially with increased combustion temperature. In this range of bed 

temperature, very little thermal NOx is formed.

All of the above technologies are technically feasible. The Permittee is proposing to use a 

combination of 1 & 3 as MSER for NOx control. The catalyst system will be a selective 

catalytic reaction (SCR) that will reduce NOx emissions. In addition the Permittee is 

proposing a NOx limit of 0.06 lb/MMBtu based on a one hour block average and a long term 

NOx emission limit of 0.03 lb/MMBtu for an annual block average.
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There are a number of wood fired electrical generating stations both proposed and operating 

in the northeast that utilize a selective catalytic reduction system for controlling NOx 

emissions. Some of these SCR systems are located as a “cold side” SCR and they 

incorporate a regenerative heat exchanger to maintain the proper temperatures some of

which use a minimal amount of additional fuel to re-heat the exhaust gases.

Many of the operating facilities are controlling NOx emissions, on a long term basis (typically 

a 3 month average) to qualify for the Massachusetts or Connecticut renewable energy credit 

markets. Since the REC markets with the highest value credits allow for a maximum 

quarterly NOx emission rate of 0.065 and 0.075 lb/MMBtu, this is the typical range of 

demonstrated emission rate performance for this technology.

Two of the most recently proposed projects in Massachusetts: Palmer Renewable Energy 

and Pioneer Renewable Energy have proposed to achieve a NOx emission rate of 0.055 

lb/MMBtu based on a one hour block average. The Palmer Renewable Energy project has 

also proposed an annual average NOx emission rate of 0.017 lb/MMBtu. Since neither of 

these projects has been constructed and these emission rates have not been demonstrated, 

they are not being considered as a basis to lower the proposed NOx emission rates for the 

project under review.
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Table 5-1: NOX Emission Limits and Performance

Facility Nominal 

Rating

Permit 

Date

NOX Controls NOX Limit

(lb/MMBtu) NOX Emission Performance

Pioneer Renewable Energy,

Greenfield, MA 47 MW Application 

pending MPCR 0.055 (1 hr block)0.022 (12 month block) Plant has not been built.

Beaver Wood Energy – Fair Haven 34 MW 2/10/2012 MPCR 0.060 (1-hr block)

0.030 (12-month avg) Plant has not been built.

Palmer Renewable Energy,

Springfield, MA 38 MW 6/30/2011 Combustion control, 

OFA, HRSCR 1 0.055 (1 hr block)0.017 (12 month avg)) Plant has not been built.

Warren Co. Biomass – GA 100 MW 12/17/2010 SNCR 0.10 (30 day rolling avg) Plant has not been built.

Clean Power Berlin,

Berlin, NH 29 MW 9/25/2009 Staged combustion & 

SCR 0.065 (30 day avg) Plant has not been built.

Laidlaw Berlin BioPower,

Berlin, NH 70 MW 7/26/10 SCR 0.060 (30 day rolling avg) Under construction.

Montville Power, Uncasville, CT 42 MW 4/6/10 RSCR 0.06 (24 hr block) Plant has not been built.

Boise White Paper - AL 435 

MMBtu/hr 3/23/2010 LNB 0.30 Plant has not been built.

Lindale Renewable Energy – TX 50 MW 1/8/2010 SNCR 0.15 Plant has not been built.

Lufkin Generating Plant - Lufkin, 

TX 45 MW 10/26/09 SCR 0.075 (30 day avg) Started August 2011

Concord Power & Steam

Concord, NH 19.5 MW 8/12/2011 SCR 0.065 (30 day avg) Plant has not been built.

McNeil Generating Station -

Burlington, VT 50 MW 2/2/09 RSCR 0.075 (Quarterly block) 2010 Quarterly averages: 

0.067, 0.072, 0.072, 0.069.

Russell Biomass,

Russell, MA 50 MW 12/30/08 RSCR 0.060 (12 month rolling avg) Plant has not been built.

Yellow Pine Energy Company

Fort Gaines, GA 115 MW 5/15/09 SNCR 0.10 (30 day rolling avg) Plant has not been built.

Koda Energy – MN

(120,000 lb/hr steam plus 17.8 MW)

308 

MMBtu/hr 8/23/2007 SNCR 0.25 (30 day rolling avg) Started operation in 2009

Simpson Tacoma Kraft – WA

(Power Boiler #7)

340,000 

lb/hr 

steam

12/12/2011 Combustion Controls 

w/ over-fire air (OFA)

0.20 (30 day avg)

Changing to 0.30 (30 day avg)

Operating. OFA design unable 

to meet the 0.20 NOx limit.

PSNH - Schiller Station (Unit SR5)

Portsmouth, NH 50 MW 3/7/06 SNCR 0.075 (24 hr avg) Based on CEMS, 1st qtr 2011 

estimated at 0.064 lb/MMBtu 1 HRSCR – high efficiency regenerative selective catalytic reduction system. The proposed system at this facility includes an oxidative catalyst as well for 

reducing CO and VOC emissions.
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Based on review of the proposed alternatives, the Agency concurs that MSER for NOx is the 

use of combustion controls with a SCR and the following NOx emission rates: Hourly 

average of 0.060 lb/MMBtu of heat input and a 12 month rolling average of 0.030 lb/MMBtu 

of heat input.

5.2 Boiler – Particulate Matter (“PM/PM10”) MSER Review

The alternatives identified in the permit application for the proposed wood fired Boiler- listed 

in order of effectiveness: 

1. Electrostatic Precipitator (ESP) or fabric filter 

2. Wet scrubber

3. Dry Scrubber

4. Multi-clone

Either a fabric filter or ESP can achieve 99.9+% PM removal. Although ESPs have been 

historically favored for wood-fired units, primarily over fire-related concerns with fabric filters, 

a few fabric filters have been placed in operation in the past few years and have 

demonstrated their viability. Fabric filters are generally considered equal to ESPs for overall 

PM control but to have slightly superior fine particle control. Furthermore, fabric filters tend 

to be installed in lower flue gas temperature zones which promotes condensation of various 

compounds onto the solid material that is then efficiently removed by the filters, rather than, 

in a conventional unit, condensing in the atmosphere to form PM10/PM2.5.

A wet scrubber can achieve removal efficiencies in the high 90s percent range, though the 

sludge and wastewater handling and processing is much more involved and costly than dry 

ash handling. Wet processed ash tends also to be less marketable as a reusable byproduct. Wet scrubbers tend to be utilized only when there is a specific acid gas removal 

issue that needs to be addressed in addition to PM control.

Dry scrubbers, when utilized, precede a fabric filter and are generally limited to projects 

wherein acid gas removal is a concern. Similarly, sorbent injection may be used to resolve a 

site-specific issue.

Multi-clones sometimes precede the high-efficiency particulate removal device as a means 

to substantially decrease the loading of that device so that it can be designed and operated 

more efficiently. Multi-clones are virtually never used alone any more as they remove much 

less than 90% of the PM. Although they are listed last above, they are sometimes a part of 

any modern PM collection system.

All of the above technologies are technically feasible. 

The Permittee is proposing the use of a fabric filter as MSER for PM/PM10 control. In 

addition, the Permittee is proposing a filterable PM emission limit of 0.010 lb/MMBtu and a 

total PM (filterable + condensable PM) limit of 0.019 lb/MMBtu.
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The Agency asked the Permittee about the potential use of multi-cyclones up stream of the 

fabric filters in order to help minimize the potential for damaging (burning) the filter bags due 

to char/cinder carry over. The vendor, Babcock and Wilcox (B&W), replied as follows:

While the use of multi-cyclones (mechanical dust collectors – “MDC”) are common practice 

for wood fired stoker/grate fired settings, bubbling fluid bed combustors have inherently 

better combustion characteristics that result in reduced char carry over, unburned carbon 

loss, and lower carbon monoxide emissions. With prudent fuel management and operating 

practice, B&W’s experience is that an MDC is not necessary with a properly designed BFB 

combustion system. B&W’s design philosophy incorporates low velocity plenums and dropout hoppers prior to the fabric filter. While an MDC could offer an additional margin of 

protection against cinder carry over, this would come at a higher capital and operational 

cost.

In the Table 5-2 is a summary of the PM emission limits of several recently permitted wood 

fired boiler EGUs, as well as the two wood fired EGUs currently operating in Vermont.

The Agency has not found enough PM emission data on large boilers to adequately 

characterize the contribution of the condensable portion of the PM, so we are not requiring a 

lower emission rate for total PM. The condensable PM data that has been gathered 

suggests that the emission rate of 0.008 lb/MMBtu for Seneca Sustainable Energy for total 

PM is not expected to be consistently achievable.

Based on review of the proposed alternatives, the Agency concurs that the best available 

control technology for PM/PM10 emissions from the Boiler is the use of a fabric filter and a

filter PM emission rate of 0.010 lb/MMBtu in addition to a total PM emission rate of 0.019 

lb/MMBtu. 
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Table 5-2: PM/PM10 Emission Limits and Performance

Facility Nominal 

Rating Permit Date PM Controls PM/PM10 Limit (lb/MMBtu) PM Emission Performance

Pioneer Renewable Energy,

Greenfield, MA 47 MW Application 

pending Multi-clone, ESP Filterable PM: 0.012Total PM: 0.019 Plant has not been built.

Beaver Wood Energy – Fair 

Haven 34 MW 2/10/2012 Multi-clone, ESP Filterable PM: 0.010

Total PM: 0.019 Plant has not been built.

Palmer Renewable Energy,

Springfield, MA 38 MW 6/30/2011 Dry scrubber, 

fabric filter

Filterable PM: 0.008

Total PM: 0.015 Plant has not been built.

Ryegate Power Station

East Ryegate, VT 20 MW 5/16/2011 Multi-clone, ESP

Filterable PM:

0.007 gr/dscf

(0.016 lb/MMBtu)

Average of 9 stack tests since 1993:

0.0013 lb/MMBtu (filterable PM)

Warren Co. Biomass Energy 

facility – GA 100 MW 12/17/2010 Sorbent injection 

and fabric filter

Filterable PM10 0.010

Filterable PM2.5 0.018 Plant has not been built.

Laidlaw Berlin BioPower,

Berlin, NH 70 MW 7/26/10 Fabric filter Filterable PM: 0.01 Under construction

Montville Power, Uncasville, CT 42 MW 4/6/10 Multi-clone, ESP Filterable PM: 0.012 

Total PM: 0.026 Plant has not been built.

Lindale Renewable Energy, TX 50 MW 1/8/2010 Good combustion 

practices & ESP Filterable PM: 0.02 (30-day avg) Plant has not been built.

Lufkin Generating Plant,

Lufkin, TX 45 MW 10/26/09 ESP

Filterable PM: 0.012

Total PM: 0.025

Both 30 day rolling avg

Started August, 2011

Seneca Sustainable Energy, 

Eugene, OR 18.8 MW 10/9/09 Multi-clone, ESP Total PM: 0.008 Stack tests completed. 

Seneca Sustainable Energy: There are ongoing issues with demonstrating compliance on a long term basis that include complications from the condensable PM 

test method which had problems with test artifacts causing false high PM emissions.

Russell Biomass,

Russell, MA 50 MW 12/30/08 Multi-clone, ESP 

or fabric filter

Filterable PM: 0.012

Total PM: 0.026 Plant has not been built.

Yellow Pine Energy Company -

Fort Gaines, GA 115 MW 5/15/09 Fabric filter Filterable PM: 0.010

Total PM: 0.018 Plant has not been built.

Koda Energy – MN

120,000 lb/hr steam + 17.8 MW

308 

MMBtu/hr 8/23/2007 Cyclone & ESP Total PM: 0.03Filterable PM10: 0.037 (3 hr avg) Started operation in 2009

Simpson Tacoma Kraft – WA

(Power Boiler #7)

340,000 lb/hr 

steam 12/12/2011 Existing ESP Filterable PM10: 0.02 0.01 gr/dscf @ 7% O2 Operating
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Table 5-2: PM/PM10 Emission Limits and Performance

Facility Nominal 

Rating Permit Date PM Controls PM/PM10 Limit (lb/MMBtu) PM Emission Performance

PSNH - Schiller Station (Unit

SR5) Portsmouth, NH 50 MW 3/7/06 Fabric filter

Filterable PM: 

0.025 (at all times)

0.01 (24-hour avg)

Stack tests (filterable PM)

5/6/10: 0.001 lb/MMBtu

5/13/09: 0.001 lb/MMBtu

Stack test 11/17 & 11/28/06: 

0.0007 lb/MMBtu filterable PM

0.0117 lb/MMBtu condensable PM

0.0124 lb/MMBtu total PM

McNeil Generating Station,

Burlington, VT 50 MW 2/2/09 ESP

Filterable PM:

0.007 gr/dscf

(0.016 lb/MMBtu)

Stack tests (filterable PM)

7/14/04: 0.00060 lb/MMBtu

10/26/10: 0.00015 lb/MMBtu
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5.3 Boiler – Carbon Monoxide (CO) MSER Review 

The alternatives identified in the permit application for the proposed wood fired Boiler- listed 

in order of effectiveness: 

1. Oxidative catalyst. 

2. Good combustion design and combustion practices.

Oxidation catalysts have not historically been successfully applied to wood fired units. Until 

recently, they were considered technically infeasible for reasons similar to the fouling and 

degradation experienced with SCR catalysts. Recent designs have moved them to the clean 

side and, hence, cooler operating zone. Although an oxidation catalyst is more efficient at 

higher temperatures, such temperatures occur only on the high-ash side of the particulate 

removal system where fouling and catalyst degradation are a problem. Thus cold-side 

installations have lower CO removal efficiencies than those, for example, used in gas-fired 

combustion turbine-based combined cycle power plants. 

Combustion controls incorporated in any modern boiler design reduce CO emissions to well 

below those of older boilers. The BFB boiler can achieve CO emissions rates comparable to 

a stoker unit equipped with an oxidation catalyst.

Table 5-3 contains a summary of CO emissions levels for permits recently issued to facilities 

with wood fired boilers. The most stringent short term emission limits are 0.07 (4 hr avg) to 

0.075 lb/MMBtu (24 hr avg) for recently permitted units incorporating oxidation catalysts. 

The most stringent annual average CO emission rate is proposed for Pioneer Renewable 

and included in the air permit for Palmer Renewable in Massachusetts. Neither facility has 

been built or operated, so neither this annual average, nor the 0.07 lb/MMBTU (4-hr avg) 

have been demonstrated and should not be considered as a basis for lower CO emission 

limits.

All of the above technologies are technically feasible. The Permittee is proposing to use a 

bubbling fluidized bed boiler to achieve an emission of 0.075 lb/MMBtu (24-hr average) as 

MSER for CO control. 

Based on review of the proposed alternatives, the Agency concurs that MSER for CO is the 

use of a bubbling fluidized bed boiler and a limit of 0.075 lb/MMBtu of heat input as a 24 

hour rolling average.

In response to comments regarding CO BACT in the draft permit, the Agency instructed the 

Permittee to conduct additional analysis to determine the cost effectiveness of using a an 

oxidation catalyst for their boiler to achieve 0.0365 lb/MMBtu. The addition of an oxidative 

catalyst to achieve a reduction in CO from 0.075 lb/MMBtu to 0.0365 lb/MMBtu would result 

in a potential reduction in annual CO emissions of 74 tons. The estimated cost to add a CO 

catalyst is $16,800/ton of CO controlled (includes cost to install and an estimated catalyst 

life of 3 years, which requires an estimated cost of $1,200,000 to replace the catalyst). 

Based on these costs, which can be considered in an MSER determination, the Agency 

determined that 0.075 lb/mmbtu still constitutes MSER for CO.
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Some pollutants, such as CO may be elevated during startup conditions, either due to less 

than optimum combustion during these periods, or in the case of NOx due to the SCR not 

functioning until normal operating temperatures are reached. The Permittee has requested 

that emission limits for startup be established with the Boiler Operation and Maintenance 

Plan to include proposed startup and shutdown emission limitations for NOx, CO and VOC, 

developed from operational emission data from stack tests and/or CEMs data collected 

during startup and shutdown periods. The Agency concurs with this request.
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Table 5-3: CO Emission Limits and Performance

Facility Nominal 

Rating

Permit 

Date CO Controls CO Limit (lb/MMBtu) CO Emission Performance

Pioneer Renewable Energy,

Greenfield, MA 47 MW Application 

pending

Combustion Control 

and CO catalyst

0.114 (1 hr block)

0.07 (4 hr block)

0.0365 (12 month rolling avg)

Plant has not been built.

Beaver Wood Energy – Fair 

Haven 34 MW 2/10/2012 Combustion Control 

and CO catalyst 0.075 (24-hr avg) Plant has not been built.

Palmer Renewable Energy,

Springfield, MA 38 MW 6/30/2011 Combustion Control 

and CO catalyst

0.114 (1 hr block)

0.07 (4 hr block)

0.0365 (12 month rolling avg)

Plant has not been built.

Warren Co. Biomass Energy

facility – GA 100 MW 12/17/2010 Good design and 

operating practices 0.08 (30 day rolling avg) Plant has not been built.

Laidlaw Berlin BioPower,

Berlin, NH 70 MW 7/26/10 BFB boiler & FGR 0.075 (calendar day) Under construction.

Montville Power, Uncasville, CT 42 MW 4/6/10 CO catalyst 0.10 (8 hr block) Plant has not been built.

Lindale Renewable Energy, TX 50 MW 1/8/2010 Combustion control 0.31 (30 day avg) Plant has not been built.

Lufkin Generating Plant,

Lufkin, TX 45 MW 10/26/09 Combustion control 0.075 Started August, 2011

Russell Biomass,

Russell, MA 50 MW 12/30/08 Combustion Control 

and CO catalyst 0.075 Plant has not been built.

Yellow Pine Energy Company -

Fort Gaines, GA 115 MW 5/15/09 BFB 0.149 (30 day avg) Plant has not been built.

Koda Energy – MN

120,000 lb/hr steam + 17.8 MW

308 

MMBtu/hr 8/23/2007 Combustion Control 0.35 (30 day avg) Started operation in 2009

Simpson Tacoma Kraft – WA

(Power Boiler #7)

340,000 

lb/hr 

steam

12/12/2011

Combustion 

Controls w/ over-fire 

air (OFA)

0.35 (30 day avg)

600 ppm @ 7% O2, 30 day 

rolling average

Operating

PSNH - Schiller Station 

(Unit SR5) Portsmouth, NH 50 MW 3/7/06 Good combustion w/ 

fluidized bed 0.10 (24 hr avg) Plant operating and using CEMS to monitor CO emissions.
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5.4 Boiler - Sulfur Dioxide (SO2) MSER Review:

The alternatives identified in the permit application for the proposed wood fired Boiler- listed 

in order of effectiveness: 

1. Wet scrubber

2. Spray dryer.

3. Dry sorbent injection. 

4. Use of low sulfur content fuel: 

Wet scrubbers inject a water-based solution of sodium hydroxide or calcium-based reagent 

into the flue gas. The water absorbs the SO2 and the reagent reacts with it to form sodium or 

calcium sulfate, which can be precipitated from the spent solution and disposed of as a solid 

waste. Wet scrubbers are generally the technology of choice when dealing with flue gas 

from high- or medium-sulfur coal firing. They are very efficient at removing SO2 when the 

initial driving force for the reactions is a high SO2 concentration, such as when the fuel is 

high-sulfur coal or oil. Wet scrubbers are technically challenged and not cost effective when 

starting at a very low SO2 concentration in the flue gas and so have not been applied to 

wood-fired plants, where the fuel sulfur content is much lower than coal or residual oil. A 

wet scrubber is not considered to be practical or cost-effective for the NSSEP project, and 

would have other environmental impacts.

A spray dryer injects a reagent-water solution that reacts with the SO2. The water then 

evaporates in the heat of the flue gas, leaving behind dry particles to be removed, typically 

in a fabric filter. Spray dryer-absorber systems like wet scrubbers, are not cost-effective 

unless applied to relatively high concentration flue gas streams. Spray dryers (dry scrubber) 

are generally applied to low- and medium-sulfur coal and oil-fire facilities and are not 

considered to be technically feasible for the NSSEP unit. 

Table 5-4 contains a summary of SO2 emissions levels for permits recently issued to 

facilities with wood fired boilers. A few projects have proposed scrubber technology, 

including Palmer Renewable in MA, with the same short term emission rate as proposed for 

NSSEP (0.02 lb/MMBtu). Palmer has not been built and had originally been proposed as a 

C&D wood boiler which included the dry scrubber.

Dry sorbent injection (DSI) systems add trona or sodium bicarbonate as dry particles into the 

flue gas. Reaction with SO2 takes place on the surface of the particle, binding the sulfur, and 

the particles are removed in a downstream fabric filter. DSI is less costly than wet systems 

as well as being better suited to lower SO2 concentrations in the flue gas. For this project, 

the estimated cost of control for a DSI system using trona in 1-ton flexible intermediate bulk 

containers (supersacks) is $14,700/ton of SO2 controlled. If a full bulk storage and handling 

system is required, the cost of control nearly doubles. DSI has been used on a few woodfired plants when the fuel supply was found to have higher-than-expected sulfur content or 

as a precaution to accommodate fuels of varying sulfur content. Variations in the sulfur 

content of wood do occur both locally and regionally depending on sulfur uptake rates from 

the soil in which the tree is grown. Monitoring of SO2 emission at the two operating wood 

fired EGUs in Vermont indicates that there are very low emission rates of SO2 from the 

combustion of wood in this region.
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The Permittee is proposing that wood as a low sulfur fuel represents MSER for SO2 control. 

In addition, the Permittee is proposing a SO2 limit of 0.02 lb/MMBtu. The averaging period 

will depend on whether a CEMS is required by the EPA Acid Rain program. 

Based on review of the proposed alternatives, the Agency concurs that the MSER for SO2 is 

the use of wood as a low sulfur content fuel and a limit of 0.02 lb/MMBtu of heat input based 

on an hourly average. 
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Table 5-4: SO2 Emission Limits and Performance

Facility Nominal 

Rating

Permit 

Date SO2 Controls SO2 Limit (lb/MMBtu) SO2 Emission Performance

Warren Co. Biomass Energy 

facility – GA 100 MW 12/17/2010 Sorbent injection 0.010 (30 day rolling avg) Plant has not been built.

Laidlaw Berlin BioPower,

Berlin, NH 70 MW 7/26/10 Sorbent injection 

(as needed) 0.012 (stack test) Under construction

Yellow Pine Energy Company -

Fort Gaines, GA 115 MW 5/15/09 Dry scrubber 

system 0.014 (30 day avg) Plant has not been built.

Beaver Wood Energy – Fair 

Haven 34 MW 2/10/2012 None 0.020 Plant has not been built.

Lufkin Generating Plant,

Lufkin, TX 45 MW 10/26/09 None 0.025 (30 day avg) Started August, 2011

Lindale Renewable Energy, TX 50 MW 1/8/2010 Low sulfur fuels 0.025 (30 day avg) Plant has not been built.

Seneca Sustainable Energy, 

Eugene, OR

18.8 

MW 10/9/09 None 0.025 Stack test completed; results were not available at this time

Montville Power, Uncasville, CT 42 MW 4/6/10 Low sulfur fuels 0.025 (3-hr block avg) Plant has not been built.

Pioneer Renewable Energy,

Greenfield, MA 47 MW Application 

pending Low sulfur fuels 0.025 Plant has not been built.

Palmer Renewable Energy,

Springfield, MA 38 MW 6/30/2011 Sorbent injection, 

Turbosorp scrubber

0.02 (1-hr avg)

0.012 (annual avg) Plant has not been built.

PSNH - Schiller Station (Unit 

SR5) Portsmouth, NH 50 MW 3/7/06 Dry sorbent 

injection 1 0.02 Plant operating and using CEMS to monitor SO2 emissions. 1

 Schiller Station is also permitted to burn coal in Unit SR5.
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Diesel Engines MSER Determination:

The Facility will include a 3 MW diesel engine to provide power through emergency 

generators and a 450 hp diesel-driven fire water pump. These engines are sources of NOX, 

CO, PM, and SO2.

MSER for the engines will be met through the use of new engines that are Tier certified in 

accordance with 40 CFR Part 60 Subpart IIII, and a limit of 65 hours/year for maintenance 

and exercising of the engines.

Facility Greenhouse Gas Emissions MSER Review:

The science and technical issues regarding the effect of a bioenergy facility on carbon 

stocks and overall carbon emissions is complex and evolving. On June 3, 2010, EPA 

finalized new thresholds for greenhouse gas emissions that define when Clean Air Act 

permits are required (also known as the “Tailoring Rule”). In January 2011, Vermont 

adopted the Tailoring Rule thresholds for greenhouse gas emissions in the Vermont Air 

Pollution Control Regulations. In July 2011, EPA deferred for a period of three years the 

application of permitting requirements to biogenic carbon dioxide (CO2) emissions and 

committed to conducting a detailed examination of the science and technical issues 

associated with accounting for emission of biogenic CO2 emissions.

Vermont has not amended its regulations to defer the applicability of permitting 

requirements for biogenic CO2 emission sources such as NSSEP. However, because a 

carbon accounting method has not yet been developed to accurately adjust a bioenergy 

facility’s actual stack emissions up or down based on the induced changes in carbon stocks 

on land (in soils, plants and forests), such sources are currently subject to air permitting 

requirements in Vermont based solely on direct CO2 emissions from the stationary sources. 

In other words, at this time, air permitting for biogenic stationary sources is not taking into 

account possible supplemental emissions such as from depleted soils after harvesting or 

any future carbon sequestration that could result from the use of biogenic feedstocks. 

Likewise, the Agency is not establishing wood procurement requirements in its air permits 

for biogenic sources at this time. This may change in the future, for example when an 

accounting method for biogenic CO2 emissions from the stationary sources is finalized.

The Agency reserves its right to raise any issues related to the management of forest 

resources, and the potential impact of this or any other facility, in the context of other 

proceedings such as Act 250, Section 248, or other permitting regimes.

5.5 Boiler Greenhouse Gas MSER Review:

One of the central questions to determining BACT for GHGs for this project is whether 

alternative fuels as a control option would fundamentally redefine the proposed facility or 

whether alternative fuels should be included as a control option in determining BACT/MSER. 

In doing so, the Agency “must be mindful that BACT, in most cases, should not be applied to 

regulate the applicant’s objective or purpose for the proposed facility, and therefore, the 

permit issuer must discern which design elements are inherent to that purpose, articulated 
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for reasons independent of air quality permitting, and which design elements may be 

changed to achieve pollutant emission reductions without disrupting the applicant’s basic 

business purpose for the proposed facility.” In re Prairie State Generating Co., 13 E.A.D. 1, 

23 (EPA 2006). The crucial question to consider in determining whether a control option, 

such as alternate or cleaner fuels, would redefine the project is “when does the imposition of 

a control technology require enough of a redesign of the proposed facility that it strays over 

the dividing line to become an impermissible redefinition of the source?” In re Desert Rock 

Energy Company, PSD Appeal No. 08-03 et al. at 63-64 (EAB Sept. 24, 2009).

The Permittee is proposing to construct a 37 MWe (net, average) biomass fuel electric 

generating facility in North Springfield, Vermont. The Permittee maintains that the choice of 

biomass fuel is integral to the proposed facility’s fundamental purpose and basis of design

and reiterated that alternative fuels would fundamentally redefine the project. According to 

information supplied in connection with the Permittee’s air permit application and application 

for a Certificate of Public Good, the Permittee designed and sited the facility based on the 

Permittee’s conclusion that there is sufficient biomass fuel in the project area. The 

Permittee relies on a biomass fuel supply study for the area surrounding the facility location 

conducted by Innovative Natural Resource Solutions, LLC for the Permittee, along with a 

recent study by the Biomass Energy Resource Center (Vermont Wood Fuel Supply Study –

2010 Update), as the basis for its conclusion that there is an ample supply of wood fuel 

available. The Agency has not undertaken, as part of the air permitting process, an 

independent analysis of the conclusions reached in the aforementioned wood supply 

studies, and has considered the studies for the limited purpose of addressing whether 

alternative fuels should be included as a control option in determining BACT/MSER. 

The Agency finds that the Permittee’s objective is to build a biomass fuel electric generating 

facility. Based on the air permit application and other statements made by the Permittee, the 

Agency also finds that the Permittee has “defined its ‘goal, objectives, purpose, or basic 

design’ for the proposed facility,” In re Desert Rock Energy Company, PSD Appeal No. 08-

03 et al. at 65 (EAB Sept. 24, 2009), based on the Permittee’s conclusions regarding the 

availability of biomass wood fuel. Thus, for the limited purpose of considering whether 

alternative fuels should be included as a control option in determining BACT/MSER, the 

Agency concludes that the Permittee’s choice of fuel is integral to the proposed facility’s 

fundamental purpose and basic design. Thus, imposing alternate fuels such as coal, natural 

gas, or oil as a control option would fundamentally redefine the proposed facility. For these 

reasons, the Agency finds that such alternate fuels should not be included as a control 

option in determining MSER. With respect to alternative biogenic fuels, the Agency finds 

there is currently not sufficient availability of other biogenic fuels (such as grasses, 

agricultural byproducts, bio oils from seed crops or bio gases from digesters) to contribute 

significant fuel energy to a project such as the North Springfield Sustainable Energy Project.

Step 1: Identify all Control Technologies: The alternatives identified in the permit 

application for the proposed wood fired Boiler- listed in order of effectiveness: 

1. Carbon capture and storage (CSS). CSS technologies are still in the development 

stage. CSS is promising as a CO2 control technology for a source that has exhaust 

gases with high-purity CO2 streams. 

2. Energy efficiency. The design of a traditional boiler-steam-turbine-generator system 

loses the majority of its potential energy at two points in the system: (a) the turbine’s 
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condenser via the cooling water and/or cooling air and (b) the boiler’s exhaust gases 

exiting the stack. Recovery of potentially lost heat energy should increase the plant’s 

overall energy efficiency. 

a. The cooling water from the condenser has a temperature in the range of 80 –

90o

F, and is very limited in potential for additional heat recovery. At electrical 

utility plants this warm water is sometimes discharged directly to a large river

in a process known as once thru cooling. However many rivers cannot 

environmentally absorb this added heat and it must be cooled before 

discharging. For the current project, a large river is not available and the 

water must be cooled and reused. The current project will send the 

condensing steam from the steam turbine to an air cooled condenser, then 

the returning water can be reused in the boiler.

b. A portion of the heat in the hot exhaust gas can be extracted by further 

cooling of the gases via the installation of additional heat exchangers. The 

current project includes an economizer for combustion air preheating

following the SCR system for heat recovery ahead of the stack.

3. Combined heat and power (CHP). CHP offers the advantage of extracting additional 

heat energy from the low grade heat (low pressure steam) and/or other waste heat 

that may be available from the boiler process. The basic principle of CHP is to direct 

some of the thermal energy to nearby thermal heating requirements (typically 

process heat or building heat) which are inherently more energy efficient than 

converting the thermal energy (steam) into electrical energy via a steam turbine 

generator.

4. Type of fuel. Due to their chemical makeup, some fuels generate less CO2 per unit 

of energy when they are combusted. As noted above, fuel switching would redefine 

this source and is not part of the MSER review. 

5. Good operating and maintenance practices. This is an extension of energy 

efficiency; make sure that the equipment is operating at peak performance to help 

ensure that the overall system efficiency remains as designed. This would include 

minimizing air leaks into the boiler system through procedures and methods to detect 

air leakage, in addition to maintaining proper insulation on the steam and condensate 

lines and identifying and repairing condensate leaks. In addition, covering the main 

wood fuel pile will serve to minimize rain infiltration into the stored wood.

Step 2: Eliminate Technically Infeasible Options:

1. CSS: At this time, CSS technologies have not been developed for capturing CO2 in the 

dilute exhaust gases being emitted from biomass combustion. Therefore, CSS, is not 

technically feasible for this project. In addition, there can be a significant energy penalty 

in moving this gas stream under high pressure to the underground geological formations 

for sequestration.

2. Energy efficiency is technically feasible, within limits. The recovery of waste heat from 

the boilers exhaust gases is limited due to the potential of condensing the moisture in 

the gases which can adversely affect the condition of the exhaust handling equipment if 

it is not designed for this potential corrosive environment. In addition, cooler exhaust 

gases have worse dispersion characteristics after exiting the exhaust stack. The 

Permittee’s boiler design includes an economizer after the SCR which reduces the 

exhaust gas temperature to the range of 250 – 310 o

F.
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3. CHP is technically feasible. The Permittee has stated their intent to utilize low pressure 

steam, from an extraction point off the turbine, to produce warm water which will be 

used as a thermal heat loop for other businesses in the industrial park. 

4. Good operating and maintenance practices to maintain system performance is 

technically feasible.

Step 3: Rank Remaining Control Technologies by Control Effectiveness:

1. Energy efficiency

2. CHP – through the recovery of low grade heat to produce hot water for a thermal loop in 

the North Springfield Industrial Park. The applicant has indicated that there is an 

anticipated heat demand from the existing industrial park buildings for up to 20,000 lb/hr 

of low pressure steam. The annual average heat demand is estimated to be 4,000 lb/hr.

3. Good operating and maintenance practices does not reduce GHG emissions, but it does 

help ensure that the facility continues to operate as designed.

Steps 4 & 5 are combined since the Facility will be using all three of the control technologies 

identified in Steps 1 through 3. 

The Agency has determined that MSER for GHGs is implementing energy efficiency, a 

thermal loop to provide heat to businesses in the industrial park, and good operating and 

maintenance practices for GHG control. In addition, a CO2e emission limit has been 

established based on the annual average heat input to the boiler (464 MMBtu/hr), an 

electrical output of 36.72 MW, an average annual output of the thermal loop of 4 MMBtu/hr

and a plant long term performance heat rate ”degradation” of 3%. In spite of good operating 

and maintenance practices, it is expected that there will be some loss of performance over 

time. The plant’s heat rate degradation is estimated to have a long term average of 

0.15%/yr; the value of 3% is based on 20 years of operation. The CO2e emission limit is

2,675 lb CO2e / MW-hr net electrical and heat output based on a 12 month rolling average.

The applicant will be allowed to phase in the implementation of the heat loop to the industrial 

park. For the first 2 years of the operation of the boiler, the CO2e emission limit will not be 

based on the operation of the heat loop, and will be 2,668 lb CO2e / MW-hr net electrical

output based on a 12-month rolling average. This limit does not include any energy sent to 

the thermal loop and does not include the 3% heat rate degradation.

Starting with the 3rd year of operation, the CO2e emission limit will be 2,675 lb CO2e / MW-hr 

net electrical and heat output based on a 12-month rolling average.
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5.6 Diesel Engine Greenhouse Gas MSER Review:

The Agency is not aware of any technologies that have been designed to reduce the GHG 

emissions from diesel powered emergency engines generators and/or fire pumps. Energy 

efficiency of the engine design is the best way to minimize the emissions of GHGs from these 

sources. Since the EPA’s engine emission standards for other criteria pollutants are based on 

the emission rate of the pollutant per unit of energy output, engine manufactures have employed 

a combination of reducing the mass emission rate of the pollutant(s) and increasing the overall 

efficiency of the engines. Thus the use of a Tier certified engine will help ensure the use of 

highest energy efficient diesel engine(s) available.

The Agency has determined MSER for GHGs from the emergency diesel engine will be met 

through the use of new engines that are Tier certified in accordance with 40 CFR Part 60 

Subpart IIII.

6.0 AMBIENT AIR QUALITY IMPACT ANALYSIS

An ambient air quality impact evaluation is performed to demonstrate whether or not a proposed 

project will cause or contribute to violations of the ambient air quality standards and/or 

significantly deteriorate existing air quality. The Agency's implementation procedures 

concerning the need for an ambient air quality impact evaluation under §5-406(1) of the 

Regulations, specifies that such analyses may be required when a project results in an 

allowable emissions increase of ten (10) tons per year or more of any air contaminant, excluding 

VOCs.

6.1 Model Data Inputs

For this review, EPA’s AERMOD model was used for both screening and interactive modeling. 

The meteorological data sets were for the years 2006 – 2010 which were recently developed 

using the 1 minute ASOS data. The surface met data was from the Springfield (Hartness) 

Airport, and the upper air data was from Albany, NY. 

Since the issuance of the draft permit on 8/9/2012, an updated review, unrelated to the air 

permit, of the proposed stack height relative to the location of the Hartness Airport runway 

indicated that the stack was just tall enough that it exceeded a FAA criteria so a further study 

would be required. The project decided to lower both the base elevation for the main boiler 

building and the stack base by 1 foot. This brought the stack tip below the FAA criteria. To 

confirm that this change would not affect the previous modeling analysis, changes were made to 

the model inputs to reflect the new elevation of both the stack and the main boiler building and 

the model was re-run. The results showed that most of the modeled concentrations remained 

unchanged while a few changes by a small amont (less than 1%). The tables in this section 

have been updated, as needed with the new data. There are no changes in the Agencies 

review and conclusions.

The Permittee conducted modeling for several operating load scenarios for the boiler as well as 

a startup scenario for the boiler. This is necessary since full load operation does not necessarily 

correspond to the highest emission rate or worst dispersion. In some cases, lower operating 
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loads can result in higher ambient impacts due to either higher emission rate concentrations 

(even though lower mass) or lower temperature or velocity of the exhaust. The startup scenario 

modeling was for short term emission (less than 24-hour standards) for CO (1-hr) and SO2 (1-hr 

and 3-hr). Table 6-1 summarizes the operating loads and emission rates for the operating 

scenarios that were modeled.

Table 6-1: Operating Load Scenarios

% Load/ 

Fuel 

Moisture 

Heat Input 

(MMBtu/hr)

Gas Flow 

(ACFM)

Stack 

Gas Exit 

Velocity 

(ft/sec)

(m/s)

Stack Gas 

Exit 

Temperature 

(°F)

(

o

K)

NOx 

Emission 

Rate 

(lb/hr)

(g/s)

SO2

Emission 

Rate 

(lb/hr) 

(g/s)

PM10/2.5 1

Emission 

Rate 

(lb/hr) 

(g/s)

CO 

Emission 

Rate 

(lb/hr) 

(g/s)

100/55 502 190,956 63.32

19.3

310

427

30.12

3.795

10.04

1.265

9.538

1.202

37.65

4.744

100/45 464 161,555 53.57

16.3

300

422

27.84

3.508

9.28

1.169

8.816

1.111

34.80

4.385

75/45 344 114,795 38.06

11.6

270

405

20.64

2.601

6.88

0.864

6.536

0.824

25.80

3.251

60/35 262 88,141 29.23

8.9

250

394

15.72

1.981

5.24

0.660

4.978

0.627

19.65

2.476

Cold start 40 13,000 4.3

1.3

250

394

N/A 0.6

0.0076

N/A 60

7.56

Emission rates are “short term.” Annual NOx emission rate is half the maximum 100%/45% hourly rate. Although 

other loads will not normally operate on an annual average basis (13.92 lb/hr), maximum short term emission rates 

were conservatively used for annual average impacts. 1

 The PM emission is assumed to all be fine enough to be characterized as PM2.5 . This PM emission therefore also 

represents PM10.

6.2 NAAQS Analysis

Based on the above scenarios, the emissions from the facility were modeled to establish 

the significant impact area (SIA). The SIA is based on the distance from the facility to 

the maximum point at which predicted impacts fall below the Significant Impact Level 

(SIL). The SIA is a circle around the facility with a radius equal to this distance. If there 

are no predicted impacts greater than the SIL for a pollutant then there is no SIA and 

interactive modeling is not necessary. 

Table 6-2 shows that the emissions for PM2.5, NOX, and SO2 are predicted to exceed one 

or more their respective SILs, so it was necessary to include any sources that met the 

above noted criteria as interactive sources in the modeling analysis.
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Table 6-2: Distance to Significant Impact Level (km)

Pollutant Averaging 

Time

Significant Impact 

Levels (μg/m3)

Distance (km) from project Load 

Case

PM10

24-hour 5 0.1 60/35

Annual 1 1 No impacts > SIL N/A

PM2.5

24-hour 2,4 1.2 7.0 60/35

Annual 2,4 0.3 2.25 100/45

SO2

1-hour 2,3 7.8 15.1 100/55

3-hour 25 No impacts > SIL N/A

24-hour 5 0.1 60/35

Annual 1 No impacts > SIL N/A

NO2

1-hour 2,3,5 7.5 37.9 100/55

Annual 5,6 1 No impacts > SIL 60/35

CO

1-hour 2,000 No impacts > SIL N/A

8-hour 500 No impacts > SIL N/A

1 Note that effective 12/28/2006, the EPA revoked the PM10 annual NAAQS standard. However, up until 

May 2011, in certain cases, the EPA allowed a PM10 surrogate policy that allowed a project to demonstrate 

compliance with the PM10 annual NAAQS as a means to also demonstrate compliance with the PM2.5 annual 

NAAQS. This permit demonstrated compliance with the PM2.5 annual NAAQS and did not propose to use 

the PM10 surrogate policy. Since the application for this permit included information on the PM10 annual

NAAQS, we are including this information in this document.

2 Averaged over 5 years per applicable EPA guidance.

3 High 1st High maximum daily 1-hr concentration averaged over 5 years. 4 High 1st High (100%) maximum concentration averaged over 5 years.

5 NO2 uses ARM values for NOX to NO2 conversion (0.75 for Annual, 0.8 for 1-hour). 6

Annual NO2 emissions based on guaranteed rates. Hourly NO2 emissions represent maximum emissions. 

Conservative for reduced load conditions.

For the pollutants/averaging times with predicted impacts below their respective SIL, the 

monitored background concentrations were added to the appropriate modeled concentrations 

for a comparison with the NAAQS. Table 6-3 summarized this NAAQS review. Since there are 

no nearby sources of PM10 or PM2.5 that will require cumulative source modeling these pollutants 

are included in this review. Table 6-3 shows that for the list pollutants there are no predicted 

exceedances of the NAAQS. 
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Table 6-3: NAAQS Review

Predicted Impact Concentrations for Pollutants Not Requiring Cumulative Source Modeling

Pollutant Averaging 

Time 1

Operating 

Load 

Scenario 2

Modeled 

Conc. 

(μg/m3)

Background 

(μg/m3)

Total Impact 

(μg/m3)

NAAQS 

(μg/m3)

PM10

24-hr (H6H) 100/45 3.83 35.0 38.8 150

Annual (H) 100/55 0.55 13.3 13.9 50

PM2.5 

24-hr 4 60/35 4.44 19.1 23.5 35

Annual 5 100/45 0.51 7.8 8.3 15

SO2

3-hour (H2H) 100/45 17.1 73.3 90.4 1,300

Annual (H) 100/55 0.58 7.6 8.2 80

NO2 

3 Annual (H) 60/35 0.90 16.4 17.3 100

CO

1-hour (H2H) 100/45 117.7 3,435 3553 40,000

8-hour (H2H) 100/55 36.3 1,832 1868 10,000

1 H = highest annual average; H2H = highest second high value; H6H = Highest 6th high value over 5 years of 

meteorological data.

2 100/55 = 100% load / 55% moisture; 100/45 = 100% load / 45% moisture; 60/35 = 60% load / 35% moisture.

3

 For annual NO2 modeling, used ambient ratio method of 0.75 for NO/NO2 conversion. 4

 High 1st High (100%) maximum concentration averaged over 5 years. 5 Averaged over 5 years per applicable EPA guidance.

The Agency used the following criteria to determine if the emissions from a nearby 

source would need to be included in the interactive modeling for this Facility:

1. Each pollutant for which a SIA has been identified, shall include the 

following class of nearby sources in the interactive modeling:

a. Nearby sources located within the SIA with actual emissions 

greater than the following significant emission rates: 

i. CO: 50 tons/yr

ii. NOx: 40 tons/yr

iii. SO2: 40 tons/yr

iv. PM10: 15 tons/yr

v. PM2.5: 10 tons/yr

b. Nearby sources located within 20 km of the wood boiler stack that 

have actual emissions greater than 50 tons/yr.

c. Nearby sources located within 50 km of the wood boiler stack that 

have actual emissions greater than 500 tons/yr.

Based on the above noted criteria the interactive source modeling included emissions of 

NOX and SO2 for the following two sources: APC Paper and Wheelabrator, both located 

in Claremont, NH. There were no nearby sources of PM2.5 or PM10 that met the criteria 

noted above. The stack and emissions data for APC Paper and Wheelabrator were 

supplied by the NHDES and are summarized in Table 6-4.
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Table 6-4: Cumulative Source Stack and Emissions Data

Source

UTM E 

(m)

UTM N 

(m)

Stack 

Base 

Elev. 

(m)

Stack 

Height 

(m)

Stack 

Gas 

Temp. 

(K)

Stack 

Gas 

Velocity 

(m/s)

Stack 

Diam. 

(m)

Short 

Term 

SO2

(g/s)

Short 

Term 

NOX

(g/s)

APC Paper 714956 4805760 137.8 38.1 493 7.67 1.37 13.056 3.049

Wheelabrator 

Claremont 712571 4802400 164.6 45.7 421 24.62 0.79 1.991 5.756

The emissions from the proposed Facility (for the 4 operating load scenarios listed in 

Table 6-1) along with the emissions from the two facilities noted above were modeled to 

predict the maximum impacts to determine if there were any predicted NAAQS violations 

for the 1-hr NO2, 1-hr SO2 and 3-hr SO2 NAAQS.

Table 6-5 summarizes the results of the cumulative source modeling results. For the 24-

hr SO2 NAAQS there were no predicted violations. For both the 1-hr NO2 and 1-hr SO2

there are predicted violations of the NAAQS.

The NSSEP ‘contribution’ shown in Table 6-5 of the draft permit has been updated.

Table 6-5, shown below has the updated values which are higher than those shown in 

the draft permit, but still below the SILs. The data in the draft permit showed the 

Facility’s contribution that coincided with the form of the standard (4th high for SO2 and 

8th high for NO2).Further review of the data showed that a higher contribution from the 

Facility could and did occur at other, lower overall cumulativeconcentrations that were 

over the NAAQS. The highest contribution for any modeled exceedance is shown in the 

updated table.
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Table 6-5: Cumulative Source Modeling Results

Pollutant 

/ Avg 

Time

Load %/ 

Moisture %

Overall 

Cumulative 

Concentration 

(μg/m3)

NAAQS 

(μg/m3)

Number of 

Receptors 

Exceeding 

NAAQS

NSSEP 

Contribution

(μg/m3) 1

Significant 

Impact Levels 

(μg/m3)

NO2 2

1-hour

100%/55% 246

188

12 2.63

7.5

100%/45% 246 12 3.19

75%/45% 246 12 4.06

60%/35% 246 12 3.56

SO2

1-hour

100%/55% 805

195

263 0.06

7.8

100%/45% 805 263 0.07

75%/45% 805 263 0.09

60%/35% 805 263 0.11

SO2

24-hour

100%/55% 149.3

365

0

N/A 3 N/A 3 100%/45% 149.3 0

75%/45% 149.3 0

60%/35% 149.3 0

1

 Highest contribution from NSSEP for the affected receptors to any modeled exceedance. 2

 NO2 1-hour SIL = 7.5 μg/m3. Uses 0.8 for modeled 1-hour ARM for NOx to NO2 conversion. 3

 N/A – Since below NAAQS, no further analysis is required.

To determine if the Facility’s emissions cause or contribute to a violation of the 1-hour 

NO2 or SO2 NAAQS, it is necessary to identify the Facility’s contribution to impacts at the 

receptors that have a total impact that is greater than the NAAQS. 

There were 263 receptors with combined source 1-hour SO2 impacts greater than the 

NAAQS. The Facility’s maximum contribution to the impacts at any of these receptors 

was 0.11 μg/m3 which is below the SIL of 7.8 μg/m3

. This demonstrates that the Facility 

does not cause or contribute to any violation of the 1-hour SO2 NAAQS.

There were 12 receptors with combined source 1-hour NO2 impacts greater than the 

NAAQS. The Facility’s maximum contribution to the impacts at any of these receptors 

was 4.06 μg/m3 which is below the SIL of 7.5 μg/m3

. This demonstrates that the Facility 

does not cause or contribute to any violation of the 1-hour NO2 NAAQS.

Start-up scenario:

During the first few hours of a cold startup, the cold equipment, fuel transitions and a 

very low operating rate contribute to low flow rates and temperatures of the exhaust 

gases and subsequently reduced dispersion from the exhaust gas. This can result in 

elevated higher pollutant impacts during cold startup conditions. Since cold startups are 

expected to occur infrequently, longer term averaging times were not evaluated.

The Permittee modeled the estimated emission of CO (1-hr) and SO2 (1-hr and 3-hr) 

from a cold startup scenario. The emission rates are shown in Table 6-1. For SO2 the 
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emission rate during the first few hours of a cold startup are lower due to the use of 

ULSD fuel. The modeled impacts for both the 1-hr and 3-hr SO2 were well below their 

respective SILs and NAAQS. During the cold startup, the emission rate of CO (in terms 

of lb/MMBtu) is much higher compared with steady state/full load operation. This higher 

emission rate was modeled and demonstrated that the modeled 1-hr CO impacts were 

below both the SIL and the NAAQS. These results are summarized in Table 6-6.

Table 6-6: Modeling Startup Conditions

Pollutant Averaging 

Time

Modeled 

Conc. 

(μg/m3)

SIL 

(μg/m3)

Background 

(μg/m3)

Total Impact 

(μg/m3)

NAAQS 

(μg/m3)

SO2

1-hour 0.62 7.8 70.7 71.3 195

3-hour (H2H) 0.51 25 73.3 73.8 1,300

CO 1-hour (H2H) 745 2000 3,435 4180 40,000

The results of this refined modeling, shown in Section 6.2 above, demonstrate that the 

Facility will not cause or contribute to a violation of the NAAQS.

6.3 Prevention of Significant Deterioration (PSD) Increment Analysis

Major new sources of air pollution must demonstrate that the proposed project will not 

significantly deteriorate the existing air quality in regions that have been established as 

being in attainment of federal air quality standards. All of Vermont has been determined 

to be in attainment, or unclassified, for all of the federal air quality standards. Significant 

deterioration is considered to have occurred if the air quality impact concentration of the 

facility alone exceeds the remaining PSD increment value. In Vermont, major new 

sources are allowed to consume no more than 75% of the available short term increment 

and no more than 25% of the available annual increment. 

Vermont and the U.S. EPA have adopted PSD increments for three classifications of 

geographical areas. Except for the Lye Brook Wilderness Area near Manchester, VT, all 

of Vermont is considered Class II. The Lye Brook Wilderness Area is classified as Class 

I. Class I areas are afforded greater protection under air pollution control laws in order 

to preserve their more pristine characteristics.

Nearby sources that consume increment are to be included in the PSD increment 

analysis for the proposed project in order to determine what the remaining available 

increment is to the proposed source. Certain facilities that have increased their 

emissions of respective pollutants since the respective baseline date are considered to 

have consumed increment. A review of the sources near the proposed Facility has 

determined that there are no nearby sources that consume increment for NO2, SO2, 

PM2.5, or PM10.
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Table 6-7 summarizes the results of the predicted PSD increment impacts. The 

maximum predicted impacts for both Class I and Class II areas are less than the 

available increment.

Table 6-7: PSD Increment Impacts

Pollutant Averaging 

Time

Max Impact 

(μg/m3)

PSD Increment 

Standard (μg/m3)

Available 

Increment in 

Vermont (μg/m3)

1

Class I Class II Class I Class II Class I Class II

PM10

24-hour 0.12 3.8 8 30 6 22.5

Annual 0.016 0.55 4 17 1 4.25

PM2.5

24-hour 0.15 4.4 2 9 1.5 6.75

Annual 0.014 0.51 1 4 0.25 1

SO2

3-hour 0.79 17.1 25 512 18.76 384

24-hour 0.14 5.8 5 91 3.75 68.25

Annual 0.017 0.58 2 20 0.5 5

NO2 Annual 0.018 0.90 2.5 25 0.625 6.25

1

 Vermont regulations allow major new sources to consume only 25% of the annual increment and 75% of

the short term increment.

6.4 Class I Air Quality Related Values Analyses

For facilities that are further than 50 km from a Class 1 Area, the Federal Land 

Managers Air Quality Related Values (AQRV) Workgroup (FLAG) has established a 

method to screen out from AQRV review those sources with relatively small amounts of 

emissions and/or located a large distance from a Class I area (a.k.a. Q/d). However, the 

Facility is located within 50 km distance of the Lye Brook Wilderness, so the Permittee 

must evaluate the air pollution effects from their proposed project on the AQRVs for the 

impacted Class 1 area. 

6.4.1 Class I Area Air Quality Impact Modeling

New sources must demonstrate compliance with all National Ambient Air Quality 

Standards as well as demonstrate that there will not be any exceedances of any 

PSD Increments. As discussed in Section 6.2 of this document, the predicted 

impacts from this project will not exceed any NAAQS; this includes the Lye Brook 

Wilderness Area. As shown in Section 6.3, the air quality impacts were predicted 

for the Lye Brook Wilderness Area and compared to the PSD increments: the 

impacts were below the available increments. Any growth associated with this 

project is not expected to result in secondary emissions which need to be 

included in the NAAQS review or the PSD increment review.
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6.4.2 Visibility Impairment

The visibility regulations for new source review (40 CFR §51.307 and §52.27) 

require visibility impact analysis in PSD areas for major new sources or major 

modifications that have the potential to impair visibility in any Class I area. An 

“adverse impact on visibility” means visibility impairment which interferes with the 

management, protection, preservation, or enjoyment of a visitor’s visual 

experience of the Class I area. The Permittee conducted a Level 1 Screening 

Procedure as outlined in EPA’s Workbook for Plume Visual Impact Screening 

and Analysis using EPA’s VISCREEN model (Version 1.01 dated 88341). 

VISCREEN is used to calculate the potential visual impact of a plume of 

emissions for specific transport and meteorological conditions. Based on the 

results of this Level 1 Screening Procedure using VISCREEN, the proposed 

Facility’s plume will not cause adverse visual impacts inside the Lye Brook Class 

I area.

Table 6-8: Class I Visibility Modeling Results 

Maximum Visual Impacts Inside the Class I Area

Delta-E Absolute Contrast

Background

Theta 

(°)

Azimuth 

(°)

Distance 

(km)

Alpha 

(°)

Screening 

Criteria Plume

Screening 

Criteria Plume

SKY 10 135 52.7 34 2.00 0.891 0.05 0.014

SKY 140 135 52.7 34 2.00 0.431 0.05 -0.009

TERRAIN 10 84 41.4 84 2.00 1.957 0.05 0.015

TERRAIN 140 84 41.4 84 2.00 0.145 0.05 0.002

6.4.3 Class I Area - Deposition Analysis

The Permittee performed a modeling analysis to estimate the deposition of total 

nitrogen and total sulfur to the Lye Brook Wilderness Area. AERMOD was 

selected to perform this deposition modeling. The gaseous and particulate 

deposition rates were modeled separately, and the results summed at each 

receptor to obtain total deposition. Both wet and dry deposition was evaluated. 

The average annual emissions rates were adjusted to represent only the sulfur or 

nitrogen (versus SO2 or NOx) emitted. 

The summed gaseous and particle deposition results are compared to the 

Deposition Analysis Threshold (DAT) of 0.010 kg/ha-yr (0.001 g/m2

-yr) for 

nitrogen and 0.010 kg/ ha-yr (0.001 g/m2

-yr) for sulfur.

The maximum predicted total sulfur deposition from the proposed facility (100% 

load/55% moisture) at any Lye Brook Wilderness Area receptor is 2.20x10-4 g/m2

-

yr or 22% of the DAT.

The maximum predicted total nitrogen deposition from the proposed facility (75% 

load/45% moisture) at any Lye Brook Wilderness Area receptor is 1.77x10-4 g/m2

-

yr or 18% of the DAT.
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6.5 Additional Impact Analysis

As required by federal PSD regulations, 40 CFR 52.21(o), the Permittee included in the 

permit application additional impact analysis of: (a) the impairment to visibility, soils and 

vegetation that would occur as a result of the new major source and general, 

commercial, residential, industrial, and other growth associated with the new major 

source, except that an analysis of the impact on vegetation having no significant 

commercial or recreational value is not required; (b) the air quality impact projected for 

the area as a result of the general commercial, residential, industrial, and other growth 

associated with the facility.

Vermont’s State Implementation Plan, states that impacts on vegetation, soils and an 

assessment of secondary growth will be conducted through procedures established in 

Title 10 Chapter 151, Vermont Statures Annotated. Section 6081 of this law requires the 

review and issuance of an Act 250 Land Use Permit for all significant changes in land 

use throughout the state. This section includes all secondary growth and all 

development of a nature likely to impact soils and vegetation through emissions to the 

ambient air. When the SIP was written, it was assumed that all development in Vermont 

would be required to obtain an Act 250 Land Use Permit. Since the Facility under review 

is an energy facility, it is required to just obtain approval through Act 248. For this 

project, the Air Pollution Control Division will perform the review to ensure that the 

project will not cause the impairment of visibility, soils and vegetation due to the direct

effects of the facility or due to secondary growth associated with the construction of this

new source of air pollution.

6.5.1 Growth Analysis

The peak construction work force is estimated to be 125 persons. The facility 

expects to employ a staff of 20-30 employees for plant operations. 

It is expected that a significant construction force is available and is supported by 

the fact that within New England, significant construction activities have already 

occurred (including construction of a number of existing power projects). 

Therefore, it is expected that because this area can support the Project’s 

construction from within the region, new housing, commercial and industrial 

construction will not be necessary to support the Project during the building 

period.

For any new personnel moving to the area as a permanent employee to support 

the Project operations once constructed, a significant housing market is already 

established and available. Therefore, no new housing is expected. Further, due 

to the small number of new individuals expected to move into the area to support 

the Project and the significant level of existing commercial activity in the area, 

new commercial construction is not foreseen to be necessary to support the 

Project’s permanent work force. In addition, no significant level of industrial 

related support will be necessary for the Project, thus industrial growth is not 

expected. No new significant emissions from secondary growth during either 

operations, or the construction phase, are anticipated.
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6.5.2 Ambient Air Quality

New sources must demonstrate compliance with all National Ambient Air Quality 

Standards as well as demonstrate that there will not be any exceedances of any 

PSD Increments. As discussed in Section 6.2 of this document, the predicted 

impacts from this project will not exceed any NAAQS. As shown in Section 6.3, 

the air quality impacts were predicted for the Lye Brook Wilderness Area and 

compared to the PSD increments: the impacts were below the available 

increments. As noted in Section 6.5.1, there are no new significant emissions 

expected from secondary growth associated with this project, so NAAQS review 

and the PSD increment review adequately reflect the potential impacts from this 

proposed facility.

6.5.3 Effects on Soils, Vegetation, and Secondary Impact Analysis

New major sources and major modifications are required to evaluate the effects 

of their air pollution emissions on soils and vegetation in the impact area. Any 

permit application for such a project is expected to provide a characterization of 

the soils and vegetation in the impact area and an evaluation of any adverse 

economic and ecological effects from the ambient concentration projected by the 

air quality modeling.

Evaluation of impacts on sensitive vegetation was performed by comparison of 

predicted project impacts with screening levels presented in A Screening 

Procedure for the Impacts of Air Pollution Sources on Plants, Soils and Animals

(EPA, 1980). The assessment was performed by adding the Facility impacts with 

ambient background concentrations and comparing the total to vegetation 

sensitivity screening levels presented in Table 3.1 of EPA’s screening procedure.

The screening levels represent the minimum screening levels at which visible 

damage or growth effects to vegetation may occur. Screening levels have been 

established for the following pollutants that will be emitted from the Facility:

• 1-hour, 3-hour and annual SO2,

• 4-hour, 8-hour, monthly and annual NO2,

• Weekly CO,

• Monthly beryllium, and

• Quarterly lead.
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The same background concentrations were used for NO2, SO2, and CO as 

shown in Table 6-3 above. The closest beryllium background values are

available from the Underhill, VT monitoring station. There are monitors near Lye 

Brook and in Underhill and Burlington Vermont that provide data for lead in PM2.5. 

Burlington will be used to represent the background value for this project. In 

addition, data is not presented for all averaging periods being examined. In 

those cases, the next shortest averaging period was used to conservatively 

estimate background. 

Table 6-9 presents the results of the vegetative impact analysis. The modeled 

concentrations from the Facility, in combination with representative background 

values, are less than the vegetation sensitivity concentrations. Therefore, the air 

pollution emissions from Facility will not adversely impact vegetation in the area.
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Table 6-9: Vegetative Impact from Criteria Pollutants

Pollutant

Averaging 

Time

Maximum 

Modeled 

Concentration 

(μg/m3)

Background 

Concentration(1)

(μg/m3)

Total 

(μg/m3)

Intermediate 

Vegetation 

Sensitivity 

Concentration 

(μg/m3)

Resistant 

Vegetation 

Sensitivity 

Concentration 

(μg/m3)

Sensitive 

Vegetation 

Sensitivity 

Concentration 

(μg/m3)

Load %/ 

Moisture 

% Case

SO2

1 HOUR 31.4 70.7 102.1 - - 917.0 100%/45%

3 HOUR 17.1 73.3 90.4 2096.0 13100.0 786.0 100%/45%

ANNUAL 0.6 7.6 8.2 18.0 18.0 18.0 100%/55%

CO WEEKLY (5) 21.6 1832.0 1853.6 - 18000000.0 1800000.0 60%/35%

NO2 

(6)

4 HOUR (4) 41.1 77.1 118.2 9400.0 16920.0 3760.0 100%/45%

8 HOUR 23.3 77.1 100.4 7520.0 15040.0 3760.0 100%/55%

MONTHLY (5) 13.8 77.1 90.9 564.0 564.0 564.0 60%/35%

ANNUAL (7) 0.9 16.4 17.3 94.0 94.0 94.0 60%/35%

BERYLLIUM MONTHLY 0.001 0.0000058 0.001 0.01 0.01 0.01 60%/35%

LEAD QUARTERLY 0.026 0.0042 0.030 1.5 1.5 1.5 60%/35% 1 From VTDES (SO2, CO & NO2) and AIRData Website (Lead) 2 Background was conservatively estimated for: Use of 1-hour values for 4-hour, 8-hour and monthly NO2, and use of 8-hour CO values for weekly CO. 3 High Second High values used for all short term averages. High values used for annual. 4 4-hour value conservatively based on modeled 3-hour value. 5 Weekly, Monthly, and Quarterly modeled concentration averages conservatively based on modeled 24-hour average. 6 NO2 uses ARM values for NOX to NO2 conversion (0.75 for Annual; , 0.8 for 4-hour, 8-hour & Monthly). 7 Annual NO2 emissions based on guaranteed rates. Hourly NO2 emissions represent maximum emissions (100%/45%). 
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The EPA screening procedure also contains threshold levels for several 

elements to assess the impacts of trace element deposition to soil. Table 3.4 in

the screening procedure lists the screening level for the concentration of the 

listed elements in the soil. The procedure also shows how to estimate the 

element deposition concentration in the impacted soils based on the annual 

average concentration of the pollutant.

Equation 5.1: DC (ppmw) = 21.5 * (N/D) * X

Where:

DC = deposited concentration (ppmw),

N = expected lifetime of source (yr),

D = depth of soil through which deposited material is distributed (cm), and

X = maximum annual average ambient concentration from the source 

(μg/m3

).

The procedure recommends using a value of 40 years for the expected lifetime of 

the source (N), and a soil depth of 3 cm (d).

The maximum annual average ambient concentration can be estimated by using 

the results of the NAAQS modeling. For an emission rate of 1 gram/second, the 

modeled maximum annual average ambient concentration is 0.4538 μg/m3

(100%/55% load scenario). Table 3-5 of this document has the emission factors 

and mass emission rate for these listed elements. By multiplying the element’s 

estimated emission rate (in terms of g/s), and multiplying by the normalized 

modeling impact (0.4538 μg/m3

/ 1 g/s) yields a calculated maximum annual 

concentration for the element.

Table 6-10 summarizes the potential deposition concentrations for the listed 

elements along with their respective screening levels. Emission factors for boron 

and fluoride were not available for wood, however because only natural 

(untreated) wood is permitted as the main fuel for this facility, there are not 

expected to be significant emissions of either of these elements. Therefore the 

air pollution emissions from the Facility will not adversely affect soil quality.
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Table 6-10: Trace Element Emission Assessment

Element

Potential 

Emissions 

(Tons per 

Year)1

Estimated 

emission 

rate (g/s)

Estimated 

Maximum 

Annual 

Concentration 

(μg/m3)

Estimated Soil 

Concentration 

from Deposition 

DC

(ppmw)

Screening 

Level 2

(ppmw)

Arsenic 0.008 2.34E-04 1.06E-04 0.030 3

Boron N/A 0.5

Cadmium 0.008 2.40E-04 1.09E-04 0.031 2.5

Chromium 0.043 1.23E-03 5.58E-04 0.160 8.4

Copper 0.100 2.87E-03 1.30E-03 0.373 40

Fluoride N/A 400

Lead 0.098 2.81E-03 1.27E-03 0.365 1000

Manganese 0.175 5.03E-03 2.28E-03 0.655 2.5

Mercury 0.007 2.05E-04 9.29E-05 0.027 455

Nickel 0.067 1.93E-03 8.76E-04 0.251 500

Selenium 0.006 1.76E-04 7.97E-05 0.023 13

Vanadium 0.002 5.73E-05 2.60E-05 0.007 2.5

1 Based on maximum potential emissions.

2 Table 3.4 lists the screening level of the concentration of the element in the soil - A 

Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils and 

Animals (EPA, 1980). 

6.5.4 Visibility Analysis

§5-502(4)(d) of the Regulations requires the evaluation of major sources and 

major modifications to demonstrate that the increase in allowable emissions will 

not cause an adverse impact on visibility in any sensitive area. The Regulations

further define sensitive area as any portion of the area comprising Lye Brook 

Wilderness Area and all other terrain in Vermont at or above the elevation of 

2500 feet above mean sea level. Section 6.4.2 of this document contains the 

review of visibility impairment for the Lye Brook Wilderness Area. 

The nearest sensitive area to the Facility is Mount Ascutney located in Ascutney 

State Park. To help establish if the proposed Facility will cause an adverse 

impact on the visibility from the summit of Mount Ascutney, a Level 1 screening 

analysis using VISCREEN was conducted, and the results exceeded the 

screening criteria. Subsequently a Level 2 screening analysis was conducted. 

Since there is complex terrain between the Facility and Mount Ascutney 

containing some terrain features that are higher in elevation than the plume 

height, the atmospheric stability class was selected as ‘E’ instead of ‘F’ to 

represent that there will be some disruption of the plume. The model was run 

using two different wind speeds to help determine the worst case impacts. Table 

6-11 has a summary of the results for the Level 2 screening. Based on the 

results of the Level 2 screening, the Facility will not cause an adverse impact and 
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further analysis is not required. 

Table 6-11: Sensitive Area Visibility Modeling Results 

Maximum Visual Impacts Inside the Sensitive Area

Delta-E Absolute Contrast

Background

Theta 

(°)

Azimuth 

(°)

Distance 

(km)

Alpha 

(°)

Screening 

Criteria Plume

Screening 

Criteria Plume

SKY 10 46 12.3 123 2.00 0.697 0.05 -0.004

SKY 140 46 12.3 123 2.00 0.295 0.05 -0.000

TERRAIN 10 46 12.3 123 2.00 0.442 0.05 0.002

TERRAIN 140 46 12.3 123 2.00 0.159 0.05 0.004

Maximum Visual Impacts Outside the Sensitive Area

SKY 10 1 1.0 168 2.00 1.280 0.05 -0.016

SKY 140 1 1.0 168 2.00 0.753 0.05 0.004

TERRAIN 10 1 1.0 168 2.00 1.827 0.05 0.021

TERRAIN 140 1 1.0 168 2.00 0.673 0.05 0.025

7.0 HAZARDOUS AIR CONTAMINANTS

Emissions of hazardous compounds into the air are regulated under both state and federal 

regulations. Federal regulations are promulgated under 40 CFR Part 63 and use the terms 

“Hazardous Air Pollutants (HAPs)”, “Major Source of HAPs”, and “Area Source of HAPs”. 

These regulations are specific to source emission categories, such as boilers, reciprocating 

engines, or chrome plating operations. Typically separate emission standards are 

established for Major Sources and Area Sources. The proposed Facility is not considered a 

Major Source of HAPs and is instead classified as an Area Source. The applicable federal 

regulations for HAPs were discussed above in Section 4.2. Vermont regulates emissions of 

hazardous air contaminants (“HACs”) under to §5-261 of the Regulations. This regulation is 

pollutant specific rather than emission category specific. The Owner/Operator of a source 

must quantify its facility wide emissions of each HAC regulated by this rule. Any Facility 

whose emission rate of a HAC exceeds its respective Action Level (“AL”) is subject to the 

rule for that respective HAC. The Owner/Operator must then demonstrate that the 

emissions of the HAC are minimized to the greatest extent practicable by achieving the 

Hazardous Most Stringent Emission Rate (“HMSER”) for that HAC.

As shown in Section 3.2, the facility is expected to exceed the action level of 35 different 

HACs and is therefore subject to §5-261. 

For the HMSER review, the HACs are divided up into several categories based on their 

emission control characteristics: (1) non-mercury metallic HACs; (2) organic HACs; (3) acid 

gases; (4) ammonia; and (5) CDD/CDF.
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7.1. HMSER Selection – non-mercury metallic HACs

The non-mercury metallic HACs that are estimated to exceed their respective action level 

include: arsenic, barium, beryllium, cadmium, chromium (total), chromium (hexavalent), 

cobalt, copper (dusts & mists), iron oxides (dusts & fumes), lead compounds, manganese, 

nickel compounds, vanadium pentoxide and zinc oxide.

Non-mercury metallic HACs are a component of the PM contained in the fly ash from the 

boiler. The choice of control devices for non-mercury metallic HACs is the same as those 

for fine PM.

The Agency is establishing HMSER for non-mercury metallic HACs from the Boiler as the 

use of a fabric filter control device and a filterable PM emission limit of 0.010 lb/MMBtu (1 

hour block average). The single filterable PM emission limit is serving as a surrogate for 

separate emission limits for each of these numerous non-mercury metallic HACs from the 

boiler. 

7.2. HMSER Selection – organic HACs

The Facility’s organic HAC emissions that are estimated to exceed their respective action 

level include: 1,2-dichloroethane (ethylene dichloride), 1,2-dichloropropane (propylene 

dichloride), acetaldehyde, acrolein, benzene, benzo(a)pyrene, bromodichloromethane, 

chloroform, dichloromethane (methylene chloride), dinitrotoluene-2,4, formaldehyde, 

hexachlorobenzene, naphthalene, tetrachloroethylene (perchloroethylene), 

trichloroethylene, and vinyl chloride.

These organic emissions are formed by incomplete combustion of fuel. The methods for 

control of organic HACs from the Boiler would be the same as for the control of VOCs. Thus 

total VOC emissions or CO can reasonable serve as a surrogate to demonstrate adequate 

control of the individual organic HACs.

HMSER for organic HACs is good combustion control and the use of a BFB, and a CO

emission limit of 0.075 lb/MMBtu (24 hour rolling average), and a VOC emission limit of 

0.005 lb/MMBtu (hourly average).

7.3. Acid Gases

Sulfuric acid mist, hydrogen chloride and chlorine are estimated to exceed their respective 

action level. 

Sulfur that is present in fuels is converted during combustion to SO2 and to a lesser degree 

SO3. The SO3 rapidly reacts with the water vapor in the exhaust gases to form H2SO4

(sulfuric acid mist). Some of the chlorine that is present in the wood fuel may also be 

released from the chemical composition of the wood and a portion of this may be released 

as chlorine, but it is more likely to form hydrochloric acid.

Add-on control technologies that are available to reduce acid gas emissions include dry 

sorbent injection, wet scrubbing systems and spray dryer adsorbers. These control 
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technologies were reviewed in Section 5.4 above for the control of SO2 and were 

determined to not be cost effective for SO2, with the lower emission rate of sulfuric acid mist, 

the cost of control would be even higher.

HMSER for the Boiler is the use of natural wood which has an inherently low level of sulfur 

and chlorine, and a HCl emission limit of 0.000834 lb/MMBtu.

7.4. Ammonia

Ammonia is used as a reagent in the SCR unit of the boiler to react with NOX to form 

nitrogen and water. Some of the ammonia will pass through the SCR unreacted and be 

emitted with the exhaust gas. This is referred to as ammonia slip. Ammonia slip is 

minimized through good controls of the ammonia feed system and the use of an ammonia 

CEMS. A review of ammonia emission limits for other wood fired boilers equipped with SCR 

systems for NOx control show that the lowest limit is 10 ppm NH3 @ 7% O2 (this is 

essentially the same as 13 ppm NH3 @ 3% O2).

The Permittee has proposed an HMSER of 10 ppm NH3 @ 7% O2. 

The Agency concurs with this proposed limit and is establishing HMSER as an ammonia slip 

limit of 10 ppm NH3 @ 7% O2 based on a 24-hour rolling average for the wood fired boiler.

7.5. CDD/CDF

In combustion processes, CDDs and CDFs can be formed from the thermal breakdown of 

precursor ring compounds and chlorine. These precursor compounds are produced as a 

result of incomplete combustion. According to the EPA, dioxin formation occurs between 

392 and 842o

F. Typical control is using fuels with low chlorine content and through the use 

of good combustion design and combustion practices to minimize the formation of the 

precursors. 

In municipal incinerators, which have higher levels of chlorine in the fuels and therefore 

greater CDD/CDF emission rates, controls have also included the injection of powdered 

activated carbon (PAC) into the exhaust gas. The gaseous CDD/CDFs are absorbed onto 

the activated carbon, and carbon can be removed from the exhaust gases with a traditional 

PM control device (ESP or fabric filter). For this approach to be the most effective it must be 

located at a point in the exhaust system where the exhaust temperatures are lower than the 

dioxin formation range (less than ~ 400o

F). This would require a PAC system on this 

Facility’s boiler to be located downstream of the SCR, which would necessitate a second PM 

control device to remove the carbon.

The Permittee is proposing HMSER for CDD/CDFs to be good combustion practices and 

properly operated air pollution control equipment.

The Agency agrees that HMSER for CDD/CDFs is good combustion practices and properly 

operated air pollution control equipment.