VERMONT AGENCY OF NATURAL RESOURCES 

Department of Environmental Conservation 

Air Pollution Control Division 

TECHNICAL SUPPORT DOCUMENT 

FOR 

PERMIT TO CONSTRUCT 

#AP-11-015 

Permit Date: February 10, 2012 

Beaver Wood Energy Fair Haven, LLC 

Fair Haven, 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. 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

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Facility: 

Beaver Wood Energy Fair Haven, LLC 

Wood fired power boiler 

Wood pellet manufacturing 

Exit 1, Route 4 

Fair Haven, Vermont 05261 

Application Contact Person: 

Tim Donnelly or Amy Austin 

MacMillan & Donnelly, Inc. 

361 U.S. Route One, Suite 2 

Falmouth, ME 04105 

Phone - (207) 781-7392 

Facility Contact Person: 

Thomas Emero 

Beaver Wood Energy Fair Haven, LLC 

82 Village Street 

Medfield, MA 02053 

Phone - (508) 321-1181 

1.0 INTRODUCTION 

Beaver Wood Energy Fair Haven, LLC (hereinafter “Permittee”) has proposed to 

construct/install and operate a 34 MW (gross) wood fired electrical generating station and a 

115,000 ton/yr wood pellet manufacturing facility at Exit 1 (across from the Vermont Visitor 

Center) on Route 4 in Fair Haven, Vermont (also referred to herein as “Facility”). 

Administrative Milestones 

Table 1-1: Administrative Summary 

Administrative Item Result or Date 

Date Application Received: 2/22/2011 

Date Administratively Complete: 2/22/2011 

Date Draft Decision: 9/15/2011 Approved 

Date & Location Draft Decision/Comment Period 

Noticed: 

9/15/2011 The Rutland Herald

Date & Location Public Meeting Noticed: 9/22/2011 The Rutland Herald 

Date & Location of Public Meeting: 10/13/2011 Fair Haven Grade School 

Deadline for Public Comments: 10/17/2011 

Date Proposed Decision: 2/10/2012 

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

§5-401(4): Wood products industries 

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 

2499 – Wood Products not Elsewhere Classified 

 
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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

63.2 43.2 99.9 190.5 49.9 <10/25 470,900 

1

 PM/PM10 - 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 

Beaver Wood Energy Fair Haven, LLC. (also referred to herein as "Permittee") owns a 

property on Route 4 in the town of Fair Haven, Vermont (also referred to herein as 

"Facility"). The Facility is located approximately 2 km from the center of Fair Haven. 

2.2 Facility Description 

Operations performed at the Facility are classified within the Standard Industrial 

Classification Code - 4911 (Electrical Services) and 2499, wood products, not elsewhere 

classified. The regulated sources of air contaminant emissions at the Facility are listed 

in Table 2-1. Refer to Table 2-2 for information on air pollution control equipment used 

at the facility 

 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

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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) 

Main Boiler: wood fired Advanced 

Stoker Boiler 

Two auxiliary/start-up burners for the 

main boiler 

482 

MMBtu/hr 1 wood Multi-clone, ESP, 

Multi Pollutant 

Catalytic Reactor 

180 

60 MMBtu/hr 

(each) ULSD 6

Main Boiler: Cooling Tower – 2 cells 25,000 gpm 

(nominal) - Drift eliminator - 

Pellet Plant: Wood fired burner for 

rotary drum dryer. 

30 MMBtu/hr wood Low NOx burner, 

cyclone & fabric 

filter 

100 

Pellet Plant: Rotary drum dryer – 60’ 

long, single pass 

15 ODT/hr 2

wood 

Pellet Plant: Wood pellet processing 

equipment (hammermill, storage silos, 

conveyors, pellet mills, pellet cooler, 

pellet bagging) 

115,000 

ODT/yr 3 Wood / 

wood 

pellets 

Fabric filter(s) - 

Fly ash storage silo 900 Wood ash Fabric filter - 

Dry wood storage 25,000 ft3 Dry wood None - 

Pellet storage silos (2 silos) 22,500 ft3 each Wood 

pellets 

None - 

Two (2): Caterpillar C32 Diesel Engine 

Generator 

1,000 kW 4

(each) 

ULSD 

Tier 2 

per 40 CFR 

Part 89 

- 

Two (2): Caterpillar C15 Diesel Engine 

Generator 

500 kW 4

(each) 

- 

Diesel Engine Fire Pump 400 bhp 5 Tier 3 

per 40 CFR 

Part 89 

- 

Temporary 

Five (5) Diesel Engine Generators – for 

construction 

100 kW 4

(each) 

- 

Temporary 

Fuel oil boiler – for use during the 

construction phase of the project 

< 10 MMBtu/hr ULSD None TBD 

1

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

2

 ODT/hr - oven-dry ton of wood output per hour 

3

 ODT/yr - oven-dry ton of wood output per year 

4

 kW – rated kilowatt output 

5

 bhp – rated brake horse power output 

6

 ULSD – ultra low sulfur diesel (0.0015% or 15 ppm sulfur content). 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

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Table 2-2: Air Pollution Control Equipment 

Main Boiler – multi-clone Pressure Drop: 3.2” w.c. nominal 

Inlet Temperature: 450 oF 

Dimensions: 13’-10” D x 24’-8” W x 10’-4” H 

Air Flow Rate: 269,000 acfm 

Main Boiler – ESP Inlet Temperature: 450 oF 

Air Flow Rate: 269,000 acfm 

ESP 

4-field single chamber, solid electrodes and collecting plates. 

Method of cleaning: rapping 

Dimensions: 99,467 ft2

Specific Collection Area: 370 ft2/1000 acfm 

Main Boiler - Multi Pollutant 

Catalytic Reduction (MPCR) 

including oxidation catalyst for CO 

and selective catalytic reduction for 

NOx. 

Inlet Temperature: 425 oF 

Details not available at this time. 

Pellet burner / rotary dryer - 

Cyclone 

Cyclone: 

Pressure Drop: 5 – 6 inch w.c. 

Inlet temperature: 170 – 180 oF 

Dimensions: 42’-8 7/16” H x 11’ D 

Pellet burner / rotary dryer – 

Fabric filter 1 Fabric filter: Performance: 0.005 gr/dscf 

Pressure Drop: 4 – 5” w.c. 

Inlet Temperature: 170 - 180 oF 

Dimensions: 494 bags, 7,118 ft2

16 oz. Dacron fabric 

Air Flow Rate: 70,000 acfm 

Air-to-cloth Ratio: 9.1:1 

Cleaning: plenum blowback 

Pellet mills, dry hammermill, pellet 

cooler and pellet packaging 

system. 

One or more fabric filters. 

Fabric filter: 

Performance: 0.005 gr/dscf 

Inlet Temperature: 125 oF 

Estimate total Air Flow Rate: 50,000 acfm 

Further details not available at this time. 

Ash silo vent fabric filter Performance guarantee: 0.02 gr/dscf 

Inlet temperature: 135 oF 

Air Flow Rate: 900 acfm 1

 The term fabric filter is synonymous with the term bag house for this document. 

2.3 Description of Compliance Monitoring Devices 

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

measure the emission of NOx, CO, NH3, and CO2 from the Main Boiler 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 Main Boiler. 

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 
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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. 

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 

To avoid triggering the need to acquire NOx emission reduction credits, the Permittee 

has proposed to limit the annual emission of NOx to less than 100 tons at the Facility. 

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

below. 

 

The Permittee has proposed an annual capacity factor of 96% for the Main Boiler. The 

Permittee has also proposed to limit the production of wood pellets to 115,000 tons/year. 

This permit limits the Facility to 115,000 oven-dry (0% moisture content) tons/year of 

output from the rotary dryer. The dried material leaving the rotary dryer will have a 

moisture content of approximately 10%. So the annual output from the rotary dryer 

could be 126,500 tons (at 10% moisture content). As the dried material is processed 

into pellets, some of it will become fines/dust and will not become part of the final pellet 

product. The fines are used on site as fuel. There is expected to be about 1 ton of fines 

for every 15 tons of output from the dryer; at full production this is about 8,400 tons each 

year. With the loss of the fines, there is approximately 118,100 tons of this 10% 

moisture content material made into pellets. As the wood material from the dryer is 

processed into pellets, there is some further loss of moisture and the moisture content in 

the finished pellets will be around 7%. So the total weight of the annual production of 

wood pellets is expected to be 114,880 tons at 7% moisture content. Unless noted 

otherwise in this permit, the weight of wood materials in the pellet manufacturing 

operation will be in terms of oven dry ton (ODT). 

 
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3.0 QUANTIFICATION OF POLLUTANTS 

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

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

applicability with 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 Main 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 a 

96% capacity factor. Since ULSD oil firing is only for startup there are no separate 

emission limits established specifically for oil firing and the Facility is expected to comply 

with the emission limits at all times regardless of fuel. 

 

The potential emissions for HAPs 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 of this data is available in section 3.2 of this document. 

Table 3-1: Main Boiler - Allowable Emissions 

482 MMBtu/hr heat input x 96% Capacity Factor = 4,053,427 MMBtu/yr annual heat input 

Emission Factor Allowable Emissions 

Factor Units 1 Source tons per year 

SO2 0.02 lb/MMBtu MSER 40.5 

NOx – Annual 0.03 lb/MMBtu MSER 60.8 

NOx – hourly 0.065 lb/MMBtu MSER - 

NOx – 8-hr avg 0.33 lb/MMBtu Startup limit when SCR is offline - 

PM10/PM2.5/PM 2 0.019 lb/MMBtu MSER / HMSER 38.5 

CO 0.075 lb/MMBtu MSER / HMSER 152 

VOC 0.005 lb/MMBtu MSER / HMSER 10.1 

HAPs 0.0053 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. 

10.8 

1

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

 PM: total PM including filterable and condensable fractions. 
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Table 3-2: Burner / Rotary Dryer - Allowable Emissions 

Based on 

115,000 ODT/yr 

30 MMBtu/hr 

Emission Factor Allowable Emissions 

Factor Units Source tons per year 

SO2 0.025 lb/MMBtu 1

MSER & 

Permit application – burner manufacturer’s 

guarantee 4

2.7 

NOx 0.35 lbs/MMBtu 37.7 

PM10/PM2.5/PM 2 0.20 lb/ODT 3 11.6 

CO 0.35 lb/MMBtu 37.7 

VOC 0.69 lb/ODT 39.8 

HAPs 

0.18 

0.014 

lb/ODT 

lb/ODT 

AP-42, Wood Residue Combustion in 

Boilers Table 1.6-3 and; 

Formaldehyde emissions testing at New 

England Wood Pellet – Jaffrey, NH 

10.2 

1

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

 PM: total PM including filterable and condensable fractions. 

3

 lb/ODT: pounds of pollutant emitted per oven-dry ton of wood output from the rotary dryer 4

 Manufacturer: Coen 

1

 gr/dscf: grains of particulate matter per dry standard cubic feet of exhaust gas. 2

 Assumes a 3% moisture content exhaust gas. 

Table 3-4: Diesel Generators – Allowable Emissions 

Emission estimate 

based on 65 hours 

Total of 3000 kW of 

Tier 2 Engines

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: Allowable Emissions by Production Process – Particulate Emissions 

Equipment/Source 

Emission 

Factor 

(gr/dscf) 1

Source of 

Emission Factor 

Maximum

Flow Rate 

(acfm) 

Maximum Flow 

Rate (dscfm) Emission Rate 

(ton/yr) 

Pellet mill processes 

other than burner/dryer 

Fabric filter 

0.005 Application for 

AP-11-015 

50,000 43,800 2

 8.2 

Ash silo vent - fabric filter 0.02 900 800 0.6 
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Table 3-5: Fire Pump/Diesel Engine – Estimated Emissions 

Emission estimate 

based on 65 hours 

250 kW Tier 3 Engine

Emission Factor Allowable Emissions, 

tons/yr Factor Units Source 

SO2 0.0015 lb/MMBtu 15 ppm sulfur content in fuel 0.0001 

PM 0.2 

g/kW-hr 

EPA Tier 3 Engine 

0.004 

NOX 4.0 0.07 

CO 3.5 0.06 

VOC - - - 

The operation of the cooling towers also results in the emission of PM. This is a result of the 

release of cooling water droplets to the atmosphere: “drift.” The water droplets contain 

suspended solids and this becomes fine PM in the atmosphere when the water evaporates. 

The cooling towers will be equipped with a ‘drift eliminator’ to minimize this emission. The 

estimated emission of PM from the cooling towers is based on the flow rate of the cooling tower 

circulating water (12,696,055 lb/hr), the concentration of the total dissolved solids in the water 

(1,520 ppm), the drift rate (0.005%) and the operating hours (8760 hours/year * 96% capacity 

factor of the Main Boiler). 

(12,696,055) * (1,520/1000000) * (0.005/100) * (8760) * (96%) / (2000lbs/ton) = 4.1 tons/yr PM 

Table 3-6: Summary of Allowable Air Contaminant Emissions by Source (tons/year) 

Source PM/PM10 SO2 NOX CO VOC Total 

HAPs 

Main Boiler 38.5 40.5 60.8 152 10.1 10.8 

Pellet Plant: Burner/Rotary Dryer 11.6 2.7 37.7 37.7 39.8 10.2 

Pellet Manufacturing area 8.2 - - - - - 

Diesel generators (2@500kW, 

2@1000kW) 0.04 - 1.37 0.75 - - 

Diesel fire pump - - 0.07 0.06 - - 

Cooling Towers 4.1 - - - - - 

Ash Silo vent 0.6 - - - - - 

Facility Totals 63.1 43.2 99.96 190.5 49.99 21 

Significance Levels 25/15 40 40 50 40 - 

As summarized in Table 3-6 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 
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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 PM, 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.’ SO2 and VOC 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. 

Table 3-7: Temporary Oil Fired Boiler - Allowable Emissions 

These emissions are not added to the facility total since this boiler is only to be used during the 

construction phase of the project. 

Unlimited operating - Total Fuel input : 634,783 gallons/yr ULSD 

Emission Factor Allowable Emissions 

Factor Units 2 Source tons per year 

SO2 142S 1

0.0213 

lb/1000 gal 

AP-42, Fuel Oil Combustion, Table 1.3-

1 (9/98) 0.01 

NOx 20 AP-42, Fuel Oil Combustion, Table 1.3-

1 (9/98) 6.4 

PM 3.3 AP-42, Fuel Oil Combustion, Tables 

1.3-1 and 1.3-2 (9/98) 1.1 

CO 5 AP-42, Fuel Oil Combustion, Table 1.3-

1 (9/98) 1.6 

VOC 0.34 AP-42, Fuel Oil Combustion, Table 1.3-

3 (9/98) 0.1 

HAPs 0.062 AP-42, Fuel Oil Combustion, Tables 

1.3-8 to 1.3-10 (9/98) 0.02 

1

 The sulfur content of ULSD is 0.0015% sulfur, so the emission factor is 0.0213 lb/1000 gal. 

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 Main Boiler and the burner/rotary dryer, 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 and wood pellet manufacturing 

operations located in Vermont and the rest of New England. 

 
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Table 3-8 Quantification of HAC Emissions 

Hazardous Air 

Contaminant CAS# 

Toxic 

Category 

Boiler 

Emission 

Factor 

Boiler EF 

Source 1 

Burner/ 

Rotary 

Dryer 

Emission 

Factor 

Facility 

Emission 

Rate 2 

Action 

Level 

 (lb/mmbtu) (lb/ODT) (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 NCASI 1.07E-01 3.20E-03

1,2-Dichloropropane 

(propylene dichloride) 78875 I 3.30E-05 NCASI 1.22E-01 4.20E-03

2,4,6-Trichlorophenol 88062 I 2.20E-07 NCASI 8.14E-04 2.70E-02

Acetaldehyde 75070 I 1.90E-04 NCASI 5.90E-02 6.90E+00 3.80E-02

Acetone 67641 II 2.20E-04 NCASI 4.70E-02 5.75E+00 2.61E+01

Acrolein 107028 II 1.59E-05 test 1.50E-02 1.63E+00 2.00E-03

Ammonia 7664417 II 10ppm HMSER 2.18E+01 8.30E+00

Antimony 0 II 4.20E-07 NCASI 1.55E-03 3.00E-01

Arsenic 0 I 1.00E-06 NCASI 3.70E-03 1.90E-05

Barium 0 II 1.60E-04 NCASI 5.92E-01 4.00E-02

Benzene 71432 I 5.94E-04 test 4.70E-03 2.69E+00 1.10E-02

Benzo(a)pyrene 50328 I 2.67E-06 NCASI 9.88E-03 4.00E-05

Beryllium 0 I 1.90E-06 NCASI 7.03E-03 3.50E-05

bromodichloromethane 75274 I 3.00E-03 NCASI 1.11E+01 4.60E-03

Bromomethane (methyl 

bromide) 74839 II 1.50E-05 NCASI 5.55E-02 4.00E-01

Cadmium 0 I 1.90E-06 NCASI 7.03E-03 4.60E-05

Carbon disulfide 75150 II 1.30E-04 NCASI 4.44E-01 5.45E+01

Carbon tetrachloride 56235 I 8.90E-07 NCASI 3.29E-03 5.50E-03

Chlorine 7782505 III 7.90E-04 AP-42 3.05E+00 1.00E-02

Chlorobenzene 108907 II 1.70E-05 NCASI 6.29E-02 2.00E-01

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

Chloromethane (methyl 

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

Chromium (total) 0 II 6.00E-07 NCASI 2.22E-03 1.00E-02

Chromium, hexavalent 0 I 4.90E-07 NCASI 1.81E-03 6.90E-06

Cobalt 0 I 1.90E-07 NCASI 7.03E-04 8.30E-04

Copper (dusts & mists) 0 II 5.50E-06 NCASI 2.04E-02 2.00E-02

cumene 98828 II 1.80E-05 NCASI 6.66E-02 3.32E+01
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Table 3-8 Quantification of HAC Emissions 

Hazardous Air 

Contaminant CAS# 

Toxic 

Category 

Boiler 

Emission 

Factor 

Boiler EF 

Source 1 

Burner/ 

Rotary 

Dryer 

Emission 

Factor 

Facility 

Emission 

Rate 2 

Action 

Level 

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

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

Dichloromethane 

(methylene chloride) 75092 I 5.40E-04 NCASI 2.15E+00 1.70E-01

dinitrotoluene-2,4 121142 I 9.40E-07 NCASI 3.48E-03 4.20E-04

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

Ethylbenzene 100414 I 6.80E-06 NCASI 2.52E-02 8.30E+00

Fluoranthene 206440 II 1.64E-06 NCASI 6.07E-03 1.20E+00

Formaldehyde 50000 I 2.19E-04 test 1.40E-02 2.28E+00 6.50E-03

Hexachlorobenzene 118741 I 1.00E-06 NCASI 3.70E-03 1.80E-04

Hexane 110543 II 2.90E-04 NCASI 1.07E+00 5.81E+02

Hydrogen Chloride 7647010 II 3.40E-04 test 1.26E+00 1.70E+00

Iron oxides - dusts & 

fumes 0 II 9.90E-04 AP-42 3.66E+00 1.00E+00

Isopropanol 67630 II 3.90E-03 NCASI 1.44E+01 1.84E+02

Lead compounds 0 I 5.80E-06 NCASI 2.15E-02 8.30E-04

Manganese 0 II 3.43E-05 test 1.27E-01 4.00E-03

Mercury 0 II 9.90E-07 NCASI 3.66E-03 2.00E-02

Methanol 67561 II 8.30E-04 NCASI 5.90E-02 9.27E+00 9.70E+01

Methyl ethyl ketone 78933 II 9.10E-06 NCASI 3.40E-03 3.91E-01 4.15E+02

Methyl Isobutyl Ketone 108101 II 2.30E-05 NCASI 8.51E-02 2.49E+02

Molybdenum 

compounds (metal & 

insoluble) 0 II 1.10E-06 NCASI 4.07E-03 2.00E-01

Naphthalene 91203 I 1.60E-04 NCASI 5.92E-01 2.00E-02

Nickel compounds 0 I 2.90E-06 NCASI 1.07E-02 1.70E-04

PCDD/PCDF - 0 1.38E-10 NCASI 5.11E-07 1.93E-09

Pentachlorophenol 87865 I 4.60E-08 NCASI 1.70E-04 2.40E-03

Phenanthrene 85018 II 7.21E-06 NCASI 2.67E-02 8.70E+00

Phenol 108952 II 1.40E-05 NCASI 7.90E-03 8.82E-01 5.30E+00

Pyrene 129000 II 3.79E-06 NCASI 1.40E-02 8.70E-01

Selenium 0 II 3.00E-06 NCASI 1.11E-02 1.50E-01
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Page 13 of 47 

Table 3-8 Quantification of HAC Emissions 

Hazardous Air 

Contaminant CAS# 

Toxic 

Category 

Boiler 

Emission 

Factor 

Boiler EF 

Source 1 

Burner/ 

Rotary 

Dryer 

Emission 

Factor 

Facility 

Emission 

Rate 2 

Action 

Level 

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

Silver compounds 

(metal) 0 II 1.40E-04 NCASI 5.18E-01 6.60E-01

Styrene 100425 I 6.40E-04 NCASI 5.70E-04 2.43E+00 8.30E+00

Sulfuric Acid Mist 

7664939 II 

9.19E-04 

 B&W 

3.51E+00 

 2.70E-02

Tetrachloroethylene 

(perchloroethylene) 127184 I 2.80E-05 NCASI 1.04E-01 1.50E-02

Tin compounds (metal 

and inorganic) 0 II 3.90E-05 NCASI 1.44E-01 4.00E-01

Toluene 108883 II 2.90E-05 NCASI 5.90E-03 7.27E-01 2.49E+01

Trichloroethylene 79016 I 2.80E-05 NCASI 1.04E-01 4.00E-02

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

Vanadium pentoxide 0 I 5.90E-07 NCASI 2.18E-03 8.30E-04

Vinyl Chloride 75014 I 1.80E-05 NCASI 6.66E-02 9.10E-03

Xylenes (o,m,p) - II 2.80E-05 NCASI 6.38E-03 7.74E-01 8.30E+00

Zinc oxide 0 II 4.50E-05 NCASI 1.67E-01 8.30E-02

1

 Sources of Emission Factors: 

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

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

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

B&W = 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. 2

 For category 3 contaminants, the calculated emission rate is based on maximum short term capacity of the facility. . 

For category 1 & 2 contaminants, the emission rate is based on the annual capacity of the facility taking into account 

operating restrictions. 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

Page 14 of 47 

3.3 – Estimating Potential Green House Gas Emissions 

Section 3.3 Estimation of CO2e EmissionsFacility: BWE - Fair Haven Permit #: AP-11-015Source Source

Estimated 

wood 

usage 

ID Description Units (raw tons)

Main Boiler 275,233 tons 450381 45.0%

Auxiliary burners 6,500 gallons 0 0.0%

Emergency generator 15,301 gallons 0 0.0%

Wood burner - dryer 14,632 tons 23944 45.0%

Table 2. Total Company-Wide Stationary Source Fuel Combustion

Quantity

Fuel Type Combusted Units

21,801 gallons

289,865 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 #2 222,511 490,553 9.0 19.9 1.8 4.0Total Fossil Fuel Emissions 222,511 490,553 9.0 19.9 1.8 4.0Wood and Wood Waste 418,172,227 921,910,856 142,660 314,511 18,724 41,280Total Non-Fossil Fuel Emissions 418,172,227 921,910,856 142,660 314,511 18,724 41,280Total Emissions for all Fuels 418,394,739 922,401,409 142,669 314,531 18,726 41,284

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) 9,024 9,947All CO2e emissions at stack (Fossil CO2e + Biogenic CO2e) - for APCD Permit info 427,196 470,902

CO2e

For w ood - the calculations are based on tons of w ood at 10% MC

Wood and Wood Waste

Fuel Type

Distillate Fuel Oil #2Wood and Wood WasteDistillate Fuel Oil #2

Potential 

or 

Allowable 

Quantity 

Combusted

Fuel Combusted

Estimated 

%MC for 

raw wood 

fuel

Wood and Wood WasteDistillate Fuel Oil #2
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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. 

§5-211(3) - Prohibition of Visible Air Contaminants – Exceptions – Wood 

Fuel Burning Equipment

This emission standard applies to the Main Boiler and the burner for the rotary 

dryer. 

§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 

fuel. 

§5-231(1)(b) - Prohibition of Particulate Matter; Industrial Process 

Emissions 

This emission standard applies to the wood pellet manufacturing operations. 

Based on the application submitted the Permittee is expected to comply with the 

particulate matter emission limit of this section through the use of fabric filters to 

control the particulate matter. 

§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 are shown in Table 4-1. 

 
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Page 16 of 47 

 

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

Equipment ID Size/Capacity Emission Standard, 

lbs/MMBtu 

Allowable 

Emissions, 

lbs/hr 

Main Boiler 482 MMBtu/hr 0.1 1 48.2 

Temporary boiler <10 MMBtu/hr 0.5 < 0.5 1

 The Main Boiler is held to a more stringent emission standard under the MSER requirements of 

§5-502(3).

§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 

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 

main boiler is greater than 250 MMBtu/hr and is subject to this regulation 5-

251(1) while burning fossil fuel. However the main 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 

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

burning fossil fuel. However the main 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 generators at the Facility. 
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4.2 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 Main Boiler is subject to this regulation. However the main 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 

generators 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). 

This regulation applies to the Main Boiler. 

This regulation also applies to the temporary boiler: biennial tune-up, notification 

and reporting requirements. 

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 

generators and the fire pump at the Facility. 
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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 CO, PM and NOx from the 

Main Boiler are subject to CAM because: 

• the Facility is a Title V Subject Source; 

• the uncontrolled emission rates of CO, PM and NOx exceed their 

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

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

HMSER) and NOx (MSER) are subject to an applicable rule; 

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

these pollutants. 

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 section also requires that the Facility be 

equipped with a CEMS and 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. 

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 Main Boiler. 

4.3 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. 

 
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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 3-6 above, the Facility must achieve MSER for PM/PM10, SO2, CO, VOC 

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: Main Boiler, pellet plant burner/rotary dryer, 

and the emergency engines. 

Wood Fired Boiler – MSER Determination:

5.1 Main Boiler - NOX MSER Review 

The NOx control alternatives identified in the permit application for the proposed Main 

Boiler, listed in order of effectiveness: 

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

temperatures between 500 to 800°F. There are several approaches to using a 

catalyst for NOx reduction. One is a hot side SCR where the exhaust gases pass 

straight through the catalyst and out the stack. 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. Straight SCR systems can achieve very high 

levels of emission reductions depending on the volume of catalyst and amount of 

ammonia used. RSCR systems perform slightly lower. 

 
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Page 20 of 47 

2. Selective non-catalytic reduction (SNCR): injection of ammonia or urea into the 

boiler exhaust gases under high temperatures (between 1600 to 2100°F) to reduce 

NOx to N2. 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. Flue gas recirculation and/or water injection into the combustion zone to lower 

combustion temperature and thermal NOx formation. 

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

combustion parameters to achieve efficient combustion and to lower the formation of 

fuel and thermal NOx. 

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

combination of 1 & 4 as MSER for NOx control. The catalyst system will be a multi pollutant 

catalytic reactor (MPCR) that will reduce NOx, CO and VOC 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. 

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 with the 

minimal amount of additional fuel to heat up the exhaust gases. 

Table 5-1: NOX Emission Limits and Performance 

Facility Nominal 

Rating

Permit 

Date 

NOX

Controls

NOX Limit

(lb/MMBtu) 

NOX Emission 

Performance 

Clean Power Berlin, 

Berlin, NH 29 MW 9/25/09 SCR 0.065 (30 day 

rolling avg) 

Plant has not been 

built. 

Concord Steam 

Concord, NH 19.5 MW 8/12/2011 SCR 0.065 (30 day 

rolling avg) 

Plant has not been 

built. 

Montville Power, 

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

built. 

Russell Biomass, 

Russell, MA 50 MW 12/30/08 RSCR 0.060 (12 month 

rolling avg) 

Plant has not been 

built. 

Palmer Renewable 

Energy, 

Springfield, MA 

38 MW 

3/7/11 

(draft 

permit) 

HRSCR 1 0.055 (1 hr block) 

0.017 (12 month 

block) 

Plant has not been 

built. 

Pioneer Renewable 

Energy, 

Greenfield, MA 

47 MW 

7/2/09 

application 

w/ amend. 

MPCR 

0.055 (1 hr block) 

0.022 (12 month 

block) 

Plant has not been 

built. 

Lufkin Generating 

Plant, 

Lufkin, TX 

45 MW 10/26/09 SCR 0.075 (30 day 

rolling avg) Started August 2011 

Laidlaw Berlin 

BioPower, 

Berlin, NH 

70 MW 7/26/10 SCR 0.060 (30 day 

rolling avg) 

Plant has not been 

built. 

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 

Yellow Pine Energy 

Company 

Fort Gaines, GA 

115 MW 5/15/09 SNCR 0.10 (30 day rolling 

avg). 

Plant has not been 

built. 
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Page 21 of 47 

Table 5-1: NOX Emission Limits and Performance 

Facility Nominal 

Rating

Permit 

Date 

NOX

Controls

NOX Limit

(lb/MMBtu) 

NOX Emission 

Performance 

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. 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. 

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. 

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

use of combustion controls with a MPCR 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 Main Boiler – Particulate Matter (“PM/PM10”) MSER Review 

The alternatives identified in the permit application for the proposed wood fired Main Boilerlisted in order of effectiveness: 

1. Multi-clone followed by an Electrostatic Precipitator (ESP) or fabric filter. 

2. Multi-clone followed by a wet scrubber. 

3. Electrified filter bed. 

4. Multi-clone. 

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

a multi-clone followed by an ESP as MSER for PM/PM10 control. In addition, the Permittee 

is proposing a filterable PM emission limit of 0.012 lb/MMBtu and a total PM (filterable + 

condensable PM) limit of 0.019 lb/MMBtu. 

In the table shown below 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. 

 
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Page 22 of 47 

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

Facility Nominal 

Rating

Permit 

Date 

PM 

Controls

PM/PM10 Limit 

(lb/MMBtu) 

PM Emission 

Performance 

Seneca Sustainable 

Energy, 

Eugene, OR 

18.8 MW 10/9/09 Multiclone, ESP Total PM: 0.008 

Stack test completed; 

results did not 

demonstrate 

compliance at this 

time. 

Montville Power, 

Uncasville, CT 42 MW 4/6/10 Multiclone, ESP 

Filterable PM: 

0.012 

Total PM: 0.026 

Plant has not been 

built. 

Russell Biomass, 

Russell, MA 50 MW 12/30/08 

Multiclone, ESP 

or fabric 

filter 

Filterable PM: 

0.012 

Total PM: 0.026 

Plant has not been 

built. 

Palmer Renewable 

Energy, 

Springfield, MA 

38 MW 6/30/2011 

Multiclone, 

fabric filter 

Filterable PM: 

0.008 

Total PM: 0.015 

Plant has not been 

built. 

Pioneer Renewable 

Energy, 

Greenfield, MA 

47 MW 

7/2/09 

application 

w/ amend. 

Multiclone, ESP 

Filterable PM: 

0.012 

Total PM: 0.019 

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 

Laidlaw Berlin 

BioPower, 

Berlin, NH 

70 MW 7/26/10 Fabric filter Filterable PM: 0.01 Plant has not been 

built. 

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 test 5/6/10 

0.001 lb/MMBtu 

Stack test 5/10/09 

 0.001 lb/MMBtu 

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. 

McNeil Generating 

Station, 

Burlington, VT 

50 MW 2/2/09 ESP 

Filterable PM: 

0.007 gr/dscf 

(0.016 lb/MMBtu) 

Stack test 7/14/04 

0.00060 lb/MMBtu 

Stack test 10/26/10 

0.00015 lb/MMBtu 

Ryegate Power 

Station 

East Ryegate, VT 

20 MW ESP 

Filterable PM: 

0.007 gr/dscf 

(0.016 lb/MMBtu) 

Average of 9 stack 

tests since 1993: 

0.0013 lb/MMBtu 

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

control technology for PM/PM10 emissions from the Main Boiler is the use of a multi-clone in 

conjunction with either an ESP or a fabric filter and a total PM emission rate of 0.019 

lb/MMBtu. 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. 

 
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Page 23 of 47 

However, for the filterable PM emission rate unit SR5 at the Schiller Station in Portsmouth, 

NH has a filterable PM emission rate of 0.01 lb/MMBtu. In addition numerous stack test 

results for filterable PM from Schiller Station, McNeil, and Ryegate have all demonstrated 

that 0.010 lb/MMBtu is attainable and therefore the Agency is establishing MSER for 

filterable PM at 0.010 lb/MMBtu as an hourly average. 

5.3 Main Boiler – Carbon Monoxide (CO) MSER Review 

The alternatives identified in the permit application for the proposed wood fired Main Boilerlisted in order of effectiveness: 

1. Oxidative catalyst. 

2. Good combustion design and combustion practices. 

Table 5-3: CO Emission Limits and Performance 

Facility Nominal 

Rating

Permit 

Date 

CO 

Controls

CO Limit 

(lb/MMBtu) 

CO Emission 

Performance 

Montville Power, 

Uncasville, CT 42 MW 4/6/10

Combustion Control and CO 

catalyst 

0.10 (8 hr block) Plant has not been 

built. 

Russell Biomass, 

Russell, MA 50 MW 12/30/08 0.075 Plant has not been 

built. 

Palmer Renewable 

Energy, 

Springfield, MA 

38 MW 

3/7/11 

(draft 

permit) 

0.114 (1 hr block) 

0.07 (4 hr block) 

0.0365 (12 month 

rolling avg) 

Plant has not been 

built. 

Pioneer Renewable 

Energy, 

Greenfield, MA 

47 MW 

7/2/09 

application 

w/ amend. 

0.07 Plant has not been 

built. 

Lufkin Generating 

Plant, 

Lufkin, TX 

45 MW 10/26/09 0.075 Started August, 2011 

Laidlaw Berlin 

BioPower, 

Berlin, NH 

70 MW 7/26/10 

Bubbling 

fluidized 

bed boiler 

and FGR 

0.075 (24 hr avg) Plant has not been 

built. 

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. 

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

combination of 1 & 2 as MSER for CO control. In addition, the Permittee is proposing a CO 

limit of 0.075 lb/MMBtu based on a 24-hour block average. 

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

use of combustion controls with a MPCR and a limit of 0.075 lb/MMBtu of heat input as a 24 

hour rolling average. 

 
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Page 24 of 47 

5.4 Main Boiler – Volatile Organic Compounds (VOC) MSER Review 

Similar to CO, volatile organic compounds are formed because of incomplete combustion of 

fuel. Thus, the above discussion regarding the generation and control of CO emissions for 

the proposed project applies to volatile organic compounds. 

The alternatives identified in the permit application for the proposed wood fired Main Boilerlisted in order of effectiveness: 

1. Oxidative catalyst. 

2. Good combustion design and combustion practices. 

Table 5-4: VOC Emission Limits and Performance 

Facility Nominal 

Rating

Permit 

Date 

VOC 

Controls

VOC Limit 

(lb/MMBtu) 

VOC Emission 

Performance 

Montville Power, 

Uncasville, CT 42 MW 4/6/10

Combustion Control and CO 

catalyst 

0.01 Plant has not been 

built. 

Russell Biomass, 

Russell, MA 50 MW 12/30/08 0.01 Plant has not been 

built. 

Palmer Renewable 

Energy, 

Springfield, MA 

38 MW 

3/7/11 

(draft 

permit) 

0.01 Plant has not been 

built. 

Pioneer Renewable 

Energy, 

Greenfield, MA 

47 MW 

7/2/09 

application 

w/ amend. 

0.01 Plant has not been 

built. 

Lufkin Generating 

Plant, 

Lufkin, TX 

45 MW 10/26/09 0.01 Started August, 2011. 

Ryegate Power 

Station 

East Ryegate, VT 

20 MW 5/15/2011 

Good 

combustion 

control 

0.03 

Average of 7 stack 

tests since 1993: 

0.0013 lb/MMBtu 

PSNH - Schiller 

Station (Unit SR5) 

Portsmouth, NH 

50 MW 3/7/06 

Good 

combustion 

w/ fluidized 

bed 

0.005 

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

combination of 1 & 2 as MSER for VOC control. In addition, the Permittee is proposing a 

VOC limit of 0.005 lb/MMBtu. 

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

the use of combustion controls with an oxidation catalyst within the MPCR and a VOC limit 

of 0.005 lb/MMBtu of heat input based on an hourly average. 

 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 25 of 47 

5.5 Main Boiler - Sulfur Dioxide (SO2) MSER Review: 

The alternatives identified in the permit application for the proposed wood fired Main Boilerlisted in order of effectiveness: 

1. Use of low sulfur content fuel: 

2. Installation and Operation of a Wet Scrubber (70-90% Control Efficiency): Exhaust 

gas temperature from the boiler would decrease to below 212°F, reducing buoyancy 

induced dispersion of boiler exhaust which would likely increase ground level SO2

concentrations. The Palmer Renewable Energy project is proposing to use this 

technology to control SO2 and HCl. 

3. Installation and Operation of a Spray Dryer. The South Point Biomass project 

proposes this technology as one of their options for controlling SO2 emissions. 

4. Dry Sorbent Injection. Depending upon the SO2 loading and the system design, the 

control efficiency can be as high as 80%. Table 5-5 lists a couple facilities that use 

or are proposing to use this technology. 

Table 5-5: SO2 Emission Limits and Performance 

Facility Nominal 

Rating

Permit 

Date 

SO2

Controls

SO2 Limit 

(lb/MMBtu) 

SO2 Emission 

Performance 

Seneca 

Sustainable 

Energy, 

Eugene, OR 

18.8 MW 10/9/09 None 0.025 

Stack test completed, 

results not available at 

this time. 

Montville Power, 

Uncasville, CT 42 MW 4/6/10 None 0.025 Plant has not been 

built. 

PSNH - Schiller 

Station (Unit SR5) 

Portsmouth, NH 

50 MW 3/7/06 Dry sorbent 

injection 1 0.02 

Based on CEMS from 

1st Qtr 2011, estimated 

average emission rate 

< 0.001 lb/MMBtu. 

Lindale 

Renewable 

Energy, Lindale, 

TX 

50 1/08/2010 None 0.025 Plant has not been 

built. 

Lufkin Generating 

Plant, 

Lufkin, TX 

45 MW 10/26/09 None 0.025 Started August , 2011 

South Point 

Biomass, South 

Point, OH 

7 boilers, 

318 

MMBtu/hr 

(each) 

4/04/2006 

Spray dryer 

or sodium 

bicarbonate 

injection 

22.13 lb/hr 

(0.07 lb/MMBtu) 

Plant has not been 

built. 

Laidlaw Berlin 

BioPower, 

Berlin, NH 

70 MW 7/26/10 Dry sorbent 

injection 0.012 Plant has not been 

built. 

Palmer Renewable 

Energy, 

Springfield, MA 

38 MW 

3/7/11 

(draft 

permit) 

Sorbent 

injection, 

Turbosorp 

scrubber 

0.02 Plant has not been 

built. 

Pioneer 

Renewable 

Energy, 

Greenfield, MA 

47 MW 

7/2/09 

application 

w/ amend. 

None 0.025 Plant has not been 

built. 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 26 of 47 

Table 5-5: SO2 Emission Limits and Performance 

Facility Nominal 

Rating

Permit 

Date 

SO2

Controls

SO2 Limit 

(lb/MMBtu) 

SO2 Emission 

Performance 

Ryegate Power 

Station 

East Ryegate, VT 

20 MW 5/16/2011 None None Stack test 6/16/2004 

0.0022 lb/MMBtu 

1

 Schiller Station is also permitted to burn coal in Unit SR5. 

All of the above technologies are technically feasible. However, due to the relatively low 

emission rate of SO2 due in part to a lack of dual fuel use except for start-up, the costs of 

control for the wet and dry scrubbing technologies are prohibitive. 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. 

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 a limit of 0.02 lb/MMBtu of heat input based on 

an hourly average. If the facility is required by the Acid Rain Program to operate an SO2 

CEMS, then the limit is based on an annual average. 

Pellet Plant Burner/Rotary Dryer MSER Determination:

A review of the US EPA RACT/BACT/LAER Clearinghouse yielded only one wood pellet 

manufacturing facility: International Biofuels Inc. in Greenville, VA. This facility received a 

construction permit in 2005 but was subsequently never built. It was permitted for over 

500,000 dry tons per year of output from the dryers compared to Beaver Wood Energy’s 

proposed 115,000 oven dry tons. This higher capacity results in much higher estimated 

emissions of VOCs; resulting in the facility being required to use a thermal oxidizer for 

controlling VOC emissions. 

As noted in the permit application, the rotary dryers used in particle and/or wafer board 

manufacturing plants are similar to the rotary dryer proposed by the Permittee. However, 

the information available in the RBLC for board manufacturer dryers is for much larger 

facilities with much higher potential air emissions. As a result, many of these larger board 

manufacturing facilities employ regenerative thermal oxidizers to control the VOC emissions 

from their rotary dryers. 

Since there are several permitted wood pellet manufacturing plants that are more 

representative of the Permittee’s proposed operation, the emission rates from these facilities 

will be reviewed for the MSER determinations from the pellet plant burner and rotary dryer. 

 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 27 of 47 

Table 5-6: Wood Dryers at Wood Pellet Plants 

Facility Burner Size 

(MMBtu /hr) 

Permitted 

Capacity 

(ODT/yr) 

Max hourly 

dryer 

throughput 

(ODT/hr)

Permit 

Date Operating Status 

Vermont Renewable 

Energy Company, 

Brighton, VT 

40 100,000 11.4 2/10/2010 Plant has not been 

built. 

New England Wood 

Pellet, 

Jaffery, NH 

40 89,300 10.2 9/10/2007 Operating 

Stack test 8/2006 

Schuyler Wood Pellet 

Schuyler, NY 50 131,400 15 5/7/2010 Operating 

Stack test 2/2009 

Deposit Wood Pellet 

Deposit, NY 50 113,800 15 4/27/2010 

Operating 

Testing required 

(CO, NOx, PM) 

Geneva Wood Fuels 

Strong, ME 40 136,065 1

 16.38 3/18/2010 Operating 

 Stack test 10/2010 

Maine Woods Pellet 

Company 

Athens, ME 

50 114,480 2 14.4 3/16/2010 Operating 

Stack test 11/2008 

Corinth Wood Pellet 

Corinth, ME 

20 each (2 

lines) 

Varies based 

on wood 

species 

11.1 each 6/25/2009 Operating 

Stack test 9/2009 

1

 Based on the permit limit of 8,322 hours/year and the maximum production rate of 16.38 ODT/hr 2

 Based on the permit limit of 7,950 hours/yr and the maximum production rate of 14.4 ODT/hr 

Table 5-7: Burner/Dryer Emission Limitations 

Facility (ODT/hr) NOX limit CO limit PM limit VOC limit SO2 Limit

Vermont Renewable 

Energy Company 

(11.4) 

0.66 lb/ODT 

7.5 lb/hr 

0.66 lb/ODT 

7.5 lb/hr 

0.97 lb/ODT 

11.0 lb/hr 

11.4 lb/hr 

(~ 1.0 lb/ODT) NA 

New England Wood 

Pellet (10.2) 

0.69 lb/ODT 

7.04 lb/hr 

1.43 lb/ODT 

14.59 lb/hr

0.30 lb/MMBtu 

0.84 lb/ODT 

8.57 lb/hr 

0.57 lb/ODT 

5.81 lb/hr 

0.025 

lb/MMBtu 

Schuyler Wood 

Pellet (15) 

21.5 lb/hr 

(~1.4 lb/ODT) 

21.5 lb/hr 

(~1.4 lb/ODT) 0.42 lb/MMBtu 10.5 lb/hr (~0.7 lb/ODT) NA 

Deposit Wood Pellet 

(15) 

19.15 lb/hr 

(~1.3 lb/ODT) 

17.5 lb/hr 

(~1.2 lb/ODT) 0.050 gr/dscf 

8.55 lb/hr 

(~0.57 

lb/ODT) 

Fuel limit: 

 lb S/ MMBtu 

2.5 max 

1.9 3-mo avg 

1.7 12-mo avg 

Geneva Wood Fuels 

(16.38) 

0.66 lb/ODT 

10.8 lb/hr 

0.66 lb/ODT 

10.8 lb/hr 

8.5 lb/hr 

(~0.5 lb/ODT) 

0.59 lb/ODT 

9.7 lb/hr 

1.9 lb/hr 

(~0.048 

lb/MMBtu) 

Maine Woods Pellet 

Company (14.4) 

5.0 lb/hr 

(~0.35 

lb/ODT) 

15.1 lb/hr 

(~1.1 lb/ODT) 

8.5 lb/hr 

(~0.59 

lb/ODT) 

12.5 lb/hr 

(~0.9 lb/ODT) 

5.1 lb/hr 

(~0.010 

lb/MMBtu) 

Corinth Wood Pellet 

(11.1 each) 

lb/hr limits are for 

each of the 2 lines 

5.7 lb/hr 

0.51 lb/ODT 

Pine & other 

SW: 65.5 lb/hr 

5.9 lb/ODT 

HW: 50 lb/hr 

4.5 lb/ODT 

Pine: 20 lb/hr 

1.8 lb/ODT 

SW: 25.5 lb/hr 

2.3 lb/ODT 

HW: 30.0 lb/hr 

2.7 lb/ODT 

Pine 48.8 lb/hr 

4.4 lb/ODT 

SW: 23.3 lb/hr 

2.1 lb/ODT 

HW: 11.1 lb/hr 

1.0 lb/ODT 

0.5 lb/hr 

0.025 

lb/MMBtu 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 28 of 47 

Table 5-8: Burner/Dryer Control Technology 

Facility NOX limit CO limit PM limit 1 VOC limit SO2 Limit 3

Vermont 

Renewable Energy 

Company 

Good 

combustion 

Good 

combustion Multi-clone Good 

combustion No limit 

New England 

Wood Pellet 

Good 

combustion 

Good 

combustion Multi-clone Good combustion Low sulfur fuel 

Schuyler Wood 

Pellet 

Good 

combustion 

Good 

combustion & 

combustion 

temperature > 

1700 o

F 

Multi-clone Good 

combustion NA 

Deposit Wood 

Pellet 

Good 

combustion 

Good 

combustion Multi-clone Good 

combustion Low sulfur fuel 

Geneva Wood 

Fuels 

Good 

combustion 

Good 

combustion Multi-clone Good 

combustion Low sulfur fuel 

Maine Woods 

Pellet Company 

Good 

combustion 

Good 

combustion Wet scrubber Good combustion No controls 

Corinth Wood 

Pellet 

Good 

combustion 

Good 

combustion Cyclone 2 Good 

combustion No controls 

1

 If a cyclone or multi-clone is listed, it also serves as process equipment that is used to separate the dried wood 

product from the rotary dryer’s exhaust gas. 

2

 The Maine DEP has also required this facility to investigate the use of exhaust gas recycle as a control option. 3

 For all facilities, if there is an SO2 emission limit, the facility’s plan is to use wood as the fuel since it is 

considered to be inherently low in sulfur content. 

Table 5-9: Burner/Dryer Test Results 

Facility NOX CO PM VOC SO2

Vermont Renewable 

Energy Company Facility not constructed – no testing. 

New England Wood 

Pellet 

8/2006 

3.3 lb/hr 

(~0.33 lb/ODT) 

8/2006 

11.5 lb/hr 

(~1.15 lb/ODT) 

8/2006 

7.4 lb/hr 

(~0.74 lb/ODT) 

8/2006 

2.6 lb/hr 

(~0.26 lb/ODT) 

- 

Schuyler Wood 

Pellet 

2/2009 

5.96 lb/hr 

~ 0.4 lb/ODT 

2/2009 

0.85 lb/hr 

~ 0.06 lb/ODT 

2/2009 

0.41 lb/ MMBtu 

2/2009 

3.6 lb/hr 

~ 0.24 lb/ODT 

- 

Deposit Wood Pellet Facility operating, no test results available at this time. 

Geneva Wood Fuels - 

10/2010 

3.21 lb/hr 

~ 0.43 lb/ODT 

10/2010 

4.28 lb/hr 

~ 0.58 lb/ODT 

10/2010 

1.49 lb/hr 

~ 0.20 lb/ODT 

- 

Maine Woods Pellet 

Company - - 

11/2008 

4.88 lb/hr 

0.26 lb/MMBtu 

6/2010 

3.4 lb/hr 

11/2008 

11.97 lb/hr 

6/2010 

6.4 lb/hr 

- 

Corinth Wood Pellet 

9/2009 

Line 1 HW: 

2.1 lb/hr 

0.35 lb/ODT 

Line 2 HW: 

2.3 lb/hr 

0.36 lb/ODT 

9/2009 

Line 1 HW: 

18.8 lb/hr 

3.1 lb/ODT 

Line 2 HW: 

9.8 lb/hr 

1.5 lb/ODT 

9/2009 

Line 1 HW: 

4.1 lb/hr 

0.67 lb/ODT 

Line 2 HW: 

4.2 lb/hr 

0.64 lb/ODT 

9/2009 (THC) 

Line 1 HW: 

0.2 lb/hr 

0.03 lb/ODT 

Line 2 HW: 

0.21 lb/hr 

0.03 lb/ODT 

- 

 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 29 of 47 

5.6 Wood Pellet Burner/Dryer - NOX MSER Review: 

The NOx control alternatives identified in the permit application for the proposed wood 

dryer/burner, listed in order of effectiveness: 

1. Selective catalytic reduction (SCR). Due to the high particulate loading in the 

burner’s exhaust gas between the burner and the rotary dryer (where the combustion 

gases are at the correct temperature for the reaction), the catalyst would become 

fouled. If the catalyst is located after the proposed fabric filter, the temperature of the 

exhaust gas is too low for the reaction to take place without prohibitive levels of 

reheating. The exhaust temperatures exiting the dryers are much lower than for a 

conventional boiler. The temperature profile in the dryer itself cannot be significantly 

increased without partially combusting the wood material and increasing incomplete 

combustion emissions. SCR is not technically feasible. 

2. Selective non-catalytic reduction (SNCR). As noted in Table 5-8 none of the 

permitted wood pellet manufacturing operations utilize SNCR to reduce the 

emissions of NOX. As noted in Section 5.1 above, an SNCR system requires a 

section in combustion gas pathway that has both a specific temperature range (1600

– 2100oF) and sufficient residence time for the ammonia to mix and react with the 

NOX. The burner in wood pellet drying systems do not typically operate at the high 

temperatures present in a boiler, and almost immediately after exiting the burner, the 

exhaust gases are cooled to temperatures well below 1600o

F. The exhaust gases 

must be cooled to prevent charring of the wood in the rotary dryer. SNCR is not 

technically feasible. 

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

combustion parameters to achieve efficient combustion and to lower the formation of 

fuel and thermal NOx. This is the technique used to control NOx at all of the 

referenced permitted wood pellet manufacturing facilities. 

The Permittee is proposing the use of a Coen low NOx burner and good combustion controls 

with an emission rate of 0.35 lb/MMBtu as MSER. The optimal temperature range for achieving 

the proposed emission rate, as measured at the exit of the burner, will be established during 

stack testing. 

The Agency agrees that MSER for the wood burner/dryer system is the use of a Coen low NOx 

burner and good combustion controls with an hourly average emission rate of 0.35 lb/MMBtu 

heat input at the burner. 

5.7 Wood Pellet Burner/Dryer - CO MSER Review: 

The alternatives identified in the permit application for the proposed wood burner/dryer 

system - listed in order of effectiveness: 

1. Oxidative catalyst. The oxidative catalyst has the same issues as the SCR, and it is 

not considered a feasible technology for controlling CO from this process. 

2. Good combustion design and combustion practices. 

The Permittee is proposing the use of a Coen low NOx burner and good combustion controls 

with an emission rate of 0.35 lb/MMBtu as MSER for CO. The Coen burner design incorporates 

a dual air zone scroll feed that is intended to optimize the combustion by ensuring good mixing 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 30 of 47 

for low CO emissions, and limiting the availability of oxygen in the hottest part of the flame to 

minimize the formation of thermal NOx. 

The Agency agrees that MSER for CO for the wood burner/dryer system is the use of a Coen 

low NOx burner and good combustion controls with an hourly average emission rate of 0.35 

lb/MMBtu. As with the NOx limit, the optimal combustion temperature range for achieving the 

proposed emission rate, as measured at the exit of the burner, will be established during stack 

testing. 

5.8 Wood Pellet Burner/Dryer - VOC MSER Review: 

VOCs are emitted from the burner/dryer process due to incomplete combustion in the burner as 

well as the VOCs that are released from the wood as it is being dried in the rotary dryer. It is 

expected that the bulk of the VOC emissions will be from the drying of the wood, especially if 

pine is being dried. While good control of the combustion process in the burner will help 

minimize the VOCs from that stage of the process, it will not influence the VOCs released in the 

dryer. The temperature at which the drying takes place is a key parameter in the release of the 

VOCs in the drying phase of this system. 

The alternatives identified in the permit application for the proposed wood burner/dryer 

system - listed in order of effectiveness: 

1. Regenerative Thermal Oxidizer (RTO). This is a common control technology used 

on the larger dryer systems used in the board manufacturing industry. The cost for 

an RTO to treat the VOCs from this smaller system is estimated to be $32,336/ton 

and this is not considered to be economically feasible. 

2. Oxidative catalyst. The oxidative catalyst has the same issues as the SCR for NOx 

control, and it is not considered a feasible technology for controlling VOC from this 

process. 

3. Carbon Adsorption: This technology is best suited for cool, dry exhaust gases from 

lower volume systems. Since the burner/dryer system is a high volume, hot, very 

moist gas, the carbon adsorption is not a feasible technology. 

4. Good combustion design and combustion practices. This technique is feasible for 

the VOCs from the combustion process, but will not affect the VOCs released from 

drying wood in the rotary dryer. 

5. Process controls for the dryer such as controlling the temperature profile in the dryer 

to prevent overheating of the wood material that would release VOC emissions. 

The Permittee is proposing to use the same approach for VOC control from the burner as they 

have proposed for CO control: a Coen low NOx burner and good combustion controls with an 

overall emission rate of 0.69 lbs/ODT as MSER for VOCs. The Coen burner design 

incorporates a dual air zone scroll feed that is intended to optimize the combustion by ensuring 

good mixing for low CO and VOC emissions, and by limiting the availability of oxygen in the 

hottest part of the flame to minimize the formation of thermal NOx. 

The Agency has determined that VOC MSER is a combination of 4 and 5 that will use dryer 

process controls as well as the proposed Coen burner and an overall hourly average emission 

rate of 0.69 lb/ODT. The Permittee will also need to establish the operating temperature range 

at the inlet to the rotary dryer that is necessary to achieve this emission limit. 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 31 of 47 

5.9 Wood Pellet Burner/Dryer – Particulate Matter (“PM/PM10”) MSER Review 

The base level of PM control from the rotary dryer output is the use of a cyclone or multi-clone 

to separate the dried wood material from the exhaust gases. All of the control devices shown 

below are preceded by a cyclone. 

The alternatives identified in the permit application for the proposed wood fired Main Boilerlisted in order of effectiveness: 

1. Fabric filter 

2. Electrostatic Precipitator (ESP). 

3. Wet scrubber. 

4. Electrified gravel filter bed. 

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 0.005 gr/dscf and a total PM 

(filterable + condensable PM) limit of 0.2 lb/ODT. 

The Agency agrees that MSER for PM/PM10 is the use of a fabric filter and an hourly average 

filterable PM emission limit of 0.005 gr/dscf and an hourly average total PM limit of 0.2 lb/ODT. 

5.10 Wood Pellet Burner/Dryer - Sulfur Dioxide (SO2) MSER Review: 

The alternatives identified in the permit application for the proposed burner/dryer - listed in order 

of effectiveness: 

1. Use of low sulfur content fuel: 

2. Wet Scrubber. 

3. Dry Sorbent Injection. 

Based on the review of the facilities listed in Table 5-6 and the RBLC, no examples were 

found where a wet scrubber or dry sorbent injection is in use for controlling SO2

emissions from wood pellet manufacturing plants. These types of facilities limit their 

emissions of SO2 through the use of wood fuel which is considered to be a low sulfur 

content fuel. 

Based on the emission limit for Geneva Wood Fuels, the Permittee has proposed MSER 

to be an SO2 emission limit of 0.05 lb/MMBtu. 

Upon review of the facilities listed in Table 5-7, both New England Wood Pellet and 

Corinth Wood Pellet have a lower SO2 emission limit of 0.025 lb/MMBtu. 

The Agency has determined MSER for SO2 to be an hourly average limit of 0.025 

lb/MMBtu heat input at the burner. 

 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 32 of 47 

Diesel Engines MSER Determination:

The Facility will use diesel engines to provide power through emergency generators and a fire 

water pump. These engines are sources of NOX, CO, PM, SO2 and VOCs. 

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 upon start up of the Main Boiler, 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 BWE. 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 and/or standards for sustainable harvesting and production are established. 

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. 

5.11 Main Boiler Greenhouse Gas MSER Review: 

In response to public comments on the draft permit, the Agency has added additional 

documentation of our review process. The Agency has also taken a closer look at 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 for reasons 

independent of air quality permitting, and which design elements may be changed to achieve 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 33 of 47 

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). 

BWE is proposing to construct a 34 MW (gross) biomass fuel electric generating facility colocated with a 115,000 ton per year wood pellet production facility. According to BWE, “The 

BWE Fair Haven project concept, design, and development are based on the availability of 

sufficient biomass fuel in the project area. . . . The project was designed and sited on the basis 

of the availability of biomass wood waste in the project area.” As part of the development for this 

project, BWE hired Innovative Natural Resource Solutions, LLC to conduct a biomass fuel 

supply study for the Fair Haven area. This study concluded that there is enough wood available 

to sustainably supply the proposed BWE project. The Agency has not undertaken, as part of the 

air permitting process, an independent analysis of the conclusions reached in the wood supply 

study, and has looked at the study for the limited purpose of considering whether alternative 

fuels should be included as a control option in determining BACT/MSER. BWE also maintains 

that the use of fossil fuels, such as coal, natural gas, or oil, would fundamentally redefine the 

proposed facility. In addition, BWE states that the use of fossil fuels would also be infeasible 

due to availability and/or economic considerations. Further, BWE is “unaware of any sources of 

alternative biogenic fuel stocks available in the required amounts within a reasonable radius of 

the facility.” 

The Agency finds that BWE’s objective is to build a biomass fuel electric generating facility colocated with a wood pellet production facility. Based on the application and statements made by 

BWE, the Agency also finds that BWE 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 BWE’s conclusions regarding the availability of 

biomass wood fuel. The Agency further notes that the co-location of the electric plant and the 

wood pellet facility will allow bark and other residue generated by the adjacent wood pellet 

manufacturing plant to be used as a small portion of the overall fuel source at the wood-fired 

electric generating plant. In addition, the proposed facility is designed to allow waste heat from 

the Main Boiler at the electric generating plant to replace an equivalent amount of fuel input to 

the wood fired burner at the pellet plant. Thus, for the limited purpose of considering whether 

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

finds that these design elements are inherent to BWE’s basic purpose. 

The Agency concludes that BWE’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 BWE Fair Haven. 
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Step 1: Identify all Control Technologies: The alternatives identified in the permit application for 

the proposed wood fired Main 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 Permittee reviewed the advantages and disadvantages of two 

major biomass combustion technologies: stoker fired and bubbling fluidized bed 

systems and found that their overall efficiencies are very similar, with a slight advantage 

to the stoker design. Due to the proposed design of the air pollution control equipment 

(the tail end MPCR), there needs to be a minimum temperature in the exhaust gases for 

efficient operation of the catalytic reduction system, so too much heat recovery from the 

exhaust gases before treatment in the MPCR would adversely affect the performance of 

the MPCR. 

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

heat energy from the low grade waste heat emitted from the biomass boiler – in this 

case the exhaust gas. 

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 therefore not considered further in 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. 

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, it is therefore not 

technically feasible for this project.. 

2. Energy efficiency is technically feasible. 

3. CHP is technically feasible through the use of boiler exhaust gas as a source of heat for 

the pellet plant’s rotary dryer. The Permittee is also exploring the possibility of heating 

green houses as a means to expand the combined heat idea. 

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 waste heat in the boiler exhaust gas in the pellet plant 

rotary dryer. 

3. Good operating and maintenance practices do 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 Step 3. Note that CHP is deferred to the GHG MSER for the 

burner/dryer in the pellet plant since this is where the heat is recovered. 
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The Agency has determined that MSER for GHGs is implementing energy efficiency 

and good operating and maintenance practices for GHG control. In addition, a CO2e 

emission limit has been established based on the rated heat input to the boiler and the 

design electrical output: 2993 lb CO2e / MW-hr electrical output based on a 30 day 

rolling average. 

5.12 Wood Pellet Burner/Dryer Greenhouse Gas MSER Review: 

The Agency is not aware of any prior GHG BACT determinations for wood pellet manufacturing 

operations. The main alternatives that may be used for minimizing GHG emissions from the 

wood pellet production process include: 

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

heat energy from the low grade waste heat emitted from the biomass boiler – in this 

case the exhaust gas. The Permittee has proposed to use a portion of the Main Boiler’s 

exhaust gas to supply up to 12 MMBtu/hr of the heat energy required for the rotary dryer. 

2. 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. 

Both of the above alternatives are technically and economically feasible. 

The Agency has determined MSER for GHGs to be good operating and maintenance practices, 

when available, heat energy from the Main Boiler exhaust and a CO2e emission limit of 427 lb 

CO2e / ton of finished pellets produced based on a monthly average. 

The CO2e emission limit for the burner/dryer will be phased in over three years. 

• During the first year of operation, the limit will be 591 lb CO2e / ton of finished pellets. 

This limit is based on no heat recovery. This is being done to provide the Permittee with 

time to work through any issues associated with the start-up of a new facility. 

• During the second year of operation, the limit will be 509 lb CO2e / ton of finished pellet – 

this limit is based on using ‘50%’ of the available waste heat. 

• For the third year and after, the limit will be 427 lb CO2e / ton of finished pellets. 

Regardless of the operating year, for periods of time when the Main Boiler is not operating, the 

limit is 591lb CO2e/ton finished pellets. For months that include periods of pellet plant operation 

while the Main Boiler is down, the limit will be prorated: [ (hours without Main Boiler)*591 + 

(hours with Main Boiler)*(591 or 509 or 427) ] / [hours without Main Boiler + hours with Main 

Boiler] 

5.13 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 
Beaver Wood Energy – Fair Haven, LLC AP-11-015 

 

Page 36 of 47 

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 engines 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 EVALUATION 

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 1998 – 2002. The surface met data was from 

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

The Permittee conducted modeling for several operating load scenarios for the main boiler and 

the dryer as well as a startup scenario for the main 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 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. Tables 6-1 and 6-2 summarize the operating loads and emission rates for the 

operating scenarios that were modeled. 

Table 6-1: Operating Load Scenarios 

ID Description Device Heat input 

(MMBtu/hr) 

Production Rate 

(ODT/hr) 

MAX 

55% moisture fuel; maximum boiler heat 

input; full dryer load 

Boiler 482 - 

Dryer 17.9 14.6 

Case 1 45% moisture fuel; full dryer load Boiler 403 - 

Dryer 17.9 14.6 

Case 2 

55% moisture fuel; 100% boiler load; no 

dryer 

Boiler 435.8 - 

Dryer 0 0 

Case 3 

45% moisture fuel; 75% boiler load; 65% 

dryer load; 

Boiler 301.3 - 

Dryer 7.99 9.5 

 
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Case 4 

35% moisture fuel; 50% boiler load; full 

dryer load, maximum (dryer) burner heat 

input 

Boiler 191.5 - 

Dryer 30 14.0 

Case 5 

35% moisture fuel; 100% boiler load; lowest 

dryer flow (dryer burner not operating). 

Boiler 382.5 - 

Dryer 0 4.5 

Table 6-2: Short Term Exhaust Parameters 

ID Device Emission Rate [ lb/hr (top); gram/sec (bottom) ] 

NOX CO PM 1 SO2 NH3

MAX 

Boiler 28.92 

3.64 

36.15 

4.55 

10.6 

1.34 

9.64 

1.21 

2.31 

0.29 

Dryer 6.27 

0.79 

6.27 

0.79 

2.08 

0.26 

0.36 

0.05 

-- 

-- 

Case 1 

Boiler 24.18 

3.05 

30.23 

3.81 

8.87 

1.12 

8.06 

1.02 

1.93 

0.24 

Dryer 6.27 

0.79 

6.27 

0.79 

2.08 

0.26 

0.36 

0.05 

-- 

-- 

Case 2 

Boiler 26.15 

3.29 

32.69 

4.12 

9.59 

1.21 

8.72 

1.10 

2.09 

0.26 

Dryer -- 

-- 

-- 

-- 

-- 

-- 

-- 

-- 

-- 

-- 

Case 3 

Boiler 18.08 

2.28 

22.60 

2.85 

6.63 

0.84 

6.03 

0.76 

1.45 

0.18 

Dryer 2.80 

0.35 

2.80 

0.35 

2.08 

0.26 

0.16 

0.02 

-- 

-- 

Case 4 

Boiler 11.49 

1.45 

14.36 

1.81 

4.21 

0.53 

3.83 

0.48 

0.92 

0.12 

Dryer 10.50 

1.32 

10.50 

1.32 

2.10 

0.27 

0.60 

0.08 

-- 

-- 

Case 5 

Boiler 22.95 

2.89 

28.69 

3.62 

8.42 

1.06 

7.65 

0.96 

1.84 

0.23 

Dryer 0 

0 

0 

0 

2.07 

0.26 

0 

0 

-- 

-- 

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. 
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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. 

Table 6-3 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. 

Table 6-3: Distance to Significant Impact Level (km)

Pollutant Averaging 

Time 

Significant Impact 

Levels (μg/m3) 

Distance (km) from project Load 

Case 

PM10 

24-hour 5 No impacts > SIL N/A 

Annual 1 1 No impacts > SIL N/A 

PM2.5

24-hour 1.2 9.0 MAX 

Annual 0.3 0.6 MAX, 

1,3,4,5 

SO2 

1-hour 7.8 10.5 MAX 

3-hour 25 No impacts > SIL N/A 

24-hour 5 No impacts > SIL N/A 

Annual 1 No impacts > SIL N/A 

NO2 

1-hour 7.55 30.6 MAX 

Annual 1 1.0 Case 4 

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. 

Based on the above noted criteria the interactive source modeling included emissions of 

NOX and/or SO2 for the following five sources: Telescope Casual Furniture in Granville, 
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NY (NOX); NYS Great Meadow Correctional Facility in Comstock, NY (SO2); Finch Paper 

LLC in Glens Falls, NY (SO2 & NOx); International Paper in Ticonderoga, NY (NOx & 

SO2) and Lehigh Northeast Cement Company in Glens Falls, NY (NOx). There were no 

nearby sources of PM2.5 that met the criteria noted above. 

The maximum emissions from the proposed Facility (MAX in Table 6-2) along with the 

emissions from the five facilities noted above were modeled to predict the maximum 

impacts to determine if there were any predicted NAAQS violations. 

Table 6-4: Summary of Maximum Impacts – NAAQS Review

Pollutant Averaging 

Time 

Max Impact 

(μg/m3) 

Background 

(μg/m3) 

Total Impact 

(μg/m3) 

NAAQS 

(μg/m3) 

PM10 

24-hour 3.5 35 38.5 150 

Annual 0.6 13.6 14.2 50 

PM2.5

24-hour 3.5 28.7 32.2 35 

Annual 0.6 10.4 11.0 15 

SO2 

1-hour 2,907.3 94.2 2,001.5 196 

3-hour 819.6 96.9 916.5 1,300 

24-hour 258.7 60.2 318.9 365 

Annual 28.2 9.7 37.9 80 

NO2 

1-hour 568.2 80.9 649.1 188 

Annual 10.1 18.1 28.2 100 

CO

1-hour 63.6 3,664 3,727.6 40,000 

8-hour 14.6 2,406 2,419.6 10,000 

With the exception of the 1-hr NO2 and SO2 standards, comparison of the total impacts 

to the NAAQS indicates that the Facility’s emissions will not cause or contribute to a 

violation of the NAAQS. 

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. This was done with a 

post-processing software program provided by BEE-Line Software. 

There were 100 receptors with combined source 1-hour SO2 impacts greater than the 

NAAQS. The Facility’s maximum contribution to the impacts at any of these 100 

receptors was 0.53 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. 
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There were 28 receptors with combined source 1-hour NO2 impacts greater than the 

NAAQS. The Facility’s maximum contribution to the impacts at any of these 28 

receptors was 0.033 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. 

The results of this refined modeling demonstrate that the Facility, in conjunction with 

emissions from other nearby sources, 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, PM2.5, or 

PM10. Finch Paper and International Paper Ticonderoga both consume SO2 increment, 

so these sources were included in this PSD increment analysis. 

Table 6-5 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. 

 
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Table 6-5: PSD Increment Impacts

Pollutant Averaging 

Time 

Max Impact 

(μg/m3) 

PSD Increment 

Standard (μg/m3) 

Available 

Increment 

(μg/m3)

1 

Class I Class II Class I Class II Class I Class II 

PM10 

24-hour 0.028 3.5 8 30 6 22.5 

Annual 0.002 0.6 4 17 1 4.25 

PM2.5

24-hour 0.028 3.5 2 9 1.5 6.75 

Annual 0.002 0.6 1 4 0.25 1 

SO2

3-hour 0.87 84.1 25 512 18.76 384 

24-hour 0.16 14.4 5 91 3.75 68.25 

Annual 0 2.4 2 20 0.5 5 

NO2 Annual 0.004 1.4 2.5 25 0.625 6.25 

1

 Vermont regulations allow major new sources to consume only 25% of the annual increment and 75% off 

the short term increment. 

6.4 Class I 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 Federal Land Managers Air Quality Related Values (AQRV) Workgroup (FLAG) 

Phase 1 report revised (2010)1

 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. The method calculates a ratio (Q/d) of the total tons of 

pollutants (SO2, NOX, SO4, and total PM) divided by the distance, in kilometers, between 

the source and the Class I area. The guidance document FLAG 2010 states that the 

pollutant tonnage rate should be based on the maximum daily emission rates * 365 days 

to determine the ton/year value for Q. The Facility uses a 96% capacity factor for the 

main boiler and an 82% capacity factor for the burner/dryer: the annual emissions from 

these two production areas will need to be increased proportionately to determine the 

inputs for calculating Q. 

 

 

1 U.S. Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land 

managers’ air quality related values work group (FLAG): phase I report—revised (2010). Natural 

Resource Report NPS/NRPC/NRR—2010/232. National Park Service, Denver, Colorado.
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Main boiler: 

SO2: 40.5 tpy / 96% = 42.2 

NOX: 60.8 tpy / 96% = 63.3 

SO4: 1.9 tpy / 96% = 2.0 

PM (boiler and cooling towers): (38.5 + 4.1 tpy)/96% = 44.4 

Burner/dryer: 

SO2: 2.7 tpy / 82% = 3.3 

NOX: 37.7 tpy / 82% = 46 

SO4: 0.06 tpy / 82% = 0.07 

PM (dryer and pellet plant bag houses): (11.6 + 8.8 tpy)/82% = 24.9 

Q = SO2 + NOX + SO4 + PM = (42.2+3.3) + (63.3+46) + (2.0 + 0.07) + (44.4+24.9) = 

226.2 ton/yr 

The distance from the source to Lye Brook Class I area is 52 km. 

Q/d = 226.2 / 52 = 4.35 

The combination of potential emissions from the proposed project and the distance to 

the Lye Brook Class I area results in a Q/d value that is well below the threshold of 10, 

and additional assessments of impacts on AQRVs by the FLM are not anticipated to be 

necessary. 

The Permittee also conducted a Level 1 Screening Procedure as outlined in EPA’s 

Workbook for Plume Visual Impact Screening and Analysis using EPA’s VISCREEN 

model. 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 visual 

impact will not cause an adverse impact in the Lye Brook Class I area. 

6.5 Effects on Soils, Vegetation, and Secondary Impact Analysis 

New major sources and major modifications are required to evaluate their effects 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. 

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. 
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In accordance with Vermont’s State Implementation Plan, 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. 

Section 6086 requires each district commission or the Environmental Board to review all 

environmental impacts of a proposed development prior to issuing a permit. Section 

6086(a)(1) specifically requires a finding that the proposed project "will not result in 

undue water or air pollution." Section 6086(a)(8) further requires a finding that such 

projects "will not have an undue adverse effect of the scenic or natural beauty of the 

area, aesthetics, historic sites or rare and irreplaceable natural areas". 

The air quality impact of general commercial, residential, industrial and other growth 

occurring as a result of construction of the proposed source under review is included in 

these analyses. Since the Air Pollution Control Division and the Environmental Board 

have maintained a close working relationship in the past, it is expected that these 

provisions will be adequate to prevent the impairment of visibility, soils and vegetation 

and the effects of such secondary growth due to the construction of new sources of air 

pollution. 

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 32 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-hexavalent, 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 and/or the wood pellet burner/dryer. The choice of control devices for non-mercury 

metallic HACs is the same as those for fine PM. 

7.1.1. Main Boiler – non-mercury metallic HACs 

The Agency is establishing HMSER for non-mercury metallic HACs from the Main Boiler 

as the use of an ESP, or equivalent PM air pollution 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 main boiler. 

7.1.2. Wood Pellet Burner/Dryer – non-mercury metallic HACs 

The Agency is establishing HMSER for non-mercury metallic HACs from the wood pellet 

burner/dryer as the use of a fabric filter and a filterable PM emission limit of 0.005 gr/dscf 

(1 hour block average). This single filterable PM emission limit also is serving as a 

surrogate for separate emission limits for each of these non-mercury metallic HACs from 

the wood pellet burner/dryer. 

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), 2,4-dinitrotoluene, formaldehyde, 

hexachlorobenzene, naphthalene, tetrachloroethylene (perchloroethylene), 

trichloroethylene, and vinyl chloride. 

These organic emissions are formed by incomplete combustion of fuel. In the case of the 

pellet plant dryer, they are also formed by the high temperature drying of the wood material 

that volatilizes and partially combusts organic components in the wood. 

7.2.1. Main Boiler – organic HACs 

The methods for control of organic HACs from the Main 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 an oxidative 

catalyst in the MPCR, 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). 

 
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7.2.2. Wood Pellet Burner/Dryer – organic HACs 

These HACs are organic compounds for which emission control techniques would be 

similar to the techniques to control volatile organic compounds. The potential control 

technologies for VOCs (and organic HACs) include carbon adsorption, condensation, 

biofiltration, and thermal oxidation. The exhaust from the rotary dryer is a high moisture 

content, low VOC content, high volume exhaust stream which is challenging for existing 

control technologies to reduce the emissions. 

Carbon adsorption: A carbon adsorption system removes VOCs from the exhaust 

stream when the VOC is adsorbed to the surface of activated carbon. Over time, the 

carbon media becomes saturated with VOCs requiring the unit to be desorbed by 

introducing heat (usually steam). The desorption process results in the production of a 

VOC laden wastewater stream that must be treated prior to discharge. Generally carbon 

adsorption systems are used on dry, lower volume streams. To use this technology, the 

hot exhaust stream from the rotary dryer would need to be cooled before being 

processed by a carbon adsorber, and this would result in additional condensate/waste 

water that would also need to be treated prior to discharge. Additionally the particulate 

matter in the dryer’s exhaust would tend to foul the carbon media. Carbon adsorption is 

not a suitable technology for the exhaust from a wood dryer. 

Condensation: Condensers in use today may fall in either of two categories: refrigerated 

or non-refrigerated. Non-refrigerated condensers are widely used as raw material and/or 

product recovery devices in chemical process industries. They are frequently used prior 

to control devices (e.g., incinerators or absorbers). Refrigerated condensers are used as 

air pollution control devices for treating emission streams with high VOC, concentrations 

(usually > 5,000 ppmv). The low concentration (anticipated to be less than 100 ppm) of 

VOCs in the dryer’s exhaust gas is too low for condensers to be effective. This 

technology is not technically feasible for wood dryers. 

Biofilters: Biofilters operate by passing the VOC laden stream through organic or 

inorganic structural media containing microbes. The VOCs are degraded by the 

microbial populations living in the media. Biofilters depend upon constant pollutant 

streams with high humidity. This technology is technically feasible to treat the exhaust 

gases from the dryer. The air permit A-736-71-C-A issued by the Maine Bureau of Air 

Quality to Maine Woods Company, LLC in 2004 has capital cost information for a 

biofilter designed for 80,000 acfm of exhaust gases from lumber drying operating. The 

design exhaust volume is similar to the exhaust flow rate from the rotary dryer, so the 

cost of the system would be similar. In the permit it was noted that organic biofilter 

packing must be replaced every one to three years due to packing deterioration. 

Inorganic packing is expected to be replaced once every ten years. That system was 

designed to achieve 90% control of VOCs and was estimated to cost $2,400,000. This 

type of control device is not economically feasible for controlling the estimated 10 tons/yr 

of organic HACs from the rotary dryer. In addition, since the dryer exhaust also contains 

combustion products the low temperature and low release height from a biofilter would 

be of concern from a pollution dispersion stand point. 

Catalytic Oxidation: Catalytic oxidation units are very sensitive to particulate 

contamination, and are usually only used on clean exhaust streams. For this technology 
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to work on the dryer exhaust, a high efficiency particulate matter control device such as 

an ESP or a fabric filter would be needed to pretreat the exhaust gases. The system will 

be equipped with such a fabric filter however if the catalyst is located after the proposed 

fabric filter, the temperature of the exhaust gas is too low for the reaction to take place 

without prohibitive levels of reheating. The exhaust temperatures exiting the dryers are 

much lower than for a conventional boiler. The temperature profile in the dryer itself 

cannot be significantly increased without partially combusting the wood material and 

increasing incomplete combustion emissions. 

Regenerative Thermal Oxidation: The application included cost estimates for an RTO 

which is anticipated to have a 95% destruction efficiency for organic VOCs and HACs. 

The RTO was estimated to have a total annual cost of $1,230,000. There are an 

estimated 10 tons/year of organic HACs; the cost per ton for this type of control would be 

approximately $130,000/ton. This is not a feasible control solution for HACs from this 

source. 

The Permittee has proposed HMSER for organic HACs from the dryer system to be the 

burner design and good combustion practices as well as a VOC emission limit of 0.69 

lb/ODT. 

The Agency agrees that HMSER for organic HACs is proper burner design and good 

combustion practices as well as an hourly average VOC emission rate of 0.69 lb/ODT. 

The Permittee will also need to establish the operating temperature ranges at the inlet 

and outlet to the rotary dryer that are necessary to achieve this emission limit. 

7.3. Acid Gases 

Sulfuric acid mist and chlorine are estimated to exceed their respective action level. 

Based on the emission testing at wood fired boilers in New England HCl is not expected 

to exceed its 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 

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 

technologies were reviewed in Section 5.5 and 5.11 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. The Agency is not aware of any 

conventional wood fired plants that are equipped with acid gas controls. 

HMSER for both the Main Boiler and the wood pellet burner/dryer is the use of natural 

wood which has an inherently low level of sulfur and chlorine. 

 
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7.4. Ammonia 

Ammonia is used as a reagent in the MPCR unit of the boiler to react with NOX to form 

nitrogen and water. Some of the ammonia will pass through the MPCR 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 agrees 

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. 

No ammonia is expected to be emitted from the dryer process. 

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 MPCR, 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.