### VERMONT AGENCY OF NATURAL RESOURCES Department of Environmental Conservation

Air Pollution Control Division



## TECHNICAL SUPPORT DOCUMENT

FOR

PERMIT TO CONSTRUCT

#AP

- 11

- 038

Permit Date: April 19, 2013



## North Springfield Sustainable Energy Project, LLC North Springfield, VT

Prepared By: Steven K. Snook

Air Pollution Control Division

This Technical Support Document details the Agency of Natural Resources, Department of Environmental Conservation, Air Pollution Control Division review for the Air Pollution Control

Permit to Construct and is intended to provide additional technical information, discussion and clarification in support of the Permit. It is not intended to provide a comprehensive review of the Facility or permit process or duplicate the information contained in the Permit.North Springfield Sustainable Energy Project, LL C AP

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### Page 2 of 52 Facility : North Springfield Sustainable Energy Project, LLC

36 Precision Drive North Springfield, VT 05150 Application Contact Person:

Dale Raczynski Epsilon Associates, Inc. 3 Clock Tower Place, Suite 250 Maynard, MA 01754

Phone

- (978)

- 897

- 7100

Facility Contact Person : Daniel Ingold 36 Precision Drive, North Springfield, VT 05150

- 9706

Phone

- 802

- 886

- 6100

1.0 INTRODUCTION

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

co nstruct/install and operate wood fired electrical generating station

, with an electrical generation rate of approximately 37 MW (net)

, at 36 Precision Drive in N orth Springfield, Vermont (also referred to herein as “Facility”). The parent corporation for North Springfield Sustainable Energy Project, LLC is Winstanley Enterprises, LLC.

Administrative Milestones :

Table 1

- 1: Administrative Summary

Administrative Item Result or Date

Date Application Received: 12/29 /2011

Date Administratively Complete: 1 2/2 9 /2011

Date Draft Decision: 8/9 / 2012

Date & Location Draft Decision/Comment Period

Noticed: 8/9 /2012 Claremont Eagle Times

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

Date & Location of Public Meeting: 8/2 9 /2012 at Springfield High School

Deadline for Public Comments: 9/10/2012

Date Final Decision: 4/19/2013

Classification of Source Under §5

- 401: §5

- 401(3): Electric power generation facilities

Classification of Application: New Source Review/ Prevention of Significant

Deterioration Construction Permit

New Source Review Designation of Source: Major Stationary Source

Facility SIC Code(s) & Descriptions: 4911

– Electrical ServicesNorth Springfield Sustainable Energy Project, LL C AP

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### Page 3 of 52 The allowable emissions for the Facility are summarized below:

Table 1

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

**PM /**  **PM 10**  **/ PM**  **2.5 SO**  **2 NO** 

**x CO**  **VOC HAPs**  **2 CO**  **2 e**  **3**

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

1 PM/PM 10 /PM 2.5 - particulate matter, SO 2 - sulfur dioxide, NO
x - 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 C O 2 e ‘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 PM 2.5 

### and thus also PM 10 

### . Filterable PM represents the PM that is in solid form in the heated exhaust gas at the point of sampli ng. Condensable PM represents pollutants that are in gaseous form in the heated exhaust at the point of sampling but will become PM upon cooling and condensing and includes high molecular weight organics.

2.0 FACILITY DESCRIPTION AND LOCATION

2.1 Facility Locations and Surrounding Area

North Springfield Sustainable Energy Project , LLC will be located at 36 Precision Drive in North Springfield, Vermont. The areas surrounding the Facility include mixed industrial, commercial, forested, and suburban residential land uses. The Facility is approximately 0.9 km from the western bank of the Black River. The Jeld

- Wen door company is immediately to the west of the Project site. A gravel pit operation is immediately to the north and east of the project sit e. A non

- operating gravel pit and concrete block plant is immediately to the south of the project site. A number of other small industrial firms are located immediately northwest of the Facility. To the north, south, and east of the Facility, the land use is mixed residential, farmland and forested areas. The Facility is located less than 1 km south of the center of North Springfield, and approximately 5 km to the northwest of Springfield, VT.

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

The n earest Vermont designated sensitive area (elevation at or above 2500 ft eleva tion): is Mount Ascutney, with an elevation of 3,143 feet, located approximately 14.5 km northeast of the Facility

.

2.2 Facility Descripti on

Operations performed at the Facility are classified within the Standard Industrial

Classification Code / North American Industrial Classification System Code 4911

- Electrical services (other electrical power generation) / 221119

- Other Electric Power

Generation

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

Table 2

- 1, and Table 2

- 2 lists information on air pollution control equipment at the Facility.North Springfield Sustainable Energy Project, LL C AP

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### Page 4 of 52 TABLE 2

- 1: Equipment and Stack Information

Equipment/Make/Model Capacity/ Size Fuel or input

material Air Pollution

Control Equipment Stack Height (feet)

Boiler: wood fired advanced

fluidized bed boiler

Four (4) auxiliary/start

- up burners

for the boiler Maximum annual average heat input

(45%moisture content wood):

464 MMBtu/hr 1

Maximum short

term 6 heat input

(55%moisture content wood):

502 MMBtu/hr 1 Natural

Wood Fabric filter

and Selective Catalytic Reduction (SCR) 140

40 MMBtu/hr (each)

160 MMBtu/hr 1

(total) ULSD 2

One (1): Emergency Diesel Engine

Generator 3,000 kW 4

ULSD 2 Tier 2

per 40 CFR

Part 89 -

Diesel Engine Fire Pump 450 bhp 5 Tier 3

per 40 CFR

Part 89 -

1 MMBtu/hr

– million British Thermal Units of heat input per hour

2 ULSD

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

3 gpm

– gallons per minute

4 kW

– rated kilowatt output

5 bhp

– rated brake horse power output

6 Maximum short term heat input has been used to establish pollutant emission rates for review of short term NAAQS ( ≤ 24

- hr standards).

Table 2

- 2: Air Pollution Control Equipment

Boiler

– Pulse

- jet fabric filter dust collector Inlet Temperature: 4 30 o F Maximum design flue gas rate: 260,000 acfm 6 compartments, each with 340 filter bags Nominal bag dimensions: 6” x 26.33’ (39.77 ft 2 /bag) Total cloth filtering area: 81,130 ft 2 , Air/Cloth = 3.2 (gross) 22 oz./yd 2 woven fiberglass with Teflon and ePTFE coating Pressure drop

– typical range: 4.5

– 6.5” w.c.

Boiler

- Selective Catalytic

Reduction for NOx. Inlet Temperature: 425 o F

Details not available at this time. In series, following boiler fabric filter dust collector.

1 The term fabric filter is synonymous with the term bag house for this document.North Springfield Sustainable Energy Project, LL C AP

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### Page 5 of 52 2.3 Description of Compliance Monitoring Devices

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

which measure s exhaust flow and the emission rates of NO

x 

### , CO, NH 3 

### , and CO 2 

### from

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

maintain a continuous opacity monitoring system (COMS) which measures the opacity of the exhaust gas from the Boiler. If required by the Acid Rain Program

, an SO 2 

### CEMS

will also be used.

2.4 Identification of Sources with Insignificant or Negligible Emissions

Although not required for determining applicability with Subchapter X, quantifiable emissions from “insignificant activiti es” must be included for the purposes of establishing whether or not a source is subject to other air pollution control requirements, including, but not limited to: reasonably available control technology, major source status, and Title V operating permit applicability.

Additionally, guidance provided by the U.S. EPA (entitled “White Paper for Streamlined Development of Part 70 Permit Applications”) lists activities which are considered as “trivial” sources of air contaminants, and may be presumptively omitted from operating permit applications.

Table 2

- 3 lists activities at the Facility which were considered trivial, negligible or exempt sources of air contaminant emissions, and therefore were not considered as emission sources as part of the Permit re view.

Table 2

- 3: Negligible Sources of Contaminant Emissions

Fuel storage tanks: Diesel fuel storage tanks.

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

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

wetted cake.



### It should be noted that a process or piece of equipment which is considered a “negligible activity” does not relieve the owner or operator from the responsibility of complying with any applicable requ irements associated with said process or equipment.

2. 5 Proposed Limitations

The Permittee has not proposed any operating limits for the Boiler. However, the annual potential to emit calculations are based on an average heat input of 464 MMBtu/hr (vs. the maximum design heat input of 502 MMBtu/hr), for 365 days per year, so the permit will have an annual heat input limit of 4,064 ,640 MMBtu/yr. Assuming 4,500 B tus per pound of 45% moisture wood, this equates to approximately 451,627 tons/yr of wet

wood fuel.North Springfield Sustainable Energy Project, LL C AP

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### Page 6 of 52 In their application, the Permittee used 65 hours of operation to estimate the potential emissions from the diesel powered emergency generator and the diesel engine fire pump during routine testing and maintenance. The permit will include 65 hours as a limitation for the routine testing and maintenance of these diesel engines. Actual emergency hours of operation are not limited.

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

below.

3.0 QUANTIFICATION OF PO LLUTANTS

The quantification of emissions from a stationary source is necessary in order to establish the appropriate regulatory review process for the operating permit application and to determine applicabi lity of various air pollution control requirements. These determinations are normally based upon allowable emissions. Allowable emission is defined as the emission rate calculated using the maximum rated capacity of the source and, if applicable, either: (a) the applicable

emission standard contained in the Regulations , if any, or (b) the emission rate or design, operational or equipment standard specified in any order or agreement issued under the Regulations that is state and federally enforceable. An applicant may impose in its application an emission rate or design, or an operational or equipment limitation which may be incorporated in the Permit to restrict operation to a lower level. Such limitations may include fuel restrictions or production lim its.

3.1 Estimating Potential Emission of Criteria Pollutants from the Proposed Stationary Source

For the Boiler, the calculated allowable annual emissions of SO 2 

### , NO X 

### , PM, CO and VOCs are based on the established emission limits expressed in lbs/MMBtu a nd an annual average maximum heat input of 464 MMBtu/hr. Short term emission rates (for air dispersion modeling) will be based on the maximum design heat input of 502 MMBtu/hr. Since firing with ULSD only occurs at startup there are no separate emission limits established specifically for oil firing . Th e Facility is expected to comply with the long

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

short term limits for NOx, CO and VOC do not apply during the start up of the boiler. Start up emission limits for NOx, CO and VOC will be established from operating data

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

.

Potential HAP emissions are based on a combinati on 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 bioma ss boilers in New England; additional

details regarding this data is available in S ection 3.2 of this document.North Springfield Sustainable Energy Project, LL C AP

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### Page 7 of 52 Table 3

- 1: Boiler

- Allowable Emissions

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

Emission Factor Allowable Emissions

tons per year Factor Units 1 Source

SO 2 0.020 lb/MMBtu MSER 40.6

NO
x – Annual 0.03 lb/MMBtu MSER 61.0

NO
x – hourly 0.06 lb/MMBtu MSER

-

PM 10 /PM 2.5 /PM 2 0.019 lb/MMBtu MSER / HMSER 38.6

CO 0.075 lb/MMBtu MSER / HMSER 152.4

VOC 0.005 lb/MMBtu HMSER 10.2

HAPs 0.0075 lb/MMBtu AP

- 42, Wood Residue Combustion in
Boilers, Tables 1.6

- 3 and 1.6

- 4 (9/03), NCASI Technical Bulletin No. 858, representative stack tests. 15.3 3

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

2 PM: total PM including filterable and condensable fractions.

3 No individual HAP exceeds 10 tons per year and combined HAPs are less than 25 tons per year.

Table 3

- 2: Diesel Generators

– Allowable Emissions

Emission estimate

based on 65 hours 3000 kW Tier 2 Engine Emission Factor Allowable Emissions, tons/yr Factor Units Source

SO 2 0.0015 lb/ MMBtu 15 ppm sulfur content in fuel 0.0015

PM 0.2

g/kW

- hr EPA Tier 2 Engine 0.04

NO X 6.4 1.37

CO 3.5 0.75

VOC

- - -

Table 3

- 3: Fire Pump/Diesel Engine

– Estimated Emissions

Emission estimate

based on 65 hours 450 hp Tier 3 Engine

23.5 gph Emission Factor

Allowable Emissions, tons/yr Factor Units Source

SO 2 0.0015 lb/ MMBtu 15 ppm sulfur content in fuel 0.0002

PM 0.15

g/BHP

- hr EPA Tier 3 Engine 0.005

NO X 3.0 0.10

CO 2.6 0.09

VOC

- - -North Springfield Sustainable Energy Project, LL C AP

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### Page 8 of 52 Table 3

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

**Source PM/PM**  **10 SO**  **2 NO**  **X CO**  **VOC Total** 

**HAPs**

Boiler 38.6 40.6 61.0 152.4 10.2 15.3

Diesel generators (1@3 000kW) 0.04

- 1.37 0.75

- -

Diesel fire pump

- - 0. 1 0.08

- -

Facility Totals 38.64 40.6 62.4 153.3 10.2 15.3

Significance Levels 25/15 40 40 50 40

-



### As summarized in Table 3

- 4 above:

• The Facility has allowable emissions of all air contaminants in the aggregate of ten (10) or more tons per year and has allowable emissions of carbon monoxide in excess of 100 tons per year: the Facility is therefore subject to Subchapter X of the Regulat ions and is designated as a Title V Subject Source. The Facility will be required to file an application for a Title V Permit to Operate within one year of commencing operation.

• The Facility has allowable emissions of NO X 

### and CO greater than 50 ton/year w hich 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.’ PM 10 

### and SO 2 

### 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 po llutants.

• 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 lea st 24 months before commencing operation.

3.2 Estimating Emissions of Hazardous Air Contaminants.

The potential emissions of Vermont Hazardous Air Contaminants are estimated based on the maximum operating load for the Boiler and an appropriate emission f actor. 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 si milar wood fired boilers located in Vermont and the rest of New England.North Springfield Sustainable Energy Project, LL C AP

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### Page 9 of 52 Table 3

- 5 Quantification of HAC Emissions

Hazardous Air

Contaminant CAS#ToxicCategory

Boiler

Emission

FactorBoiler EFSource1

Facility

Emission

Rate Action

Level Above

Action

Level?

(lb/mmbtu) (lb/8

- hrs) (lb/8

- hrs)

1,1,1

- Trich loroethane 71556 II 3.10E

- 05 AP

- 42 1.15E

- 01 8.30E+01

1,2

- Dichloroethane (ethylene dichloride) 107062 I 2.90E

- 05 AP

- 42 1.08E

- 01 3.20E

- 03 Yes

1,2

- Dichloropropane (propylene dichloride) 78875 I 3.30E

- 05 AP

- 42 1.22E

- 01 4.20E

- 03 Yes

2,4,6

- Trichlorophenol 88062 I 2.20E

- 07 NCASI 8.17E

- 04 2.70E

- 02

Acetaldehyde 75070 I 1.90E

- 04 NCASI 7.05E

- 01 3.80E

- 02 Yes

Acetone 67641 II 2.20E

- 04 NCASI 8.17E

- 01 2.61E+01

Acrolein 107028 II 2.40E

- 04 AP

- 42 (LO) 8.91E

- 01 2.00E

- 03 Yes

Ammonia II 6.00E

- 03 HMSER 2.23E+01 8.30E+00 Yes

Antimony II 7.90E

- 06 AP

- 42 2.93E

- 02 3.00E

- 01

Arsenic I 4.00E

- 06 AP

- 42 (LO) 1.48E

- 02 1.90E

- 05 Yes

Barium II 1.70E

- 04 AP

- 42 6.31E

- 01 4.00E

- 02 Yes

Benzene 71432 I 8.50E

- 04 AP

- 42 (LO) 3.16E+00 1.10E

- 02 Yes

Benzo(a)pyrene 50328 I 2.67E

- 06 NCASI 9.91E

- 03 4.00E

- 05 Yes

Beryllium I 1.90E

- 06 NCASI 7.05E

- 03 3.50E

- 05 Yes

B romodichloromethane 75274 I 3.00E

- 03 NCASI 1.11E+01 4.60E

- 03 Yes

Bromomethane (methyl bromide) 74839 II 1.50E

- 05 AP

- 42 5.57E

- 02 4.00E

- 01

Cadmium I 4.10E

- 06 AP

- 42 1.52E

- 02 4.60E

- 05 Yes

Carbon disulfide 75150 II 1.30E

- 04 NCASI 4.83E

- 01 5.45E+01

Carbon tetrachloride 56235 I 8.90E

- 07 NCASI 3.30E

- 03 5.50E

- 03

Chlorine 7782505 III 7.90E

- 04 AP

- 42 2.93E+00 1.00E

- 02 Yes

Chlorobenzene 108907 II 3.30E

- 05 AP

- 42 1.22E

- 01 2.00E

- 01

Chloroform 67663 I 3.10E

- 05 NCASI 1.15E

- 01 3.60E

- 03 Yes

Chloromethane (methyl chloride) 74873 II 4.00E

- 05 NCASI 1.48E

- 01 7.50E+00

Chromium (total) II 2.10E

- 05 AP

- 42 7.80E

- 02 1.00E

- 02 Yes

Chromium, hexavalent I 2.00E

- 06 AP

- 42 (LO) 7.42E

- 03 6.90E

- 06 YesNorth Springfield Sustainable Energy Project, LL C AP

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### Page 10 of 52 Table 3

- 5 Quantification of HAC Emissions

Hazardous Air

Contaminant CAS#ToxicCategory

Boiler

Emission

FactorBoiler EFSource1

Facility

Emission

Rate Action

Level Above

Action

Level?

(lb/mmbtu) (lb/8

- hrs) (lb/8

- hrs)

Cobalt I 6.50E

- 06 AP

- 42 2.41E

- 02 8.30E

- 04 Yes

Copper (dusts & mists) II 4.90E

- 05 AP

- 42 1.82E

- 01 2.00E

- 02 Yes

C umene 98828 II 1.80E

- 05 NCASI 6.68E

- 02 3.32E+01

Di

- butyl phthalate 84742 II 3.30E

- 05 NCASI 1.22E

- 01 2.50E

- 01

Dichloromethane (methylene chloride) 75092 I 5.40E

- 04 NCASI 2.00E+00 1.70E

- 01 Yes

D initrotoluene

- 2,4 121142 I 9.40E

- 07 NCASI 3.49E

- 03 4.20E

- 04 Yes

Ethanol 64175 II 6.80E

- 05 NCASI 2.52E

- 01 3.72E+01

Ethylbenzene 100414 I 3.10E

- 05 AP

- 42 1.15E

- 01 8.30E+00

Fluoranthene 206440 II 1.64E

- 06 NCASI 6.09E

- 03 1.20E+00

Formaldehyde 50000 I 1.20E

- 03 AP

- 42 (LO) 4.45E+00 6.50E

- 03 Yes

Hexachlorobenzene 118741 I 1.00E

- 06 NCASI 3.71E

- 03 1.80E

- 04 Yes

Hexane 110543 II 2.90E

- 04 NCASI 1.08E+00 5.81E+02

Hydrogen Chloride 7647010 II 8.34E

- 04 Test 3.10E+00 1.70E+00 Yes

Iron oxides

- dusts &

fumes II 9.90E

- 04 AP

- 42 3.67E+00 1.00E+00 Yes

Isopropanol 67630 II 3.90E

- 03 NCASI 1.45E+01 1.84E+02

Lead compounds I 4.80E

- 05 AP

- 42 1.78E

- 01 8.30E

- 04 Yes

Manganese II 8.60E

- 05 AP

- 42 (LO) 3.19E

- 01 4.00E

- 03 Yes

Mercury II 3.50E

- 06 NCASI 1.30E

- 02 2.00E

- 02

Methanol 67561 II 8.30E

- 04 NCASI 3.08E+00 9.70E+01

Methyl ethyl ketone 78933 II 9.10E

- 06 NCASI 3.38E

- 02 4.15E+02

Methyl Isobutyl Ketone 108101 II 2.30E

- 05 NCASI 8.54E

- 02 2.49E+02

Molybdenum compounds (metal & insoluble) II 2.10E

- 06 AP

- 42 7.80E

- 03 2.00E

- 01

Naphthalene 91203 I 1.60E

- 04 NCASI 5.94E

- 01 2.00E

- 02 Yes

Nickel compounds I 3.30E

- 05 AP

- 42 1.22E

- 01 1.70E

- 04 Yes

PCDD/PCDF (VT APCD Memo 2/7/2011)

- I 1.38E

- 10 NCASI 5.12E

- 07 1.93E

- 09 YesNorth Springfield Sustainable Energy Project, LL C AP

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### Page 11 of 52 Table 3

- 5 Quantification of HAC Emissions

Hazardous Air

Contaminant CAS#ToxicCategory

Boiler

Emission

FactorBoiler EFSource1

Facility

Emission

Rate Action

Level Above

Action

Level?

(lb/mmbtu) (lb/8

- hrs) (lb/8

- hrs)

Pentachlorophenol 87865 I 5.10E

- 08 AP

- 42 1.89E

- 04 2.40E

- 03

Phenanthrene 85018 II 7.21E

- 06 NCASI 2.68E

- 02 8.70E+00

Phenol 108952 II 5.10E

- 05 AP

- 42 1.89E

- 01 5.30E+00

Pyrene 129000 II 3.79E

- 06 AP

- 42 1.41E

- 02 8.70E

- 01

Selenium II 3.00E

- 06 NCASI 1.11E

- 02 1.50E

- 01

Silver compounds (metal) II 1.40E

- 04 NCASI 5.20E

- 01 6.60E

- 01

Styrene 100425 I 6.40E

- 04 NCASI 2.38E+00 8.30E+00

Sulfuric Acid Mist II 9.19E

- 04 APCD 3.41E+00 2.70E

- 02 Yes

Tetrachloroethylene (perchloroethylene) 127184 I 3.82E

- 05 AP

- 42 1.42E

- 01 1.50E

- 02 Yes

Tin compounds (metal and inorganic) II 3.90E

- 05 NCASI 1.45E

- 01 4.00E

- 01

Toluene 108883 II 2.90E

- 05 NCASI 1.08E

- 01 2.49E+01

Trichloroethylene 79016 I 3.00E

- 05 AP

- 42 1.11E

- 01 4.00E

- 02 Yes

Trichlorofluoromethane 75694 II 4.10E

- 05 AP

- 42 1.52E

- 01 4.66E+01

Vanadium pentoxide I 9.80E

- 07 AP

- 42 3.64E

- 03 8.30E

- 04 Yes

Vinyl Chloride 75014 I 1.80E

- 05 AP

- 42 6.68E

- 02 9.10E

- 03 Yes

Xylenes (includes o,m,p)

- II 2.80E

- 05 NCASI 1.04E

- 01 8.30E+00

Zinc oxide II 4.20E

- 04 AP

- 42 1.56E+00 8.30E

- 02 Yes

1 Sources of Emission Factors:

AP

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

AP

- 42 (LO) = An adjusted emission factor after auditing AP

- 42 for outlier data. Refer to the NSSEP permit application, Appendix A, Table A

- 2 for further details.

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

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

. APCD = Based on Babcock & Wilcox technical paper: A System Approach to SO 3 Mitigation , and Motobec USA technical paper: Reducing SO 2 Emissions at Coal Fired Power Plants

. HMSER = Haza rdous Most Stringent Emission Rate

– see section 7.4 of this document.North Springfield Sustainable Energy Project, LL C AP

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### Page 12 of 52 3.3

– Estimating Potential Greenhouse Gas Emissions

The estimate for potential GHG emissions includes the distillate fuel oil that would be used for 4 cold sta rtups of the boiler. Each cold startup is expected to take 11 hours and consume an estimated 9,000 gallons of distillate fuel. The estimate does not ‘back

- out’ the reduced wood fuel usage during these startups, so the estimate for GHG is conservatively h igh.



### Section 3.3 Estimation of CO 2 

### e Emissions

Source Source Estimated

wood

usage

ID Description Units (raw tons)

Main Boiler 275,994 tons 451627 45.0%
Auxilliary burners 36,000 gallons 0 0.0%
Emergency engines 15,386 gallons 0 0.0%

Table 2. Total Company-Wide Stationary Source Fuel Combustion

Quantity

Fuel Type Combusted Units

51,386 gallons

275,994 tons
Table 3. Total Company-wide CO 2 , CH 4 and N 2 O Emissions from Stationary Source Fuel Combustion

CO 2 CO 2 CH 4 CH 4 N 2 O N 2 O
(kg) (lb) (kg) (lb) (kg) (lb)

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

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

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

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

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

Global Warming Potential CO 2 CH 4 N 2 O

1.0 21.0 310.0 metric ton short ton

Total CO 2 Emissions - Equivalent (Fossil CO2e + Biogenic CH4 & N2O) 8,905 9,817

All CO2e emissions at stack (Fossil CO2e + Biogenic CO2e) - for APCD Permit info 407,067 448,714 CO 2 e Wood Fuel Distillate Fuel Oil #2

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

converted to 275,994 tons @ 10% MC Potential/

Allowable

Quantity

Combusted Estimated

%MC for

raw wood

fuel

Wood Fuel

Distillate Fuel Oil #2

Distillate Fuel Oil #2 Fuel CombustedNorth Springfield Sustainable Energy Project, LL C AP

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### Page 13 of 52 4.0 DISCUSSION OF SELECT APPLICABLE AND NON

- APPLICABLE REQUIREME NTS

The Agency will assess compliance with these regulations during any inspections of the Facility. The inspections will include confirmation of the proper operation and maintenance of equipment and air pollution control devices, visual observations of emission points, and review of any records required by the Permit.

4.1 Vermont Air Pollution Control Regulations and Statutes

**§5**

**- 201 and §5** 

**- 202** 

**- Open Burning Prohibited and Permissible Opening**  **Burning** Open burning of materials is prohibited except in conformance with the requirements of this section.

**§5**

**- 211(2)** 

**- Prohibition of Visible Air Contaminants** 

**- Installations**  **constructed subsequent to April 30, 1970** This emission standard applies to all point sources of air emissions at the Facility.

**§5**

**- 221(1)** 

**- Prohibition of Potentially Polluting Materials in Fuel; Sulfur** 

**Limitation in Fuel** This prohibition applies to all st ationary 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) su lfur by weight and natural

wood

.

**§5**

**- 231(3)** 

**- Prohibition of Particulate Matter; Combustion Contaminants**  Based on the application submitted and information available to the Agency, this Facility has applicable fuel burning equipment subject to this regulat ion. The allowable particulate emissions based on minimum standards of 5

- 231(3) are

shown in Table 4

- 1, however the Facility is limited to a more stringent emission standard under the MSER requirements of 5

- 502(3).

Table 4

- 1: Equipment Subject to §5

- 231(3)

**Equipment ID Size/Capacity**  **Emission Standard,**

**lbs/MMBtu Allowable Emissions,** 

**lbs/hr**

Boiler 502 MMBtu/hr 0.1 50.2



### §5

**- 231(4)** 

**- Prohibition of Particulate Matter; Fugitive Particulate Matter**  This section requires the use of fugitive PM control equipment on all process operations and the application of reasonable precautions to prevent PM from becoming airborne during the handling, transportation, and storage of materials, or use of roads. This requirement applies to the entire Facility.

**§5**

**- 241**  **(1) & (2)**

**- Prohibition of Nuisance and Odor**  This requirement applies to the entire Facility and prohibits the discharge of airNorth Springfield Sustainable Energy Project, LL C AP

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### Page 14 of 52 contaminants that would be a nuisance to the public or the discharge of objectionable odors beyond the property

- line of the Fa cility.

**§5**

**- 251** 

**- Control of Nitrogen Oxide Emissions**  Based on the application submittal and information available to the Agency, the boiler is greater than 250 MMBtu/hr and is subject to this regulation 5

- 251(1) while burning fossil fuel. However the boiler is being held to a more stringent emission standard under the MSER requirements of 5

- 502(3). The Facility does

not have allowable emissions of NO X 

### in excess of 100 tons per year and is therefore not subject to subsection 5

- 251(3).

**§5**

**- 252** 

**- Control**  **of Sulfur Dioxide Emissions** Based on the application submittal and information available to the Agency, the boiler is greater than 250 MMBtu/hr and is subject to this regulation while burning

fossil fuel. However the boiler is being held to a more stringe nt 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 subj ect 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 i nternal combustion engines with a brake horsepower output rating of 450 hp or greater. This section applies to the emergency generator and fire pump engine at the Facility.

4.2 Regional Greenhouse Gas Initiative Vermont CO 2 

### Budget Trading Program

-

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

- based regulatory CO 2 

### emission trading program among nine Northeast and Mid

- Atlantic states (States). Participating states include Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and

Vermont. RGGI is intended to stabilize and then reduce emissions of CO 2 

### from

fossil fuel

- fired electrical generating systems with a nameplate capacity equal to or greater than 25 MWe. Sources subject to RGGI ar e required to purchase and hold allowances equivalent to their actual emissions of CO 2 

### over each three year control period and certify compliance at the end of each respective control period. Emission allowances are primarily auctioned by the States, whic h, in turn, invest the auction proceeds in energy

- related consumer benefit programs.

Compliance with RGGI is defined and administered under the Vermont CO 2 

### Budget Trading Program Regulations ( Program Regulations )North Springfield Sustainable Energy Project, LL C AP

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### Page 15 of 52 A “fossil fuel

- fired electrical generatin g system” is defined under § 22

- 102 of the Program Regulations as a unit where “

... the combustion of fossil fuel, alone or in combination with any other fuel, where the fossil fuel combusted comprises, or is projected to comprise, more than 50 percent of the annual heat input on a Btu basis during any year “.

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

than 25 MWe , the Facility is not intended or projected to use greater than 50 percent fossil fuel for its annual heat input. As such, it is not subject to the requirements of RGGI or the Program Regulations

.

4.3 Federal Air Pollution Control Regulations and the Clean Air Act

40 **C.F.R.** Part 60 Subpart Db

**– Standards of Performance for Small** 

**Industrial**

**- Commercial** 

**- Institutional Steam Generating Units**  “The affected facility to which this Subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June
19, 1984 and that has a maximum de sign heat input capacity of greater than 29 megawatts (MW) (100 million BTU per hour).

The Boiler is subject to this regulation. However the boiler is held to more stringent emission standards through MSER.

40 **C.F.R.** Part 60 Subpart IIII

– **Standards of Per**  **formance for Stationary Compression Ignition Internal Combustion Engines** 

Applies to CI RICE model year 2007 and newer . This regulation establishe s emission rates for affected engines, requires routine engine maintenance and

sets maximum sulfur content for the diesel fuel. Beginning October 1, 2010 applicable engines shall only use diesel fuel with a maximum sulfur content of 15 ppm (ULSD).

This regulation applies to the diesel engines that power the emergency generator and the fire pump at the Fac ility.

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), w ork practice standards, operating limits for the PM control device, performance stack testing, and demonstrating continuous compliance (similar to Compliance Assurance Monitoring discussed below).

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

and less than 25 tons for all HAPs combined it is classified as an area source of HAPs, not a major HAP source, and therefore t his regulation applies to the Boiler rather than the major source regulation Subpart DDDDD.North Springfield Sustainable Energy Project, LL C AP

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### Page 16 of 52 40 **C.F.R** . Part 6 3 Subpart ZZZZ

– National Emission Standards for

Hazardous Air Pollutants for Reciprocating Internal Combustion Engines. Applies to new engines installed after June 12, 2006 at area sources of HAPs. Requires such engines to meet the emission standards of NSPS Subpart IIII and JJJJ, imposes ULSD fuel limitations, and imposes maintenance requirements. Separate provisions of ZZZZ also apply to existing engines installed prior to June
12, 2006.

Subpart ZZZZ applies to the diesel engines that power the emergency generator and the fire pump at the Facility requiring them to meet NSPS Subpart IIII.

Clean Air Act §§114(a)(3), 502(b), and 504(a)

- (c); 40 CFR Part 70 §§70.6(a)(3)(i)(B) and 70.6(c)(1); and 40 CFR Part **64**

- **Compliance Assurance Monitoring.** 

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

• the Facility is a Title V Subject Source ;

• the uncontrolled emission rate s of PM and NOx exceed their respective Title V major source thresholds (100 ton/yr);

• the emissions of PM (NSPS, MSER and HMSER ) and NOx (MSER) are subject to an applicable rule;

• the Boiler is eq uipped with emissions control devices for each of these pollutants. Note that CO is controlled based on the bubbling fluidized bed boiler design which is not considered an emission control device for CAM, so CAM does not apply to CO for this Facility. Co nsidering that the Facility is otherwise required to have a CO CEMS, CAM does not offer any additional significant monitoring benefits for CO.

The CAM Plan for this Facility will be included in the Title V Operating permit. The Facility is required to fi le 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 port ion of the Title V operating permit application.

40 **C.F.R.** Parts 72

- 78

– Acid Rain Program

The Permittee is required to operate the Facility under a permit that includes the Acid Rain Program requirements. This regulation requires that the Facility be equipped with a CEMS for opacity, exhaust flow, diluents, NO X 

### and SO 2 

### emissions , although the Permittee may petition EPA to use a default SO 2 

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

Pe r mittee 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.North Springfield Sustainable Energy Project, LL C AP

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### Page 17 of 52 40 **C.F.R.** Part 98

– Mandatory Greenhouse Gas Rep orting

Pursuant to §98.2(a)(1)(i) the Permittee is required to report the Facility’s greenhouse gas emissions from the Boiler.

4.4 Non

- Applicable Requirements for Which a Permit Shield Provision Has Been Requested

Pursuant to §5

- 1015(a)( 14) of the Regulations, an owner/operator may request to be shielded from potentially applicable state or federal requirements. The Facility has not requested a permit shield from any specific, potentially applicable requirement. Accordingly, the Agency h as not granted any permit shields for the Facility.

5.0 CONTROL TECHNOLOGY R EVIEW FOR MAJOR SOUR CES AND MAJOR

MODIFICATIONS

Pursuant to §5

- 502 of the Regulations each new major source and major modification must apply control technology adequate to achie ve 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 equiva lent to the federal Best Available Control Technology.

As shown in Tables 3

- 4 above, the Facility must achieve MSER for PM/PM 10 

### /PM 2.5 

### , SO 2 

### , CO,

and NO

x 

### . 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 wh ich 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 Handbo ok”, 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 bot tom (top being the most effective). One of the sources for information on emission limits and control technologies for permitted facilities is the U.S. EPA’s “RACT, BACT, LAER Clearinghouse (RLBC).” MSER requires the application of the top option unless it can be demonstrated based upon costs (economic, energy, and environmental) or technical constraints that such an option is not achievable for the proposed project. If the Agency concurs with the applicant that an option is not achievable, then the next most effective option is evaluated. This process may take several iterations before MSER is established.

MSER will be established for the following sources: Boiler and the emergency engines.North Springfield Sustainable Energy Project, LL C AP

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### Page 18 of 52 Wood Fired Boiler

– MSER Determination:

5.1 Boiler

- NO X 

### MS ER Review

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

listed in order of effectiveness:

1. Selective catalytic reduction (SCR): U se of a catalyst to reduce NO

x 

### to N 2 

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

, conventional SCR

, where the exhaust gases pass straight through the catalyst and

out the stack. To achieve the necessary inlet temperatures, the SCR is placed immediately after the boiler on the “hot side” of the other emission control devices. In cases where the exhaust gases are too cool for the catalyst to function properly, additional heat is necessary to bring the exhaust gases up in temperature. In these systems, the added heat energy is often recovere d by cycling back and forth over heat recovery media beds. This is referred to as a regenerative SCR (RSCR).

Conventional SCR systems can achieve very high levels of emission reductions depending on the volume of catalyst and amount of ammonia used. RSC R systems

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

. SCR had not been applied to wood

- fired units until about 2004, having been considered technically infeasible due to the adverse impacts o f alkaline materials in the wood ash that rapidly deactivate the catalyst. However, vendors of this technology have begun to overcome these issues by physical catalyst configuration, and by placing the catalyst downstream of the particulate removal device, thus avoiding the worst effects of fouling and degradation. This lower temperature zone also required reformulation of the catalyst material to obtain adequate reaction at temperatures 2 00 to 300 o 

### F lower than the 600

- 750 o 

### F that was

the previous norm fo r SCR applications.

2. Selective non

- catalytic reduction (SNCR): Reducing NO

x 

### to N 2 

### by i njection of ammonia or urea into the boiler exhaust gases at high temperature (1600 to 2100 ° F). This can achieve NOx reduction levels ranging from 30

– 50%. When combined with combustion controls, the overall NOx reduction can be in the range of 65

– 75%.

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

combu stion parameters to achieve efficient combustion and to control the stoichiometry in the combustion zone to minimize the formation of thermal NO

x 

### . Combustion controls also include flue gas recirculation to lower combustion temperature and thermal NO

x 

### form ation. To varying degrees, these have become integral components in modern boiler design. The bubbling fluidized bed proposed herein varies FGR rates to compensate for variations in fuel moisture content to maintain the bed temperature of 1,300 to 1,600 o 

### F. NOx formation increases exponentially with increased combustion temperature. In this range of bed temperature, very little thermal NOx is formed.

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

combination of 1 & 3 as MSER for NOx control. The catalyst system will be a selective catalytic reaction (SCR) that will reduce NOx emissions. In addition the Permittee is proposing a NOx limit of 0.06 lb/MMBtu based on a one hour block average and a long term

NOx emission limit of 0.03 lb/MMBtu for an annual block average.North Springfield Sustainable Energy Project, LL C AP

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### Page 19 of 52 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. S ome of these SCR systems are located as a “cold side” SCR and they incorporate a regenerative heat exchanger to maintain the proper temperatures some of

which use a minimal amount of additional fuel to re

- heat the exhaust gases.

Many of the operating faci lities 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 NO x 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 p roposed 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.North Springfield Sustainable Energy Project, LL C AP

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### Page 20 of 52 Table 5

- 1: NO X Emission Limits and Performance

Facility Nominal Rating Permit

Date NO X Controls NO X Limit (lb/MMBtu) NO X Emission Performance

Pioneer Renewable Energy, Greenfield, MA 47 MW Application pending MPCR 0.055 (1 hr block) 0.022 (12 month block) Plant has not been built.

Beaver Wood Energy

– Fair Haven 34 MW 2/10 /2012 MPCR 0.060 (1

- hr block) 0.030 (12

- mo nth avg) Plant has not been built.

Palmer Renewable Energy, Springfield, MA 38 MW 6/30/2011 Combustion control, OFA, HRSCR 1 0.055 (1 hr block) 0.017 (12 mo nth avg)) Plant has not been built.

Warren Co. Biomass

– GA 100 MW 12/17/2010 SNCR 0.1 0 (30 day rolling avg) Plant has not been built. Clean Power Berlin, Berlin, NH 29 MW 9/25/2009 Staged combustion &

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

Laidlaw Berlin BioPower, Berlin, NH 70 MW 7/26/10 SCR 0.06 0 (30 day rolling avg) U nder construction

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

Boise White Paper

- AL 435

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

Lindale Renewable Energy

– TX 50 MW 1/8/2010 SNCR 0.15 Plant has not been built.
Lufkin Generating Plant

- Lufkin,

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

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

McNeil Generating Station

- Burlington, VT 50 MW 2/2/09 RSCR 0.075 (Quarterly block) 2010 Quarterly averages:
0.067, 0.072, 0.072, 0.069. Russell Biomass, Russell, MA 50 MW 12/30/08 RSCR 0.060 (12 month rolling avg) Plant has not been built.

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

Koda Energy

– MN (120,000 lb/hr steam plus 17.8 MW) 308

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

Simpson Tacoma Kraft

– WA (Power Boiler #7) 340,000

lb/hr

steam 12/12/2011 Combustion Controls

w/ over

- fire air (OFA) 0.20 (30 day avg) Changing to 0.30 (30 day avg) Operating. OFA design unable

to meet the 0.20 NOx limit.

PSNH

- Schiller Station (Unit SR5) Portsmouth, NH 50 MW 3/7/06 SNCR 0.075 (24 hr avg) Based on CEMS, 1 st qtr 2011

estimated at 0.064 lb/MMBtu

1 HRSCR

– high efficiency regenerative selective catalytic reduction system. The proposed system at this facility includes an oxidative catalyst as well for reducing CO and VOC emissions.North Springfield Sustainable Energy Project, LL C AP

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### Page 21 of 52 Based on review of the proposed alternatives, the Agency concurs that MSER for NOx is the use of combustion controls with a SCR and the following NOx emission rates: H ourly average of 0.060 lb/MMBtu of heat input and a 12 month rolling average of 0.030 lb /MMBtu of heat input.

5.2 Boiler

– Particulate Matter (“PM/PM 10 

### ”) MSER Review

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

- listed

in order of effectiveness:

1. Electrostatic Precipitator (ESP) or fabric filter

2. We t scrubber

3. Dry Scrubber

4. Multi

- clon e

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

- fired units, primarily over fire

- related concerns with fabric filters

, a few fabric filters have been p laced in operation in the past few years and have demonstrated their viability. Fabric filters are generally considered equal to ESPs for overall PM control but to have slightly superior fine particle control. Furthermore, fabric filters tend

to be install ed in lower flue gas temperature zones which promotes condensation of various compounds onto the solid material that is then efficiently removed by the filters, rather than, in a conventional unit, condensing in the atmosphere to form PM 10 

### /PM 2.5



### .

A wet sc rubber can achieve removal efficiencies in the high 90s percent range, though the sludge and wastewater handling and processing is much more involved and costly than dry ash handling. Wet processed ash tends also to be less marketable as a reusable by

prod uct. Wet scrubbers tend to be utilized only when there is a specific acid gas removal

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

Dry scrubbers, when utilized, precede a fabric filter and are generally limited to projects wherein acid gas removal is a concern. Similarly, sorbent injection may be used to resolve a

site

- specific issue.

Multi

- clones sometimes precede the high

- efficiency particulate removal device as a means to substantially decrease the loading of that device so that it can be designed and operated more efficiently. Multi

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

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

All of the abo ve technologies are technically feasible.

The Permittee is proposing the use of a fabric filter as MSER for PM/PM 10 

### control. In addition, the Permittee is proposing a filterable PM emission limit of 0.010 lb/MMBtu and a total PM (filterable + condensab le PM) limit of 0.019 lb/MMBtu.North Springfield Sustainable Energy Project, LL C AP

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### Page 22 of 52 The Agency asked the Permittee about the potential use of multi

- cyclones up stream of the fabric filters in order to help minimize the potential for damaging (burning) the filter bags due to char/cinder carry over. The vend or, Babcock and Wilcox (B&W), replied as follows:

While the u se of multi

- cyclones (mechanical dust collectors

– “MDC”) are common practice

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

better combustion characte ristics that result in reduced char carry over , unburned carbon loss, and lower carbon monoxide emissions. With prudent fuel management and operating practice, B&W’s experience is that an MDC is not necessary with a properly designed BFB combustion system

. B&W’s design philosophy incorporates low velocity plenums and drop

out hoppers prior to the fabric filter. While an MDC could offer an additional margin of protection against cinder carry over, this would come at a higher capital and operational

cost.

In the T able 5

- 2 is a summary of the PM emission limits of several recently permitted wood fired boiler EGUs, as well as the two wood fired EGUs currently operating in Vermont.

The Agency has not found enough PM emission data on large boilers to adequate ly 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 Ener gy for total PM is not expected to be cons istently achievable.

Based on review of the proposed alternatives, the Agency concurs that the best available control technology for PM/PM 10 

### emissions from the Boiler is the use of a fabric filter and a

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

lb/MMBtu.North Springfield Sustainable Energy Project, LL C AP

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### Page 23 of 52 Table 5

- 2: PM/PM 10 Emission Limits and Performance

Facility Nominal Rating Permit Date PM Controls PM/PM 10 Limit (lb/MMBtu) PM Emission Performance

Pioneer Renewable Energy, Greenfield, MA 47 MW Application pending Multi

- clone, ESP Filterable PM: 0.012

Total PM: 0.019 Plant has not been built.

Beaver Wood Energy

– Fair

Haven 34 MW 2/10 /2012 Multi

- clone, ESP Filterable PM: 0.010

Total PM: 0.019 Plant has not been built.

Palmer Renewable Energy, Springfield, MA 38 MW 6/30/2011 Dry scrubber,

fabric filter Filterable PM: 0.008

Total PM: 0.015 Plant has not been built.

Ryegate Power Station East Ryegate, VT 20 MW 5/16/2011 Multi

- clone, ESP Filterable PM: 0.007 gr/dscf (0.016 lb/MMBtu) Average of 9 stack tests since 1993:

0.0013 lb/MMBtu (filterable PM)

Warren Co. Biomass Energy facility

– GA 100 MW 12/17/2010 Sorbent injection

and fabric filter Filterable PM 10 0.010

Filterable PM 2.5 0.018 Plant has not been built.

Laidlaw Berlin BioPower, Berlin, NH 70 MW 7/26/10 Fabric filter Filterable PM: 0.01 U nder construction

Montville Power, Uncasville, CT 42 MW 4/6/10 Multi

- clone, ESP Filterable PM: 0.012

Total PM: 0.026 Plant has not been built.

Lindale Renewable Energy, TX 50 MW 1/8/2010 Good combustion practices & ESP Filterable PM: 0.02 (30

- day avg) Plant has not been built.

Lufkin Generating Plant, Lufkin, TX 45 MW 10/26/09 ESP Filterable PM: 0.012

Total PM: 0.025 Both 30 day rolling avg Started August, 2011

Seneca Sustainable Energy, Eugene, OR 18.8 MW 10/9/09 Multi

- clone, ESP Total PM: 0.008 Stack test s completed

. Seneca Sustainable Energy: There are ongoing issues with demonstrating compliance on a long term basis that include complications from the condensable PM test method which had problems with test artifacts causing false high PM emissions.
Russell Biomass, Russell, MA 50 MW 12/30/08 Multi

- clone, ESP

or fabric filter Filterable PM: 0.012

Total PM: 0.026 Plant has not been built.

Yellow Pine Energy Company

- Fort Gaines, GA 115 MW 5/15/09 Fabric filter Filterable PM: 0.01 0

Total PM: 0.018 Plant has not been built.

Koda Energy

– MN 120,000 lb/hr steam + 17.8 MW 308

MMBtu/hr 8/23/2007 Cyclone & ESP Total PM: 0.03

Filterable PM 10 : 0.037 (3 hr avg) Started operation in 2009

Simpson Tacoma Kraft

– WA (Power Boiler #7) 340,000 lb/hr

steam 12/12/2011 Existing ESP Filterable PM 10 : 0.02 0.01 gr/dscf @ 7% O2 OperatingNorth Springfield Sustainable Energy Project, LL C AP

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### Page 24 of 52 Table 5

- 2: PM/PM 10 Emission Limits and Performance

Facility Nominal Rating Permit Date PM Controls PM/PM 10 Limit (lb/MMBtu) PM Emission Performance

PSNH

- Schiller Station (Unit SR5) Portsmouth, NH 50 MW 3/7/06 Fabric filter Filterable PM: 0.025 (at all times) 0.01 (24

- hour avg) Stack test s (filterable PM)

5/6/10: 0.001 lb/MMBtu

5/13 /09: 0.001 lb/MMBtu

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

0.0007 lb/MMBtu filterable PM

0.0117 lb/MMBtu condensable PM

0.0124 lb/MMBtu total PM

McNeil Generating Station, Burlington, VT 50 MW 2/2/09 ESP Filterable PM: 0.007 gr/dscf (0.016 lb/MMBtu) Stack test s (filterable PM)

7/14/04: 0.00060 lb/MMBtu

10/26/10: 0.00015 lb/MMBtuNorth Springfield Sustainable Energy Project, LL C AP

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### Page 25 of 52 5.3 Boiler

– Carbon Monoxide (CO) MSER Review

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

- listed

in order of effectiveness:

1. Oxidative catalyst.

2. Good combustion design and combustion practices.

Oxidation catalysts have not historically been successfully applied to wood fired units. Until recently, they were considered technically infeasible for reasons similar to the fouling and degradation experienced with SCR catalysts. Recent designs have moved them to the clean side and, hence, cooler operating zone. Although an oxidation catalyst is more efficient at higher temperatures, such temperatures occur only on the high

- ash side of the particulate removal system where fouling a nd catalyst degradation are a problem. Thus cold

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

- fired

combustion turbine

- based combined cycle power plants.

Combustion controls incorporated in any modern boiler design reduce CO emissions to well below those of older boilers. The BFB boiler can achieve CO emissions rates comparable to a stoker unit equipped with an oxidation catalyst.

Table 5

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

with wood fired boilers. The most stringent short term emission limits are 0.07 (4 hr avg) to 0.075 lb/MMBtu (24 hr avg) for recently permitted units incorporating oxidation catalysts. The most stringent annual average CO emission rate is p roposed for Pioneer Renewable and included in the air permit for Palmer Renewable in Massachusetts. Neither facility has been built or operated, so neither this annual average, nor the 0.07 lb/MMBTU (4

- hr avg)

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

limits.

All of the above technologies are technically feasible. The Permittee i s proposing to use a bubbling fluidized bed boiler to achieve an emission of 0.075 lb/MMBtu (24

- hr average) as MSER for CO control.

Based on review of the proposed alternatives, the Agency concurs that MSER for CO is the use of a bubbling fluidized bed boiler and a limit of 0.075 lb/MMBtu of heat input as a 24 hour rolling average.

In response to comment s regarding CO BACT in the draf t permit , the Agency instructed the Permittee to conduct additional analysis to determine the cost effectiveness of using a an oxidation catalyst for their boiler to achieve 0.0365 lb/MMBtu. The addition of an oxidative catalyst to achieve a reduction in CO from 0.075 lb/MMBtu to 0.0365 lb/MMBtu would result in a potential reduction in annual CO emissions of 74 tons. The estimated cost to add a CO catalyst is $16,800/ton of CO controlled (includes cost to install and an estimated catalyst life of 3 years, which requires an estimated cost of $1,200,000 to replace the catalyst). Based on these costs, which can be considered in an MSER determination, the Agency

determined that 0.075 lb/mmbtu still constitutes MSER for CO.North Springfield Sustainable Energy Project, LL C AP

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### Page 26 of 52 Some polluta nts, such as CO may be elevated during startup conditions, either due to less than optimum combustion during these periods, or in the case of NOx due to the SCR not functioning until normal operating temperatures are reached. The Permittee has requested

th at emission limits for startup be esta blished with the Boiler Operation and Maintenance

Plan to include proposed startup and shutdown emission limitations for NOx, CO and VOC, developed from operational emission data from stack tests and/or CEMs data colle cted during startup and shutdown periods . The Agency concurs with this request.North Springfield Sustainable Energy Project, LL C AP

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### Page 27 of 52 Table 5

- 3 : CO Emission Limits and Performance

Facility Nominal Rating Permit

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

Pioneer Renewable Energy, Greenfield, MA 47 MW Application pending Combustion Control and CO catalyst 0.114 (1 hr block) 0.07 (4 hr block) 0.0365 (12 month rolling avg) Plant has not been built.

Beaver Wood Energy

– Fair

Haven 34 MW 2/10/ 2012 Combustion Control and CO catalyst 0.075 (24

- hr avg) Plant has not been built.

Palmer Renewable Energy, Springfield, MA 38 MW 6/30/2011 Combustion Control and CO catalyst 0.114 (1 hr block) 0.07 (4 hr block) 0.0365 (12 month rolling avg) Plant has not been built.

Warren Co. Biomass Energy facility

– GA 100 MW 12/17/2010 Good design and operating practices 0.08 (30 day rolling avg) Plant has not been built.

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

. Montville Power, Uncasville, CT 42 MW 4/6/10 CO catalyst 0.10 (8 hr block) Plant has not been built. Lindale Renewable Energy, TX 50 MW 1/8/2010 Combustion control 0.31 (30 day avg) Plant has not been built. Lufkin Generating Plant, Lufkin, TX 45 MW 10/26/09 Combustion control 0.075 Started August, 2011

Russell Biomass, Russell, MA 50 MW 12/30/08 Combustion Control and CO catalyst 0.075 Plant has not been built.

Yellow Pine Energy Company

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

Koda Energy

– MN 120,000 lb/hr steam + 17.8 MW 308

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

Simpson Tacoma Kraft

– WA (Power Boiler #7) 340,000

lb/hr

steam 12/12/2011 Combustion

Controls w/ over

- fire air (OFA) 0.35 (30 day avg) 600 ppm @ 7% O2, 30 day rolling average Operating

PSNH

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

fluidized bed 0.10 (24 hr avg) Plant operating and using CEMS

to monitor CO emissions.North Springfield Sustainable Energy Project, LL C AP

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### Page 28 of 52 5.4 Boiler

- Sulfur Dioxide (SO 2 

### ) MSER Review:

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

- listed

in order of effectiveness:

1. Wet scrubber

2. Spray dryer.

3. Dry sorbent injection.

4. Use of low sulfur content fuel:

Wet scrubbers inject a water

- based solution of sodium hydroxide or calcium

- based reagent into the flue gas. The water absorbs the SO 2 

### and the reagent reacts with it to form sodium or calcium sulfate, which can be precipit ated from the spent solution and disposed of as a solid waste. Wet scrubbers are generally the technology of choice when dealing with flue gas from high

- or medium

- sulfur coal firing. They are very efficient at removing SO 2 

### when the initial driving force f or the reactions is a high SO 2 

### concentration, such as when the fuel is high

- sulfur coal or oil. Wet scrubbers are technically challenged and not cost effective when starting at a very low SO 2 

### concentration in the flue gas and so have not been applied to

wo od

- fired plants, where the fuel sulfur content is much lower than coal or residual oil. A wet scrubber is not considered to be practical or cost

- effective for the NSSEP project, and would have other environmental impacts.

A spray dryer injects a reagent

- water solution that reacts with the SO 2 

### . The water then evaporates in the heat of the flue gas, leaving behind dry particles to be removed, typically in a fabric filter. Spray dryer

- absorber systems like wet scrubbers, are not cost

- effective unless applied to relatively high concentration flue gas streams. Spray dryers (dry scrubber) are generally applied to low

- and medium

- sulfur coal and oil

- fire facilities and are not considered to be technically feasible for the NSSEP unit.

Table 5

- 4 contains a summary of SO 2 

### emissions levels for permits recently issued to

facilities with wood fired boilers. A few projects have proposed scrubber technology, including Palmer Renewable in MA, with the same short term emission rate as proposed for

NSSEP (0.02 lb/MMBtu). Palmer has not been built and had originally been proposed as a C&D wood boiler which included the dry scrubber.

Dry sorbent injection (DSI) systems add trona or sodium bicarbonate as dry particles into the flue gas. Reaction with SO 2 

### t akes place on the surface of the particle, binding the sulfur, and the particles are removed in a downstream fabric filter. DSI is less costly than wet systems as well as being better suited to lower SO 2 

### concentrations in the flue gas. For this project,

t he estimated cost of control for a DSI system using trona in 1

- ton flexible intermediate bulk containers (supersacks) is $14,700/ton of SO 2 

### controlled. If a full bulk storage and handling system is required, the cost of control nearly doubles. DSI has be en used on a few wood

fired plants when the fuel supply was found to have higher

- than

- expected sulfur content or as a precaution to accommodate fuels of varying sulfur content

. Variations in the sulfur content of wood do occur both locally and regionally depending on sulfur uptake rates from the soil in which the tree is grown. Monitoring of SO 2 

### emission at the two operating wood fired EGUs in Vermont indicates that there are very low emission rates of SO 2 

### from the combustion of wood in this region.North Springfield Sustainable Energy Project, LL C AP

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### Page 29 of 52 The Permittee is proposing that wood as a low sulfur fuel represents MSER for SO 2 

### control. In addition, the Permittee is proposing a SO 2 

### limit of 0.02 lb/MMBtu. The averaging period will depend on whether a CEMS is required by the EPA Acid Rain program.

B ased on review of the proposed alternatives, the Agency concurs that the MSER for SO 2 

### is

the use of wood as a low sulfur content fuel and a limit of 0.02 lb/MMBtu of heat input based on an hourly average.North Springfield Sustainable Energy Project, LL C AP

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### Page 30 of 52 Table 5

- 4 : SO 2 Emission Limits and Performance

Facility Nominal Rating Permit

Date SO 2 Controls SO 2 Limit (lb/MMBtu) SO 2 Emission Performance

Warren Co. Biomass Energy facility

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

Laidlaw Berlin BioPower, Berlin, NH 70 MW 7/26/10 Sorbent injection (as needed) 0.012 (stack test) Under construction

Yellow Pine Energy Company

- Fort Gaines, GA 115 MW 5/15/09 Dry scrubber
system 0. 014 (30 day avg) Plant has not been built.

Beaver Wood Energy

– Fair

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

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

Lindale Renewable Energy, TX 50 MW 1/8/2010 Low sulfur fuels 0.025 (30 day avg) Plant has not been built. Seneca Sustainable Energy, Eugene, OR 18.8

MW 10/9/09 None 0.025 Stack test completed; results were

not available at this time Montville Power, Uncasville, CT 42 MW 4/6/10 Low sulfur fuels 0.025 (3

- hr block avg) Plant has not been built. Pioneer Renewable Energy, Greenfield, MA 47 MW Application pending Low sulfur fuels 0.025 Plant has not been built.

Palmer Renewable Energy, Springfield, MA 38 MW 6/30/2011 Sorbent injection, Turbosorp scrubber 0.02 (1

- hr avg) 0.012 (annual avg) Plant has not been built.

PSNH

- Schiller Station (Unit SR5) Portsmouth, NH 50 MW 3/7/06 Dry sorbent injection 1 0 .02 Plant operat ing and using CEMS to

monitor SO 2 emissions.

1 Schiller Station is also permitted to burn coal in Unit SR5.North Springfield Sustainable Energy Project, LL C AP

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### Page 31 of 52 Diesel Engines MSER Determination:

The Facility will include a 3 MW diesel engine to provide power through emergency generators and a 450 hp diesel

- driven fire water pump. These engines are sources of NO X 

### , CO, PM, and SO 2



### .

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

accordance with 40 CFR Part 60 Subpart IIII, and a limit of 65 hours/year for maintenance and exercising o f 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 threshol ds 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 Regul ations. In July 2011, EPA deferred for a period of three years the application of permitting requirements to biogenic carbon dioxide (CO 2 

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

associated with acco unting for emission of biogenic CO 2 

### emissions.

Vermont has not amended its regulations to defer the applicability of permitting requirements for biogenic CO 2 

### emission sources such as NSSEP . However, because a carbon accounting method has not yet been dev eloped 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 so lely on direct CO 2 

### 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 car bon 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

account ing method for biogenic CO 2 

### emissions from the stationary sources is finalized

.

The Agency reserves its right to raise any issues related to the management of forest resources, and the potential impact of this or any other facility, in the context of othe r proceedings such as Act 250, Section 248, or other permitting regimes.

5.5 Boiler Greenhouse Gas MSER Review:

One of the central question s to determining BACT for GHGs for this project is whether alternative fuels as a control option would fundamentally r edefine 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 pu rpose for the proposed facility, and therefore, the permit issuer must discern which design elements are inherent to that purpose, articulatedNorth Springfield Sustainable Energy Project, LL C AP

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### Page 32 of 52 for reasons independent of air quality permitting, and which design elements may be changed to achieve pollutant emission reductions without disrupting the applicant’s basic business purpose for the proposed facility.” In re Prairie State Generating Co., 13 E.A.D. 1, 23 (EPA 2006). The crucial question to consider in determining whether a control option,

such as alte rnate 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 r e Desert Rock Energy Company, PSD Appeal No. 08

- 03 et al. at 63

- 64 (EAB Sept. 24, 2009).

The Permittee is proposing to construct a 37 MWe (net, average) biomass fuel electric generating facility in North Springfield, Vermont. The Permittee maintains that the choice of

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

and reiterated that alternative fuels would fun damentally redefine the project

. According to information supplied in connection with the Permittee’s air permit application and application for a Certificate of Public Good, the Permittee de signed and sited the facility based on the

Permittee’s conclusion that there is sufficient biomass fuel in the project area. The Permittee relies on a biomass fuel supply study for the area surrounding the facility location conducted by Innovative Natural Resource Solutions, LLC for the Permittee, along with a recent study by the Biomass Energy Resource Center (Vermont Wood Fuel Supply Study

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

available. The Agency ha s not undertaken, as part of the air permitting process, an independent analysis of the conclusions reached in the aforementioned wood supply studies, and has considered the studies for the limited purpose of addressing whether

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

The Agency finds that the Permittee ’s objective is to build a biomass f uel electric generating facility . Based on the air permit application and other statements made by the Permittee , the Agency also finds that the Permittee has “defined its ‘goal, objectives, purpose, or basic design’ for the proposed facility,” In re Desert Rock Energy Company, PSD Appeal No. 08

- 03 et al. at 65 (EAB Sept. 24, 2009), based on the Permittee ’s conclusi ons regarding the availability of biomass wood fuel. Thus, for the limited purpose of considering whether alternative fuels should be included as a control option in determining BACT/MSER, the Agency concludes that the Permittee ’s choice of fuel is integr al 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 alter nate 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 oi ls from seed crops or bio gases from digesters) to contribute significant fuel energy to a project such as the North Springfield Sustainable Energy Project

.

Step 1: Identify all Control Technologies: The alternatives identified in the permit application for the proposed wood fired Boiler

- listed in order of effectiveness:

1. Carbon capture and storage (CSS). CSS technologies are still in the development stage. CSS is promising as a CO 2 

### control technology for a source that has exhaust gases with high

- purity CO 2 

### streams.

2. Energy efficiency. The design of a traditional boiler

- steam

- turbine

- generator system loses the majority of its potential energy at two points in the system: (a) the t urbine’sNorth Springfield Sustainable Energy Project, LL C AP

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### Page 3 3 of 52 condenser via the cooling water and/or cooling air and (b) the boiler’s exhaust gases exiting the stack. Recovery of potentially lost heat energy should increase the plant’s overall energy efficiency.

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

– 90 o 

### F, and is very limited in potential for additional heat recovery. At electrical utility plants this warm water is sometimes discharged directly to a large river

in a process known as once thru cooling. However many riv ers cannot environmentally absorb this added heat and it must be cooled before discharging. For the current project, a large river is not available and the water must be cooled and reused. The current project will send the condensing steam from the steam turb ine to an air cooled condenser, then the returning water can be reused in the boiler.

b. A portion of the heat in the hot exhaust gas can be extracted by further cooling of the gases via the installation of additional heat exchangers. The current projec t includes an economizer for combustion air preheating following the SCR system for heat recovery ahead of the stack

. 3. Combined heat and power (CHP). CHP offers the advantage of extracting additional heat energy from the low grade heat (low pressure steam) and/or other waste heat that may be available from the boiler process. The basic principle of CHP is to direct some of the thermal energy to nearby thermal heating requirements (typically process heat or building heat) which are inherently more energy ef ficient than converting the thermal energy (steam) into electrical energy via a steam turbine
generator.

4. Type of fuel. Due to their chemical makeup, some fuels generate less CO 2 

### per unit of energy when they are combusted. As noted above, fuel switching w ould redefine this source and is not part of the MSER review.

5. Good operating and maintenance practices. This is an extension of energy efficiency; make sure that the equipment is operating at peak performance to help ensure that the overall system effic iency 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 co ndensate leaks. In addition, covering the main wood fuel pile will serve to minimize rain infiltration into the stored wood.

Step 2: Eliminate Technically Infeasible Options:

1. CSS: At this time, CSS technologies have not been developed for capturing CO 2 

### in the dilute exhaust gases being emitted from biomass combustion. Therefore, CSS, is not technically feasible for this project. In addition, there can be a significant energy penalty in moving this gas stream under high pressure to the underground geo logical formations for sequestration.

2. Energy efficiency is technically feasible, within limits. The recovery of waste heat from the boilers exhaust gases is limited due to the potential of condensing the moisture in the gases which can adversely affect the condition of the exhaust handling equipment if it is not designed for this potential corrosive environment. In addition, cooler exhaust gases have worse dispersion characteristics after exiting the exhaust stack. The Permittee’s boiler design includes a n economizer after the SCR which reduces the exhaust gas temperature to the range of 250

– 310 o 

### F.North Springfield Sustainable Energy Project, LL C AP

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### Page 34 of 52 3. CHP is technically feasible. The Permittee has stated their intent to utilize low pressure steam, from an extraction point off the turbine, to produce warm water which will be used as a thermal heat loop for other businesses in the industrial park.

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

Step 3: Rank Remaining Control Technologies by Control Effecti veness:

1. Energy efficiency

2. CHP

– through the recovery of low grade heat to produce hot water for a thermal loop in the North Springfield Industrial Park. The applicant has indicated that there is an anticipated heat demand from the existing industrial park buildings for up to 20,000 lb/hr of low pressure steam. The annual average heat demand is estimated to be 4,000 lb/hr.

3. Good operating and maintenance practices does not reduce GHG emissions, but it does help ensure that the facility continues to oper ate as designed. Steps 4 & 5 are combined since the Facilit y will be using all three of the control technologies identified in Step s 1 through 3.

T he Agency has determined that MSER for GHGs is implementing energy efficiency , a thermal loop to provide he at to businesses in the industrial park, and good operating and maintenance practices for GHG control . In addition, a CO 2 

### e emission limit has been

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

, an electrical output of 3 6

. 7 2 MW

, an average annual ou tput of the thermal loop of 4 MMBtu/hr and a plant long term performance heat rate ”degradation” of 3%. In spite of good operating and maintenance practices, it is expected that there will be some loss of performance over

time. The plant ’s heat rate degradation is estimated to have a long term average of 0.15%/yr; the value of 3% is based on 20 years of operation. The CO 2 

### e emission limit is
2,675 lb CO 2 

### e / MW

- hr net electrical and heat output based on a 12 month rolling average

.

The applicant will be allowed to phase in the implementation of the heat loop to the industrial park. For the first 2 years of the operation of the boiler, the CO 2 

### e emission limit will not be based on the operation o f the heat loop, and will be 2,668 lb CO 2 

### e / MW

- hr net electrical output based on a 12

- month rolling average. This limit does not include any energy sent to the thermal loop and does not include the 3% heat rate degradation.

Starting with the 3 rd 

### year of operation, the CO 2 

### e emission limi t will b e 2,675 lb CO 2 

### e / MW

- hr

net electrical and heat output based on a 12

- month rolling average.North Springfield Sustainable Energy Project, LL C AP

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### Page 35 of 52 5.6 Diesel Engine Greenhouse Gas MSER Review:

The Agency is not aware of any technologies that have been designed to reduce the GHG emissions from diesel po wered 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 em ission rate of the pollutant per unit of energy output, engine manufactures have employed a combination of reducing the mass emission rate of the pollutant(s) and increasing the overall efficiency of the engines. Thus the use of a Tier certified engine wi ll help ensure the use of highest energy efficient diesel engine(s) available.

The Agency has determined MSER for GHGs f rom the emergency diesel engine will be met through the use of new engines that are Tier certified in accordance with 40 CFR Part 60

Su bpart IIII.

6.0 AMBIENT AIR QUALITY IMPACT ANALYSIS

An ambient air quality impact evaluation is performed to demonstrate whether or not a proposed project will cause or contribute to violations of the ambient air quality standards and/or significantly deteriorate existing air quality. The Agency's implementation procedures concerning the need for an ambient air quality impact evaluation under §5

- 406(1) of the Regulations, specifies that such analyses may be required when a project results in an

allowabl e 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 20 06

– 2010 which were recently developed

usin g the 1 minute ASOS data. The surface met data was from the Springfield (Hartness) Airport, and the upper air data was from Albany, NY.

Since the issuance of the draft permit on 8/9/2012 , a n updated review, un related to the air permit, of the proposed stack height relative to the location of the Hartness Airport runway

indicated that the stack was just tall enough that it exceeded a FAA criteria so a further study would be required. The project decided to lowe r both the base elevation for the main boiler building and the stack base by 1 foot. This brought the stack tip below the FAA criteria. To confirm that this change would not affect the previous modeling analysis, changes were made to the model inputs to reflect the new elevation of both the stack and the main boiler building and

the model was re

- run. The results showed that most of the modeled concentrations remained unchanged while a few changes by a small amont (less than 1%) . The tables in this sect ion have been updated, as needed with the new data. There are no changes in the Agencies

review and conclusions.

The Permittee conducted modeling for several operating load scenarios for the boiler as well as a startup scenario for the boiler. This is n ecessary since full load operation does not necessarily correspond to the highest emission rate or worst dispersion. In some cases, lower operatingNorth Springfield Sustainable Energy Project, LL C AP

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### Page 36 of 52 loads can result in higher ambient impacts due to either higher emission rate concentrations (even though l ower mass) or lower temperature or velocity of the exhaust. The startup scenario modeling was for short term emission (less than 24

- hour standards) for CO (1

- hr) and SO 2 

### (1

- hr

and 3

- hr). Table 6

- 1 summarizes the operating loads and emission rates for the operating

scenarios that were modeled.

Table 6

- 1: Operating Load Scenarios

% Load/

Fuel

Moisture Heat Input (MMBtu/hr) Gas Flow (ACFM) Stack

Gas Exit Velocity (ft/sec)

(m/s) Stack Gas

Exit Temperature (°F) ( o K) NOx

Emission

Rate (lb/hr) (g/s) SO 2 Emission

Rate (lb/hr) (g/s) PM10/2.5 1

Emission

Rate (lb/hr) (g/s) CO

Emission

Rate (lb/hr) (g/s)

100/55 502 190,956 63.32

19.3 310

427 30.12

3.795 10.04

1.265 9.538

1.202 37.65

4.744

100/45 464 161,555 53.57

16.3 300

422 27.84

3.508 9.28

1.169 8.816

1.111 34.80

4.385

75/45 344 114,795 38.06

11.6 270

405 20.64

2.601 6.88

0.864 6.536

0.824 25.80

3.251

60/35 262 88,141 29.23

8.9 250

394 15.72

1.981 5.24

0.660 4.978

0.627 19.65

2.476

Cold start 40 13,000 4.3

1.3 250

394 N /A 0.6

0.0076 N/A 60

7.56

Emission rates are “short term.” Annual NOx emission rate is half the maximum 100%/45% hourly rate. Although other loads will not normally operate on an annual average basis (13.92 lb/hr), maximum short term emission rates were conservatively used for ann ual average impacts.

1 The PM emission is assumed to all be fine enough to be characterized as PM 2.5 . This PM emission therefore also
represents PM 10

.



### 6.2 NAAQS Analysis

Based on the above scenarios, the emissions from the facility were modeled to establish the significant impact area (SIA). The SIA is based on the distance from the facility to the maximum point at which predicted impacts fall below the Significant Impact Level (SIL). The SIA is a circle around the facility with a radius equal to this distance. If there are no predicted impacts greater than the SIL for a pollutant then there is no SIA and interactive modeling is not necessary.

Table 6

- 2 shows that the emissions for PM 2.5 

### , NO X 

### , and SO 2 

### 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.North Springfield Sustainable Energy Project, LL C AP

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### Page 37 of 52 Table 6

- 2 : Distance to Significan t Impact Level (km)

Pollutant Averaging

Time Significant Impact Levels (μg/m 3 ) Distance (km) from project Load

Case

PM 10 24

- hour 5 0.1 60/35

Annual 1 1 No impacts > SIL N/A

PM 2.5 24

- hour 2,4 1.2 7.0 60/35

Annual 2,4 0.3 2.25 100/45

SO 2 1

- hour 2,3 7.8 15.1 100/55

3

- hour 25 No impacts > SIL N/A

24

- hour 5 0.1 60/35

Annual 1 No impacts > SIL N/A

NO 2 1

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

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

CO 1

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

8

- hour 500 No impacts > SIL N/A

1 Note that effective 12/28/2006, the EPA revoked the PM 10 annual NAAQS standard. However, up until May 2011, in certain cases, the EPA allowed a PM 10 surrogate policy that allowed a project to demonstrate compliance with the PM 10 annual NAAQS as a means t o also demonstrate compliance with the PM 2.5 annual NAAQS. This permit demonstrated compliance with the PM 2.5 annual NAAQS and did not propose to use

the PM 10 surrogate policy. Since the application for this permit included information on the PM 10 annual NAAQS, we are including this information in this document.

2 Averaged over 5 years per applicable EPA guidance.

3 High 1st High maximum daily 1

- hr concentration averaged over 5 years.

4 High 1st High (100%) maximum concentration averaged over 5 years.

5 N O 2 uses ARM values for NO X to NO 2 conversion (0.75 for Annual, 0.8 for 1

- hour).

6 Annual NO 2 emissions based on guaranteed rates. Hourly NO 2 emissions represent maximum emissions.

Conservative for reduced load conditions.



### For the pollutants/averaging times with predicted impacts below their respective SIL, the monitored background concentrations were added to the appropriate modeled concentrations for a comparison with the NAAQS. Table 6

- 3 summarized this NAAQS review. Si nce there are no nearby sources of PM 10 

### or PM 2.5 

### that will require cumulative source modeling these pollutants

are included in this review. Table 6

- 3 shows that for the list pollutants there are no predicted
exceedances of the NAAQS.North Springfield Sustainable Energy Project, LL C AP

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### Page 38 of 52 T able 6

- 3 : NAAQS R eview Predicted Impact Concentrations for Pollutants Not Requiring Cumulative Source Modeling

Pollutant Averaging

Time 1 Operating

Load

Scenario 2 Modeled

Conc. (μg/m 3 ) Background (μg/m 3 ) Total Impact (μg/m 3 ) NAAQS (μg/m 3 )

PM 10 24

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

Annual (H) 100/55 0.55 13.3 13.9 50

PM 2.5 24

- hr 4 60/35 4.44 19.1 23.5 35

Annual 5 100/45 0.51 7.8 8.3 15

SO 2 3

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

Annual (H) 100/55 0.58 7.6 8.2 80

NO 2 3 Annual (H) 60/35 0.90 16.4 17.3 100

CO 1

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

8

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

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

2 100/55 = 100% load / 55% moisture; 100/45 = 100% load / 45% moisture; 60/35 = 60% load / 35% moisture.

3 For annual NO 2 modeling, used ambient ratio method of 0.75 for NO/ NO 2 conversion.

4 High 1st High (100%) maximum concentration averaged over 5 yea rs.

5 Averaged over 5 years per applicable EPA guidance.



### The Agency used the following criteria to determine if the emissions from a nearby source would need to be included in the interactive modeling for this Facility:

1. Each pollutant for which a SIA has been identified, shall include the following class of nearby sources in the interactive modeling:

a. Nearby sources located within the SIA with actual emissions greater than the following significant emission rates:

i. CO: 50 tons/yr

ii. NOx: 40 tons/yr

iii. SO2: 40 tons/yr

iv. PM10: 15 tons/yr

v. PM2.5: 10 tons/yr

b. Nearby sources located within 20 km of the wood boiler stack that have actual emissions greater than 50 tons/yr.

c. Nearby sources located within 50 km of the wood boiler stack that

have actual emissions greater than 500 tons/yr.

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

NO X 

### and SO 2 

### for the following two sources: APC Paper and Wheelabrator, both located in Claremont, NH. There were no nearby sources of PM 2.5 

### or PM 10 

### t hat met the criteria

noted above. The stack and emissions data for APC Paper and Wheelabrator were supplied by the NHDES and are summarized in Table 6

- 4.North Springfield Sustainable Energy Project, LL C AP

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### Page 39 of 52 Table 6

- 4: Cumulative Source Stack and Emissions Data

Source UTM E (m) UTM N (m) Stack

Base

Elev. (m) Stack Height

(m) Stack

Gas Temp.

(K) Stack

Gas Velocity

(m/s) Stack

Diam.

(m) Short

Term

SO 2 (g/s) Short

Term

NO X (g/s)

APC Paper 714956 4805760 137.8 38.1 493 7.67 1.37 13.056 3.049

Wheelabrator

Claremont 712571 4802400 164.6 45.7 421 24.62 0.79 1.991 5.756



### The emissions from the proposed Facility (for the 4 operating load scenarios listed in

Table 6

- 1) along with the emissions from the two facilities noted above were modeled to predict the maximum impacts to determine if there were any predicted NAAQS violations

for the 1

- hr NO 2 

### , 1

- hr SO 2 

### and 3

- hr SO 2 

### NAAQS.

Table 6

- 5 summarizes the results of the cumulative source modeling results. For the 24

- hr SO 2 

### NAAQS there were no predicted violations. For both the 1

- hr NO 2 

### and 1

- hr SO 2 

### ther e are predicted violations of the NAAQS.

The NSSEP ‘contribution’ shown in Table 6

- 5 of the draft permit has been updated

. Table 6

- 5, shown below has the updated values which are higher than those shown in the draft permit, but still below the SILs. The data in the draft permit showed the Facility’s contribution that coincided with the form of the standard (4 th 

### high for SO 2 

### and

8 th 

### high for NO 2 

### ).Further review of the data showed that a higher contribution from the Facility could and did occur at other, lower overall cumulativeconcentrations that were over the NAAQS. The highest contribution for any modeled exceedance is shown in the updated tab le.North Springfield Sustainable Energy Project, LL C AP

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### Page 40 of 52 Table 6

- 5: Cumulative Source Modeling Results

Pollutant

/ Avg

Time Load %/

Moisture % Overall

Cumulative

Concentration (μg/m3) NAAQS (μg/m 3 ) Number of Receptors Exceeding

NAAQS NSSEP

Contribution

(μg/m3) 1 Significant Impact Levels (μg/m 3 )

NO 2 2

1

- hour 100%/55% 24 6

188 12 2.63

7.5 100%/45% 24 6 12 3.19

75%/45% 24 6 12 4.06

60%/35% 24 6 12 3.56

SO 2 1

- hour 100%/55% 805

195 263 0.06

7.8 100%/45% 805 263 0.07

75%/45% 805 263 0.09

60%/35% 805 263 0.11

SO 2 24

- hour 100%/55% 149.3

365 0

N/A 3 N/A 3 100%/45% 149.3 0

75%/45% 149.3 0

60%/35% 149.3 0

1 Highest contribution from NSSEP for the affected receptors to any modeled exceedance

. 2 NO 2 1

- hour SIL = 7.5 μg/m3. Uses 0.8 for modeled 1

- hour ARM for NOx to NO 2 conversion.

3 N/A

– Since below NAAQS, no further analysis is required.



### To determine if the Facility’s emissions cause or contribute to a violation of the 1

- hour

NO 2 

### or SO 2 

### NAAQS, it is necessary to identify the Facility’s contribution to impacts at the receptors that have a total impact that is greater than the NAAQS.

There were 263 receptors with combined source 1

- hour SO 2 

### impacts greater than the NAAQS. The Facility’s maximum contribution to the impacts at any of these receptors

was 0.11 μg/m 3 

### which is below the SIL of 7.8 μg/m 3 

### . This demonstrates that the Facility does not cause or contribute to any violation of the 1

- hour SO 2 

### NAAQS.

There were 12 receptors with com bined source 1

- hour NO 2 

### impacts greater than the NAAQS. The Facility’s maximum contribution to the impacts a t any of these receptors

was 4.06 μg/m 3 

### which is below the SIL of 7.5 μg/m 3 

### . This demonstrates that the Facility

does not cause or contribute to a ny violation of the 1

- hour NO 2 

### NAAQS.

Start

- up scenario: During the first few hours of a cold startup, the cold equipment, fuel transitions and a very low operating rate contribute to low flow rates and temperatures of the exhaust gases and subsequently r educed dispersion from the exhaust gas. This can result in

elevated higher pollutant impacts during cold startup conditions. Since cold startups are expected to occur infrequently, long er term averaging time s were not evaluated.

The Permittee modeled th e estimated emission of CO (1

- hr) and SO 2 

### (1

- hr and 3

- hr) from a cold startup scenario. The emission rates are shown in Table 6

- 1. For SO 2 

### theNorth Springfield Sustainable Energy Project, LL C AP

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### Page 41 of 52 emission rate during the first few hours of a cold startup are lower due to the use of ULSD fuel. The modeled impacts for both the 1

- hr and 3

- hr SO 2 

### were well below their respective SILs and NAAQS. During the cold startup, the emission rate of CO (in ter ms of lb/MMBtu) is much higher compared with steady state/full load operation. This higher

emission rate was modeled and demonstrated that the modeled 1

- hr CO impacts were
below both the SIL and the NAAQS. These results are summarized in Table 6

- 6.

Tabl e 6

- 6: Modeling Startup Conditions

Pollutant Averaging

Time Modeled

Conc. (μg/m 3 ) SIL

(μg/m 3 ) Background (μg/m 3 ) Total Impact (μg/m 3 ) NAAQS (μg/m 3 )

SO 2 1

- hour 0.62 7.8 70.7 71.3 195

3

- hour (H2H) 0.51 25 73.3 73.8 1,300

CO 1

- hour (H2H) 745 2000 3,435 4180 40,000



### The results of this refined modeling , shown in Section 6.2 above, demonstrate that the Facility will not cause or contribute to a violation of the NAAQS.

6.3 Prevention of Significant Deterioration (PSD) Increment Analysis

Major new sources of air pollution must demonstrate that the proposed project will not significantly deteriorate the existing air quality in regions that have been established as being in attainment of federal air quality standards. All of Vermont has bee n 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 val ue. 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

ge ographical 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 sour ce. 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 s ources that consume increment fo r NO 2 

### , SO 2, 

### PM 2.5 

### , or PM 10



### .North Springfield Sustainable Energy Project, LL C AP

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### Page 42 of 52 Table 6

- 7 summarizes the results of the predicted PSD increment impacts. The maximum predicted impacts for both Class I and Class II areas are less than the

available increment.

Table 6

- 7 : PSD Increment Impacts

Pollutant Averaging

Time Max Impact (μg/m 3 ) PSD Increment Standard (μg/m 3 ) Available

Increment in Vermont (μg/m 3 ) 1

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

PM 10 24

- hour 0.12 3.8 8 30 6 22.5

Annual 0.016 0.55 4 17 1 4.25

PM 2.5 24

- hour 0.15 4.4 2 9 1.5 6.75

Annual 0.014 0.51 1 4 0.25 1

SO 2 3

- hour 0.79 17.1 25 512 18.76 384

24

- hour 0.14 5.8 5 91 3.75 68.25

Annual 0.017 0.58 2 20 0.5 5

NO 2 Annual 0.018 0.90 2.5 25 0.625 6.25

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

the short term increment.



### 6.4 Class I Air Quality Related Values Analyses

For facilities that are further than 50 km from a Class 1 Area, t he Federal Land Managers Air Quality Related Values (AQRV) Workgroup (FLAG) has established a method to screen out from AQRV review those sources with relatively small amounts of emissions and/or located a large distance from a Class I area (a.k.a. Q/d)

. However, the Facility is located within 50 km dista nce of the Lye Brook Wilderness, so the Permittee must evaluate the air pollution effects from their proposed project on the AQRVs for the impacted Class 1 area.

6.4.1 Class I Area Air Quality Impact Modeling

New sources must demonstrate compliance with all National Ambient Air Quality Standards as well as demonstrate that there will not be any exceedances of any PSD Increments. As discussed in Section 6.2 of this document, the predicted impacts from this proj ect will not exceed any NAAQS; this includes the Lye Brook Wilderness Area. As shown in Section 6.3, the air quality impacts were predicted for the Lye Brook Wilderness Area and compared to the PSD increments: the impacts were below the available increme nts. Any growth associated with this project is not expected to result in secondary emissions which need to be
included in the NAAQS review or the PSD increment review.North Springfield Sustainable Energy Project, LL C AP

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### Page 43 of 52 6.4.2 Visibility Impairment

The visibility regulations for new source review (40 CFR §51.30 7 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 wit h the management, protection, preservation, or enjoyment of a visitor’s visual experience of the Class I area. The Permittee conducted a Level 1 Screening Procedure as outlined in EPA’s Workbook for Plume Visual Impact Screening and Analysis using EPA’s V ISCREEN model (Version 1.01 dated 88341). VISCREEN is used to calculate the potential visual impact of a plume of emissions for specific transport and meteorological conditions. Based on the results of this Level 1 Screening Procedure using VISCREEN, the proposed Facility’s plume will not cause adverse visual impacts inside the Lye Brook Class

I area.

Table 6

- 8 : Class I Visibility Modeling Results Maximum Visual Impacts Inside the Class I Area

Delta

- E Absolute Contrast

Background Theta (°) Azimuth (°) Distance (km) Alpha (°) Screening

Criteria Plume Screening

Criteria Plume

SKY 10 135 52.7 34 2.00 0.891 0.05 0.014

SKY 140 135 52.7 34 2.00 0.431 0.05

- 0.009

TERRAIN 10 84 41.4 84 2.00 1.957 0.05 0.015

TERRAIN 140 84 41.4 84 2.00 0.145 0.05 0.002



### 6.4.3 Class I Area

- Deposition Analysis

The Permittee performed a modeling analysis to estimate the deposition of total nitrogen and total sulfur to the Lye Brook Wilderness Area. AERMOD was selected to perform this deposition modeling. The gaseous and particulate deposition rates were modeled separately, and the results summed at each receptor to obtain total deposition. Both wet and dry deposition was evaluated. The average annual emissions rates were adjusted to represent only the sulfur or

nitr ogen (versus SO 2 

### or NO

x 

### ) emitted.

The summed gaseous and particle deposition results are compared to the Deposition Analysis Threshold (DAT) of 0.010 kg/ha

- yr (0.001 g/m 2



### - yr) for nitrogen and 0.010 kg/ ha

- yr (0.001 g/m 2



### - yr) for sulfur

.

The maximum pred icted total sulfur deposition from the proposed facility (100% load/55% moisture) at any Lye Brook Wilderness Area receptor is 2.20x10
- 4 

### g/m 2



### - yr or 22% of the DAT.

The maximum predicted total nitrogen deposition from the proposed facility (75%

load/45% mo isture) at any Lye Brook Wilderness Area receptor is 1.77x10 - 4 

### g/m 2



### - yr or 18% of the DAT.North Springfield Sustainable Energy Project, LL C AP

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### Page 44 of 52 6.5 Additional Impact Analysis

As required by federal PSD regulations, 40 CFR 52.21(o), the Permittee included in the permit application additional impact analysis of: (a) the impairment to visibility, soils and vegetation that would occur as a result of the new major source and general, commercial, residential, industrial, and ot her 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 commer cial, residential, industrial, and other growth associated with the facility.

Vermont’s State Implementation Plan

, states that impacts on vegetation, soils and an

ass essment 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 throug h emissions to the ambient air. When the SIP was written, it was assumed that all development in Vermont would be required to obtain an Act 250 Land Use Permit. Since the Facility under review

is an energy facility, it is required to just obtain approval through Act 248. For this project, the Air Pollution Control Division will perform the review to ensure that the project will not cause the impairment of visibili ty, soils and vegetation due to the direct

effects of the facility or due to secondary growth associated with the construction of this new source of air pollution.

6.5.1 Growth Analysis

The peak construction work force is estimated to be 125 persons. The facility expects to employ a staff of 20

- 30 employees for plant operations.

It is expected that a significant construction force is available and is supported by

the fact that within N ew England, significant construction activities have already occurred (including construction of a number of existing power projects). Therefore, it is expected that because this area can support the Project’s construction from within the region, new hous ing, commercial and industrial construction will not be necessary to support the Project during the building period.

For any new personnel moving to the area as a permanent employee to support the Project operations once constructed, a significant housing market is already established and available. Therefore, no new housing is expected. Further, due to the small number of new individuals expected to move into the area to support the Project and the significant level of existing commercial activity in th e area, new commercial construction is not foreseen to be necessary to support the Project’s permanent work force. In addition, no significant level of industrial related support will be necessary for the Project, thus industrial growth is not expected. No new significant emissions from secondary growth during either operations, or the construction phase, are anticipated.North Springfield Sustainable Energy Project, LL C AP

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### Page 45 of 52 6.5.2 Ambient Air Quality

New sources must demonstrate compliance with all National Ambient Air Quality Standards as well as demonstrate that there will not be any exceedances of any PSD Increments. As discussed in Section 6.2 of this document, the predicted impacts from this proj ect will not exceed any NAAQS. As shown in Section 6.3, the air quality impacts were predicted for the Lye Brook Wilderness Area and compared to the PSD increments: the impacts were below the available increments. As noted in Section 6.5.1, there are no new significant emissions expected from secondary growth associated with this project, so NAAQS review and the PSD increment review adequately reflect the potential impacts from this proposed facility.

6.5.3 Effects on Soils, Vegetation, and Secondary Impact A nalysis

New major sources and major modifications are required to evaluate the effects of their air pollution emissions on soils and vegetation in the impact area. Any permit application for such a project is expected to provide a characterization of

the soils and vegetation in the impact area and an evaluation of any adverse economic and ecological effects from the ambient concentration projected by the air quality modeling.

Evaluation of impacts on sensitive vegetation was performed by comparison of

pr edicted project impacts with screening levels presented in A Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils and Animals (EPA, 1980). The assessment was performed by adding the Facility impacts with ambient background concent rations and comparing the total to vegetation sensitivity screening levels p resented in Table 3.1 of EPA’s screening p rocedure.

The screening levels represent the minimum screening levels at which visible damage or growth effects to vegetation may occur. Screening levels have been established for the following pollutants that will be emitted from the Facility:

• 1

- hour, 3

- hour and annual SO2,

• 4

- hour, 8

- hour, monthly and annual NO2,

• Weekly CO,

• Monthly beryllium, and

• Quarterly lead.North Springfield Sustainable Energy Project, LL C AP

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### Page 46 of 52 The same background co ncentrations were used for NO 2 

### , SO 2 

### , and CO as shown in Table 6

- 3 above. The closest b eryllium background values are available from the Underhill, VT monitoring station. There are monitors near Lye

Brook and in Underhill and Burlington Vermont that provide data for lead in PM 2.5



### . Burlington will be used to represent the background value for this project. In addition, data is not presented for all averaging periods being examined. In those cases, the next shortest averaging period was used to conservatively estimate background.

Table 6

- 9 presents the results of the vegetative impact analysis. The modeled concentrations from the Facility, in combination with representative background values, are less than the vegetation sensitivity concentrations. Therefore, the air pollution emissions f rom F acility will not adversely impact vegetation in the area.North Springfield Sustainable Energy Project, LL C AP

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### Page 47 of 52 Table 6

- 9 : Vegetative Impact from Criteria Pollutants

Pollutant Averaging

Time Maximum

Modeled

Concentration (μg/m 3 ) Background

Concentration (1)

(μg/m 3 ) Total (μg/m 3 ) Intermediate Vegetation Sensitivity

Concentration (μg/m 3 ) Resistant Vegetation Sensitivity

Concentration (μg/m 3 ) Sensitive Vegetation Sensitivity

Concentration (μg/m 3 ) Load %/

Moisture

% Case

SO 2 1 HOUR 31.4 70.7 102.1

- - 917.0 100%/45%

3 HOUR 17.1 73.3 90.4 2096.0 13100.0 786.0 100%/45%

ANNUAL 0.6 7.6 8.2 18.0 18.0 18.0 100%/55%

CO WEEKLY (5) 21.6 1832.0 1853.6

- 18000000.0 1800000.0 60%/35%

NO 2 (6) 4 HOUR (4) 41.1 77.1 118.2 9400.0 16920.0 3760.0 100%/45%

8 HOUR 23.3 77.1 100.4 7520.0 15040.0 3760.0 100%/55%

MONTHLY (5) 13.8 77.1 90.9 564.0 564.0 564.0 60%/35%

ANNUAL (7) 0.9 16.4 17.3 94.0 94.0 94.0 60%/35%

BERYLLIUM MONTHLY 0.001 0.0000058 0.001 0.01 0.01 0.01 60%/35%

LEAD QUARTERLY 0.026 0.0042 0.030 1.5 1.5 1.5 60%/35%

1 From VTDES (SO 2 , CO & NO 2 ) and AIRData Website (Lead)

2 Background was conservatively estimated for: Use of 1

- hour values for 4

- hour, 8

- hour and monthly NO 2 , and u se of 8

- hour CO values for weekly CO.

3 High Second High values used for all short term averages. High values used for annual.

4 4

- hour value conservatively based on modeled 3

- hour value.

5 Weekly, Monthly, and Quarterly modeled concentration averages conservatively based on modeled 24

- hour average

. 6 NO 2 uses ARM values for NO X to NO 2 conversion (0. 75 for Annual ; , 0. 8 for 4

- hour

, 8

- hour & Monthly).

7 Annual NO 2 emissions based on guaranteed rates. Hourly NO 2 emissions represent maximum emissions (100%/45%)

.North Springfield Sustainable Energy Project, LL C AP

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### Page 48 of 52 The EPA screening procedure also contain s threshold levels for several

elements to assess the impacts of trace element deposition to soil. Table 3.4 in the screening procedure lists the screening level for the concentration of the listed elements in the soil. The procedure also shows how to estimate the element deposition concentration in the impacted soils based on the annual average concentration of the pollutant.

Equation 5.1: DC (ppmw) = 21.5 * (N/D) * X

Where:

DC = deposited concentration (ppmw), N = expected lifetime of source (yr), D = depth of soil through which deposited material is distributed (cm), and X = maximum annual average ambient concentration from the source (μg/m 3 

### ).

The procedure recommends using a value of 40 years for the expected lifetime of the source (N), and a soil depth of 3 cm (d).

The maximum annual average ambient concentration can be estimated by using the results of the NAAQS modeling. For an emission rate of 1 gram/second, the modeled maximum annual average ambient concentration is 0.4538 μg/m 3


### (100%/55% load scenario). Table 3

- 5 of this document has the emission factors and mass emission rate for these listed elements. By multiplying the element’s estimated emission rate (in terms of g/s), and multiplying by the normalized modeling impact (0.4538 μg/m 3 

### / 1 g/s) yields a calcul ated maximum annual

concentration for the element.

Table 6

- 10 summarizes the potential deposition concentrations for the listed elements along with their respective screening levels. Emission factors for boron and fluoride were not available for wood, ho wever because only natural (untreated) wood is permitted as the main fuel for this facility, there are not expected to be significant emissions of either of these elements. Therefore the air pollution emissions from the Facility will not adversely affect s oil quality.North Springfield Sustainable Energy Project, LL C AP

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### Page 49 of 52 Table 6

- 10 : Trace Element Emission Assessment

Element Potential

Emissions (Tons per

Year) 1 Estimated

emission rate (g/s) Estimated

Maximum

Annual

Concentration (μg/m 3 ) Estimated Soil

Concentration from Deposition

DC (ppmw) Screening

Level 2

(ppmw)

Arsenic 0.008 2.34E

- 04 1.06E

- 04 0.030 3

Boron N/A 0.5

Cadmium 0.008 2.40E

- 04 1.09E

- 04 0.031 2.5

Chromium 0.043 1.23E

- 03 5.58E

- 04 0.160 8.4

Copper 0.100 2.87E

- 03 1.30E

- 03 0.373 40

Fluoride N/A 400

Lead 0.098 2.81E

- 03 1.27E

- 03 0.365 1000

Manganese 0.175 5.03E

- 03 2.28E

- 03 0.655 2.5

Mercury 0.007 2.05E

- 04 9.29E

- 05 0.027 455

Nickel 0.067 1.93E

- 03 8.76E

- 04 0.251 500

Selenium 0.006 1.76E

- 04 7.97E

- 05 0.023 13

Vanadium 0.002 5.73E

- 05 2.60E

- 05 0.007 2.5

1 Based on maximum potential emissions.

2 Table 3.4 lists the screening level of the concentration of the element in the soil

- A Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils and

Animals (EPA, 1980).



### 6.5.4 Visibility Analysis

§5

- 502(4)(d) of the Regulations requires the evaluation of major sources and major modifications to demonstrate that the increase in allowable emissions will not cause an adverse impact on visibility in any sensitive area. The Regulations

further define s ensitive area as any portion of the area comprising Lye Brook

Wilderness Area and all other terrain in Vermont at or above the elevation of

2500 feet above mean sea level. Section 6.4.2 of this document contains the review of visibility impairment for the Lye Brook Wilderness Area.

The nearest sensitive area to the Facility is Mount Ascutney located in Ascutney State Park. To help establish if the proposed Facility will cause an adverse impact on the visibility from the summit of Mount Ascutney, a Leve l 1 screening analysis using VISCREEN was conducted, and the results exceeded the screening criteria. Subsequently a Level 2 screening analysis was conducted. Since there is complex terrain between the Facility and Mount Ascutney containing some terrain features that are higher in elevation than the plume height, the atmospheric stability class was selected as ‘E’ instead of ‘F’ to represent that there will be some disruption of the plume. The model was run using two different wind speeds to help determi ne the worst case impacts. Table

6

- 11 has a summary of the results for the Level 2 screening. Based on the results of the Level 2 screening, the Facility will not cause an adverse impact andNorth Springfield Sustainable Energy Project, LL C AP

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### Page 50 of 52 further analysis is not required.

Table 6

- 11 : Sensitive Area Visibility Modeling Results

Maximum Visual Impacts Inside the Sensitive Area

Delta

- E Absolute Contrast

Background Theta (°) Azimuth (°) Distance (km) Alpha (°) Screening

Criteria Plume Screening

Criteria Plume

SKY 10 46 12.3 123 2.00 0.697 0.05

- 0.00 4

SKY 140 46 12.3 123 2.00 0.295 0.05

- 0.000

TERRAIN 10 46 12.3 123 2.00 0.442 0.05 0.002

TERRAIN 140 46 12.3 123 2.00 0.1 59 0.05 0.004



### M aximum Visual Impacts Outside the Sensitive Area

SKY 10 1 1.0 168 2.00 1.280 0.05

- 0.016

SKY 140 1 1.0 168 2.00 0.753 0.05 0.004

TERRAIN 10 1 1.0 168 2.00 1.827 0.05 0.021

TERRAIN 140 1 1.0 168 2.00 0.673 0.05 0.0 2 5



### 7.0 HAZARDOUS AIR CONTAM INANTS

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

reg ulations 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/Opera tor 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 the n demonstrate that the emissions of the HAC are minimized to the greatest extent practicable by achieving the Hazardous Most Stringent Emission Rate (“HMSER”) for that HAC.

As shown in Section 3.2, the facility is expected to exceed the action level of 35 different

HACs and is therefore subject to §5

- 261.

For the HMSER review, the HACs are divided up into several categories based on their emission control characteristics: (1) non

- mercury metallic HACs; (2) organic HACs; (3) acid gases; (4) ammonia; and (5) CDD/CDF.North Springfield Sustainable Energy Project, LL C AP

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### Page 51 of 52 7.1. HMSER Selection

– non

- mercury metallic HACs

The non

- mercury metallic HACs that are estimated to exceed their respective action level

include: arsenic, barium, beryllium, cadmium, chromium (total), chromium (hexavalent), cobalt, copper ( dusts & mists), iron oxides (dusts & fumes), lead compounds, manganese, nickel compounds, vanadium pentoxide and zinc oxide

.

Non

- mercury metallic HACs are a component of the PM contained in the fly ash from the

boiler. The choice of control devices for non

- mercury metallic HACs is the same as those

for fine PM.

The Agency is establishing HMSER for non

- mercury metallic HACs from the Boiler as the use of a fabric filter control device and a filterable PM emission limit of 0.010 lb/MMBtu (1

hour block average). The single filterable PM emission limit is serving as a surrogate for separate emission limits for each of these numerous non

- mercury metallic HACs from the

boiler.

7.2. HMSER Selection

– organic HACs

The Facility’s organic HAC emissions that are estimated to exceed their respective action level include: 1,2

- dichloroethane (ethylene dichloride), 1,2

- dichloropropane (propylene dichloride), acetaldehyde, acrolein, benzene, benzo(a)pyrene, bromodichloromethane, chloroform, dichloromethane (methylene chloride), dinitrotoluene

- 2,4, formaldehyde, hexachlorobenzene, naphthalene, tetrachloroethylene (perchloroethylene), trichloroethylene, and vinyl chloride.

These organic emissions are formed by incomplete combustion of fuel. The methods for

control of organic HACs from the Boiler would be the same as for the control of VOCs. Thus total VOC emissions or CO can reasonable serve as a surrogate to demonstrate adequate control of the individual organic HACs.

HMSER for organic HACs is good combustion control and the use of a BFB, and a CO emission limit of 0.075 lb/MMBtu (24 hour rolling average), and a VOC emission limit of 0.005 lb/MMBtu (hourly average).

7.3. Acid Gases

Sulfuric acid mist

, hydrogen chloride and chlorine are estimated to exceed their re spective

action level.

Sulfur that is present in fuels is converted during combustion to SO 2 

### and to a lesser degree

SO 3 

### . The SO 3 

### rapidly reacts with the water vapor in the exhaust gases to form H 2 

### SO 4 

### (sulfuric acid mist). Some of the chlorine that is p resent in the wood fuel may also be released from the chemical composition of the wood and a portion of this may be released as chlorine, but it is more likely to form hydrochloric acid.

Add

- on control technologies that are available to reduce acid gas em issions include dry sorbent injection, wet scrubbing systems and spray dryer adsorbers. These controlNorth Springfield Sustainable Energy Project, LL C AP

- 11

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### Page 52 of 52 technologies were reviewed in Section 5.4 above for the control of SO 2 

### and were

determined to not be cost effective for SO 2 

### , with the lower emission rate of sulfuric acid mist,

the cost of control would be even higher.

HMSER for the Boiler is the use of natural wood which has an inherently low level of sulfur

and chlorine , and a HCl emission limit of 0.000834 lb/MMBtu.

7.4. Ammonia

Ammonia is used as a reage nt in the SCR unit of the boiler to react with NO X 

### to form nitrogen and water. Some of the ammonia will pass through the SCR unreacted and be emitted with the exhaust gas. This is referred to as ammonia slip. Ammonia slip is minimized through good contr ols 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 NH 3 

### @ 7% O 2 

### (this is essentially the same as 13 ppm NH 3 

### @ 3% O 2 

### ).

The Permittee has proposed an HMSER of 10 ppm NH 3 

### @ 7% O 2



### .

The Agency concur s with this proposed limit and is establishing HMSER as an ammonia slip limit of 10 ppm NH 3 

### @ 7% O 2 

### based on a 24

- hour ro lling average for the wood fired boiler.

7.5. CDD/CDF

In combustion processes, CDDs and CDFs can be formed from the thermal breakdown of precursor ring compounds and chlorine. These precursor compounds are produced as a result of incomplete combustion. Accor ding to the EPA, dioxin formation occurs between

392 and 842 o 

### 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 act ivated 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 ~ 400 o 

### F). This would require a PAC system on this Facility’s boiler to be located downstream of the SCR, which would necessitate a second PM

control device to remove the carbon.

The Permittee is proposing HMSER for CDD/CDFs to be good combustion practices and properly operated air pollution control equipment.

The Agency agrees that HMSER for CDD/CDFs is good combustion practices and properly operated air pollution control equipment.