Page 1 of 16 

NSR ENGINEERING EVALUATION 

 Connecticut Department of Environmental Date Recv'd: 05/11/2009 

 Protection PAMS No.: 200901310 

 Bureau of Air Management EPE No.: 22584 

Permit No.: 107-0056 

Prepared by: J. Grillo 

 Date Prepared: Dec 2009 

Firm Name:Montville Power LLC 

Address:74 Lathrop Road, Uncasville, CT 06382 

Contact Person (title & phone no.):Cynthia Karlic 

Equipment Location:74 Lathrop Road, Uncasville, CT 06382 

Equipment Description:Major Modification to Unit 5 – Converting to 

Stoker fired 42 MW biomass baseload boiler with 82 MW of peaking 

firing natural gas or ultra low sulfur (15 ppm) distillate oil 

PART I. - Annual Emission Review: Tons Per Year 

Pollutant Premises PTE Permit PTE

New Premises 

PTE**

PM-10/2.5 227.1 33.1 (filt.) 

36.3* (cond.) 

 67.3* (total) 

256.8 (filt) 

256.8 (total) 

SOx 7706.8 60.4 6420.3 

NOx 5032.9 161.9 4355.9 

VOC 289.5 25.6 285.3 

CO 1077.8 265 1204.8 

*Note: Condensable PM-2.5 and total PM-2.5, including condensable PM, are estimated 

based on EPA AP-42 emission factor for condensable PM from wood residue, Table 1.6-

1, Fifth Edition, September 2003. Initially, testing for filterable PM-2.5 shall be 

required. Within one year following the US EPA’s promulgation of a condensable PM2.5 reference test method, the Permittee shall test for both filterable and 

condensable PM-2.5. 

**Note: Includes the reduction offset PTE of No. 6 fuel oil to No. 2 ULS distillate 

fuel oil and the increases from biomass firing. 
Montville Power LLC Page 2 of 16 

PART II. - Emissions Summary (TPY) for Major Modification 

 Determination(see Attachment C)

Pollutant Actual 

Emissions 

(2 yr avg)* 

PTE 

As 

limited 

by 

permit 

Actual 

Emissions 

Increase/

Decrease* 

Net 

Emissions 

Change 

Significance 

Levels 

Table 3a(k)-1 

Increase equal 

to or greater 

than Table 

3a(k)-1? 

 (Yes or NO) 

PM 0.09 33.1 2.1 35.2 25 Yes 

PM-10 0.09 33.1 2.1 35.2 15 Yes 

PM-2.5 0.09 67.3 2.1 69.4 

SO2 31.6 60.4 28.8 40 No 

NOx 

(ozone)

24.2 161.9 137.7 25 Yes 

NOx 

(NAAQS)

24.2 161.9 137.7 40 Yes 

VOC 1.05 25.6 24.55 25 No 

CO 4.6 265 260.4 100 Yes 

Pb 0.001 0.6 

 *Note: Ash and fuel handling equipment. 

 

PART III. - Emission Standards Review and Regulatory Authority: 

a. 

Reg Standard Allowable Rate Basis

PM: Opacity 

20% six minute average 

27% one 6-minute period/hr 

40 CFR Part 60.43b(f) & (g)

10% six minute average 

(Steady state only) 

See Note below 

1 

PM10/2.5: 

0.10 lbs/MMBtu (all fuels) 

RCSA §22a-174-18(e)(1)

0.012 lbs/MMBtu (biomass) 

0.024 lbs/MMBtu (oil) 

0.0076 lb/MMBtu (gas) 

1 

SOx: 

RCSA 22a-174-19(a)(2)(i): 

1% by weight dry basis; 

1.1 lbs/MMBtu 

 

CGS §16a-21a: 

0.3% S by weight 

0.025 lbs/MMBtu (biomass) 

0.006 lbs/MMBtu (ULSD) 

0.0017 lbs/MMBtu (gas) 

3 

2 

2 
Montville Power LLC Page 3 of 16 

PART III. - Emission Standards Review and Regulatory Authority, cont. 

Reg Standard Allowable Rate Basis 

NOx: 

0.2 lbs/MMBtu (gas/distillate) 

0.3 lbs/MMBtu (biomass) 

RCSA §22a-174-22(e)(1)

RCSA §22a-174-22(e)(2)(A)

0.06 lbs/MMBtu 

For all fuels 

1 

VOC: 

RCSA §22a-174-20

0.01 lbs/MMBtu (biomass) 

0.0014 lbs/MMBtu (ULSD) 

0.055 lbs/MMBtu (gas) 

1 

3 

3 

CO: 

RCSA §22a-174-21

0.1 lbs/MMBtu (biomass) 

0.036 lbs/MMBtu (ULSD) 

0.084 lbs/MMBtu (gas) 

1 

3 

3 

MASC: 

Ammonia Slip: 257,383 ppm 

RCSA §22a-174-29

18 ppm 1 

NOTE: RCSA 22a-174-18(j)(2) requires compliance with the visible emissions standard 

set forth in the applicable NSPS. This unit will be subject to Subpart Db after the 

modification to biomass firing. 

Opacity standards apply at all times, except during periods of startup, shutdown, or 

malfunction [40 CFR 60.43b(g)]. 

During periods other than startup, shutdown and malfunction (i.e. fuel switching, 

soot blowing, load changes) opacity shall not exceed one 6-minute period per hour of 

not more than 27 percent opacity [40 CFR 60.43b(f)]. 

The basis for these emission rate calculations are: 

1. Manufacturer’s Data 

2. Calculated from 0.0015% S or less in ULS distillate oil. 

3. AP-42, Table 1.6-2 (9/03); Table 1.3-1 (9/98); Table 1.3-3 (9/98) 

Table 1.4-1 (7/98); Table 1.4-2(7/98) 

b. Source subject to: NSPS, Part 60, Subpart A, Subpart Db; 

c. Hazardous Air Pollutant compliance (RCSA 22a-174-29) yes no N/A 

(see Attachment A) 
Montville Power LLC Page 4 of 16 

PART IV. - Ambient Impact Analysis: 

Source is subject to Ambient Impact Analysis yes no

If no, check applicable box: PM-10/SOx < 3 tpy NOx/CO < 5 tpy

a. SSSHG analysis

 3 < PM-10 < l5 tpy 3 < SOx < l5 tpy 

Date SSSHG completed/approved: 

(see attachment B1) 

b. Screening

“Screening” is required when the allowable emissions for all equipment 

being permitted contemporaneously exceed any of the limits below. 

 5 < CO < l00 TPY 5 < NOx < 40 TPY 

Date screening completed/approved: 

(see Attachment B2) 

 Screening analysis not required since SSSHG was completed/approved. 

c. Refined Modeling

“Refined Modeling” is required when the allowable emissions for all 

equipment being permitted contemporaneously exceed any of the limits 

below. 

 PM-10 > l5 tpy SOx > l5 tpy 

 CO > l00 tpy NOx > 40 tpy 

 Pb > 0.6 tpy 

Date refined modeling completed/approved: 12/04/09 

(see Attachment B) 

PART V. - PSD Review: 

Source is subject to PSD Review yes no 

(see Attachment B) 

Source netted out of PSD Review yes no 

(If yes, see Attachment C1) 

a. Source has significant impact (per RCSA 22a-l74-3a(i)) for: 

 PM-10 SO2 CO NOx Dioxin Pb 

 

b. PM SOx NOx Increment Consumption analysis completed. 

c. Pre-construction monitoring required for ; waived 

d. Visibility, soils, and vegetation impact analysis approved 
Montville Power LLC Page 5 of 16 

PART V. - PSD Review, continued: 

e. General commercial, residential, industrial and other associated growth 

analysis approved 

f. Ambient air quality impact projection analysis approved 

 

PART VI. - Non-attainment Review: 

Source is subject to non-attainment review yes no 

a. Pollutant(s): NOx 

b. Emissions Increase over the last 5 years (tons): None 

c. Offset Ratio: 1.2 

d. Offsets Required: (1.2 x 161.9) = 195 tons

Internal Offsets: 24.2 (Average of actual emissions from 2007/2007) 

 Offsets to be acquired: 195 – 24.2 = 171 

PART VII. - Control Technology Analysis: 

a. BACT/LAER/MACT Compliance yes N/A 

b. BACT/LAER/MACT Utilized: (See Attachment D) 

Pollutant BACT/LAER/MACT

 PM 0.026 lb/MMBtu (condensable and filterable); Dry ESP 

 CO 0.1 lbs/MMBtu; Oxidation Catalyst and good combustion. 

 VOC 0.01 lb/MMBtu; Oxidation Catalyst and good combustion. 

 NOx 0.06 lb/MMBtu; RSCR: LAER 

 SOx 0.025 lbs/MMBtu; Low sulfur fuels 

 Ammonia Ammonia slip < 18 ppm. 

PART VIII. Emission Testing Requirements: 

a. Stack emission testing shall be required for the following pollutant(s): 

 None at this time 

 PM-10 SOx NOx CO VOC Pb 

 Opacity Other (HAPS): Hydrogen Chloride (HCL); Ammonia

b. Testing schedule included in permit: yes no N/A 

c. AE 405 Stack Test Referral Form Completed: yes no N/A 

d. Recurring Tests required? yes no (If yes, notify Stack Test Group)

 Frequency: Every 5 years 

e. CEMS requirements: None at this time 

 SOx NOx CO VOC 

 Opacity Other: Ammonia, RSCR Temperature, Oxidation Catalyst 

 Temperature 
Montville Power LLC Page 6 of 16 

PART IX. - Administrative Criteria Review: 

a. Air quality status 

 ozone: severe non-attainment serious non-attainment 

 PM2.5: attainment non-attainment 

b. Premises size: <l5 tpy; >l5 <l00 tpy; > l00 tpy 

c. Source size: <l5 tpy; >l5 <l00 tpy; > l00 tpy 

d. The source is an existing fossil fuel fired unit that serves a generator 

with a nameplate capacity of 15 MW or greater or is a new fossil fuel 

fired boiler or indirect heat exchanger with a maximum heat input 

capacity of 250 MMBTU or more: yes no (If yes, notify P&S NOx 

Budget Program)

e. Fee: $15,000 (See Attachment D)

f. Signatory Responsibilities authorized yes no n/a 

 (See Attachment E) 

g. Source entered in SIMS P&E Tracking System yes no 

h. Source entered in SAS Permit Tracking System yes no 

i. Source is in the Coastal Boundary yes no 

 Source is in the Coastal Area yes no 

 (No impact, see memo from Kristal Dorismond, dated 09/23/09) 

j. Source is on federally recognized Indian lands yes no 

k. Source is in a Natural Diversity Data Base Area yes no 

l. Source is subject to conservation/preservation restrictions yes no 

See attached map 

t S O Mi ft P i t d
Montville Power LLC Page 7 of 16 

PART IX. - Administrative Criteria Review, continued: 

m. The source to be permitted combusts coal, waste oil, tires, recycled 

materials, construction/demolition debris, wood products, biological 

waste or any other non-fossil fuel that may contain or emit toxic air 

pollutants yes no Gary Ginsberg & Brian Toal notified by e-mail on 

08/26/09 

The source to be permitted is major for federal HAPs yes no 

n. The applicable facility is located in a municipality on the Connecticut 

Department of Economic and Community Development (DECD) list of 

distressed municipalities or in the defined census block to be 

considered under Public Act 08-94 and the Environmental Justice Policy. 

yes no 

 

PART X. - CGS 22a-6 and 22a-186a Compliance: 

-6g yes no n/a Certified Notice of Application 

-6Ρ yes no n/a Posting of Notice Certification 

-6m yes no n/a Compliance Information (See Attachment G) 

-186a yes no n/a Conformance Certification 

PART XI. - Special Requirements: 

Based on modeling: The Permittee shall not operate the existing 2.5 MW 

diesel generators, R107-0021 and R107-0022, for more than 30 hours/day 

combined when firing Unit 5 on biomass. 

PART XII. - Summary:

On May 11, 2009 Montville Power, LLC submitted an application to convert 

their 82 MW natural gas and No. 6 oil fired boiler (Unit 5) to a stoker 

fired 42 MW biomass (wood) boiler with 82 MW peaking capability firing 

either natural gas or ultra low sulfur distillate oil. The fossil 

fuel/peaking firing capability will be limited to a 7% annual capacity 

factor. This boiler currently operates under registration R107-0017, 

Trading Agreement & Order No. 8216A (NOx), Consent Order No. 1887 (Opacity)

and utilizes an ESP for particulate control. Once the project is complete 

the NOx trading order and Opacity Consent Order will no longer be required 

as the addition of state-of-the-art NOx and particulate controls will reduce 

these pollutant emission rates to below all state and federal limits. The 

expected start of commercial biomass operation of this unit is June 2011. 

The applicant was required to apply for a NSR permit pursuant to 22a–174-

3a(a)(1)(B) since this plant will be a major modification to an existing 

major source, [RCSA 22a-174-1(55)] where there is a significant net increase 

in emissions for PM/PM-10, NOx and CO emissions pursuant to RCSA 22a-174-

3a(k)(2)(B). This premises is located in a non-attainment area for ozone 

pursuant to RCSA 22a-174-1(98). 

This premises is located at an existing electrical generating facility and 

major source of air pollution. Currently there is one other No. 6 oil 

utility boiler on the premises along with two (2) auxiliary boilers, two (2) 

2.75 MW diesel generators and two (2) other diesel engines. The premises 

operates under Title V permit number 107-0043-TV. 
Montville Power LLC Page 8 of 16 

PART XII. – Summary, continued: 

This project is subject to PSD review for PM-10, NOx and CO pursuant to Sec. 

22a-174-3a(k). In addition, this source is subject to non-attainment/LAER 

review for NOx pursuant to Sec. 22a-174-3a(l). The boiler will be subject 

to the New Source Performance Standard (NSPS) 40 CFR Part 60 Subpart Db once 

the conversion to fire biomass is complete. This determination was made 

based on consultation with EPA Region 1 and analysis of the NSPS rules 

concerning “modification”. The applicant will be required to submit an 

application for a non-minor Title V permit within one (1) year after 

becoming subject to the Title V provisions pursuant to Sec. 22a-174-

33(f)(2). 

The applicant initially indicated that the potential to emit for a federal 

HAP, hydrogen chloride (HCL) would be greater than (10) ten tons/year, 

making this source a new major source of HAPs and would be subject to RCSA 

Sec. 22a-174-3a(m), otherwise known as a Sec. 112(g) MACT determination. 

This determination was based on using AP-42 emissions factors for HCL. 

However, on September 9, 2009 the applicant submitted additional updated 

emission data that shows that this source should not be considered a major 

source of HAP for HCL based on actual stack test data from similar plants in 

New England and revised engineering estimates. The applicant has agreed to 

accept a limitation for HAP emissions that will restrict the boiler to less 

than 10 tpy for any individual HAP and less than 25 tpy for all HAP in 

aggregate. The permit has requirements to stack test for HCL to ensure that 

this source will not emit more than the major source threshold of ten tons 

per year. All other HAP emissions estimates have been based on AP-42 

factors for wood burning. 

The proposed modification to the plant consists of converting the plant to a 

stoker grate firing clean biomass as defined in RCSA 22a-208a-1 and CGS 22a209a along with the addition of new low NOx burners and the conversion from 

No. 6 oil to ultra-low-sulfur distillate fuel oil, 15 ppmvd sulfur content. 

There will be no construction and demolition (C&D) or regulated wood fuel 

combusted in this boiler. When firing biomass the plant will have a nominal 

electrical output of 42 MW and when firing natural gas or distillate oil the 

plant will operate at 82 MW for up to a 7% annual capacity factor. There 

will be no co-firing of biomass and fossil fuel except during the 

transitional period from biomass to fossil fuels. The existing steam 

turbine will not be modified and no increase in maximum rated capacity is 

planned for the boiler/steam turbine. The modification to the plant will 

use state-of-the-art emissions controls consisting of the following: a new 

electro-static precipitator (ESP) to control particulate emissions; multiclones to collect fly ash from the exhaust stream; a new regenerative 

selective catalytic reduction (RSCR) unit to control NOx emissions; and 

oxidation catalyst to control CO and VOC emissions along with some organic 

HAPs emissions. 

Biomass fuel will be delivered to the site by local roadways via tractor 

trailers and screened for oversized material. Any oversized material will 

be hogged to appropriate fuel size specification and then transferred by 

conveyor to a storage pile and fed to the boiler by an enclosed conveyor 

system. Fly ash will be collected at the multi-clone and ESP hoppers, 

collected and trucked off site for disposal. No single fugitive particulate 

point sources have a potential to emit (PTE) greater than 15 tpy and the 

fuel/ash handling system will not require an individual NSR permit. All 

fugitive dust particulate emissions from the fuel/ash handling have been 

included in the permit and PSD review for particulate matter. 
Montville Power LLC Page 9 of 16 

PART XII. – Summary, continued: 

NSPS Requirements:

This boiler is not currently subject to any New Source Performance Standard 

as it was constructed prior to the applicability date of the boiler 

standards. After the modification the boiler will be subject 40 CFR Part 60 

Subpart Db: Industrial-Commercial-Institutional Steam Generating Units 

pursuant to 40 CFR 60.2 where there will be a change the method of operation 

which increase the amount of any air pollutant. In this case there 

currently is no NOx control and the NOx emissions rate before the RSCR is 

installed increases from 170 lbs/hr to 578 lbs/hr subjecting the boiler to 

Subpart Db because of the modification. Subpart Db contains emission 

standards for PM, NOx, and SO2. Subpart Db [60.43b(h)(1)] limits the boiler 

PM emission rate to 0.03 lb/MMBtu and there are no specific emission 

standards for NOx and SO2 for firing biomass. The applicant has proposed a 

PM emission rate of 0.012 lbs/MMBtu. The proposed natural gas and 

distillate emissions rates for NOx and SO2 are below the NSPS standards and 

will be verified with stack testing and/or CEM data. Based on the proposed 

emission rates and method of operation the boiler will easily comply with 

the applicable emissions standards required by the NSPS. All required 

monitoring, record keeping and reporting will be complied with for Subpart 

Db. Subpart Db requires that either a stack test or a particulate CEM can 

be used as a method of compliance for particulate matter. The proposed 

plant will be required to stack test to comply with the permit particulate 

emissions rate. 

RCSA 22a-174-18(j)(2) defers compliance of the State opacity standards to 

the NSPS if a standard applies. Pursuant to 40 CFR 60.43b(f) the visible 

emissions (opacity) are to be less than 20% for (6-minute average) and less 

than 27% for one 6-minute period/hour. The permit will limit the steady 

state opacity to 10% (six-minute block) and will use the NSPS 27% limitation 

as the maximum opacity limitation. The NSPS and permit opacity requirement 

is significantly more restrictive than the RCSA standard of 20% in any sixminute block average; or 40% reduced to a one-minute block average. 

Control of NOx:

The boiler is subject to Sec. 22a-174-22(b)(1)(A)(ii) since it is a major 

stationary source of NOx and has a heat input greater than 5 MMBtu/hr. 

Pursuant to Sec. –22(e)(2), this boiler must meet an emission limit of 0.3 

lbs/MMBtu when burning biomass and 0.2 lbs/MMBtu when firing fossil fuels. 

The applicant has proposed an emission rate of 0.06 lbs/MMBtu for all fuels. 

This source is currently an existing unit subject to RCSA 22a-174-22c Clean 

Air Interstate Rule (CAIR). After the modification the unit will be 

considered a new source under CAIR and additional NOx allowances will be 

assigned as there will be an increase in NOx emissions over the recent 

historical average. 

This unit is subject to the provisions of Sec. 22a-174-22(k), Emission 

testing and monitoring, and 22a-174-22(l) Reporting and record keeping. 

Control of PM-10:

Pursuant to RCSA 22a-174-18(e)(1), the boiler shall not exceed 0.1 lbs/MMBtu 

for all fuels. The permittee has proposed an emissions rate of 0.012 

lbs/MMBtu for biomass with lower rates for gas and distillate firing. 
Montville Power LLC Page 10 of 16 

PART XII. – Summary, continued: 

Control of SOx:

Pursuant to RCSA 22a-174-19(a)(2)(i) the boiler shall not exceed 1.1 

lbs/MMBtu for biomass firing. The applicant has proposed an emissions limit 

of 0.025 lbs/MMBtu. Pursuant to CGS §16a-21a the sulfur content for liquid 

fuels shall not exceed 0.3% by weight. The applicant has proposed using 

ultra low sulfur distillate fuel oil with a sulfur content of 0.0015%. 

Non-attainment/LAER NOx Offsets: 

This source is subject to non-attainment/LAER review for NOx pursuant to 

Sec. 22a-174-3a(l)(1)(A). Pursuant to Sec. 22a-174-3a(l)(4)(B)(x) the 

applicant must demonstrate that either internal NOx offsets or certified 

external emission reduction credits (ERCs) are used to offset actual NOx 

emissions at a ratio of 1.2:1. Actual NOx emissions for this project are 

calculated to be 161.9 tons/year. 

The actual NOx emissions from this boiler prior to the modification for 

calendar years 2007/2008 have been reviewed and the average has been 

determined to be 24.2 tons/year. Using the equation below, it has been 

determined that the applicant will be required to obtain 171 tons/year of 

external NOx ERCs to comply with the LEAR requirements of Section 22a-174-

3a(l)(4). 

The required NOx ERCs has been calculated as follows: 

 

Total Offsets Required = (Actual emissions x offset ratio) 

 = (161.9 TPY x 1.2) = 195 TPY 

External ERC Offset = (Total Offsets)-(internal offsets) 

External ERC Offset = (161.9 TPY x 1.2) – 24.2 = 171 Tons/year 

The applicant will be required to obtain 171 tons of certified external 

emissions reductions NOx credits from either a severe or serious NOx nonattainment area. The acquisition and transfer of the emissions reductions 

must be approved by the Bureau of Air Management prior to the final 

construction/operating permit being issued. 

Pursuant to Section 22a-174-3a(l)(2), the applicant is required to submit an 

‘Analysis of Alternatives’. This review has been submitted and has been 

part of the review process. The applicant has demonstrated that the 

proposed project’s benefits outweigh the adverse environmental impacts based 

on the following: 

• This premises is currently an electrical utility plant and is an ideal 

location for additional utility development compared to developing a 

green field location. 

• The State of Connecticut has mandated that renewable energy generation 

is part of the makeup of the overall generating portfolio. 

• This boiler will be base loaded with renewable biomass fuel and will 

be retrofitted with state-of-the-art controls that are currently not 

utilized on this unit. 

• The boiler is currently used to supply 82 MW during peak demand using 

residual oil. After the conversion to biomass the plant will provide 

42 MW of reliable base load electricity and up to 82 MW for peaking 

purposes firing either ULS distillate oil or natural gas along with 

using state-of-the-art controls. 
Montville Power LLC Page 11 of 16 

PART XII. – Summary, continued: 

• The boiler currently fires No. 6 residual oil and will be converted to 

fire ULS distillate fuel oil which will have a significant reduction 

in SOx and particulate matter emissions. In addition biomass and 

natural gas have inherently low SOx emissions when compared to 

residual oil. 

LAER for NOx has been determined to be RSCR, an emissions rate of 0.06 

lbs/MMBtu and the requirement to obtain 171 tons of external NOx ERC 

offsets, in combination with the 24.2 tons of internal emissions reduction 

offsets, prior to issuance of final permit to construct/operate. 

BACT/LAER Requirements:

BACT applies to the following pollutants: PM, NOx, SOx, VOC, CO, and ammonia 

pursuant to Sec. 22a-174-3a(j)(1)(D) where potential emissions are greater 

than 15 tons/yr from a modification to an existing source. 

As stated previously, LAER also applies to the NOx emissions pursuant to 

22a-174-3a(l)(1)(A). 

The determination of BACT for the above pollutants was based on the 

information provided in the application of similar biomass energy projects 

throughout the country and the following: 

• Review of the potential emissions and minimum regulatory requirements. 

• Review of the EPA RACT/BACT/LAER Clearinghouse to identify various 

control methods. 

• Review of the technical feasibility of each control method. 

• Rank the control technologies using a “top-down” approach, where 

energy, economic and environmental impacts are used to determine the 

best control technology for the project. 

Although there are alternate methods of control technologies identified in 

the permit application, the proposed methods have been shown by the 

applicant to comply with the BACT requirements pursuant to Sec. 22a-174-

3a(j). Some of the other control technologies considered provide no 

additional reduction in emissions, are technically infeasible, or have not 

been successfully demonstrated in practice. The permit will require the 

applicant to resubmit for review and approval an updated BACT analysis if 

construction has not commenced within 18 months of the final 

construction/operating permit. 

The BACT determination for the pollutants identified above was determined 

based on following: 

PM/PM-10: The applicant identified the following control technologies: 

Fabric Filter Baghouse, Wet Electrostatic Precipitators and Dry 

Electrostatic Precipitators. Wet ESP’s have been shown to be technically 

infeasible because they would cool the exhaust gas to below the operational 

temperature of the RSCR control device, affecting NOx control. 

Additionally, the PM loading would exceed the design specification for 

effective control. The fabric filter would also not be technically feasible 

for stoker fired wood boilers as there would be a threat of baghouse fires 

from embers not removed in the exhaust stream. The only technically 

feasible option is the use of a dry ESP. The boiler currently utilizes an 

ESP, but it will be replaced by a new and larger unit to handle the PM 

loading when firing biomass. 
Montville Power LLC Page 12 of 16 

PART XII. – Summary, continued: 

NOx: The applicant identified the top level of controls for NOx as 

regenerative selective catalytic reduction (RSCR) and selective catalytic 

reduction (SCR). For biomass firing RSCR has been shown to be the top level 

of control at 0.06 lbs/MMBtu. For firing natural gas SCR has been shown to 

be the top level of control at 0.035 lbs/MMbtu on gas only boilers, not 

firing biomass. There has not been any distillate firing boilers identified 

with an emissions rate of less than 0.06 lbs/MMBtu. Since the firing of 

fossil fuel will have an annual capacity factor of 7%, there is no technical 

reason to require the use of SCR to control NOx emissions during fossil fuel 

firing. BACT/LAER for NOx has been recommended to be the use of RSCR with 

an emissions rate of 0.06 lbs/MMBtu for all fuels. 

SOx: The applicant identified that has been no stoker biomass or fossil 

fuel fired boiler that has been required to install an acid gas control to 

meet BACT. The inherently low sulfur content of clean wood along with the 

ultra low sulfur distillate oil and natural gas use represents BACT for SOx 

emissions. 

CO and VOC: The applicant identified that catalytic oxidation is the only 

current method to reduce CO and VOC emissions available at this time. There 

are technical issues with using oxidation catalysts such as catalyst fouling 

from ash and low excess oxygen in exhaust gas. The analysis has shown that 

while there are some units that have been permitted to use oxidation 

catalysts, none have been constructed. The applicant has proposed to use a 

catalyst to control CO and VOC as BACT. Emission rates will be verified by 

an initial stack test and with a CEM for CO which can also serve as a 

surrogate for VOC emissions. 

Ammonia: The ammonia emissions are a direct result of the RSCR NOx control 

system. Ammonia is injected into the RSCR to react with NOx in the flue 

gas. The reaction produces nitrogen and water which is emitted through the 

stack. There is some un-reacted ammonia that passes through the RSCR and is 

commonly called “ammonia slip”. The applicant will optimize the RSCR to get 

the greatest NOx reduction along with the least amount of ammonia slip. 

These emissions limits will be verified with the use of CEMs recorders. 

BACT/LAER recommendations: 

Pollutant BACT/LAER Compliance Demonstration 

PM/PM-10 Dry ESP 

0.026 lb/MMBtu 

Stack test; 

COMS(10% 1 hour-block) 

NOx 0.06 lbs/MMBtu all fuels (LAER)

171 tons of emission reduction 

credits (LAER) 

RSCR (BACT) 

Stack test; 

CEMS(24 hour-block) 

SOx Use of inherently low sulfur 

fuels 

0.025 lbs/MMBtu 

Stack test; 

CEMS(3 hour-block) 

CO Oxidation catalyst and good 

combustion practices 

0.1 lbs/MMBtu 

Stack test; 

CEMS(8 hour-block) 

VOC Oxidation catalyst and good 

combustion practices 

0.01 lbs/MMBtu 

Stack test; 

CO CEMS as surrogate 

NH3 Slip Complying with emission limit 

of 18 ppmvd, and optimization 

of RSCR system 

Stack test; 

CEMS (24 hour-block) 
Montville Power LLC Page 13 of 16 

PART XII. – Summary, continued: 

Prevention of Significant Deterioration (PSD) Requirements:

Pursuant to 22a-174-3a(k)(2)(B) major modifications are subject to PSD 

review if the source has the potential to emit above the net emissions 

increase above the significant emission rate thresholds listed in Table, 

3a(k)-1 of the RCSA. The potential net emissions for the attainment 

pollutant PM-10 is above the significant threshold listed in Table 3a(k)-1. 

The other pollutants that have a significant net increase are NOx and CO. 

Refined modeling/PSD review was performed for PM10/2.5, CO, SO2, and NOx. 

The modeling report, see memo from Jude Catalano dated 12/04/09, determined 

that the facility would not cause or contribute significantly to a violation 

of the State AAQS, federal NAAQS or federal PSD increments. 

The PSD modeling also requires that additional analysis for impacts to 

visibility, soil, vegetation and growth analysis be conducted. 

• The visibility impact was not required since the nearest federal Class 

I Area is farther than 200km away. 

• Compliance with the SO2 and NOx NAAQS ensures adequate protection of 

soils and vegetation. 

• The growth analysis shows that this project would not have a 

significant effect on local air quality. 

Pursuant to Sec. –3a(k)(8)(iv), the owner /operator of a PSD source must 

include “a schedule for the construction of the subject source or 

modification.” Montville Power, LLC estimates that construction would begin 

in March 2010 and startup/commissioning would begin in June 2011. 

Acid Rain:

The applicant currently has an Acid Rain permit covering the two existing 

utility boilers. The Permittee shall comply with all applicable 

requirements of the Federal Acid Rain Program codified in Title 40 CFR Parts 

72-78, inclusive, for this boiler. 

Sec. –29 MASC:

This source complies with Sec. 22a-174-29 maximum allowable stack 

concentrations for all identified HAPs at this time. An initial stack test 

will be required for ammonia and HCL. Stack testing for HCL will be 

repeated every five years from the last test. 

The proposed permit has requirements that will limit all individual and any 

combination of HAPs listed in Section 112(b) of the Clean Air Act Amendments 

of 1990 to less than 10 tons and 25 tons/year respectively. The applicant 

will show compliance with these limitations with stack test, AP-42 emission 

factors and/or fuel sampling. 

The applicant currently has an active application for two peaking GE LM6000 

turbines for the premises. On April 15, 2009 the applicant requested that 

these applications be withdrawn. Pursuant to RCSA 22a-174-26(m)(1), the 

commissioner shall retain 50% of any application fee if the Commissioner has 

not published the tentative determination on the application. Since these 

applications were never acted on by the Department, the applicant is due 50% 

($750.00) of the two application fees which will be transferred to this 

application by CPPU. The refund is included in the calculation of the permit 

fee. 

 
Montville Power LLC Page 14 of 16 

PART XII. – Summary, continued: 

Compliance History Review:

The compliance record was reviewed in accordance with the Environmental 

Compliance History Policy. The applicant’s submitted compliance information 

form was reviewed along with agency records, including the SIMS Enforcement 

database, for information to evaluate the applicant’s compliance history and 

the relevance of such history to the activity for which authorization is 

being sought. Additionally, a review of air program compliance was requested 

from the Enforcement Section and that response forms a part of this record. 

 

There are currently no enforcement actions that prevent this permitting 

process from moving forward. 

Based on the information submitted by the applicant, this engineering 

evaluation and the compliance history review, the granting of a permit to 

construct and operate a 42 MW biomass/82 MW gas/distillate power plant is 

recommended for Montville Power, LLC.

 /s/ James Grillo 1/14/10 

James A. Grillo, APCE Date 

Approvals: 

/s/ Kiernan Wholean 1/14/10

Kiernan Wholean 

Supervising APCE 

/s/ Richard Pirolli 

Richard A. Pirolli 

Assistant Director 

/jad 
Montville Power LLC Page 15 of 16 

NSR Engineering Evaluation Attachment Coversheet 

 Connecticut Department of Environmental Protection 

 Bureau of Air Management 

For Attachment: 

 A Hazardous Air Pollutant (HAP) Review 

 B Ambient Impact Analysis 

 Refined Modeling 

 Increment Consumption Analysis 

 Additional Analysis (soils, visibility, growth, etc.) 

 C Premises Non-attainment Pollutant Summary 

 C1 Netting analysis (See Part V) 

 C2 5 yr aggregation (Deminimis Rule) (See Part VI) 

 D Best Available Control Technology (BACT) Review; Lowest Achievable 

Emission Rate Review; Maximum Achievable Control Technology (MACT) 

Review (See Part VII) 

 E Premises Emissions/Fee Calculations 

 F Signatory Responsibility Certification 

 G CGS 22a-6m: Compliance History 

 

Findings: 

Attachment Findings

 A All HAPs are in compliance with Section 29. 

 B Modeling report shows that the facility will not cause or 

contribute significantly to a violation of any State AAQS, 

federal NAAQS or federal PSD increment. 

 C Applicant is required to obtain 171 tons of NOx offsets 

prior to final CP/OP being issued. 
Montville Power LLC Page 16 of 16 

NSR Engineering Evaluation Attachment Coversheet 

 Connecticut Department of Environmental Protection 

Bureau of Air Management

Findings, continued: 

Attachment Findings

 D BACT has been determined to be the following: 

Pollutant BACT/LAER Compliance Demonstration 

PM/PM-10 Dry ESP 

0.026 lb/MMBtu 

Stack test; 

COMS(10% 1 hour-block) 

NOx 0.06 lbs/MMBtu all fuels (LAER)

171 tons of emission reduction 

credits (LAER) 

RSCR (BACT) 

Stack test; 

CEMS(24 hour-block) 

SOx Use of inherently low sulfur 

fuels 

0.025 lbs/MMBtu 

Stack test; 

CEMS(3 hour-block) 

CO Oxidation catalyst and good 

combustion practices 

0.1 lbs/MMBtu 

Stack test; 

CEMS(8 hour-block) 

VOC Oxidation catalyst and good 

combustion practices 

0.01 lbs/MMBtu 

Stack test; 

CO CEMS as surrogate 

NH3 Slip Complying with emission limit 

of 18 ppmvd, and optimization 

of RSCR system 

Stack test; 

CEMS (24 hour-block) 

 

 E Based on the analysis of alternatives provided by the 

applicant it has been determined that this project is a 

suitable method of power generation for this site. 

 

 F The permit fee is $15,000.00. 

 H No past or present violations prevent this permit from being 

issued.
Ms Cynthia Karlic 

NRG Energy – Montville Power, LLC 

P.O. Box 1001 

Middletown, CT 06457 

Dear Ms Karlic: 

This letter is to inform you that the Department of Environmental Protection Bureau of Air Management 

has completed the evaluation of your application and has made a tentative determination to approve the 

permit to construct and operate the conversion of Unit 5 located at 74 Lathrop Road, Uncasville, CT to 

allow 42 MW of biomass firing and retain the peaking ability of 82 MW for up to a 7% capacity factor 

using either natural gas or ultra low sulfur distillate subject to the following: 

(1) Submission of the appropriate permit fee (invoice enclosed) under Section 22a-174-26 of the 

Regulations of Connecticut State Agencies (RCSA). Remit payment as directed on the enclosed 

invoice. The following is a description of the permit fee: 

Application No. 200901310 Permit No. 107-0056 

 

Permit to Construct & Operate (per RCSA 22a-174-3a) 

Premises size: Major 

Total Permit Fee: $15,000.00 

Minus application fee received: - 750.00 

Minus transfer of 2 withdrawn application fees (50%) - 750.00

Amount Owed $13,500.00

(2) Pursuant to RCSA section 22a-174-2a(b) and Section 22a-6h of the Connecticut General Statutes 

(CGS), publication of the enclosed notice of tentative determination is required to provide the 

opportunity for public comment. Within five (5) days of the date of this letter, the notice will be 

published in the following newspaper: 

 The Day 

 47 Eugene O’Neill Drive 

 New London 06320 
-2- 

Cynthia Karlic 

Gary S. Rose 

Montville Power, LLC 

Under CGS Section 22a-6h the notice is to be published at the applicants' expense. Further processing 

of the permit is contingent on receipt of the permit fee and reimbursement for the cost of public notice. 

In order to avoid delays in the processing of your permit, it is in your best interest to submit this 

payment promptly. 

A tentative determination is not a final permit to construct and operate. The tentative determination 

starts a 30-day public comment period and affords the public an opportunity to request a public hearing. 

Construction activities allowed prior to permit issuance are specifically addressed in RCSA Section 22a174-3a(b). You may enter into legally binding contracts and may begin site clearing activities. You are 

not allowed to begin actual construction specific to your project. This includes excavation, blasting and 

removal of rock and soil, installing footings, foundations, retaining walls, or permanent storage 

structures. To do so would be a violation of the Connecticut Air Regulations and the Federal Clean Air 

Act. 

Please read the enclosed tentative determination carefully. If you have any comments or questions, 

please contact Mr. James Grillo by calling (860) 424-4152. 

 

Date Gary S. Rose 

Director 

Engineering and Enforcement Division 

Bureau of Air Management 

GSR:JAG:jad 

Enclosure

Certified Mail
The Honorable Joseph W. Jaskiewicz 

Mayor 

Montville Town Hall, 2nd Floor 

310 Norwich-New London Tpke. 

Uncasville, CT 06382 

Subject: Connecticut General Statutes (CGS) Section 22a-6h Notice 

Montville Power, LLC, 74 Lathrop Road, Montville, CT 

Application No. : 200901310 

Dear Mayor Jaskiewicz: 

Section 22a-6h of the Connecticut General Statutes requires the Commissioner of the 

Department of Environmental Protection, prior to approving or denying certain permit 

applications, to publish or cause to be published notice of tentative determination regarding such 

applications. This Section also requires that “The commissioner shall further give notice of such 

determination to the chief elected official of the municipality in which the regulated activity is 

proposed.” 

In accordance with this requirement, we are providing to you a copy of the tentative 

determination notice regarding the above-referenced application. 

If you have any questions, please feel free to contact Mr. James Grillo at (860) 424-4152. 

Sincerely, 

Gary S. Rose 

Director 

Engineering and Enforcement Division 

Bureau of Air Management 

GSR:JAG:jad 

Enclosure 
Department of Environmental Protection 

Bureau of Air Management 

Request for Publication 

Date: 

VIA ELECTRONIC MAIL

Laurie Taylor 

Graystone Group Advertising 

2710 North Avenue, Suite 105 

Bridgeport, CT 06604 

ads@graystoneadv.com

1-800-544-0005 

cc: Dennise Goulbourne, DEP 

Contact Name: James Grillo Phone: 424-3570 

E-mail: james.grillo@ct.gov

Publication

Requested Publication Date: 

Please make a one-time insertion of the attached public notice in a single column space set solid under 

Legal Notices in the following newspaper(s): 

 Connecticut Post Waterbury Republican The Hour 

 Bristol Press The Middletown Press Norwich Bulletin 

 The Chronicle The Record-Journal Register Citizen 

 The Day Naugatuck Daily News The Advocate 

 Greenwich Time The Herald Waterbury American 

 The Hartford Courant The New Haven Register 

 Journal Inquirer The News-Times 

Billing

Purchase Order Number: DEPM1-0000023888 

Please note that the Department will not remit payment for publication of the attached public notice until 

copies of the public notice and certifications of the publications are forwarded to the Department. 

Please address such mailings as follows: 

Attn: Dennise Goulbourne, (JAG-4152) 

Department of Environmental Protection 

Bureau of Air Management 

79 Elm Street 

Hartford, CT 06106-5127 

Payment will occur through Dennise Goulbourne, Fiscal Administrative Officer, Bureau of Air 

Management, at (860) 424-3026. Please contact her for further information regarding billing. 
LEGAL NOTICE DEPARTMENT 

Dear Sir: 

Please make one (1) insertion in a single column space, set solid, under Legal Notices, in the 

issue of your next paper following the receipt of this letter, of the notice provided below. 

Kindly render the invoice in duplicate with two clippings showing the insertion. 

_____________________________________________________________________________ 

MONTVILLE POWER, LLC 

MONTVILLE, CT 

 NOTICE OF TENTATIVE DETERMINATION REGARDING A POINT SOURCE 

 PERMIT 

The Department of Environmental Protection hereby gives notice it has made a tentative 

determination to approve an application submitted by Montville Power, LLC ("the applicant") 

under section 22a-174 of the Connecticut General Statutes for permit to construct, install, 

enlarge or establish an air contaminant source or to operate a source regulated under the Clean 

Air Act Amendments of 1990. Specifically, the applicant proposed a major modification to add 

biomass firing to their existing 82 MW (Unit 5) boiler to combust biomass at 42 MW and retain 

the peaking ability of 82 MW for up to a 7% annual capacity factor using either natural gas or 

ultra low sulfur distillate oil. 

The DEP has tentatively determined that the Lowest Achievable Emission Rate (LAER) for NOx

control shall be 0.06 lbs/MMBtu (heat input) for all fuels. The total emissions reduction offset 

required is 195 tpy. The applicant is required to purchase 171 tons of approved serious “nonattainment” NOx emission reduction credits after all internal reduction offsets are considered, to 

offset the potential 161.9 annual tons of NOx that may be emitted from Unit 5. The internal 

reduction offsets, 24.2 tons/year, used in this calculation are the average annual NOx emissions 

for calendar years 2007 and 2008 for the boiler prior to this modification. 

According to the ambient air impact analysis, the proposed facility will not cause or contribute 

significantly to any violation of a National Ambient Air Quality Standard or Prevention of 

Significant Deterioration (PSD) increment. The predicted PSD multi-source ambient impacts for 

nitrogen dioxide (NO2), sulfur dioxide (SO2), and PM-10 are presented in the table below: 

PARAMETER PSD INCREMENT (μg/m3

) MAXIMUM IMPACT (μg/m3) 

SO2 annual 20 <1* 

SO2 24-hr average 91 <5* 

SO2 3-hr average 512 <25* 

NO2 annual 25 <1* 

PM-10 annual 17 1 

PM-10 24-hr 30 11 

* NRG Boiler 5 maximum impact below the significant impact level (SIL). No further PSD 

modeling required. 
-2- 

Legal Notice, continued 

The name and address of the permit applicant are: Montville Power, LLC, 74 Lathrop Road, 

Montville, CT. The proposed activity will take place at: 74 Lathrop Road, Montville, CT. The 

proposed activity will affect air resources. The application has been assigned SIMS number 

200901310 by the Department of Environmental Protection Bureau of Air Management. 

Interested persons may obtain copies of the application and proposed permit from Ms. Cynthia 

Karlic, NRG Energy, P.O. Box 1001 Middletown, CT 06457; Tel: 860-343-6962. The 

application, engineering evaluation and proposed permit are available for inspection at the office 

of the Department of Environmental Protection Bureau of Air Management, 79 Elm Street, 5th 

floor, Hartford, Connecticut, 06106-5127 from 8:30 - 4:30 Monday through Friday. 

Interested persons will have thirty (30) days from publication of such notice to submit comments 

in writing to the Department of Environmental Protection, Bureau of Air Management or request 

a public hearing concerning the Commissioner’s tentative determination to approve the permit 

application, in accordance with section 22a-3a-5(b) and section 22a-174-2a(c) of the Regulations 

of Connecticut State Agencies. Comments should be directed to Mr. James Grillo, Bureau of Air 

Management, Department of Environmental Protection, 79 Elm Street, Hartford, CT 06106-

5127. 
Ms Cynthia Karlic 

NRG Energy – Montville Power LLC 

P.O. Box 1001 

Middletown, CT 06457 

Dear Ms Karlic: 

Enclosed is a certified copy of your original permit to construct and operate the conversion of Unit 5 to 

allow 42 MW of biomass firing and retain the peaking ability of 82 MW for up to a 7% capacity factor 

using either natural gas or ultra low sulfur distillate oil at the above location at 74 Lathrop Road, Montville, 

CT. 

This letter does not relieve you of the responsibility to comply with the requirements of other appropriate 

Federal, State, and municipal agencies. The permit is not transferable from one permittee to another 

(without prior written notification), from one location to another, or from one piece of equipment to 

another. The permit must be posted for easy access at the site of operation. 

Permit renewal applications must be filed at least one hundred twenty (120) days prior to the permit 

expiration date, if applicable. Pursuant to Section 22a-174-3a of the Regulations of Connecticut State 

Agencies, Montville Power LLC must apply for a permit modification/revision in writing if it plans any 

physical change, change in method of operation, or addition to this source which constitutes a modification 

or revision pursuant to Section 22a-174-1 and 22a-174-2a, respectively. Any such changes should first be 

discussed with Mr. James Grillo of the Bureau of Air Management, by calling (860) 424-4152. Such 

changes shall not commence prior to the issuance of a permit modification. 

 Sincerely, 

 Gary S. Rose 

 Director 

 Engineering & Enforcement Division 

 Bureau of Air Management 

GSR:JAG:jad 

Enclosure 
Ms. Ida McDonnell 

Unit Manager 

Air Permits Program (CAP) 

U.S. Environmental Protection Agency 

Region 1 – New England 

5 Post Office Square, Suite 100 

Mail Code OEP05-2 

Boston, Massachusetts 02109-3912 

Dear Ms. McDonnell: 

Please find enclosed materials related to a new source review permit. The source is identified as: 

A. Name of Facility: Montville Power LLC 

B. Location: 74 Lathrop Road, Montville, CT 

C. Brief Description of Project: Conversion of their 82 MW (natural gas or No. 6 oil) Unit 5 boiler to 

allow 42 MW of biomass firing and retain the peaking ability up to 82 MW for up to a 7% capacity 

factor using natural gas or ultra low sulfur distillate oil. 

D. Source/Premises Size: Major Modification/Major Source 

E. Nature of Material Enclosed: application, engineering evaluation and proposed permit.

We understand that EPA requires thirty (30) calendar days to review this package. Should you have any 

questions, please contact Mr. James Grillo the case engineer at (860) 424-4152. 

Sincerely, 

Gary S. Rose 

Director 

Engineering and Enforcement Division 

Bureau of Air Management 

GSR:JAG:jad 

cc: Donald Dahl, EPA Region I 

Enclosures 
MEMO 

TO: CPPU 

FROM: James Grillo, APCE 

 Kiernan Wholean, SAPCE 

SUBJECT: Transfer of application fees for Montville Power 

 

On January 17, 2008 Montville Power LLC submitted applications for two LM6000 combustion turbines, 

200800125 and 200800126. On 04/15/09 the applicant requested that those applications be withdrawn 

since they changed their plans for the site which included a major modification to Unit 5, application no. 

200901310. 

Please transfer 50% of the application fees ($750.00) from the above referenced applications to the current 

application, 200901310, as part of the permit process fee. 

 

James Grillo, APCE 

 

Kiernan Wholean, SAPCE 

JAG:jad 
Montville Power Major Modification, Unit 5 

• Currently Unit 5 is a registered 82 MW electrical generating boiler 

firing No. 6 fuel oil that operates under an RMR (Reliability Must Run) 

contract with ISO-New England until June 1, 2010 as a peaking unit. 

After that time it will operate in the Forward Capacity Market. 

• Major modification consists of converting to a stoker fired 42 MW 

biomass (no construction debris or regulated wood fuel) base load boiler 

with 82 MW peaking capability firing either natural gas or ultra low 

sulfur distillate oil. The fossil fuel/peaking firing capability will 

be limited to a 7% annual capacity factor. 

• The modification to the plant will use state-of-the-art emissions 

controls consisting of the following: a new electro-static precipitator 

(ESP) to control particulate emissions; multi-clones to collect fly ash 

from the exhaust stream; a new regenerative selective catalytic 

reduction (RSCR) unit to control NOx emissions; and oxidation catalyst 

to control CO and VOC emissions along with some organic HAPs emissions. 

• The boiler will be subject to the New Source Performance Standard (NSPS) 

40 CFR Part 60 Subpart Db once the conversion to fire biomass is 

complete. Currently this boiler is exempt from NSPS regulation due to 

its original construction date. 

• There will be no co-firing of biomass and fossil fuel except during the 

transitional period from biomass to fossil fuels. The existing steam 

turbine will not be modified and no increase in maximum rated capacity 

is planned for the boiler/steam turbine. 

• Biomass fuel will be delivered to the site by local roadways via tractor 

trailers and screened for oversized material. Any oversized material 

will be hogged to appropriate fuel size specification and then 

transferred by conveyor to a storage pile and fed to the boiler by an 

enclosed conveyor system. No single fugitive particulate point sources 

require an individual NSR permit. 

• All fugitive dust particulate emissions from the fuel/ash handling have 

been included in the permit. 

• Refined modeling/PSD review was performed for PM10/2.5, CO, SO2, and NOx. 

The modeling report determined that the facility would not cause or 

contribute significantly to a violation of all state and federal ambient 

air quality regulations. 

• Plant will meet all state and federal emissions limitations which will 

be verified through the use of continuous emissions monitoring and 

recurring stack testing. 

• There has been no public interest concerning the air permit for this 

source. There was some concern over traffic during the Siting Council 

hearing. The Siting Council directed the town and applicant to submit 

another traffic plan that was agreeable to both parties.