M E M O R A N D U M 

TO: Richard A. Pirolli, Assistant Director SIMS No.: 200901310 

EPE No.: 22584

Date Rec'd: 05/11/2009 

 FROM: James Grillo, APCE 

Kiernan J. Wholean, SAPCE 

SUBJECT: Final Permit to Construct and Operate 42 MW Biomass Utility Boiler for permit 

107-0056 

 

DISCUSSION:

On January 26, 2010, a tentative determination was made to issue a major modification permit to 

construct and operate a 42 MW biomass utility boiler located in Montville, CT to NRG LLC. The 

Notice of Tentative determination was published in The Day on 01/28/2010. The 30 day comment 

period expired on 02/26/2010. The permit fee and publication fee were paid on March 25, 2010. 

There were no comments from the public. On February 24, 2010 the applicant submitted several 

minor comments to the draft permit (see attached letter and enclosure). These comments are not 

technical in nature and are mostly clarifications or corrections. On February 26, 2010, comments were 

received from EPA (see attached letter and enclosure). 

The following changes have been made to the draft permit in response to the applicant’s 

comments: 

• Removed comma from owner name. (Page 1 of 20) 

• Clarified description of operating condition for natural gas and distillate oil concerning the 

electrical output and annual capacity factor (Part I.A) 

• Clarified description of the Fuel Restrictions to allow for fossil fuel use other than peaking. (i.e. 

fuel stabilization for excessively wet biomass, temperature control of RSCR and shutdown of 

biomass firing) (Part I.B) 

• Clarified description of Primary Fuel to make it clear that any of the biomass fuels in Table 1 

of the permit can be fired at 100% capacity. (Part I.B) 

• Clarified Maximum Firing Rate for Primary Fuel by adding 4,600 Btu/lb. (Part I.B.2) 

• Clarified the annual distillate oil restriction to be MMgal not MMgal/hr; fuel heating value was 

changed from MMBtu/gal to MBtu/gal. (Part I.B) 

• Added a note to define how the expected control efficiencies were determined. (Part I.E) 

• Removed the word “or” in third line to correct a grammatical error. (Part II.B.2) 

• Changed “combustible fuel” to “biomass fuel”. (Part II.B.2) 

• Clarified the monitoring of electrical output to be consistent with the RCSA 22a-174-31 and 

RSCA 22a-174-22c(f)(4)(A)(ii). (Part IV.A.13) 

• Added a statement that using electronic records would meet the requirements of recording all 

exceedances of a permit limit or operating parameter. (Part IV.A.15) 

• Changed the total PM2.5 from 67.3 tons/yr to 69.3 tons/yr to accurately reflect the total of 

filterable and condensable PM emissions. (Part V.C Annual Emissions table) 

• Clarified that the predictive emission monitoring for VOC is defined in Part VI.D of the permit. 

(Part V.F) 
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Montville Power LLC 

Responses to EPA’s comments concerning the NSR Engineering Evaluation are as follows: 

Comment 1: EPA commented that the record is unclear how PM2.5 emissions were evaluated and that 

some parts of the evaluation refer to PM10 while others refer to PM10/2.5. 

Response: The Department assumed that all filterable PM2.5 emissions to be equivalent to the PM10 

emissions. The condensable PM2.5 emissions were estimated using AP-42, Table 1.6-1. The draft 

permit has a requirement to test for condensable PM2.5 emissions once a test method is approved by 

EPA. 

The total PM emissions in the Part V emissions table of the permit has been changed from “PM2.5 

(total)” to “PM10/2.5 (total)” to accurately state the particulate emissions. 

Comment 2: EPA commented that the record did not show the increment analysis for PM10 and if the 

impact on a Class 1 area was analyzed. 

Response: The modeling analysis from Jude Catalano, dated December 4, 2009, clearly shows that 

the increment analysis was conducted for PM10. The public notice also included this information. The 

annual PSD increment is 17 μg/m3 and the maximum impact is 1 μg/m3. The 24-hour PSD increment 

is 30 μg/m3 and the maximum impact is 11.24 μg/m3

. EPA did not receive the modeling analysis to 

review along with the permit and evaluation. Any subsequent submittals to EPA for review will 

include the modeling analysis. 

 

Impact on Class I areas from the proposed source were not analyzed. The nearest Class I area to the 

proposed facility (Lye Brook Wilderness Area, Vermont) is located approximately 200 kilometers to 

the northwest. Brigantine National Wildlife Refuge in southern New Jersey (the next nearest Class I 

area) is located approximately 285 kilometers to the southwest. Due to these large distances, CTDEP 

did not pursue a determination of need for an AQRV analysis from the appropriate Federal Land 

Manager. This is consistent with previous determinations by the Department. 

Comment 3: EPA commented on the rationale for waiving pre-construction monitoring. 

Response: The Connecticut Department of Environmental Protection (CTDEP) operates twenty four 

(24) ambient air monitoring sites in the state of Connecticut. Most of these monitoring sites are 

located generally upwind of the Montville location and in areas that are more urbanized than the 

proposed facility surroundings. There are twelve PM2.5, sites (FRM, BAM, FDMS), six PM10 sites, 

four NOx sites, six SO2 sites, and seven CO sites. CTDEP has historically relied on its extensive air 

monitoring network to avoid the need for pre-construction monitoring in most locations of 

Connecticut. The department feels that the existing air monitoring network can be relied on to 

adequately represent existing background at the Montville Power facility location for all criteria 

pollutants. See attached figure, entitled “Air Monitoring Sites in Connecticut Summer 2009”, which 

depicts the current monitoring site locations and lists the pollutants sampled at these sites. The 

proposed facility is located in southeastern Connecticut approximately 12 kilometers south of the 

“Court House (Norwich)” PM2.5 monitoring location. 

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Montville Power LLC 

Comment 4: Part VIII.E of the engineering evaluation does not state that a SO2 CEM will be used and 

the permit indicates that CEM will be used. 

Response: The facility will have a SO2 CEM and the engineering evaluation should have indicated 

that CEM would be used to show compliance with the permit emission limits. 

Comment 5: EPA commented that the engineering evaluation should state why the boiler is not 

subject to NSPS, Subpart Da. 

Response: This boiler is currently not subject to any NSPS requirements. After the modification, the 

boiler will not be subject to 40 CFR Part 60 Subpart Da because “Any change to an existing fossilfuel-fired steam generating unit to accommodate the used of combustible materials, other than fossil 

fuels, shall not bring that unit under the applicability of this subpart” [40CFR60.40Da(c)]. The boiler 

will be subject to Subpart Db after the modification as discussed in the engineering evaluation. 

Comment 6: EPA commented that the opacity limitation in the draft permit is inconsistent with 

Connecticut’s SIP approved NSR program that does not allow for exemptions to startup, shutdown and 

malfunction (SSM) for opacity. EPA recommends that the opacity requirement should be removed 

from the permit or revise the opacity limitation to be used as a indicator for other regulated pollutants. 

Response: Connecticut adopted revisions to its SIP approved opacity regulations in April 2004 which 

allow for exemptions during SSM. The opacity limit was intended to reflect the ability of the source to 

minimize opacity while complying with this regulation. 

In recognition that EPA has not yet approve this revised regulation in the Connecticut SIP, the opacity 

limitation has been changed to: “Opacity during steady state operating modes shall 

not exceed 10% for any six-minute block average”. (NOTE: Part VII.E of the permit 

states that the source is subject to Subpart Db, so the opacity limitations in Db will apply during all 

other times without contradicting the PSD/SIP issue. 

Responses to EPA’s comments concerning the draft NSR permit are as follows: 

Comment 1: EPA commented that since the project is significant for PM10/2.5 that a BACT analysis is 

required for the wood/ash handling system. 

Response: EPA is correct and the PSD rules require a BACT analysis for all pollutants that are 

significant. The applicant submitted additional information concerning BACT for these operations on 

03/16/10. After reviewing the BACT analysis submitted by the applicant, BACT for the fuel and ash 

handling has been determined to be: 

• Proper material management to limit fuel and ash exposure to the environment. 

• Tipping areas will be partially enclosed, use of wind screens and minimizing drop height. 

• Any hogging of off-spec fuel will take place in an enclosed building evacuated through a 

fabric filter. 

• Conveying of the biomass fuel to the storage building will consist of three-quarter enclosed 

hood covers. All biomass transfer points will be enclosed and exhausted to fabric filter dust 

collectors. 

• Fuels will be stored in an enclosed storage building. 

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Montville Power LLC 
• Fuels will be transferred to the boiler via enclosed conveyors to transfer towers and day bins 

exhausted through fabric filters. 

• Bottom ash from the boiler stoker grate will be handled wet and moved by a drag chain 

conveyor to the ash silo or be directly loaded into a truck or container. 

• Fly ash from the ESP will be transferred in enclosed pneumatic conveyors or wetted and 

loaded into trucks for disposal offsite. The conveyors will utilize baghouse dust collectors. 

• The ash silo will utilize a dust collector. 

 In addition, Part II.B of the permit “Control Equipment Operational Conditions”, has been changed 

to: “The Permittee shall develop an operating and maintenance plan (O&M) to 

implement the manufacturer’s specifications and written recommendations. 

Appropriate records shall be made to verify that there is proper operation, 

monitoring and maintenance of all pollution control devices including those 

associated with the fuel and ash handling systems.” 

Comment 2: EPA commented that the production limit of biomass fuel used should be changed from 

amount of fuel consumed to the amount of fuel purchased. 

Response: Part IV.5 of the permit requires the permittee to keep records of the weight of all biomass 

purchased and also additional records to show compliance with the fuel specifications in Part I.B 

Table 1. Table 1 details the regulatory requirements for the fuel to be considered “clean wood”, 

which is the only type of wood fuel that can be combusted in this boiler. The permittee must keep 

records of the amount of fuel combusted on a daily and annual basis (Part IV.3). The permit 

production limit should not be changed to a purchased amount limitation because the short-term 

emission limits in the permit are based on a heat input value combusted not purchased. The purchased 

amount of fuel in any 12-month period may be greater than the 521,000 tons/yr limitation in Part I.B 

of the permit since there will almost always be several days of biomass fuel stored on site. 

Comment 3: EPA commented that Part I.B does not adequately restrict the fossil fuel for use for 

natural gas and distillate oil to a 7% annual capacity factor as stated in the Engineering Evaluation. 

Response: The applicant also commented on this condition. Minor clarifications to Parts 1.A and 

1.B have been made to the permit in response to the applicant’s comments as stated above. 

A statement after the “Auxiliary Fuels” heading in Part I.B has been added to the permit to 

specifically limit the total fossil fuel use to a 7% annual capacity factor based on a heat input value: 

The boiler shall be limited to a combined maximum annual heat input of 

610,134 MMBtu/yr (7% annual capacity factor) for natural gas and distillate 

firing. The following equation establishes the maximum fuel usage. 

 X*(0.140 MMBtu/gal) + Y*(0.001 MMBtu/ft3

) < 610,134 MMBtu 

 Where, X = gallons of ULS distillate oil fired over any 

consecutive 12 month period 

 Y = ft3

 of natural gas fired over the same consecutive 12 

month period 
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Montville Power LLC 

Additional recordkeeping was also added to Part IV.3 of the permit: “The record keeping 

requirements for fossil fuel consumption shall also be sufficient to show 

compliance with the annual capacity factor limitation using the equation in 

Part I.B of this permit.” 

Comment 4: EPA commented that the nomenclature to designate the sulfur content in the distillate 

fuel is incorrect. 

Response: The permit has been changed from 15 ppmvd to 0.0015 in Part I.B of the permit to be 

consistent with the nomenclature used in RCSA 22a-174-19a. 

Comment 5: EPA commented that the requirement to monitor ammonia and the ammonia emission 

limit should be a state-only-requirement since ammonia is not a regulated PSD pollutant in 

Connecticut. 

Response: Ammonia is a pollutant regulated under Connecticut’s SIP approved NSR program. 

Connecticut issues combined NSR/PSD permits under its SIP. The permits issued under that program, 

including this permit, are enforceable by both EPA and the state. The requirement will not be 

identified as state-only. 

Comment 6: EPA commented that Part III, note 3 implies that CEM is only required for natural gas 

and distillate oil firing and that it should be removed to make it consistent with Part V.F that requires 

CEM data to be used to show compliance with permit emission limits for all fuels. 

Response: Note 3 was removed from the permit and that language was added to the introduction 

paragraph which now clearly states that CEM is required for all fuels. All subsequent notes in the 

permit were also renumbered.

Comment 7: EPA commented that Connecticut should require adequate monitoring and recordkeeping 

for PM10/2.5 emissions that are sufficient to meet the requirements of 40 CFR Part 64 (CAM). 

Response: The current approved CAM plan justification for this unit is based upon the principle that 

adequate power must be applied to the ESP in order to develop the electrically charged field that 

drives the collection of particulate matter (PM) as it passes through the various fields. As power gets 

up to moderate to high levels, the relationship between power and performance becomes relatively 

“flat”. This break point for Unit 5 is 27 kW of secondary power. 

A completely new ESP is going to be installed and until adequate stack testing and performance 

testing of the ESP is accomplished there is no technical basis on which to set the exact monitoring 

requirements. Part IV.2 of the permit requires the monitoring of the ESP TR secondary voltage and 

that the Permittee shall maintain these parameters within the ranges recommended by the 

manufacturer and/or determined by the performance test required in Part VI of the permit to achieve 

compliance with the particulate emission limits in the permit. The CAM plan will be incorporated into 

the Title V permit during the modification process of that permit. 
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Montville Power LLC 

Comment 8: EPA commented that the method for determining the compliance with all of the emission 

limits of Part V of the permit is unclear. (i.e. how will CEM data be converted to a lbs/MMbtu or 

lbs/hr basis.) 

Response: All pollutants monitored by CEM (i.e. SOx, NOx, and CO) will be recorded by CEM system 

for all units in the table. The boiler currently uses a Part 75 certified CEM system and it will continue 

to be used once the boiler is modified. That system has an exhaust flow meter and the data will be 

used to make the appropriate conversions to show compliance with the permit limits in Part V of the 

permit. 

Comment 9: EPA commented that the reporting requirement in Part IV.C.1 should be modified so that 

it does not infer that a malfunction of the CEM system could cause an exceedance of the permit limits. 

Response: The paragraph has been changed to: 

“The Permittee shall notify the commissioner in writing each calendar 

quarter of any malfunction of the boiler or the air pollution control 

system that resulted in an exceedance of any of the specified emission 

limits. Reporting of malfunctions for the CEM system shall be in 

accordance with RCSA 22a-174-4.” 

Comment 10: EPA commented that the permit does not contain emission limits during “transient” 

operation and that the permit does not require Connecticut to establish emission limits for these types 

of operations. The comment also states that the BACT analysis in the Engineering Evaluation does not 

contain a rational on why emission limits cannot be met during “transient” operation. EPA also states 

that in other PSD permits the only pollutants of concern during these times is CO and NOx. 

Response: The draft permit does not have specific short term transient emission limits at this time 

because it is difficult to estimate the emissions on a retrofitted boiler of this type. Transient emissions 

are limited through the annual emission limits. The intent of Part VII.C is to track emissions during 

the first year of operation and require the permittee to modify the permit based on the results of the 

analysis. 

While traditionally CO and NOx emissions during transient operation have been the only pollutant of 

concern, the Department would like to have data on the other pollutants to be sure that there are not 

any unexpected exceedances of permit limits during transient operation. While not expected, an 

example would be concerning PM emissions where there could be some variation in PM emissions 

that exceed the steady state emission limits during load changes and those emissions should count 

toward the annual emission limit. 

The paragraph has been modified to require the tracking of steady state and transient operation and 

that transient emission limits will be established and incorporated into the permit for any pollutant for 

which a deviation from the steady-state emission limits occurs. 
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Montville Power LLC 

In response to the BACT analysis: The applicant submitted a supplemental BACT analysis of transient 

operation for review on 03/16/2010. The Department has determined that BACT for transient 

operation is the following: 

• The boiler will be started with either natural gas or distillate oil and emissions will be 

representative of a typical boiler startup. The oxidation catalyst and RSCR will not become 

operational until the flue gas reaches approximately 3000F or 50% load. 

• The steady state lb/hr rates will apply at all times during transient operation because of the low 

firing rate. Once the boiler is at approximately 50% load the oxidation catalyst and RSCR will 

become operational and the steady state BACT rates will apply. 

• During startup, compliance with the steady state lb/MMBtu and ppm limits will not be required 

until the controls are activated at approximately 50% load or until the catalysts are within 

manufacturer’s operating temperature specification. 

• The ESP will be operational at startup and the lb/MMBtu and lb/hr limits will apply for PM. 

• Modeling was conducted using the steady state lb/hr limits, these emission rates apply at all 

times, including transient operations. Using these emission rates, compliance with all NAAQS 

and PSD increments was demonstrated through the modeling analysis. 

• As discussed above, requirements have been added to the permit to establish actual transient 

emission limits to be incorporated into the permit after the first year of commercial operation. 

• The permit specifically states that during start-up/shut-down the (lb/hr) limitations apply and 

that the (lb/MMBtu) and (ppm) limits do not apply. (Part V.A.1) 

Comment 11: EPA commented that Part VII.C that PM2.5 should be included in the analysis. 

Response: The permit, Part VII.C, has been changed from PM10 to PM10/2.5. 

Comment 12: EPA commented on the new National Ambient Air Quality Standard (NAAQS) for NO2

which takes effect on April 12, 2010. EPA 

Response: The permit will be issued prior to the effective date of the standard and no compliance 

demonstration has been conducted for the new 1-hour NO2 standard. 

NOx Emission Reduction Offsets:

On March 30, 2010 the Department approved the use of excess external emission reduction credits 

from Devon Power LLC, Milford, CT to meet the requirement to offset 171 tons/yr of NOx emissions 

after considering the internal offset of 24.2 tons/yr. The approval letter required the applicant to 

respond acknowledging that they are required to obtain 171 tons/yr of external CERCs. On April 5, 

2010 the applicant submitted their required response letter by e-mail with original copies to follow in 

the US mail. Part VII.A of the permit was updated to reflect the Department’s approval of the external 

NOx offsets. 
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Montville Power LLC 

RECOMMENDATION:

It is recommended to issue the major modification permit to construct and operate the conversion of 

Unit 5, to fire biomass at a nominal 42 MW and retain the ability to fire natural gas and/or ultra low 

sulfur distillate oil with a combined annual capacity factor of 7% up to a nominal 82 MW, for 

Montville Power LLC, Montville, CT. 

/s/ James Grillo 04 / 06 / 10

James Grillo, APCE Date 

REVIEW: 

/s/ Kiernan Wholean 4/6/10 

Kiernan J. Wholean, Supervising APCE