### 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 Primar y 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 PM 2.5 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)-2-

Montville Power LLC

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

Comment 1: EPA commented that the record is unclear how PM 2.5 emissions were evaluated and that some parts of the evaluation refer to PM 10 while others refer to PM 10/2.5

.

Response: The Department assumed that all filterable PM 2.5 emissions to be equivalent to the PM 10 emissions. The condensable PM 2.5 emissions were estimated using AP-42, Table 1.6-1. The draft permit has a requirement to test for condensable PM 2.5 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 “PM 2.5 (total)” to “PM 10/2.5 (total)” to accurately state the particulate emissions.

Comment 2: EPA commented that the record did not show the increment analysis for PM 10 and if the impact on a Class 1 area was analyzed.

Response: The modeling analysis from Jude Ca talano, dated December 4, 2009, clearly shows that the increment analysis was conducted for PM 10. The public notice also included this information. The annual PSD increment is 17 μg/m 3 and the maximum impact is 1 μg/m 3 . The 24-hour PSD increment is 30 μg/m 3 and the maximum impact is 11.24 μg/m 3 . 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 PM 2.5, sites (FRM, BAM, FDMS), six PM10 sites, four NO

x sites, six SO 2 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)” PM 2.5 monitoring location.

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Comment 4: Part VIII.E of the engineering evaluation does not state that a SO 2 CEM will be used and the permit indicates that CEM will be used.

Response: The facility will have a SO 2 CEM and the engineering evaluation should have indicated

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

Comment 5: EPA commented that the engineeri ng 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, theboiler 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 PM 10/2.5 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/ft 3 ) < 610,134 MMBtu Where, X = gallons of ULS distillate oil fired over any consecutive 12 month period
Y = ft 3 of natural gas fired over the same consecutive 12 month period-5-

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 shoul d require adequate monitoring and recordkeeping

for PM 10/2.5 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.-6-

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. SO x, 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 require ment in Part IV.C.1 should be modified so that it does not infer that a malfunction of the CEM syst em 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 BA CT analysis in the Engineering Evaluation does not contain a rational on why emission limits cannot be me t 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 th ere could be some variation in PM emissions that exceed the steady state emission limits dur ing 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.-7-

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 300 0 F 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 st art-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 PM 2.5 should be included in the analysis.

Response: The permit, Part VII.C, has been changed from PM 10 to PM 10/2.5

.

Comment 12: EPA commented on the new Nationa l Ambient Air Quality Standard (NAAQS) for NO 2 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 NO 2 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 requi rement 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.-8-

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 cap acity 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