UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION III 1650 Arch Street Philadelphia, Pennsylvania 19103-2029



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# o 2wo Mr. Mark Wejkszner, Manager Air Quality Program Northeast Regional Office Pennsylvania Department ofEnvironmental Protection 2 Public Square Wilkes-Barre, PA 18711-0790
Re: Northampton Generating Company PSDINSR Analysis Dear: Mr. Wejszner: On March 16, 2009, the PennsylvaniaDepartment ofEnvironmental Protection (PADEP) submitted a draft plan approval forthe Northampton Generating Company. On June 5, 2009, the Environmental Protection Agency (EPA) submitted comments on~the draft plan approval, specifically regarding the New Source Review (NSR)fPrevention of Significant Deterioration (PSD) applicability determination. In ourcomments we determined thatthere were errors in the NSRIPSD applicability analysis. Both the PADEP and Northampton responded to EPA’s comments and submitted additional information on the project and the company’s interpretation ofcertainprovisions in 40 CFR 52.21. We have concluded our review ofthat information and would like to provide further clarification supporting our initial conclusionswith respcctto the projectproposed in the plan approval forNorthampton. Background
The company operates a steam electric generating plant with one circulating fluidized bed (CFB) boilerthat combusts anthracite cuim and up to 50 percent by weightfor any ofthe following: anthracite coal, bituminous coal, petroleum coke, paperprocessing residual, virgin wood chips, high carbon ash and tire-derived fuel. The current permit places atonper-hour cap on each ofthe above fuels (through a PSD analysis conducted in 2007), limits charging rate forall fuels combined to 105 tons perhour, and limits allowable heat inputto 10,038,960 million British thermal units peryear (MMBtuIyr) or 1146 MMBtu/hr. Continuous emissions monitors (CEMs) are in place for opacity, SO2, NOx and CO. The source is located in a moderate nonattainmentarea for ozone and is considered a major source for NOx under NSR. The Northampton facility also is a major PSD source.EPA Comments
The draft Plan Approval proposes to increase allowable heat input to 11,703,360 MMBtu/yr (1336 MMBtu/hr), keep the current annual permit limits forall pollutants except CO, and to change the CO limit from 753.4tons peryear (tpy) to 747.0 tpy to avoid being subjectto PSD. An increase in heat input limits is proposed to produce more electricity.
Fine Particulate Matter (PM2.5) On May 16, 2008, EPA published final regulations implementing NSRJPSD for PM2.5. Upon the effective date ofthe rule (July 15, 2008) Pennsylvaniawas required to immediately implement40 CFR part 51 Appendix S for PM2.5 nonattainment areas and the revised 40 CFR 52.21 forattainment areas/unclassifiable areas. Subsequentto the effective date ofthe rule, EPA received a petition for reconsideration forvarious aspects ofthe rule, including grandfathering ofapplications submitted priorto the effective date forthe purposes ofusing the PMIO surrogate policy. EPA has granted that petition and has also stayed the provision allowing grandfathering ofapplications. Therefore, all pre-construction permits issued in PennsylvaniaafterJuly 15, 2008, must implementthe new rules and may no longer rely on the PM1O surrogate policy.
Neitherthe plan approval northe Technical Review Memo forthis project addressed the impact ofthe project on emissions ofPM2.5. It is ourassumption that PADEP and Northampton included only a PSD analysis for PM1O on the basis ofEPA’s former PM1O surrogate policy. As noted above, pre-construction permits in Pennsylvania may no longer rely on the surrogate policy and all plan approvals must include an NSR/PSD analysis for both PM1O and PM2.5. PSD Applicability for CO
The company may electto use eitherprojected actual emissions orpotential to emit (PTE) to estimate post-change emissions. CFR 52.21 (b)(41)(ii)(d). The company elected to use projected actual emissions (PAR) in performing the actual-to-projected-actual applicability test as allowed under40 CFR 52.21 (a)(2) (iv)(c). Note that foreither approach baseline actual emissions (BAE) must be used and based on the information submitted, the BAR ofcarbon monoxide forthe CFB appears to be 495.5 tpy. Belowwe providegeneral comments and analysis regarding the requirements ofthe applicabilitytest using either PAE or PTE to estimate post-change emissions. ApplicabilityTest Using ProjectedActual Emissions (PAR)
The PAE means the maximum annual rate, in tons peryear, atwhich the CFB is projected to emit a regulated NSR pollutant in any one ofthe five years (12-month period) following the date the :CFB resumes regularoperation afterthe project, or in any one ofthe ten years following thatdate, ifthe project involves increasing the emissions units design capacity or its potential to emitthat regulated NSR pollutant and full utilization ofthe unit

2would result in a significant emissions increase ora significant net emissions increase atthe

major stationary source. See 40 CFR 52.21 (b)(41)(i). Examples offactors that should be considered bythe company in calculating PAE include, but are not limited to, projections ofheat input, planned outages, projected hours of operation, and fuel mix. In addition, the company must consider all relevant information as outlined in 40 CFR 52.21 (b)(41)(ii)(a) and (b), including historical operational data, quantifiable fugitive emissions, and emissions associated with startups, shutdowns, and malfunctions. Forthis CFB, which is a steam electric generating unit, the company is also required under40 CFR 52.21 (r)(6)(i) and (ii) to submitthe bases ofthe applicability determination, including the baseline actual emissions, the PAE, the amount ofemissions excluded under40 CFR 52.2l(b)(41)(ii)(c) and an explanation forwhy such amountwas excluded, and any netting calculations, ifapplicable. Foremissions excluded frotn the PAE, the company must demonstrate that such emissions could have been legally and physically accommodated before the project and are unrelatedto the project. It is importantto notethat both ofthese requirements must be metforany emissions to be excluded. The company is required to submit all this information to the PADEP priorto beginning actual construction.
To our knowledge, the information used and other bases forthe company’s calculation ofPAE has not been provided by the company to eitherthe PADEP orto EPA Region 3. It is our understanding thatthe company has proposed a PAE level simply on the basis ofcalculating a level thatwould result in emissions increases from the projectthat are belowthe PSD significance levels. The company has not shared the expected utilization, fuel mix, demand growth, etc. and other information needed to properly make aprojection of actual.emissions. Therefore, EPA can not provide its views on this specific proposed applicability determination until this information is provided.
In orderto properly uae PAE to make an applicabilitycalculation, the companyfirst n~!oroeowthey intend tn npe~rateafterthe change, including but not limited to how much the unit(s) will be used demand 

## ) and the mix offuels orother inputs necessary to ac ieve the projected use. The company must also identify the associated emissions rates based onthe unit’s operational capabilities following the change taking into account any legally enforceable restriction that could affectthe hourly emission rate following the change.’ Then, based onthe operation or utilization projections and the associated emission rates, the company should calculatethe ~çjmum expected post-change emissions irito_ns peryear for each NSR regulated pollut~int.2 For clarification, the following arethe steps necessaryto determine whethera projectwill result in a significant increase in emissions, using projected actual emissions.

Examples oflegallyenforceable restrictions are MAC1 NSPS, and synthetic minorpermitlimits that restrictthe level ofthe pollutant at issue. V 2 Because PAE is based on the company’s expected operations, itj~generally inappropria~~jelon allowable emissions to project post-change emissions t h sically incapable ofachiev~g. For ,exan’ple, iLan. emissions unit as a 700 t~, emissions limitation, but other~h~sical or operationaIiestii~~i~son the unitw ldrçclude it from everemitting atthis level, then it wouldkcjiiappropriate to use this level for PAE.

3Step 1. Calculate BAE forall existing units affected by the project. Step 2. Calculate the maximum annual emission rate in tons peryear, overthe five years (in some cases 10 yeas) afterthe change, considering all relevant information, including fugitive emissions and start-up, shut-down, and malfunctions. 52.21 (b)(41)(i) and (ii)(a) and 

### (b). Step 3. Examine the portion ofpost-change emissions and determine ifany of such emissions above the baseline are not related to the pr~e~t. jf~y~f~he emissions are not related, and the emissions unit(s) could have emitted at this level before the change ifoperated as projected, then those emissions m~y~c excluded from the PAE ca~u i~n~This determination must consider such things as the

~ emission rate limits, maximum firing rates, and allowable amountofeach fuel that could befired, and the expected mode of operations. A source may only subtract emissions from the maximum annual emission rate determined in Step 2 ift1mseemissions~.i~iil.cLhave been legally and physicallyaccommodated during the baseline period and are unrelated to the change. 5~2l(bX4O(ii)(c). Step 4. Subtractthe BAE from the emissions derived in Step 3. Step 5. Compare the emissions increase from Step 4 to the significance level for each pollutant.
EPA has observed that acommon mistake isto assume that a unit “could” haye emitted up to its permitted amount durj~g_the baseline period and this is the amountth~ç~n be excluded from the,~PAE. This notion and any variation ofthis notion is incorrect. Excluded emissions from the PAE must satisf~’ two criteria. First, a facility can only subtract that portion ofthe projected actual emissions thatthe unit(s) could have already ~ and legally emitted durin the d. For instance, a facility is permittedto bum co Wi a sulfur content up to two percent but actually burns coal with one percent sulfur during the baseline period. The company bases the projected actual emissions on continuing to bum one percent sulfur coal. Emissions that can be excluded would be limited to emissions associated with burning one percent coal, regardless ofthe limit thatwould allow them to burn a higher sulfur coal. In otherwords, the emissions that “could have been accommodated” are not defined by all the many different operating conditions that could have occurred during the baselme period; ratheremissions that may be excluded are limited by the proposed operating conditions used to project emissions into the future. Second, the facility must be ableto demonstrate that excluded emissions are mpl~tely-umelated-to.-the-proj.eet. As an example, afacility that proposes to switch from onefuel to anothermay be able to demonstrate that all ofthe projected emissions afterthe change could have occurred during the baseline period using the original fuel type. However, forthis example none ofthe projected maximum annual emissions from the new fuel can be

4excluded because all ofthe emissions thatwill occur afterthe project are related to the

change in fuel. Anplicabilit-yTest using Potential to Emit (PTE)
40 CFR §52.21(b)(4) describes PTE as (among otherthings):
The maximum capacity ofa stationary source to emit a pollutant under its physical or operational design. Any... operational limitation on the capacity ofthe source to emit a pollutant.., shall betreated as part ofits design ifthe limitation.., is federally enforceable.
The PSD rules at 40 CFR §52.21(b)(41)(ii)(d) statethat PTE may be used to determine an emissions increase in lieu ofPAE. Furthermore, afacilitythat chooses to use PTE instead ofPAE for its PSD applicability determination must choose to elect a synthetic minor permit limit to avoid triggering PSD ifits PTE afterthe project results in asignificant emissions increase. In the latter situation, the regulations provide no opportunity fora source to exclude emissions in the PTh calculations. Using CO from the CFB as an example, the synthetic minor limit needed to avoid PSD forCO would be derived as follows:
BAE + [lessthan significance level] 496.55 tpy + < 100 tpy <596.55 tpy
The resulting synthetic minor limit must be legally and practicably enforceable, consistentwith EPA’s policy on PTE. Impact ofOther Pollutants on PSD Applicability
The company is seeking an increase in the heat input limits to accommodate changes in CO emissions overtime. As explained in the additional information submitted by the company’s consultant:
“The facility burns primarily anthracite culm andthe quality ofthe culm available as different waste coal sites are reclaimed can vary significantly overtime. As fuel quality degrades CO emissions increase. The facility contends that it needs its existing permit limit to accommodate the worst case fuel it may need to burn in the future. Indeed a review ofthe operating data forthe plant showsthat a 3 sigma analysis over a recent 39 month period shows the upper3 sigma limit ofCO emissions at 0.143 lbIMMBtu, within 35 tons ofthe existing permit limit atfull capacity.”

- When this unit triggered PSD, the permit imposed BACT limits on CO of0.15 lb/MMBtu, 172 lb/hr and 753.4 tpy. It appears that, ratherthan being unable to operate within the heat input restriction, the facility is actually concerned withbeing able to consistently comply with BACT as differentwaste piles are reclaimed. This is supported by the information submitted by the company. Baseline actual CO emissions forthe unit are

S496.55 tpy using a baseline period of2006-2007. The average annual heat inputforthe same

time period is 9,537,205 MMBTU. The facility is proposing to inercase the heat inputto 11,703,360 MMBtu, adifference of2,166,155 MMBtu or23 percent overthe average baseline heat input. However, emissions are projected to increase over baseline by 50 percent.
Even more instructive as to the intent ofthis project, the company has used the actualto- potential test forthe other NSR regulated pollutants and is not proposing to change any of the current short or long term emissions limits, including the heat input limits. As the attached table shows, the increase in heatinput is impossible to achieve without exceeding the permit limits for NOx and S02, using eitherthe actual average emissions factors orthe permitted emissions factors forthese pollutants. In fact, forthe unitto increase the heat input to 11,703,360 MMBtu, the average NOx emission factorcould notexceed 0.07 lbsfMMBtu, a 30 percent decrease from the permitted level and a26 percentdecrease from the actual average baseline emissions factor. Similarly, the average S02 emission factor could not exceed 0.09 lb/MMBtu in ordórto accommodate the increase in heat input, which is 43 percent lowerthan the cunent permitted emission rate and 22 percent lowerthan the average baseline emission factor. Although NSRLPSD applicability determinations are performed on a pollutantby pollutant basis, ~y restriction that would preventa unit from actually reaching a projected level ofutilization cannot be ignored. In this case, based on ouranalysis above, it appears the proposed increase in heat input is not achievable without exceeding the emission limits for

Conclusion
As proposed, the draft plan approval and underlying NSR/PSD applicability determination forthe changes atthe Northampton facility~io not demonstrate compliance with federal NSR requirements. Therefore, the draft plan approval should notbe issued. If you have any questions or would like todiscuss these issues ftirther, please don’t hesitate to contact me at 215-814-3297 or Gerallyn Duke at215-814-2084.

ianne McNally, Acti g AssocW~,birector Office ofPermits & AirToxics

Attachment ~ Cc: Krishnan Ramamurthy, PADEP

6Northampton Generating Station

Year Actual Total Average Permit limit PTE

— PTE

— Current Emissions Annual Actual (lb/MMBtu) Average Permitted Annual (tons/yr) Heat Emission Emission Emission Limit

Input Factor Factor Factor (tons/yr) (MMBtu) (lb/MMBtu) (tons/yr)) (tons/yr~

2005 401.4 8732180 0.092 0.1 538.0 585.2 449.5 2006 419.6 10003990 0.084 0.1 490.9 585.2 449.6 2007 384.0 9070420 0.085 0.1 495.5 585.2 449.6

2005 503.1 8732180 0.115 0.129 674.3 754.9 557.8 2006 534.5 10003990 0.107 0.129 625.3 754.9 557.8 2007 485.4 9070420 0.107 0.129 626.3 754.9 557.8

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