UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

REGION III

1650 Arch Street

Philadelphia, Pennsylvania 19103-2029

rn 2 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 Pennsylvania Department of Environmental Protection

(PADEP) submitted a draft plan approval for the 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 our comments we

determined that there 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 of certainprovisions in 40

CFR 52.21. We have concluded our review ofthat information and would like to provide

further clarification supporting our initial conclusions with respcct to the project proposed

in the plan approval for Northampton.

Background

The company operates a steam electric generating plant with one circulating fluidized

bed (CFB) boiler that combusts anthracite cuim and up to 50 percent by weight for any ofthe

following: anthracite coal, bituminous coal, petroleum coke, paper processing residual,

virgin wood chips, high carbon ash and tire-derived fuel. The current permit places a tonper-hour cap on each of the above fuels (through a PSD analysis conducted in 2007), limits

charging rate for all fuels combined to 105 tons per hour, and limits allowable heat input to

10,038,960 million British thermal units per year (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 nonattainment area 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 for all pollutants except

CO, and to change the CO limit from 753.4 tons per year (tpy) to 747.0 tpy to avoid being

subject to 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) Pennsylvania was required to

immediately implement 40 CFR part 51 Appendix S for PM2.5 nonattainment areas and the

revised 40 CFR 52.21 for attainment areas/unclassifiable areas. Subsequent to the effective

date ofthe rule, EPA received a petition for reconsideration for various aspects of the rule,

including grandfathering of applications submitted prior to the effective date for the purposes

of using the PMIO surrogate policy. EPA has granted that petition and has also stayed the

provision allowing grandfathering of applications. Therefore, all pre-construction permits

issued in Pennsylvania after July 15, 2008, must implement the new rules and may no longer

rely on the PM1O surrogate policy.

Neither the plan approval nor the Technical Review Memo for this project addressed

the impact of the project on emissions ofPM2.5. It is our assumption 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 elect to use either projected actual emissions or potential to emit

(PTE) to estimate post-change emissions. CFR 52.21 (b)(4 1 )(ii)(d). The company elected to

use projected actual emissions (PAR) in performing the actual-to-projected-actual

applicability test as allowed under 40 CFR 52.21 (a)(2) (iv)(c). Note that for either approach

baseline actual emissions (BAE) must be used and based on the information submitted, the

BAR of carbon monoxide for the CFB appears to be 495.5 tpy. Below we provide general

comments and analysis regarding the requirements of the applicability test using either PAE

or PTE to estimate post-change emissions.

Applicability Test Using Projected Actual Emissions (PAR)

The PAE means the maximum annual rate, in tons per year, at which the CFB is

projected to emit a regulated NSR pollutant in any one of the five years (12-month period)

following the date the :CFB resumes regular operation after the project, or in any one ofthe

ten years following that date, ifthe project involves increasing the emissions units design

capacity or its potential to emit that regulated NSR pollutant and full utilization of the unit

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would result in a significant emissions increase or a significant net emissions increase at the

major stationary source. See 40 CFR 52.21 (b)(41)(i).

Examples offactors that should be considered by the company in calculating PAE

include, but are not limited to, projections of heat 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)(4 1 )(ii)(a) and (b), including historical operational data,

quantifiable fugitive emissions, and emissions associated with startups, shutdowns, and

malfunctions. For this CFB, which is a steam electric generating unit, the company is also

required under 40 CFR 52.21 (r)(6)(i) and (ii) to submit the bases of the applicability

determination, including the baseline actual emissions, the PAE, the amount of emissions

excluded under 40 CFR 52.2 l(b)(41)(ii)(c) and an explanation for why such amount was

excluded, and any netting calculations, if applicable. For emissions excluded frotn the PAE,

the company must demonstrate that such emissions could have been legally and physically

accommodated before the project and are unrelated to the project. It is important to note that

both of these requirements must be met for any emissions to be excluded. The company is

required to submit all this information to the PADEP prior to beginning actual construction.

To our knowledge, the information used and other bases for the company’s

calculation ofPAE has not been provided by the company to either the PADEP or to EPA

Region 3. It is our understanding that the company has proposed a PAE level simply on the

basis of calculating a level that would result in emissions increases from the project that are

below the PSD significance levels. The company has not shared the expected utilization, fuel

mix, demand growth, etc. and other information needed to properly make a projection of

actual.emissions. Therefore, EPA can not provide its views on this specific proposed

applicability determination until this information is provided.

In order to properly uae PAE to make an applicability calculation, the company first

n~!oroeow they intend tn npe~rateafter the change, including but not limited to how

much the unit(s) will be used demand ) and the mix of fuels or other inputs necessary

to ac ieve the projected use. The company must also identify the associated emissions rates

based on the unit’s operational capabilities following the change taking into account any

legally enforceable restriction that could affect the hourly emission rate following the

change.’ Then, based on the operation or utilization projections and the associated emission

rates, the company should calculate the ~çjmum expected post-change emissions irito_ns

per year for each NSR regulated pollut~int.2 For clarification, the following are the steps

necessary to determine whether a project will result in a significant increase in emissions,

using projected actual emissions.

Examples of legally enforceable restrictions are MAC1 NSPS, and synthetic minor permitlimits that

restrict the 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 of achiev~g. For

,exan’ple, iLan. emissions unit as a 700 t~, emissions limitation, but other ~h~sical or operationaIiestii~~i~son

the unit w ldrçclude it from ever emitting at this level, then it wouldkcjiiappropriate to use this level for

PAE.

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Step 1. Calculate BAE for all existing units affected by the project.

Step 2. Calculate the maximum annual emission rate in tons per year, over the

five years (in some cases 10 yeas) after the change, considering all relevant

information, including fugitive emissions and start-up, shut-down, and malfunctions.

52.21 (b)(4 1 )(i) and (ii)(a) and (b).

Step 3. Examine the portion of post-change emissions and determine if any 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 if operated 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 amount of each fuel that could be fired, 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

physically accommodated during the baseline period and are unrelated to the change.

5~2l(bX4O(ii)(c).

Step 4. Subtract the 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 a common mistake isto assume that a unit “could” haye

emitted up to its permitted amount durj~g_the baseline period and this is the amount th~ç~n

be excluded from the,~PAE. This notion and any variation of this notion is incorrect.

Excluded emissions from the PAE must satisf~’ two criteria. First, a facility can only subtract

that portion of the projected actual emissions that the unit(s) could have already~

and legally emitted durin the d. For instance, a facility is permitted to 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 of the limit that would allow

them to burn a higher sulfur coal. In other words, 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; rather emissions that may be excluded are limited

by the proposed operating conditions used to project emissions into the future.

Second, the facility must be able to demonstrate that excluded emissions are

mpl~tely-umelated-to.-the-proj.eet. As an example, a facility that proposes to switch from

one fuel to another may be able to demonstrate that all ofthe projected emissions after the

change could have occurred during the baseline period using the original fuel type. However,

for this example none of the projected maximum annual emissions from the new fuel can be

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excluded because all of the emissions that will occur after the project are related to the

change in fuel.

Anplicabilit-y Test using Potential to Emit (PTE)

40 CFR §52.21(b)(4) describes PTE as (among other things):

The maximum capacity of a 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 be treated as part of its design ifthe limitation.., is federally

enforceable.

The PSD rules at 40 CFR §52.21(b)(41)(ii)(d) state that PTE may be used to

determine an emissions increase in lieu of PAE. Furthermore, a facility that chooses to use

PTE instead of PAE for its PSD applicability determination must choose to elect a synthetic

minor permit limit to avoid triggering PSD if its PTE after the project results in a significant

emissions increase. In the latter situation, the regulations provide no opportunity for a source

to exclude emissions in the PTh calculations. Using CO from the CFB as an example, the

synthetic minor limit needed to avoid PSD for CO would be derived as follows:

BAE + [less than significance level] 496.55 tpy + < 100 tpy <596.55 tpy

The resulting synthetic minor limit must be legally and practicably enforceable,

consistent with EPA’s policy on PTE.

Impact of Other Pollutants on PSD Applicability

The company is seeking an increase in the heat input limits to accommodate changes

in CO emissions over time. As explained in the additional information submitted by the

company’s consultant:

“The facility burns primarily anthracite culm and the quality of the culm available as

different waste coal sites are reclaimed can vary significantly over time. 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 for the plant shows that a 3 sigma

analysis over a recent 39 month period shows the upper 3 sigma limit of CO

emissions at 0.143 lbIMMBtu, within 35 tons ofthe existing permit limit at full

capacity.” -

When this unit triggered PSD, the permit imposed BACT limits on CO of 0.15

lb/MMBtu, 172 lb/hr and 753.4 tpy. It appears that, rather than being unable to operate

within the heat input restriction, the facility is actually concerned withbeing able to

consistently comply with BACT as different waste piles are reclaimed. This is supported by

the information submitted by the company. Baseline actual CO emissions for the unit are

S
496.55 tpy using a baseline period of2006-2007. The average annual heat input for the same

time period is 9,537,205 MMBTU. The facility is proposing to inercase the heat input to

11,703,360 MMBtu, a difference of 2,166,155 MMBtu or 23 percent over the average

baseline heat input. However, emissions are projected to increase over baseline by 50

percent.

Even more instructive as to the intent of this project, the company has used the actualto- potential test for the 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 heat input is impossible to achieve without exceeding

the permit limits for NOx and S02, using either the actual average emissions factors or the

permitted emissions factors for these pollutants. In fact, for the unit to increase the heat input

to 11,703,360 MMBtu, the average NOx emission factor could not exceed 0.07 lbsfMMBtu,

a 30 percent decrease from the permitted level and a 26 percent decrease from the actual

average baseline emissions factor. Similarly, the average S02 emission factor could not

exceed 0.09 lb/MMBtu in ordór to accommodate the increase in heat input, which is 43

percent lower than the cunent permitted emission rate and 22 percent lower than the average

baseline emission factor.

Although NSRLPSD applicability determinations are performed on a pollutant by

pollutant basis, ~y restriction that would prevent a unit from actually reaching a projected

level of utilization cannot be ignored. In this case, based on our analysis 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 for the changes at the Northampton facility ~io not demonstrate compliance

with federal NSR requirements. Therefore, the draft plan approval should not be issued. If

you have any questions or would like to discuss these issues ftirther, please don’t hesitate to

contact me at 215-814-3297 or Gerallyn Duke at 215-814-2084.

ianne McNally, Acti g AssocW~,birector

Office of Permits & Air Toxics

Attachment ~ Cc: Krishnan Ramamurthy, PADEP

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Northampton 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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