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### New Hampshire Regional Haze SIP Revision Responses to Federal Land Managers’ Comments

On June 26, 2009, the New Hampshire Department of E nvironmental Services (NHDES) received written comments on New Hampshire’s draft final Regional Haze SIP, May 22, 2009, from the U.S. Department of the Interior, National Park Service (NPS). These comments specifically addressed the Best Available Retrofit Technology (BART) provisions of New Hampshire’s regional haze plan. The following are NHDES’s responses to NPS’s comments. Comments are reproduced in italics and responses appear in regular font.

PSNH Merrimack Station Unit MK2

PSNH Merrimack Station has two coal-fired steam-gen erating boilers that operate nearly full time to meet baseload electric demand. Unit MK2, t he only BART-eligible unit, is a wetbottom, cyclone-type boiler with a heat input ratin g of 3,473 mmBtu/hr and an electrical output of 320 MW. Installed in 1968, this generating unit is equipped with selective catalytic reduction (SCR) to remove oxides of nitrogen (NOx) formed during the combustion process. Two electrostatic precipitators (ESPs) operate in s eries to capture particulate matter (PM). Also, construction has begun on a scrubber system t hat will reduce sulfur dioxide (SO 2 emissions. According to EPA Clean Air Markets (CAM ) database, in 2007, emissions from Unit #2 were: 25,064 tpy SO 2 (@ 1.97 lb/mmBtu) and 2,248 tpy NOx (0.19 lb/mmBtu ).

Retrofit options for this unit are limited because the facility already has controls in place for NOx and PM, and only a few emission control technol ogies are compatible with the type of boiler design employed.

BART Analysis for SO 2

STEP 1 – Identify all available retrofit emissions control techniques

NHDES: SO 2 control technologies available and potentially app licable to Unit MK2 are wet flue gas desulfurization (FGD) and use of low-sulfu r coal.

NPS: PSNH has proposed wet FGD which potentially p rovides the highest level of reduction.

STEP 2 – Eliminate technically infeasible options

NPS: No SO 2 control options were eliminated on this basis.

STEP 3 – Evaluate control effectiveness of remainin g control options

NHDES: SO 2 removal efficiencies for existing wet limestone sc rubbers range from 31 to 97 percent, with an average of 78 percent (NESCAUM, 20 05).

NPS: NHDES should include requirements that PSNH o ptimize operation of the wet FGD.

 NHDES Response : In order to meet the conditions set by state law , the wet FGD is currently being optimized for mercury emission redu ctions. It is unreasonable to require state-of-the-art performance for SO 2 removal as if it were the only pollutant of interest. However, after undertaking the large financial commitment necessary to construct and operate the FGD system, PSNH has a ve sted interest in reducingPage 2 of 16

emissions of both pollutants to the maximum practic able extent. There is little advantage to be gained by PSNH in accepting less th an optimum performance of this system because doing so could create other ope rational problems.

The Temporary Permit for this facility (Attachment EE of Regional Haze SIP) includes provisions that will reset the required SO 2 percent reduction to the maximum sustainable rate with the new FGD system after an i nitial operating period. The specific language of the permit is as follows: “Th e Owner shall submit a report no later than December 31, 2014 that includes the cale ndar month average SO 2 emission
rates at the inlet and outlet of the FGD and the co rresponding calendar month average emissions reductions during the preceding 12 months of operation, excluding the initial startup and commissioning period and any pe riods when the FGD system is not operating...DES shall establish the maximum susta inable rate of SO 2 emissions reductions based on a statistical analysis of the d ata submitted to DES...This established rate shall be incorporated as a permit condition for MK2. Under no
circumstances shall the SO 2 removal efficiency for MK2 be less than 90 percent .”

Also, it should be noted that PSNH has worked to co ntrol the sulfur content of the
coal in order to reduce SO 2 emissions. Because the particular boiler design d oes not permit the burning of straight low-sulfur coal, the company blends coals to bring average sulfur content to a level that is consisten t with sustainable boiler operations.

STEP 4 – Impact analysis

NHDES: Using 2002 baseline emissions of 30,657 ton s of SO 2 from Units MKI and MK2 combined, and a minimum capture efficiency of 90 pe rcent for this pollutant, the annualized capital cost equates to about $1,400 per ton of SO 2 removed.

NPS: The estimated cost is within the range of rea sonable costs suggested by EPA.

STEP 5 – Determine visibility impacts

see below

Determination of BART for SO 2

NHDES: New Hampshire law requires PSNH Merrimack Station to install and operate a scrubber system for both MK1 and MK2 by July 1, 201 3. While the primary intent of this law is to reduce mercury emissions from the company’s c oal-fired power plants, a major co-benefit
is SO 2 removal. Pursuant to this statutory obligation, N ew Hampshire issued a permit to PSNH on March 9, 2009, for the construction of a we t, limestone-based FGD system to control mercury and SO 2 emissions at Merrimack Station. The permit requir es an SO 2 control level of at least 90 percent for Unit MK2. Because this ins tallation is already mandated and because it
will attain SO 2 removal rates approaching the BART presumptive nor m of 95 percent (applicable to EGUs substantially larger than Merri mack Station), the FGD system is considered to be BART for SO 2 on Unit MK2. NHDES is not requesting further acti on of Merrimack station at this time in order to comply w ith BART.

NPS: NHDES should include requirements that PSNH o ptimize operation of the wet FGD.

 NHDES Response : Please see previous response.Page 3 of 16

BART Analysis for NOx

STEP 1 – Identify all available retrofit emissions control techniques

NHDES: The only NOx control technology options ava ilable and potentially applicable to Unit MK2 are selective non-catalytic reduction (SNCR) an d SCR.

NPS: PSNH has proposed SCR which potentially provi des the highest level of reduction.

STEP 2 – Eliminate technically infeasible options

NPS: No NOx control options were eliminated on thi s basis.

STEP 3 – Evaluate control effectiveness of remainin g control options

NHDES: NOx emission reductions of about 75 to 90 p ercent have been obtained with SCR on coal-fired boilers in the U.S. In 1994, PSNH insta lled an SCR system on Unit MK2, the first such system to be used on a coal-fired wet-bottom c yclone boiler in the U.S. Designed to meet NOx Reasonably Available Control Technology (RACT) limits, the SCR has reduced NOx emissions by 85 to 92 percent. Unit MK2 is also re quired to meet a federal acid rain limit of 0.86 lb NOx/mmBtu, an additional NOx RACT Order lim it of 15.4 tons per calendar day, and a NOx RACT Order limit of 29.1 tons per calendar day for Units MK and MK2 combined. PSNH is allowed to meet the 15.4 ton-per-day limit for U nit MK2 by using ozone-season discrete emission reductions (DERs). In 2002, actual NOx em issions for Unit MK2 were reported as 2,871 tons.

NPS: NHDES should explain why the SCR (with or wit hout addition of combustion controls) cannot achieve better than the estimated 85 percent control. NHDES should include requirements that PSNH optimize operation of the SC R.

 NHDES Response : Since January 2001, the SCR on Unit MK2 has redu ced NOx emissions to between 0.15 and 0.37 lb/MMBtu (calend ar monthly average), with a few excursions outside this range. (Note that the existing NOx RACT limit of 15.4 tons per calendar day is mathematically equivalent to 0.37 lb/MMBtu.) Data available from the period of 1993 to early 1995, pr ior to operation of the SCR, provide a baseline for uncontrolled NOx emissions i n the range of 2.0 to 2.5 lb/MMBtu. Taken together, this information indicat es that Unit MK2 achieves a control level greater than 85 percent most of the t ime. PSNH may also have a monetary incentive to surpass the NOx RACT requirem ent because further emission reductions allow the utility to accumulate DERs. W ith respect to optimization, Unit MK2 has an early-generation SCR that previously rec eived retrofits to improve its performance. Additional upgrades would require maj or redesign and construction at a location where physical space is already constrai ned. Capital costs would be comparable to installing a new SCR and would achiev e only marginal additional
reductions in NOx emissions.

STEP 4 – Impact analysis

NHDES: Because Unit MK2 already has SCR controls i n place, the listed costs serve for comparative purposes only. In 1998, PSNH estimated that its SCR costs would be about $400/ton for year-round operation and about $600/to n for operation limited to the ozone season (May 1 through September 30). These costs a re approximately equal to $530/ton andPage 4 of 16

$790/ton, respectively, in 2008 dollars. PSNH curr ently operates Unit MK2 full time in order to meet NOx RACT requirements. Year-round operatio n is EPA’s presumptive norm for BART (applicable to EGUs of 750 MW capacity or greater) for units that already have seasonally operated SCRs. Assuming that operating costs are p roportional to operating time, the difference in cost between year-round and seasonal SCR operati on for Unit MK2 is about $3,300,000, based on PSNH’s 1998 cost estimates. The cost diff erential could be about half that amount, if based on the current (but more generic) estimates p resented in Table 2-1.

NPS: The estimated cost is within the range of rea sonable costs suggested by EPA.

STEP 5 – Determine visibility impacts

see below

Determination of BART for NOx

NHDES: Because Unit MK2 already has SCR controls i n place, the listed costs serve for comparative purposes only. The estimated costs of NOx emission controls for SNCR and SCR at Merrimack Station Unit MK2 are presented in Tabl e 2-1 of the BART report. These estimates are based on assumptions used in EPA Inte grated Planning Model for the EPA Base Case 2006 (V.3.0), for retrofitting an EGU the size of Unit MK2. Because the SCR system is already in place to meet other air program requirem ents and can be operated year-round at reasonable cost, full-time operation of the existin g SCR is considered to be BART for NOx
control on Unit MK2.

NPS: Because the only federally-enforceable NOx li mit (described above) does not reflect the full capability of SCR and is well above the presum ptive 0.10 lb/mmBtu BART limit for a cyclone furnace, NHDES should include limits that r eflect the full capability of the NOx reduction system.

 NHDES Response : The presumptive BART limit is generally applicable to p ower plants having greater than 750 MW capacity and may not be representative of
smaller EGUs like Unit MK2. In the case of Unit MK 2, the cyclone boiler has a relatively high uncontrolled NOx emission rate ( ≥ 2.0 lb/MMBtu), so it follows that the controlled emission rate, even at 90 percent co ntrol efficiency, would be above the presumptive norm applicable to larger facilitie s. As seen in the past decade of emissions records for Unit MK2, monthly average NOx emissions have normally ranged between 50 and 100 percent of the RACT limit . The existing NOx RACT limit of 15.4 ton/day, equivalent to of 0.37 lb/MMB tu, corresponds to a NOx control rate of about 85 percent. NHDES finds that the NOx RACT limit reasonably represents the sustainable performance capabilities of this unit and is also satisfactory as a BART control level for NOx on a 3 0-day averaging basis.

BART Analysis for PM

STEP 1 – Identify all available retrofit emissions control techniques

NHDES: The only PM control technologies available and potentially applicable to Unit MK2 are electrostatic precipitators, fabric filters, me chanical collectors, and particle scrubbers.

NPS: NHDES should have considered simple, inexpens ive upgrades for the ESPs to achieve greater control.Page 5 of 16

STEP 2 – Eliminate technically infeasible options

NPS: No PM control options were eliminated on this basis.

STEP 3 – Evaluate control effectiveness of remainin g control options

NHDES: PSNH Merrimack Station Unit MK2 has two ele ctrostatic precipitators (ESPs), dry type, operating in combination with a fly ash reinj ection system. Installation of the ESPs has reduced PM emissions from this unit by about 99 per cent, based on a review of 2002 emissions data. The current air permit for the facility requ ires that Unit MK.2 meet a total suspended particulate (filterable TSP) limit of 0.227 lb/mmBt u and a TSP emissions cap of 3,458.6 tons/year. Actual TSP emissions from this unit wer e 210 tons in 2002.

NPS: A properly designed and operated ESP should b e able to achieve 0.015 lb filterable PM/mmBtu. In fact, the data presented by NHDES ind icates that the ESPs achieved 0.019 lb TSP/mmBtu in 2002 based upon CAM data heat input of 22,013,515 mmBtu in 2002.

 NHDES Response : The 0.227 lb/MMBtu limit derives from the formul a established in Env-A 2002.06 and does not reflect the true capa bilities of the ESPs serving Unit MK2 to control particulate emissions. Stack testin g on three separate dates in 1999 and 2000 (the most recent PM stack tests on this un it) found actual TSP emissions to be 0.043, 0.041, and 0.021 lb/MMBtu.

STEP 4 – Impact analysis

NHDES: Because Unit MK2 already has two dry ESPs i nstalled and operating, the tabulated costs are useful for comparative purposes only. Ap proximate cost ranges are provided for two types of ESPs and two types of fabric filters appli cable to a retrofit installation the size of Unit MK2. The costs for ESPs and fabric filters are of similar magnitude, with total annual costs ranging from about $2.6 million to $8.3 million, or $90 to $280 per ton of PM removed...

NPS: NHDES conducted no analysis of the cost of up grading the ESPs.

 NHDES Response : The existing ESPs were previously upgraded to in clude state-ofthe-art electronic controls. Further upgrading wou ld require either major equipment
substitutions or the addition of a third ESP in ser ies with the two existing units. Adding a third ESP might be physically impossible b ecause of severe spatial limitations following past improvements to emission control systems. To undertake either major equipment replacement or installation of a third ESP, if it could be done at all, would require a major capital expenditure. Typical equipment replacement costs for ESP upgrades may be in the range of $10,0 00 to $30,000 per MW. For Unit MK2, additional costs of this magnitude are no t easily justified when weighed against the visibility improvement (less than 0.01 dv on the 20 percent worst visibility days) that would be realized.

Determination of BART for PM

NHDES: ESPs already exist, physical space at the f acility is limited, and the addition of an FGD system is now in progress. The existing ESPs, operating in conjunction with the FGD process, will provide the most cost-effective contr ols for particulate emissions. Therefore, continued operation of the existing ESPs is conside red to be BART for PM control on Unit MK2.Page 6 of 16

NPS: Although the existing ESPs may well represent BART, NHDES should evaluate possible upgrades, or, at least, establish a federally-enfor ceable permit limit that reflects the actual capabilities of the units.

 NHDES Response : Despite the existence of former stack test resul ts, the volume of
data is deemed insufficient to establish a conclusi ve, long-term BART performance
level of 0.04 lb/MMBtu or lower for this unit. Acc ordingly, NHDES has developed a draft rule that will hold TSP emissions to no great er than 0.08 lb/MMBtu, but on a broader scope than required under BART: this standa rd will apply to Unit MK1 (not a BART-eligible facility) and Unit MK2. In the curre nt draft Title V operating permit, Unit MK1 has a TSP emission limit of 0.27 lb/MMBtu, or more than three times the proposed limit of 0.08 lb/MMBtu. By including Unit MK1 in the rule, the combined
allowable TSP emissions from the two coal-fired uni ts at Merrimack Station (377 lb/hr)
will be reduced to less than the total allowable TS P emissions under a hypothetical
scenario in which the limit for Unit MK2 would be r evised to 0.04 lb/MMBtu and the limit for Unit MK1 would remain unchanged (473 lb/h r).

STEP 5 – Determine visibility impacts

NHDES: The NHDES conducted a screening-level analy sis of the anticipated visibility effects of BART controls at PSNH Merrimack Station Unit MK2 . Specifically, one modeling run using the CALGRID photochemical air quality model was per formed to assess the effects of installing an FGD system on Unit MK2. The CALGRID model outpu ts took the form of ambient concentration reductions for SO 2 , PM 2.5 , and other haze-related pollutant within the regio n. NHDES post-processed the modeled concentration redu ctions to estimate the corresponding visibility improvements at Class I areas such as Ac adia National Park, Moosehorn National Wildlife Refuge, and Lye Brook Wilderness Area (i.e ., concentration impacts were converted to visibility impacts). For the affected Class I area s (located 100 to 500 kilometers away), reductions in the maximum predicted concentrations of SO 2 , PM 2.5 , and other haze-related pollutants, combined, are expected to yield a nomin al improvement in visibility (about 0.1 deciview) on direct-impact hazy days.

NPS: EPA recommends use of CALPUFF for modeling si ngle sources in situations like this. CALGRJD is more appropriate for multi-source region al modeling and under- predicts impacts relative to CALPUFF. It is likely that, ha d NHDES applied CALPUFF, it would have produced results that predict significantly higher estimates of visibility benefits that would result from the proposed emission controls.

 NHDES Response: According to EPA guidance, CALPUFF or other EPA-approved model may be used to estimate the magnitude of a so urce’s impacts on visibility after implementation of various BART control levels . NHDES agrees with NPS that, if the CALPUFF model had originally been used to perform this assessment, then higher estimates of visibility improvement may have been predicted. CALPUFF is EPA’s preferred model for performing long-range visibility assessments of individual sources to distant Class I areas, in par t because it is considered to be a conservative model or one that is capable of estima ting worst-case impacts rather than expected impacts. This makes CALPUFF ideally suited to screening BART sources for exemption purposes because it is likely to identify virtually all sources that could provide visibility benefits when their e missions are controlled.Page 7 of 16

CALGRID is a sister program to CALPUFF and shares m uch of the same chemistry; however, it works as a gridded model rather than a puff tracking model, and it has the advantage of easily tracking 20% worst visibili ty days and cumulative impacts by modeling all source sectors. NHDES chose to use CALGRID since it is much easier to track the dynamics of impacts from single sources to multiple Class I areas on targeted days, rather than just applying the max imum impact conditions that may or may not be associated with 20% worst days. Whil e the CALPUFF model’s CALPOST post-processor has an option for applicatio n on 20% best visibility days, it does not in fact isolate those 20% best days for analysis. It simply changes the background values the model uses to adjust what it estimates to be appropriate background levels. It does not account for wind di rections that may be preferentially included or excluded on such days.

Nevertheless, to provide a comparison with New Hamp shire’s CALGRID modeling results, NHDES conducted a limited set of CALPUFF r uns for the New Hampshire BART-eligible sources under controlled and uncontro lled conditions.

In previous modeling, MANE-VU used CALPUFF to assis t in the identification of BART-eligible sources. This modeling assumed natur al visibility conditions (about 7 dv) to produce the most conservative results possib le, thereby minimizing the
number of sources that would “model out” of BART re quirements. Under these conditions, uncontrolled emissions from Unit MK2 pr oduce theoretical CALPUFF worst-case impacts of 2.29 dv at Acadia National Pa rk. EPA considers acceptable source exemptions when this form of conservative mo deling indicates a source produces less than 0.5 dv of impact. MANE-VU consi ders an exemption level of 0.2 to 0.3 dv to be more appropriate but prefers, a nd has applied, an even more conservative exemption level of 0.1 dv. CALPUFF mo deling results for baseline emissions from Unit MK2 exceed all of these exempti on levels.

The BART assessment modeling provides a comparison of visibility impacts from current allowable emissions with those from the pos t-control emission level (or levels) being assessed. Results are tabulated for the average of the 20% worst visibility (in this case, about 22.8 dv) modeled da ys at each nearby Class 1 area. For any pair of control levels evaluated, the diffe rence in the level of impairment predicted is the degree of improvement in visibilit y expected.

Rather than use CALPOST to manually manipulate back ground deciview calculations, NHDES normalized CALPUFF modeling res ults and then applied predicted concentrations to a logarithmic best-fit equation to the actual observed
PM 2.5 -to-deciview relationship measured at Acadia NP, Gr eat Gulf NW, and Lye Brook NW. Thus, as recommended by BART modeling gu idance, CALPUFF was applied in a relative way using real observed data as the basis. At this point, a number of background visibility scenarios could be calculated from the resulting PM-mass-to-deciview equation. According to BART gu idance, the natural visibility condition (about 7 dv) was used for exemption purpo ses, and 20% worst visibility (22.8 dv) was used for assessment of BART control e ffectiveness. The CALPUFFpredicted visibility benefits from BART controls on 20% worst visibility days are as
follows:Page 8 of 16

CALPUFF Modeling Results for Merrimack Station Unit MK2: Visibility Improvements from BART Controls on the 2 0% Worst Visibility Days

Pollutant Control Level Acadia NP Great Gulf NW Lye Brook

SO 2 90% with FGD 0.17 dv 0.15 dv 0.08 dv

NOx Additional 25% with SCR upgrade 0.02 dv 0.01 dv < 0.01 dv*

PM 99% with upgraded controls < 0.01 dv* < 0.01 dv* < 0.01 dv*

* below sensitivity limit of model

While Unit MK2 was predicted to have up to 2.29 dv impact at Acadia National Park under natural conditions, the basis of the BAR T assessment evaluation changes to 20% worst visibility days. On those days, a 90% reduction in sulfur emissions at Unit MK2 results in only a 0.17 dv visibility impro vement. At first these results may appear to be incorrect; however, on further exa mination, it is found that CALPUFF predicts the same amount of sulfate from Un it MK2 reaching Acadia under both best and worst visibility conditions. T he difference is that there is greater than an order of magnitude more sulfate coming from other sources on the 20% worst visibility days, raising the background conce ntrations to much higher levels. Because the deciview scale is logarithmic, the same mass reduction of 0.26 μ g/m 3 of
sulfate from this one source results in wide differ ences in deciview impacts for different background visibility conditions at oppos ite ends of the range.

The above analysis indicates that CALPUFF and CALGR ID have aligned better in their predictions than might be expected. This res ult may be attributed to the similar chemistry used in both models and to the specific c ircumstances of this case in which the prevailing wind direction on the 20% wors t visibility days carries Unit MK2 emissions directly toward Acadia National Park. The big discrepancy occurs under best visibility days, when CALGRID (correctly ) does not align the source to receptor, but CALPUFF (incorrectly) applies wind di rections for worst visibility days to the best day calculations.

PSNH Newington Station Unit NT1

Unit NT1 is the sole electrical generating unit at PSNH Newington Station. It operates at irregular times, principally during periods of peak electric demand. Power is derived from an oil- and/or natural-gas-fired steam-generating boil er with a heat input rating of 4,350 mmBtu/hr and an electrical output of 400 MW. Insta lled in 1968, the boiler is equipped with low-NOx burners, an overfire air system, and water injection to minimize the formation of oxides of nitrogen (NOx) during the combustion proc ess. The facility also has an electrostatic precipitator to capture particulate matter (PM) in the flue gases. Partial control of SO 2 emissions is provided by sulfur content limits on t he fuel oil. According to EPA’s Clean Air Markets (CAM) database, in 2002, which were the bas is of the New Hampshire Department of Environmental Services (NHDES) BART analysis, emiss ions from Unit #1 were: 5,226 tpy SO 2 ( 1.08 lb/mmBtu) and 943 tpy NOx (@ 0.18 lb/mmBtu). 1

1 According to the CAM database, in 2007, emissions from Unit #1 were: 2,269 tpy SO 2 (@ 1.05 lb/mmBtu) and 415 tpy NOx (@ 0.16 lb/mmBtu).Page 9 of 16

BART Analysis for SO 2

STEP 1 – Identify all available retrofit emissions control techniques

NHDES: SO 2 control technologies available and potentially app licable to Unit NT1 are wet flue gas desulfurization (FGD) and use of low-sulfu r oil.

NPS: NHDES identified a reasonable suite of option s.

STEP 2 – Eliminate technically infeasible options

NPS: No SO 2 control options were eliminated on this basis.

STEP 3 – Evaluate control effectiveness of remainin g control options

NHDES: SO 2 removal efficiencies for existing wet limestone sc rubbers range from 31 to 97 percent, with an average of 78 percent (NESCAUM, 20 05).

NPS: NHDES should explain what control efficiency is assumed for the hypothetical new
scrubber.

 NHDES Response : For FGD systems installed at large (>750 MW) coa l-fired power plants, the presumptive norm is 95 percent re duction of SO 2 emissions. Newington Station Unit NT1 is a considerably smalle r (400 MW), oil-fired unit; and there is only limited experience with FGD systems o n oil-fired EGUs. However, it may be assumed that a hypothetical new scrubber sys tem for Newington Station would perform at a similar level, achieving SO 2 removal efficiencies of 90 percent or greater.

STEP 4 – Impact analysis

NHDES: Despite expressing concern about the high c ost estimates, 2 NHDES used the latest Merrimack Station estimate of $l,055/kW for scaling purposes to estimate that the total capital cost of a wet limestone FGD system for Newington St ation Unit NT1 would be roughly $422,000,000. NHDES states that “Much caution is n ecessary in relating this number to the Newington facility: Note that the cost of FGD on o il-fired boilers previously has been estimated to be about twice the cost of FGD on coal -fired boilers of comparable size (NESCAUM, 2005).” NHDES did not estimate annual co sts or cost-effectiveness for this option.

NPS: According to NHDES, “The costs of fuel switch ing at Unit NT1 would depend on the incremental costs of purchasing the lower-sulfur fu el at prevailing market prices. The longterm price differential between 1.0%-sulfur (low-S) residual fuel oil and 2.0%-sulfur residual fuel oil is estimated to be about 7.5 cents/gallon. The differential between 0.5%-sulfur (ultralow-S) residual fuel oil and 2.0%-sulfur residual f uel oil is estimated to be about twice this amount, or 15 cents/gallon (both estimates in 2008$ based on Energy Information Agency compiled price data for the period 1983-2008.) Usi ng these unit prices, the total cost of

2 However, PSNH’s estimated cost per kilowatt is at least triple the cost range for FGD systems as repo rted in MACTEC Federal Programs, Inc., “Assessment of Reaso nable Progress for Regional Haze in MANE- VU Class I Areas,” Final, July 9, 2007 (see Reasonable Progres s Report, Attachment Y). The PSNH estimated cost i s also more than double the recent estimate of $300 to $50 0/kW as reported in a 2008 survey of FGD systems (G eorge W. Sharp, “What’s That Scrubber Going to Cost?,” Power , March 1, 2009).Page 10 of 16

switching to low-S residual fuel oil is approximate ly $3.3 million per year, or $1,900 per ton of
SO 2 emissions removed; and the cost of switching to ul tra-low-S residual fuel oil is approximately $6.6 million per year, or also $1,900 per ton of SO 2 emissions removed (both estimates based on 2002 actual fuel oil usage; note that fuel oil usage in 2006-2008 has been below 2002 levels). These results imply that the c ost of fuel switching may be relatively constant on a $/ton basis as long as supplies are a dequate...Switching to lower-sulfur fuel oil generally reduces boiler maintenance requirements b ecause less particulate matter is emitted. With fewer material deposits occurring on internal boiler surfaces, the intervals between cleanings/outages can be longer. Also, because low er-sulfur oil reduces the formation of sulfuric acid emissions, corrosion is reduced and e quipment life is extended.”

STEP 5 – Determine visibility impacts

NHDES: The NHDES conducted a screening level analy sis of the anticipated visibility effects of BART controls at PSNH Newington Station Unit NT1 . Specifically, one modeling run using the CALGRID photochemical air quality model was per formed to assess the effects of installing an FGD system on Unit NT1. The CALGRID model outpu ts took the form of ambient concentration reductions for SO 2 , PM 2.5 , and other haze-related pollutant within the regio n. NHDES post-processed the modeled concentration redu ctions to estimate the corresponding visibility improvements at Class I areas such as Ac adia National Park, Moosehorn National Wildlife Refuge, and Lye Brook Wilderness Area (i.e ., concentration impacts were converted to visibility impacts). For the affected Class I area s, reductions in the maximum predicted concentrations of SO 2 , PM 2.5 , and other haze-related pollutants, combined, are expected to yield a negligible improvement in visibility, accor ding to NHDES.

NPS: EPA recommends use of CALPUFF for modeling si ngle sources in situations like this. CALGRID is more appropriate for multi-source region al modeling and under-predicts impacts relative to CALPUFF. It is likely that, had NHDES applied CALPUFF, it would have produced results that predict significantly higher estimates of visibility benefits that would result from the proposed emission controls.

 NHDES Response : The same methodologies used for the CALPUFF mode ling work for Merrimack Station Unit MK2 were applied to Newington Station Unit NT1.

The BART eligibility modeling conducted by MANE-VU used natural visibility conditions (about 7 dv) to produce the most conserv ative modeling results to minimize sources from modeling out of BART. Under these conditions, uncontrolled emissions from Unit NT1 produce theore tical CALPUFF worst-case impacts of 1.29 dv at Acadia National Park. EPA co nsiders acceptable source exemptions when this form of conservative modeling indicates a source produces less than 0.5 dv of impact. MANE-VU considers an e xemption level of 0.2 to 0.3 dv to be more appropriate but prefers, and has appl ied, a more conservative exemption level of 0.1 dv. CALPUFF modeling result s for baseline emissions from Unit NT1 exceed all of these exemption levels. The CALPUFF-predicted visibility benefits from BART controls on 20% worst visibility days are as follows:Page 11 of 16

CALPUFF Modeling Results for Newington Station Unit NT1: Visibility Improvements from BART Controls on the 2 0% Worst Visibility Days

Pollutant Control Level Acadia NP Great Gulf NW Lye Brook

1.0%-S Residual Fuel Oil (50% sulfur reduction*) 0.05 dv 0.04 dv 0.02 dv

0.5%-S Residual Fuel Oil (75% sulfur reduction*) 0.07 dv 0.06 dv 0.03 dv SO 2

0.3%-S Residual Fuel Oil (85% sulfur reduction*) 0.08 dv 0.07 dv 0.04 dv

NOx 50% with SCR 0.01 dv < 0.01 dv** < 0.01 dv**

PM 99% with upgraded
controls *** *** ***

* from maximum permitted level ** below sensitivity limit of model *** Modeling for PM was not performed because exist ing controls may already be achieving greater than 90% reduction, and any visibility benefit would be belo w the model’s sensitivity limit.

Determination of BART for SO 2
NHDES: Flue gas desulfurization is a potential SO 2 control option for PSNH Newington Station Unit NT1. However, the cost per ton for FG D on oil-fired boilers is estimated to be about twice the cost of this technology on coal-fir ed boilers and could be well in excess of $1,000/kW for Newington Station. Given the high co sts of this option, it is apparent that FGD would he uneconomical as a retrofit for a peak-dema nd plant the size of Unit NT1.

Use of a lower-sulfur fuel is a practical option fo r controlling SO 2 emissions at Newington Station. When natural gas is available at reasonab le cost relative to residual fuel oil, natural gas is the preferred fuel because of its very low s ulfur content. Otherwise, use of low-sulfur residual fuel oil is a reasonable option. For rela tively minor increases in the cost of fuel, switching to 1.0%-S or 0.5%-S residual fuel oil pro vides significant reductions in fuel sulfur content with proportional reductions in SO 2 emissions.

When not firing on natural gas, Unit NT1 has burned 2.0%-sulfur residual fuel oil (actual average fuel sulfur content was 1.2% in 2002). It is estimated that switching to 1.0%-sulfur residual fuel oil would reduce SO 2 emissions by about one-third, and switching to 0.5 %-sulfur residual fuel oil would cut SO 2 emissions by about two-thirds. At the 2002 produc tion level of 700 million kilowatt-hours, estimated annual costs (long-term average, 2008$), would be about $3.3 or $6.6 million (equivalent to $0.0047 or $0.0 094 per kWh), respectively. The cost per kilowatt-hour would vary more or less in proportion to the fuel price differential and would not change significantly with increases or decreases in production level.

Fuel switching could be accomplished without capita l outlay and would have predictable costs tied directly to fuel consumption and fuel price di fferentials. A major consideration is fuel availability. In recent years, there have been sud den and dramatic swings in the price of natural gas relative to fuel oil as supply/demand h as shifted. The future price and availability of natural gas are difficult to discern. While reg ional and national supplies of 1.0%-sulfur residual fuel oil appear to be adequate to meet cur rent demand, the present and future availability of 0.5%-sulfur residual fuel oil, in p articular, is uncertain and speculative.Page 12 of 16

After consideration of projected costs, ease of imp lementation, and fuel availability, it is determined that using 1.0%-sulfur (low-sulfur) resi dual fuel oil is currently the Best Available Retrofit Technology for PSNH Newington Station Unit NT1 when natural gas is not available at reasonable cost. The use of 0.5%-sulfur (ultra- low-sulfur) residual fuel oil remains a future possibility that should be re-evaluated within the next few years. A further reduction in the sulfur content of fuel oil burned at this facility would be consistent with MANE-VU’s plan to reduce sulfur levels to 0.25-0.5% for all fuel oils throughout the region by 2018.

NPS: NHDES concluded that a FGD system is too expe nsive. We agree with the NHDES approach that use of lower-sulfur fuels is BART for this EGU. And, we commend NHDES for its proposal to reduce the sulfur limit on the #6 r esidual oil to 1%. Although NHDES also concludes that the cost of switching to 0.5% sulfur fuel oil is also reasonable (@ $1,900/ton – the same as the cost to go to 1.0% sulfur oil – it has deferred proposing that this additional reduction be required at this time. NHDES suggests that “future availability of 0.5%-sulfur residual fuel oil, in particular, is uncertain and speculative” and that its use “should be reevaluated within the next few years.” To support t his contention, NHDES should present information from fuel oil suppliers concerning the uncertain availability of 0.5% sulfur oil. Furthermore, NHDES should explain how and when it w ould re-evaluate that issue and implement a requirement for 0.5% sulfur oil if it f ound it to be sufficiently available.

We believe that, if 0.5% sulfur fuel oil is found b y NHDES to be reasonably available in the future, a determination that BART is 0.5% sulfur wo uld be consistent with, and enhance the goals of the Northeast states as discussed in the d ocument: “Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, Costs an d Implementation Issues” provided by NHDES as attachment AA. For example, the Executive Summary of that document states:

The analysis summarized in this White Paper support s the Northeast states’ conclusion that significant reductions in SO 2 , NOx, and PM emissions can he achieved by mandatin g lower sulfur heating oil. Importantly, these reductions can he achieved with an expected cost savings to the consumer. Adding the public health and environment al benefits associated with lower sulfur fuel increases the favorable cost-benefit ratio of a reg ional 500 pm [sic] sulfur heating fuel program.

 NHDES Response : There is greater assurance today of the availabi lity 0.5%-sulfur residual fuel oil than when the original BART deter mination was drafted. Maine, Massachusetts, New Jersey, and possibly other state s within MANE-VU have already made commitments to require the use of 0.5% -sulfur residual fuel oil, thus ensuring the presence of a regional market for this commodity. In recognition of the dual-fuel capability of this unit, NHDES has prepar ed a draft rule that will reduce sulfur dioxide emissions by imposing an SO 2 emission limit of 0.50 lb/MMBtu for this facility regardless of fuel type. The rule wo uld allow the facility the flexibility to burn natural gas and/or fuel oil in any feasible ratio, depending on market conditions. (The boiler for Unit NT1 has a physica l limitation of about 50 maximum heat input from natural gas, with no corres ponding limitation on fuel oil.)
Past records indicate that to achieve the 0.50 lb/M MBtu limitation when burning only residual fuel oil, an average fuel sulfur cont ent of approximately 0.45 percent or less would be required. A 50:50 ratio of natura l gas to fuel oil would require a fuel oil sulfur content of 0.9 percent or less.

For the first regional haze progress report, to be submitted circa 2013, NHDES will review fuel usage, fuel supplies, fuel prices, and plant utilization/capacity factors to
determine whether the fuel sulfur limitation descri bed above is still appropriate as
BART control for Unit NT1. Should the review indic ate a different BART controlPage 13 of 16

level, the facility’s Title V operating permit will be amended as necessary before its expiration date of March 31, 2012, exactly fifteen months prior to the effective date of proposed BART control measures.

BART Analysis for NOx

STEP 1 – Identify all available retrofit emissions control techniques

NHDES: NOx control technology options available an d potentially applicable to Unit NT1 are combustion controls, selective non-catalytic reduct ion, and selective catalytic reduction.

NPS: NHDES identified a reasonable suite of option s.

STEP 2 – Eliminate technically infeasible options

NPS: NOx control options were eliminated on this b asis.

STEP 3 – Evaluate control effectiveness of remainin g control options

NHDES: NOx emission reductions of about 75 to 90 p ercent have been obtained with selective catalytic reduction (SCR) on coal-fired boilers in the U.S.

NPS: NHDES should explain why the SCR cannot achie ve better than the estimated 85 percent
control.

 NHDES Response : A hypothetical SCR system retrofit for Newington Station Unit NT1 would be expected to achieve a NOx control rate of 85 to 90 percent or better.

STEP 4 – Impact analysis

NHDES: The estimated costs of NOx emission control s for SNCR and SCR at Newington Station Unit NT1 are presented in Table 2-1. These estimates are based on assumptions used in EPA’s Integrated Planning Model for the EPA Base Case 2006 (V.3.0), for retrofitting an EGU the size of Unit NTI. For SNCR, the total annu al cost is estimated to be about $730,000, or $1,030/ton of NOx removed. For an SCR system, t he total annual cost is estimated to be $1,410,000 or $1,180/ton. Because Unit NT1 is prim arily a peak-load generator, these estimates are based on a 20-percent capacity factor

. 3

NPS: When we applied different assumptions for SCR (e.g., 90% NOx control, 20-year life, 7% interest) we arrived at a slightly higher ($1,278) cost/ton. Furthermore, Newington’s capacity utilization and emissions have dropped so much in r ecent years that it is doubtful that any major capital expenditures would be justified as lo ng as that low utilization continues. For example, in 2007, CAM data show that heat input had declined to 4.3 trillion Btu, and that NOx
emissions were 415 tons.

STEP 5 – Determine visibility impacts

(same as above for SO 2 )

3 Estimates are derived from USEPA, Documentation for EPA Base Case 2006 (V 3.0 Using the Integrated Planning Model, November 2006. Costs are scaled fo r boiler size. All costs are adjusted to 2008 doll ars. Total annual cost is for retrofit of a 400-MW unit with 2 0% capacity factor and 70l million kWh annual gener ation. Total annual cost includes amortization of capital cost over 15 years at 3.0% interest rate. Average cost per ton is based on an estimated 704 tons of NOx removed for S NCR and an estimated 1,196 tons of NOx removed for SCR.Page 14 of 16

 NHDES Response : It is useful to consider NOx emission reductions in the context of other emission reductions – especially sulfur di oxide. MANE-VU determined
that SO 2 was the target pollutant for maximizing visibility improvements. The modeling results posted above for Unit NT1 predict minimal visibility improvements
for SO 2 reductions ranging from 50% to 85%. NOx, while al so an important visibility impairing pollutant, is less hydrophilic and impairs visibility less effectively than a similar mass of SO 2 ; therefore, in comparable mass emission
reductions of SO 2 and NOx, there would be less visibility benefit fr om the NOx reductions. Further, potential NOx emission reduct ions resulting from installation of SNCR/SCR at Newington Station would be in the or der of 20 to 50%. Therefore, it is not surprising that CALPUFF predicts visibili ty improvements of less than 0.01 dv for SNCR/SCR at this facility.

Determination of BART for NOx

NHDES: For the reasons below, the existing control s, which include low-NOx burners, overfire air, and water injection, are determined t o be BART for Newington Station Unit NT1:

• Many of the NOx reduction benefits acquired thro ugh the implementation of low excess air are already being achieved at Unit NT1 through the use of low-NOx burners and overfire air.

• The additional reductions in NOx emissions that would result from adding SCR or SNCR would come at a cost of about $0.7 to $1.3 mil lion annually, with incremental NOx reductions in the 300 to 700 ton/year range. T his cost range does not include costs related to redesign of the site layout to acc ommodate existing spatial constraints. Also, this estimate is based on 2002 emission level s, when the plant’s capacity factor was around 20 percent. With the capacity factor ha ving fallen to less than 10 percent over the period 2006-2008, it is difficult today to justify additional technology retrofits to reduce NOx emissions at this facility.

• For SNCR, the total annual cost is estimated to be about $730,000, or $1,030/ton of NOx removed. For an SCR system, the total annual c ost is estimated to be $1,410,000 or $1,180/ton. SCR and SNCR are not cost-effective as Best Available Retrofit Technology for this facility and will not be consid ered further.

• Another consideration with SCR or SNCR is flue g as and fugitive ammonia emissions. Based on past operation of Unit NTI and on typical ammonia “slip” rates, it is estimated that fugitive ammonia emissions with eith er technology would be in the vicinity of 32 tons annually. Ammonia is a regulat ed toxic air toxic pollutant in New Hampshire and is also a significant contributor to visibility impairment.

NPS: We agree that the reduced capacity utilizatio n makes it difficult today to justify additional technology retrofits 4 to reduce NOx emissions at this facility. NHDES s hould

4 NHDES has approved SCR (and the associated issues w ith ammonia) at Merrimack and must explain how it arrived at its estimate for ammonia slip and why am monia is more of a problem at Newington. If NHDES believes that ammonia slip will impair visibility, it must s how why that outweighs the benefits of reducing NOx

.

NHDES Response : The issue is not so much the magnitude of ammoni a slip or visibility impairment as it is the fact that ammonia slip would occur at all. For a situation such as this one in which SCR or SNCR is essentially ruled out as not cost-effective , ammonia slip only adds to the list of reasons for not implementing either technology.Page 15 of 16

propose federally-enforceable BART limit(s) that re flect its BART determination

 NHDES Response : Because additional retrofits are not proposed fo r Unit NT1, the BART assessment for this facility revolves around i ts long-term performance capability. NHDES reviewed emissions data for Unit NT1 for the period from 2003 to 2005, when more than 99 percent of the gross hea t input came from residual fuel oil. Monthly average NOx emissions ranged between 0.21 and 0.30 lb/MMBtu. These values compare favorably with the facility’s NOx RACT limit of 0.25 lb/MMBtu, daily average, when burning natural gas a nd 0.35 lb/MMBtu, daily average, when burning fuel oil. However, the volum e of the data record is insufficient to demonstrate that the facility could sustainably meet more restrictive
emission limits. The current NOx RACT limitations for Unit NT1 are therefore considered to represent the BART control levels.

BART Analysis for PM

STEP 1 – Identify all available retrofit emissions control techniques

NHDES: The only PM control technologies available and potentially applicable to Unit NT1 are electrostatic precipitators, fabric filters, me chanical collectors, and particle scrubbers.

NPS: NHDES should have considered simple, inexpens ive upgrades for the ESPs to achieve greater control.

 NHDES Response : It may be technically feasible to install upgrad es such as replacement of the existing ESP control systems wit h newer electronic controllers or replacing old-style wire and plate systems inside t he ESP with new, rigid electrode systems. The problem arises in the cost-effectiven ess of such measures. Specifically, it is difficult to justify any major capital expens e at this facility in light of its recent operating record. Since 2006, the plant’s capacity factor has been below 10 percent. Preliminary data for the first nine months of 2009 indicate that the plant was effectively offline for all but the first month.

STEP 2 – Eliminate technically infeasible options

NPS: No PM control options were eliminated on this basis.

STEP 3 – Evaluate control effectiveness of remainin g control options

NHDES: Existing electrostatic precipitators (ESPs) are typically 40 to 60 percent efficient. New or rebuilt ESPs can achieve collection efficien cies of more than 99 percent. Collection efficiencies of baghouses may exceed 99 percent.

NPS: NHDES assumed 42% for the existing ESP at New ington. Because this is far short of the capabilities of a rebuilt ESP, NHDES should have ev aluated that option.

 NHDES Response : The 42 percent efficiency value was obtained by comparing the
PM emission factor from a 2001 controlled stack tes t report with an AP-42 emission factor for uncontrolled PM, and is therefore a crud e approximation of particulate removal efficiency. NHDES has located a 1971 perfo rmance specification for this unit from Buell Envirotech Corp. The efficiency is stated as 93 percent under normal operating conditions and a maximum of 98 per cent under design conditions.Page 16 of 16

It is unknown whether these higher control rates ar e representative of the unit’s actual long-term performance. The emission rate ca lculated from the 2001 stack testing (the only data available) was 0.058 lb/MMBt u. This emission rate is within the expected range for a properly operating ESP at a plant like Newington and may be a better measure of performance than the stated efficiencies.

STEP 4 – Impact analysis

NHDES: The costs for ESPs and fabric filters are o f similar magnitude, with total annual costs ranging from about $3.2 million to $10.4 million, o r $14,000 to $63,000 per ton of PM removed, Because Unit NT1 already has an ESP instal led and operating, the tabulated costs are useful for comparative purposes only.

NPS: NHDES should have evaluated upgrading the ESP

.  NHDES Response : Please refer to previous response on upgrades.

Determination of BART for PM

NHDES: PSNH currently operates an electrostatic pr ecipitator on Unit NT1. ESPs perform with removal efficiency rates similar to those of f abric filters but operate at about half the cost for plants of this size. Because of the estimated cost differential and the fact that an ESP is already installed and operating, the existing ESP i s determined to satisfy BART requirements for PM removal at PSNH Newington Station Unit NT1.

NPS: However, NHDES has assumed that the existing ESP is only 42% efficient – which is not “similar’ to a fabric filter. NHDES should propose a limit that reflects the 99% control it assumed in its analyses for a new ESP or fabric fil ter. Although the existing ESPs may well represent BART, NHDES should evaluate possible upgrades, or, at least, establish a federallyenforceable permit limit that reflects the actual c apabilities of the unit.

 NHDES Response : The single available stack test indicates that t he ESP at Unit NT1 produces controlled emission rates in the vicinity of 0.06 lb/MMBtu. For comparison, the existing TSP limit is 0.22 lb/MMBtu (Permit TV- OP-054, March 9, 2007; administrative amendment, December 17, 2007). The extent of the data record is insufficient to support consideration of a BART per formance level more restrictive than the current permit limit. The facility’s Titl e V operating permit requires that a compliance stack test for PM emissions be performed on Unit NT1 before the permit expires on March 31, 2012. NHDES will review the s tack test results to ascertain the unit’s performance and incorporate any new limit in to a permit amendment by the permit expiration date, as appropriate. The permit expiration date precedes the effective date of proposed BART control measures by fifteen months

.