Supporting Documentation for BART Analyses 

" PSNH Correspondence, December 4, 2009 

" PSNH Correspondence, July 9, 2010 

" PSNH Correspondence, August 16, 2010 

" PSNH Correspondence, December 15, 2010 
'~~~~Ulrr.".,= 

\ Public Service 

of New Hampshire 

December 4, 2009 

Mr. Robert R. Scott, Director 

Air Resources Division 

Dept. of Environmental Services 

29 Hazen Drive, PO Box 95 

Concord, NH 03302-0095 

PSNH Energy Park 

780 North Commercial Street, Manchester, NH 03101 

Public Service Company of New Hampshire 

P.O. Boa 330 

Manchester, NH 03105-0330 

(603) 634-2236 

Faa(603)634-2213 

macdojm@panh.com 

The Northeast Utilities System 

John M. MacDonald 

Vice President - Generation 

Public Service Company of New Hampshire 

Request for Additional Information for Determination of 

Best Available Retrofit Technology (BART) for the NH Regional Haze SIP 

Dear Mr. Scott: 

In response to your request, dated November 17, 2009, for additional information necessary to 

finalize the NH Department of Environmental Services, Air Resources Division's response to 

comments received from the U.S . Environmental Protection Agency and Federal Land Managers 

specific to DES' Best Available Retrofit Technology (BART) demonstration, Public Service 

Company of New Hampshire is submitting the enclosed information. 

As you know, PSNH did not submit written comments specific to DES' BART determination 

presented at the public hearing on June 24, 2009, because PSNH was in agreement with that 

determination . PSNH is interested in understanding the basis of any significant changes to the 

BART determination and would raise objection to overly stringent BART limits that provide 

minimal environmental benefit yet increase costs and expose PSNH's generating facilities to 

permit exceedances during the course of normal operation of the units. 

Incremental Cost Estimates of S02 Reductions at Newington Unit NTl 

In order to estimate incremental costs associated with varying grades of oil, PSNH evaluated 

historical fuel cost data provided by Platts for the period of 2002 through September 2009. 

Considering the inevitable inaccuracies in trying to predict future fuel prices, PSNH has 

calculated incremental cost estimates for illustrative purposes using the more recent historical 

fuel cost data (2005-2009). 

As illustrated on the enclosed spreadsheet, PSNH has estimated the incremental costs, on a dollar 

per ton basis, of sulfur dioxide reductions at Newington Station, Unit NT 1 to be as follows: 

2% sulfur content by weight to 1 % sulfur content by weight $1,030 per ton S02 reduced 

1 % sulfur content by weight to 0.7% sulfur content by weight $2,949 per ton S02 reduced 

0.7% sulfur content by weight to 0.5% sulfur content by weight $7,203 per ton S02 reduced 

0.5% sulfur content by weight to 0.3% sulfur content by weight $12,957 per ton S02 reduced 

086529 REV. 1-09 
Mr. Robert R. Scott, Director 

December 4, 2009 

Page 2 of 3 

Assumntions Used to Produce Estimated Incremental Costs 

The assumptions used to estimate incremental costs include historical fuel prices, maximum 

gross heat input rate of Unit NT1, S02 emission rates in lb/mmBtu and lb/hr for each grade of 

fuel, and tons of S02 reduced. Capacity factor of Unit NT 1 is not necessary to calculate 

incremental costs on a dollar per ton reduced basis. The S02 emission rates were derived from 

the sulfur content of the fuel, the heating value of the fuel, and the maximum gross heat input 

rate of Unit NTl. The tons of S02 reduced were calculated using the delta in S02 emissions 

between each fuel type on a Ib/hr basis which was calculated using the S021b/mmBtu emission 

rate for each grade of fuel and the maximum gross heat input rate of Unit NTl as contained in 

Newington Station's Title V Operating Permit, TV-OP-054. 

Additional Costs Associated with Fuel Storage Upgrades. at Newington Station 

At the present time, PSNH is hopeful that the current fuel storage and delivery system, including 

configuration and storage capacity, is adequate to handle varying grades of oil if required in the 

future. As a result, PSNH has not calculated additional costs associated with fuel storage 

upgrades . 

MK Unit #2 Boiler and SCR O ations 

The SCR has a temperature permissive that must be met in order for the SCR to be put in service 

or kept in service. During start-ups, shut-downs, and low load operation of Merrimack Unit #2, 

the temperature is lower than that permissive temperature and the SCR cannot be operated. As 

an example, Merrimack Unit 2 typically has 10 to 15 outages per year, in addition to 

approximately 8 low load operating periods per year. The timing of these conditions is not 

predictable and this estimate of occurrences provided reflects historical performance. Examples 

of low load situations include, but are not limited to: forced and planned outage start ups and 

shutdowns, loss of one of any equipment pair where both pieces of equipment are necessary for 

full load operation and the loss of one results in half load operation (such as Forced Draft Fans, 

Condensate Pumps), loss of the Main Boiler Feed Pump, loss of coal feeders, condenser 

waterbox cleaning, etc . Any condition which requires the unit be at loads below 230 mw net, 

causing the temperature to be below the SCR permissive will result in the SCR not able to be put 

in service. This load point may increase with the new, more efficient HP/IP turbine . 

In addition to boiler operations and load conditions that affect SCR operation, malfunctions of 

the SCR system and/or associated equipment can also affect the operation of the SCR. , 

Malfunctions of the SCR system and/or associated equipment can result in partial or complete 

reduction of SCR performance. 

As part of normal service, the SCR catalyst becomes coated with flyash. Blinding of the catalyst 

with flyash can cause the SCR process control settings (often referred to as the setpoint) to have 

to be increased (less NOx conversion), as the reagent distribution becomes less uniform and as 
Mr. Robert R. Scott, Director 

December 4, 2009 

Page 3 of 3 

less catalyst is exposed to the flue gas. The SCR is cleaned as needed during outages, and 

sootblowers are used on line. 

Reagent injection grid nozzles, being in the flue gas path, can become fouled with deposits . This 

can affect reagent distribution, compounding the effect of a fouled catalyst, for example. The 

reagent injection grid is cleaned, as needed, during outages. Also, reagent delivery disruption 

can occur and on-site storage is limited. 

Also as a catalyst ages, it becomes less reactive . This causes a reduction in ability for NOx 

conversion to take place. This in itself does not typically result in higher NOx emission because 

the SCR has four layers of catalyst, staggered in age. However, it will compound the effect of a 

fouled catalyst, for example. 

The uncontrolled NOx rate at reduced load and during start ups and shut-downs is typically 1 .0 -

1 .51b NOx/mmBTU. The uncontrolled NOx rate at normal full load is as high as 2.661b 

NOx/nunBTU, with an average of 2.4 1b NOx/mmBTU. 

The SCR is unable to performcontinually at its maximum capability due to these concerns . As 'a 

result, PSNH needs flexibility to operate the SCR based on current operating conditions . 

In closing, PSNH would like to reiterate its opinion that changes to DES' BART determination 

that result in more stringent emissions limitations create concerns relative to increased costs and 

decreased operational flexibility. 

Please contact Laurel L. Brown, Senior Environmental Analyst - Generation, at 634-2331 if you 

would like additional information or would like to meet to discuss the enclosed information 

further. 

John M. MacDonald 

Vice President-Generation 

Enclosure 
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Public $et-hee 

of New Hampshire 

duly 9, 2010 

NH Department of Environmental Services, Air Resourm- Division 

29 Ham Drive 

P© Box 95 

Concord, NH p3302-01D95 . 

r- -+ y {~ ~s 

; N t 

r

f! . 

Michele Roberge 

Administrator, Permitting and Environmental Health Bureau 

CONFIDENTIAL BUS 

Dear Ms. Roberge: 

S7NFORMATTUN 

- er 

A 1?- z4 

-T v 

~a1^ "t 

RECEIVED 

NEW HAMPSHIRE 

'JUL 16 2010 

Public Service of New Hampshire AIR RESQUR .tES iJiVt$10N 

Best Available Retrofit Technolagy {'BART}. 

Response to Request for Additional lnfortnatitin 

As requested, PSNH provides the following information to support the Merrimack Unit #2 (M1C2) 

NOx limits and the Newington (N71) fuel oil sulfur content for New Hampshire's Regional Haze , 

SIP. We are providing this information as confidential business information since it contains 

various operating scenarios and financial cws which are competitively sensitive in nature and 

could be harmful if disolosed. 

Merrimack Station Unit #2: Merrirnack Station was the first investor owned utility in the nation 

to install an SCR to achieve NOx reductions. Given the operation of the SCR, it is PSNH's -

position that maintaining operational flexibility is a critical priority in order to enaure continued 

and cost-effective compliance while simultaneously achieving significant reductions in NOx 

emissions. The following information summarizes the primary drivers and the associated costs 

that would be incurred in ensuring attainment of NOx emissions rates lower than the currerrt NOx 

emission limits set in the NH Ft4ional Haze SIP 

I . Operating Temperatur6 of SCR 

As previously provided, the SCR has a temperature. perrnussive that must be met in order for the 

SCR to be put in service or kept in service . -During start-ups, shut-downs, and row load operation 

of Merrimack Unit #2, the temperature is lower than that permissive temperature and the SCR 

cannot be operated. For example, Irrlerrimack Unit 2 typically has 10 to 15 outages per year and 

approximately $ low load operations per year. During these events, SCR operating temperatures 

are less than the permissive tempeirature rendering the SCR inoperable. The timing of these 

events is not predictable ; the estimate of occurrences provided reflects historical performance. 

Examples o£ low load situations include, but are not linitted to, the following: 

+ Forced and planuyed outags start ups and shutdowns; 

PsNH Energy Pw* 

700 North CornmerciaT Snr.ci, Manchester, M-1 08909 

PubLP Se7YtC4 Company of Now fkmp4him 

P.C. Box 33a 

hiame-batcr. NE 03105-W30 

(603) 689-4000 

nrovw.psn}s,oaars 

The N+n't1hease UtWties System 

1786561 REV. 11 .09 
Ms. Michele Itoberge, Admitlistratcir 

July 7, 20 10 

Page 2 of 7 

Loss of one of any equipment 

the loss of one results in half I~ a~erat;on (suc~ 

pumps); 

e Loss of the main boiler feed PUMP" 

necessary for full load operation and 

forced drafl fans, condensate 

" Loss of coal feeders, condenser waterbvx cleaning, cstc . ; and 

" Any condition which results in the flue gas temperatures to be below the SCR percnissivs 

temperature will result in the SCPL not able to be put in service. 

2. Malfunction and Fouling of the SCR and/or Associated Equipment 

in addition to boiler operations and load conditions that affect SCR operation, rrta.lfunctions of the 

SCR system and/or associated. equipment can also affect the operation of the SCR. Malfunctions 

of the SCR system and/or assaciated equipment can result in partial or complete reduction of 

SCR performance. 

Also as part of normal service, the SCR performance deg,rades overtime. One reason this occurs 

is due to blinding of the catalyst with fly ash, This condition will cause the SCR process control 

settings to compensate by increasing SCR loading to maintain the set point. This is necessary 

because the reagent distrlbution becomes less uniform as less surface area of the catalyst is 

exposed to the flue gas. To matnage this condition from developing to the point that a 

maintenance outage is ncce,ssary, the SCR is cleaned on-line utilizing soot blowers and cleaned 

during outages, as needed . Increased SCR loading will lead to more frequent maintenance 

outages. Reagent injection grid nozzles are directly exposed to the flue. gas and become fouled 

overtime. This can aff+ect reagent distribution, oompottndittg the effect of a fouled catalyst. The 

rea,gent in3ec0oa grid is cleaned, as needed, during outages. Also as catalyst ages, it becornes less 

reactive. This causes a reduction inability for NOx conversion to take place. Thus ite itself does 

not typically result in higher NChx emissions because the SCR has four layers of catalyst, 

intentionally staggered in age.- However, it will compound the~efhct of a fbuled catalyst and am 

result in the SCR being unable to perform. continually at its maximum capability. As a resuli, 

PSNH needs flexibility to operate the SCR based on current operating conditions . Cu=tly the 

SCEL avezages greater than 86% efficiency. The uncontrolled NOx rate at normal full load ,is us 

high. ~ 2,66 l~, NOx}mm'3"1'CJ, with an average of 2.4 Ib hdOxltt~mBT(J. The uncontrolled t+l{3x 

rate at reduced load and during start ups and shut-downs is typically 1.© -1.5 lb NClxfmmBTCJ. 

With:these short-term challenging operational conditions, PSN1=I's~grestest ooneexn is ensuring 

consistent compliance. We have reviewed historical daf* and concluded that start-ups and shut 

downs can significantly impact both a calendar month and a rolling 30-day average-emission rntwe 

bj+ up to 0.04 lb NOx1aYrnBTlI . 

- 

If there is more than 1 outage during the averaging period, the 

irtipsyot to the average emission rats could be as high as D.#t$ lb N(7adrnmBTU. To allow for this 

potential operating occutreneo, Merrimack Station would need to operate to maintain u much 

lower average NOx rate. Reviewing the historical monthly averages, this leaves little margin for 

typical operating fluctuations in NOx controls . For example, if a unit is off for a longer period of 

time, there are less valid operating days available to he in cluded in average rate . 'I'bis analysis is 

particularly int~eresting, because in this specific scxnario, the total tons of emissions are less than 

full load operation for tlm same averaging period, but could have a~high eznission rate . An 

extreme example of this soenario was observed in August 2009 when the monthly average 

emission raw was 4.813 ib NOzclmmB'i'U and yet total emissions for that month were 
Ms. Michele Roberge, Administrator 

July 7, 20 10 

Page 3 of ? 

approximately 1 ton. This was primarily due the unit operating only a short amount of time in 

that Month. 

3: Potential Costs Associated with Proposed Reduction in NN emission rata 

Merrimack Station will need to consider a number of additional compliance efforts if not 

provided the necessary flexibility to deal with short-term events as described above and the 

operational restrictions of the SCR. Each has an additional cost as outlined below . 

There will be increased mail3tenasxee costs to maintain peak NC3x reduction capability. For 

example, air heater-cleanings will be required more frequently because of increased loading of the 

SCR. This scenario results in additional maintenance costs and replacement power costs 

associated with the required outages. 

Maintenance (Cleaning) Costs: $30,000 to $100,000 per cleaning 

Replacement Power Costa: The table below uses an assumption of - $3Ulmwhr 

difference between the co sk of Merrimack Station and the market cost. This number can 

vary grWly depending on energy market prices . 

Duration Of TUpliteement Power Number of outages TOW Cost per Year 

C1sanEn IUuta e Cost per Ontalte p er year 

Short Q dwl $720,000 1 MD,0ao 

, 2 S 1,44Q,QQ4 

3 $2.1bf1>t}4[} 

4 $2 8 0W 

Mid (4 .5 days) $1,100,000 i _ - si,loo,aoa - ----- 

' $2,200,000 

3 S3,34Q,44(} 

Long (6 days) 1 $1,400,000 

s28o0,oaQ 

If air heater washings were rouitnely necessary to comply with d step change 'in the NOx rate, the 

c,ost par ton ofNQx reduction would be extremely costly, as illustrated below. This cost can 

increase greatly if an air heater cleaning was compleW during a high priced market, 

tmission Rate 1VOx tow emitted 

per 

Lb N{)xlEnm $T!1 ear 

Incramental tens pery aar Incremental tons per day 

0.37 56204 

0.34 5171 .99 456.35 1.25 

Duration of 

Cleanio 0uta e 

Replaeement Power Cusf 

per Outa 

Incremental tars per year Cost per Ton 

Short (3 days) $720,000 456.35 $4578 

Mid (4.5daprs) $1,14D,©00 456,35 $2,430 

Long (6 days) $1,400 .40D 456.35 $3,06$ 
Ms . Michele Roberge, Administrator 

July 7, 2010 

Page 4 of 7 

Examples of other compliance measures that would be necessary include accelerating the catalyst 

replacement in the SCR management plan. Currently, one layer 4f catalyst is exchanged every 2 

years, To revise this plan by exchanging one layer every year would result in a project expelue 

of approximately $1 million every other year. lricreasing the frequency of catalyst repl.acestnent 

would result in approximately $12 million over the period 2013 thru 2425 . This revised 

replacement plan would not likely result in additional total reduced tons ofNOx for the year, but 

rather hedp manage the brief periodic increased emission rates associated with the events 

described above. 

It should be reiterated that these compliance cneasures-are focused solely on the shortasr duration 

events that typically occur at lower loads with less beat input and for a discreet period of tirne.-

and thus do not resal# in the emission n#' a significant amount NOx emissions . For example, the 

flexibility of partial load operation during high demand paiods is important to the electrical 

reliability of the grid and can significantly protect customers from high energy costs during these 

peak events . It would not be in the public interest to require the unit to come off line since such 

action would be extremely, costly to both reliability and to customers. A half day of nn operation 

when energy prices are over $ l0Unawh will be $25(l,000, $35t},004 or greater; a cost that would 

yield a NOx reduction of only approximately 10 -15 tans. , 

This discussion demonstrates that the implementation of a caLender month and roiling 34 day 

tblmmbtu NOx emission rate can mutt in significant cost to our customers with little 

environmental benefit. To avoid permit exaeedancess due to a short-term NOx rate excursion, 

would require running the SCR harder, more frequent ttir heater cleaning, extended outages, and 

forced outages.' . 

it 1a.cement wer cost associated with outages 

, 

Cost delta with the 

Market 

Total cost bf Outage 

--forcustomers 

Cost pet' 

Ton _ 

1 day $30 $239,U40 $15,936 

$0 $318,720 $21,249 

S50- $398,400 $26,560 

2 days $30 $478,080 $15,936 

S40 S637,440 $21,248 

1$50 $796,840 $26,550 

*assurnes saving of L5 .tons per day .- 

As you are aware, Merrimack Station has aggressively reduced NOx ernisslons for the past 15 

years, Mw total annual emissions reflect that laucla.ble esffart . Going forward, Merc'ima4ic Station 

anticipabes continuing that ef'f ort, while maximizing customer value and providing reliable, 

affordabte power, but to do that sucoessfuily, we do requ'srn operational flexibility. It is critical to 

understand that such operational flexibility will ensure consistent compliance with the monthly 

avezage emission rate while not significatttly increasing total NOx emissions. 

Xe,_ winmvn Station- additional fuel oil i.nforrnetion 

In your June 15, 2010 e,may"l, you also . requested information regarding Newington Station's 

current oil stacks, storage capacity, fuel usage rates, and operational considerations and costs 
Ms. Michele Rc}berge, AdrriinistratDr 

July 7, 2010 

Page 5 of '7 

associated with switching to lower sulfur fuels required by the NH Regional Haze SIP. That 

information is provided below. 

Please describe the current oil stocks (type and quantity) and storage capabilities. 

Newington Station has the capacity to store approximately 732,504 barrels t31 million gallons) of 

fuel oil in four separate Above ground storage tanks (identified as NT-1, ''~2, TNT-2, SR-2, and SR-3). 

Curt+ently, these four tanks contairj approximately 485,000 barrels (20 million gallons) of No . 6 

fuel oil with an average sulfur concentration of approximately 1°fa . ' 

How many hours of operation would this supply at`'current usage rates? What are the ,rates 1hal 

this ostimate is based on? 

Due to various economic conditions, including the rising cost 4ftdo. b fuel oil, lower natural gas~ 

prioes and electric derrxautd, Newingbotn Station has burmd only a limited volume of oil in the past 

couple years. Current conditions are not expeoted to change considerably in the short, term, 

therefore, Newington does not anticipate consuming a significant volume of oil in the next couple 

of years . , . 

It is difficult to assess how long it would take to deplete this fuel oil inventory since fuel oil usage 

is dependent on market conditions and the demand fbr electricity. Newington 8tation will choose 

the fuel or blend-oi`fuel-(~ozly nattaral-gas ; ~ar-natrna[~as-arrd-oi-l-rbased oct°tlte~d+esired-elecirical---.. 

output and the cost of fuel . As you are e.ware, Newington Station will use the most cost effective 

fuel .to maintain its electric costs for the customer. - 

In an effort to understand how this inventory relates to future operating conditions, PSNI-1 has 

looked at different operating scenarios to estimate the length of time it may take to deplete this 

inventory. The gcenaitios include-dil:'ferent~raperating loads, a fuel mix of 75% natural gas and 

25% fuel oil, and an opeeating capacity factor of 5°l0 (see table below) . Although, PSNJi can not 

reliably predict with any certainty how Newington Station twill operate in the next couple years, 

for purposes of this eualuatiott, PSN1a has assumed an average, output level of 15(l MW with a 

heat rate of 11,750 Btu/kWh, 75°fo natural gasl25°l0 oil blend} and a capacity factor of 5% . 

Based on current fuel oil inventory levels, and the scenario presented abovc, Newington Station 

would -deplete its existing fuel supply in 16 years: ~ . . ~ . . . . . , , . 

MW BtadklNh t3tuPgaT OH Capactty Factor 9~. Bsrlyr 7596 gaelT6iL all 

smyf 

R ~ 

9 9tt411 

of current 

tmrsnto rs 

400 10,793 153,848 5 292.046 573161 T 

. " 

' ~r ~.~~,-i .~.qi 

p 

9X C rl 777777. 

_ 

_ 104 1 196p 153846 5 93,85') 2S488 h 21 

60 16,56t! t53 46 5 67,352 18,SSB 29 

Nae! 

Rasumhg an swougs output levsl of 780 MW wKh a heal telsof 11,76D BUM, a 

745XhZ~Y+~aslal aie~ra, snda capsdly rectarof s1i, the lwtrsnl hrvenloty+waulC be 

4eplelwa.ln 16 yaure. Tlwls seealatlo k Mem"ton SIsUcu'e best ssllmais tosss8 an aKrend opera8na~ 

18slary . What tire the specific operational considerations in switching to (1.3°o S oil that do or do not 

make it feasible and costly? 
Ms. Michele Robcrge, Administrator 

July 7, 2010 

Page 6 of 7 

pSN14 understands that tha Regional Ham SIP will rcquire *Newington Station tu burn 0.5% or 

0 .3 lo sulfur oil as part of its compliance aatrategy as earJy as 20 13. In order~to prepare for this 

requirement, Newington Station would need to have the available capacity to store the lower 

sulfur nil . Due to a variety of factors that affect the availability and cost of natural gas, l'SNH 

believes it would be necessary to empty one of the larger bulk fuel oil storage tanks, at a 

rninirnum, to provide the storage capacity of the lower sulfur fuel . Our largest tanks (N1'1 and 

NT-2) currently contain approximately 160,000 barrels each of fuel oil. fiased an the likely 

operating scenario presented above, it -will take more than S years to empty one of die larger 

taitics . 

In this scenario, Newington would either need to operate and utilize the on'-hand fuel or sell some 

of its current inventory if an acceptable pmcess could be identified . !t is difficult to estimate what 

the cost to PSNH would be if this were re+quired, since tlie value of this oil in 3 years is unknown. 

1'SNH currently knows af no way other than consuming oil in the unit to disposeldeplete our 

curre.nt inventory. Although offloading oil frorn the tanks to a barge or ship is beirig oonsiEtlened, 

1\iewington's oil terminal was designed to aocelat deliveries of oil from fuel vessels and was not 

designed to load vessels from the oil tanks. lwlewington Station also does not have the capability 

for loading trucks frotn the oil tanks . Any risk to.personnel safrty or the environment would need 

to be fully eliminated to consider a trausfet' of oil to a vessel or truck_ Theraefore,, at this point, it 

is assumed thstWewiWn Station would be required to burn. the oil in the unit at a potential 

incremental cost to NH eustomers. Consistent with the numbers above, to burn 160,000 barrels 

of oil to empty one of the larger tanks, the unit would have to operate an equivalent of 24 

hours/day for approximately 10 days at 400 MWs. Also, as stated above, due to coonomic 

conditions, hfewington Station has been reserved to protect customers from high priced market 

excursions. If we assume consumption of the inventory of oil is required, then it will be 

necessary for H'ewangton to operate at rates higher dian market rates. In this case, based on-an 

increrrt®ntal cost of $8{1 per MWH, the total cost to customers will- be approximately $8 million. 

This is a significant cost to customers which has no associated environmental benefit. 

81mdiag, this higher sulfur fuel with lower sulfur fuel or natural gas over time is a more cost 

effective option and wil l not result is greater emissions as compared to a targeted depletion effort 

described in the above scenario . Although it is possible to consider the depletion of current fuel 

oil inventories by blending with natural gas, natural gas is not always wailable and- Could not be 

relied upon as a sole compliance option. 

W%at are the estimated casts of making the switak- both capitai and operating costs? 

As presented in our car] ier Deoernber 4,.20491etter, the cost to FSNN in going from a 1 °o sulfur 

oil to a Q.5°Yo sulfur oil could be as higi as $42/bbl (based on fiuel oil prioes from 2005-20t19). 

Similarly, the cost to PSNH in going from Y4/ sutfur oil to 0.3°lo sulfur oil could be as high as 

$51Ibb1. Using the same operating scenario presented above, t'his equates to an additional cost to 

PSNH customers of $1 .2 miYlkonfy~ for the use 0.59r' o sulfur fuel and $1.5 million/year for the 

use 0 .3% . 
Ms. Michele Roberge, Administrator 

July 7, 201 0 

Page 7.of 7 . 

PSNH would be happy to meet with you and your staff to discu&s the information provided 

above. If you -have questions or require additional information, please contact me at 63A--244U or 

Sheila Burke at 634-2512, . 

Sincerely, 

Elizabeth H. Till&son 

Teohnr+cal Business Manager - Generation 

c+c : 

' Sheila Burke, Generation Staff 

Tara Otscm, Newau.gton Station 
August 16,2010 

¢1c 

CONFIDE SINEI SS INFORMATION 0 

(,~f'y~ public Service ofTdew Hampshire 

13est Available Retrofit Technology (BART) 

J' Response to Request. for Additional Information 

SUPPLEMENTAL INFORMATION to PS1N1-I's July 16 Lotter. Response to Request for 

Additional Information re : BART 

As requested, PSNH provides the fQllowing information to support the Merrimaclc Unit #2 (MK2) 

Ndx limits for New fSamgshire's Regional Haze SIP. We are providing this inforniation as 

ooni"identiaE business information since it contains various operating scenarios and financial costs 

whiah are competitively sensitive in nature and could bs harmful if diselosed. 

1vlereimack Station Unit #2: Merritnack Station was the first investor ownod utility in the nation 

to install an SCR to achieve. NChc reductions . Given the operation of the SCR, it is PSWs 

position that maintaining operational flexibility is a critical priority in order to ensure continued 

and cost effective compliance while simultaneously achieving significant reductions in NOac 

emissions. The following infosmation summarizes the primary drivers behind the increased costs 

that would be incurred in ensuring attainment ofNOx emissions rates lower than the currentNOx 

emission lirnits set in the NH Regional Haze SIP. 

I- Operational Impacti; 

Based on historical data R+iK2 typically has 10 to 15 outages per year and approximately $ low 

load operations per year . During these events, SCR operating temperatures are roduced and in 

some instances below the SCR permissive ternperature limit. The SCR temperature permissive 

must be met in order for the SCR to be put in service or kept in service. During start-ups, shutdowns, and partial load operation the temperature, could be lower than the parmissive temperature 

and the SCR cannot be operated. In most cases the timing offhese events is not predictable. 

Exampies of low load situations include, but are not limited to, the following: 

" Forced and planned outage start ups and shutdowns; 

" Loss of one of any equipment pair. Both pieces are neoesaary for full load operation and 

the loss of one results in half load operation (such as forced draft fins, condensate 

pumps); . 

" Loss of the main boiler feed pump; -

+ Loss of coal feeders, condsnser waterbox cleaning, eta.; and 

" Any condition whicii results in the flue gas temperatures to be below the SCR permissive 

t+smparalure will result in the-SCR not able to be put in sarvioe. 

A mom stringent limit could. result in the unnecessary shutdown of the unit rather than Operating 

at partial load, An example of this scenario has occurred in the past when a critical pump failed 

which nostricted full toad operation . While the pump was repaired the unit remained operating 
Supplemental Information to July 16 Response to R+eqt:iest far Additional Information 

August 16, 2010 

Page 2 of 7 

but at a reduced capacity, the duration of this event was approximately 240 hours. 1'SNH's 

custarners received significant benefit from-this Partial load Operation. Replacement power casts 

assaeiatod with this type of event are shown in the Table 1 . . 

Replacement Power Costs: The table below uses, an assumption of $3fl/mwhr 

difference between the cost-of MKZ and the market oost. This number can vary greatly 

depending on energy market pricos . 

Table la. Cost Associated with De-rate F10 ' ility at 0.37 lbJMMBtu I 

Assumes 4.64 tans r hr ' 

Duration of De-Rate 0e-rate 

. capacity 

Remaining Avoided 

Capacity Replacement 

Onlitis Power Cost 

Cast Per eon 

240 hr 132 MW 200 MW S1 ,440,000 

10e hr 1,2 MW 20a Mw $ 600,000 1 so 

50 hr 132 MW 200 Mw S 300,000 $0 

Table ia. Cost Associated with limited De-rate Flexibility at 0.34 IbNMBtu 

Assumes 0.59 tan er hr 

Duradon of DoRsta 

. 

De-rate 

Capadty 

---- Remaining 

capacity 

Online 

Un-avataiect 

Replacement 

Power Cost 

Cost per ton 

244 hr 132 MW 2{7OMtiN $1,440 QOD 310169 

100hr 232 MW 200 MW $ !00 OOa St 169 

50 hr 132 MW 200, MW ~_ T 300,000 1 Aia.169 I 

TL}e opportunity fur partial load oporation during high. demand periods would be even more costly 

to both reliability and to customers. The example mentioned above resultod in a long duration of 

partial load operation but it is important to mote that during periods of high ettergy prices a. much 

shor6er event could also have significant cost. For example; assurning $ $100 per MWh market 

price, operating at 2atlMVlr partial load far a period of 12-hours would avoid $240,000 of 

replacement power cost During this period a NC3x reduction of approximately T tons would be 

realized which equates to $34,004 per ton NCIx. Under some of these scenarios "le,l load 

operation would be eliminated to ensure ~catmistent compliance with the proposed NOx limit 

reduction. 

2 -- Maiate_rrance Impaats 

PS1wTH's highest priority is ensuring carnplzs.nce-with all emission limits. PSNH has reviewed 

historical data and 'concluded that start-ups, shut downs pattial load aperatittg conditions and 

upsets can significantly impact a calendar month average emission rate, To account for tluwe 

evemis FSN'f3 operates I~TC7x control equipment to maintain a ht4x emission rate of approximately 

0.25 Whwl$tu ca.leardar month average. In order to ensure complimce with the 15.4 tonlday 

limit or the equivalent 0.371bA4MBtu emissiatti rate, pSNH targets a {}.15 lb{%CM8tu difference 

between the average N4x emission rate and the specific limit. Further limitations would impact 

operation and increase incremental maintenance and capital -cost. 

in addition to boiler operation and load conditions that affect SCR operation, malfunctions of the 

SCR system and/or associated equipment can also affect the operation of the SCR. MaMrncticrns 
Supplemental Information to July 16 Response to Request for Additional Information 

August 16, 2l}10 

Page 3 of 7 

of the SCR system and/or associated equipment can result in partial or complete reduction of 

SCR performance . 

Also, as part of normal service, the SCR performance degrades overtime. One reason this occurs 

is due to blinding of the catalyst with fly ash. This condition will cause the SCR process control 

settings to compensate by increasing SCR loading to maintain the set point This is necessary 

because the reagent distribution becomes less, uniform as less -surface arM of the catalyst is 

exposed to the flue gas. To manage this condition from developing to the point that a 

maintenance outage is necessary, the SCR is cleaned on-line utilizing soot blowers and oleaned 

during r,utagcs, as -needed. Increased SCR loading could leadjo more frequent maintenance 

outages. It is anticipated that a minimum of three additional SCR cleanings and sir beater washes 

would be necessary to maintain compliance with the +4 .34 Ib1MMHtu proposed NOx limit. 

Cleanings are expected cost between $30,(?ofi and $10f?,OOC? as noted below in item 3, 

Replacement power costs associated with the necessary maintenance outages are also described in 

item 3 be14w. 

Additionally, reagent iqjection grid nozzles am directly exposed to 3he flue gas and become 

fbuled over time. This can affect reagcnt distribution, compounding the effect of blinded c.axatyst. 

The reag=t injection grid is cl=iod, as needed, during outages . Also as catalyst ages, it becomes 

less reactive. This causes a reducdon in ability for NOx conversion to take place. This in itself 

does not typically result in higlter N(7x ernissuans because the SCR has four layers of catalyst, 

inmentionslly staggered in age. However, increased loading of the SCR catalyst would be 

necessary to maintain compliance with the proposed reduction in NOx limit and accelerate 

catalyst degradation . For examplc, the SCR is unuble to perform continually at its maximum 

capability . As a rasult; PSNK needs flexibility to operate the SCR based on current operating 

conditions. Currently the SCR averages greater than 86~fa effrciency. 

Each catalyst layer hes an anticipated functional In of 8 years- and each layer is staggecod in age 

to accommodate replacing one layer every 24 --months, Further T+1C}x limitation would increase 

loading of the SCR and could result in accelerated caftlyst degradation requiring premature 

repiar,ernent. This would result in a lass of investment. Even if minor catalyst degradation 

occurred reducing the catalyst useful life -from 8 years to 7.5 years the replacement schedule 

would need to be adjusted. The change in replacement schedule is neoassary because cataJyst 

replacement projects must coincide with MK2's overhaul schedule which is on a.12-month cyale. 

PSNH would incur a loss of investment of approximately $143,000 annually due to the early 

replacement. It is also irnportent to note that the revised replacement plan would result in 

minimal reductions to the total reduced tons of Nt}x for the year, but rather be put in place tea 

avoid the periodic increased emission rates at the end of the catalyst life . As shown below in 

Table 2, PBNH believes minirnal catalyst replacenzent and maintenance cost are associated with 

the 0.371btNIIvtBtu rates provided certain exceptions for start-up and sbutdown and malfunctions . 
Suplalemeu.t"atl Information to July 16 Response to Request for Additional Enformation 

August 16, 2014 

Page 4 of 7 

Table 2. laeremettal Maintenance and Capital Cost 

Emimion Calendar Annual Increase Predicted 

Limit Month Loea of Maintenanm Incremental 

(IbtNXMBtut) GWtral Investment {Cost of Air cost 

Target of SCR heater and 

(lb(NiN48tu} Catalyst SCR 

0.37 0.22 $0 

034 0.19 s)43,000 I $195,000 1 $338*000 ----~ 

3 -Replacement Pov~rer Ccu;tg associated with the roposeid Rednctifltt ,~.n NOx Emission 

Rate 

Merritnack Station will need to consider a number of additional complisuce O:Ffotts if not 

provided the necessary flexibility to deal with short-term events as described above and the 

operational, restrictions of the SCR. Each has an additional coat as outlined below. 

'There will be incraand maintenance oosts to maintain peak NUx redwticm oambility. For 

example, air heam and SCR clo$nings will be required more frequently became of increased 

loading of the SCR. This results in additional maintenance costs and replacement power costs 

associated with the required outages. It is anticipated that at least one additional-4 .5 day (mid) 

maiaiastxance outage would be necessary to maintain compliance wlth the 0.34 lbMMBtu 

proposed limit . In addition to the maintenance outage additional oleaning will be completed as a 

proactivo measure during ;forced outages resulting in delayed start-ups . Outage duration is from 

time, offline until the unit is phand. 

if air heater washing were aompleftd #a comply with a. step change in the NOc rate as shown 

below, the coat pea ton of MOx reduction would be ex#re=ly costly. Again this number can 

increase greatly if an air heator cleaning was completed during a higb priced market. 

Table a. ratakiul amialan s 8760 hrs 

Emission Rate 

Lb NOxIrnsm BTU 

1hIQx tons em[tftd per year Inc,retnental raduction in 

,j;gibeittlAl.ernlssions tons 

ear 

0,37 5628.34 0 

0.34 3171 .99 ~ +456_ 

Maintenance (Cle*Wng) Goafrs. : $3t?,0{t0 to $100,000 per cleaning 

Replacement Power Costs: The table below uses an assumption of $30trnwhr , 

difference between the cost of )1M and the market cost: This number can Vary greatly 

depending on energy market prices. . . . " 
Supplemental Infornaation to July 16 Response to Request for Additional 111forination 

August 16, 2010 

Page 5 of 7 

Table S. [ of 0,34 UVMMBtu Limit 

Duratlan of 

aeanin 

__ .Replecemant Power Cosi 

per o e 

Short 3 s L 5720 40Q 

Mid 4.3 da ~I l+b(~ 000 

L O d $16,02201.0-00 

It shvuId be reiterated that these compliance measures are fccused solely on the shorter duration 

events that typically occur at lower toads with less hod input and for a discreet period of time 

thus do not result in the emission of s significant amount of Nflx emissions . To meet the 

proposed rates of 0.34 lb N1QxlJti+IMBtu, under the conditions re6renced above, PSNhi may be 

forced to shutdown for air heatarlSCIt cleaning and also may be frmoed to shutdown rather than 

operate at partial load, Each of thesc aforementioned s=narios has significant cost as described 

above. 

Also, with out exception s for short term operational conditions additional incrmnental costs may 

be incurred when considering a calendar month averaging period. PSNH may be forced to delay 

start-up to maintain a 4 .34 IbJMMBtu calendar month average_ It is importaut to note that st=-

up shutdowns, and partial load apersting scenarios may bias a lbJIvIM8tu rate but typfcal result in 

low tonnage ernission total . To rnandge for this situation it may be necessary for PSl`IH to adjust 

the current operating strategy by delaying statt-ups or to prevent a short operating periods during 

the calendar montb, Table 6 ., Wow illustrates the potential cost with delaying aai outage start-up . 

Table b oost assmieted with !~d start-up . . Replacement power _ 

Cost cleft with the Total cost of Outage _ Cost per 

Market for customers- Ton * 

I day $3{3 -- $239,444 $15,936 

$40 $318,720 $2 1,248 

$5ta $399,00 $2,6560 

2 days $30 $478,084 . $31,872 

$40 $637,440 $42,496 

$50 $796,00 $53, 120 

*assumes saving of XS tons per day 
o,` 

n 

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en 

o 

M 

. 

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c° 

; 

~(yy 8 

Q yl~ [~. ~I ti~ ~ ~ 

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V1 H~J " ,`y ~`- 

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S'! 

O_4 

tiw. $ ~ 

rr."+' ~ 

S? 4 

Q 

N 

b 

W 
This analysis demonstrates that the implementation of a 0 .34 16lIv'IMBtu or more sfiriiaMt mte 

will result in signifieant cost to our customers with little environmental benefit. Uis is true 

because a lbIMMBtu rate oould result in running the SCR harder, more frequent air heater 

cleaning,, extended outages, and forced outages, and limit partial load operation . 

FSNH would be happy to meet with you and your staff to discuss the information provided 

above . If you [lave questions orirequire additional ickrmation, please contact Lynn Tillotson at 

b34-2440 or Sheila Burke at 634-2512. 

cc: 

Elizabeth H. Tillotson, TBt,rI, Generation Staff 

Sheila Bucke, Gencratioin Staff 

Tara Olson, Afewington Station 
1'`~S,SMu,3 

AS-F` : pli~ltC ~ePV~Ce 

of New lliamqahire 

l+a 

December 15, 2410 

Robert Scott 

Director 

NH Department of Environmental Services, Air Resources Division 

29 Hazen Drive 

PO Box 95 

Concord, NH 03302-0095 

P5Jti"H Energy Park 

7$0 North Commercial Street . Manchester, N7-1 03101 

Public Service Company of New Hampshire 

P.O. Box 330 

Manchester, NH 03105-0330 

(603)6b9-4000 

www, psnh.com 

The Northeast UtilidesSystem 

Public Service of New Hampshire 

Best Available Retrofit Technology (BART) 

Response to Request for Additional Information 

Dear Mr. Scott: 

As requested in your December 8, 2010 letter, PSNH provides the following additional 

information to support the Merrimack Unit #2 (MK2) NOx limits for New Hampshire's Regional 

Haze SIP. 

Merrimack Station Unit #2: 

Merrimack Station was the first investor owned utility in the nation to install an SCR to achieve 

NOx reductions. Given the operation of the SCR, it is PSNH's position that maintaining 

operational flexibility is a critical priority in order to ensure continued and cost-effective 

compliance while simultaneously achieving significant reductions in NOx emissions. The 

following information summarizes the primary drivers behind the increased costs that would be 

incurred in ensuring attainment of NOx emissions rates lower than the current NOx emission 

limits set in the NH Regional Haze SIP. 

This submittal will analyze the 0.30 lb1MMBtu emission rate averaged on a 3{l-day rolling basis 

as well as the impact of a more stringent limit. A 30-day rolling average is defined as the 

arithmetic average of all hourly rates for the current boiler operating day and the previous 29 

boiler operating day' . This definition is consistent with November 22, 2410 comments provided 

by EPA pertaining to the draft rule. 

~ Badler operatri3g day for units constructed, reconstructed, or modified on or before February 28, 2005, 

means a 24-hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours. (40 CFR 60 Subpart De) 

066161 REV. 11-09 
Mr. Robert Scott, Director 

December 15, 21110 

Page 2 of 7 

The summary of the analysis is provided in the following table, all supporting calculations and 

basis for this determination are detailed in the items below. 

Summary of Analysis i 

Emission 

Limit 

IblARMBtu 

Incremental reduction 

in Potential tons per 

ear, 

Predicted Incremental 

Cost Increase 

$! 

Cost per ton ~ 

0.37 0 $O s0 

0.30 1,065 $880, 000 $826 

0,25-0.30 380 $2,888,400 S7,600 

1--Opemdonal Impacts 

Based on historical data NM typically has 14 to 15 outages per year and approximately 8 low 

load operations per year. During these events, SCR operating temperatures are reduced and in 

some instances below the SCR permissive temperature limit. The SCR temperature permissive 

must be met in order far the SCR to be put in service or kept in servioe. During start-ups, shutdawns, and partial load operation the temperature could be lower than the permissive temperature 

and the SCR cannot be operated . 

Examples of low load situations include, but are not limited to, the following: 

" Forced and planned outage start ups and shutdowns; 

" Loss of one of any equipment pair . Both pieces are necessary for full load operation and 

the loss of one results in half load operation (such as forced draft fans, condensate 

pumps); 

" Loss of the main boiler feed pump; 

" Loss of coal feeders, condenser waterbox cleaning, etc. ; and 

" Any condition which results in the flue gas temperatures to be below the SCR permissive 

temperature will result in the SCR not able to be put in service. 

The ability to manage these events is beneficial to our customers. Adequate flexibility allows the 

high cost of replacement power to be minimized. Limiting operational flexibility could result in 

the unnecessary shutdown of the unit rather than operating at partial load. Tables I a. and 1 b. 

below demonstrate the replacement power cast associated with a 0.30 lbIMMBtu, 30-day rolling 

average emission rate. The opportunity for partial load operation during high demand periods 

would be even more valuable to both reliability and to customers. 

2 Incremental reduction of Potential emissions is the calculated mean of the 0.25-0.3t? range. 
Mr. Robert Scott, Director 

December 15, 2010 

Page 3 of ? 

Replacement Power Costs: The table below uses an assumption of $301rnwhr 

difference between the cost of M22 and the market cost. 

Table la. Cast Associated with De-rate Fiexibility at 0.37 lb1MMl3tu 

Assumes 0.64 tons r hr 

'- 

T 

Dura 7 tjoln of 7 De*-R= De-rate Remaining Avoided 

capacity Capacity Replacement 

Online Power Cost 

240 hr 132 MW 200 MW $1,440,000 

I 

i 

00 hr 132 Mw 200 MW $600,000 

50 hr ~ 132 Mw ~ 200 Mw $300,000 

__

Table 1b. Cost Associated with limited De-rate Flexibility at O.-TO-7 

IblMMBtu 

Assumes 0.51 ton per hr 

- 

. , . 

.x , 

Duration of De- De-rate Remaining Un-avoided 

Rate Capacity Capacity Replacement 

Online Power Cost 

240 hr 

_ 

, ,;, . . 

132 Mw 

.f

204 Mw s1,44(} 000 . . . 

7 

. 

_ , 

J 

Duration of De- De-rate Remaining Avoided 

Rate Capacity Capacity Replacement 

Online Power Cost 

100 hr 132MW 200 MW $600,000 

50 Fir 132MW 2W MW $300,000 

The table is based on a steady state NOx emission rate of d? .22 lb/NIMBtu and a N4x emission 

rate of 0.81bJ1v1MBtu during partial load operation. The maximum number of days MK2 can 

operate in a partial load is 4.2 days (1©0 hrs) when considering a 0.3016J1NMBtu 30-day rolling 

emission limit. 

It should be noted previous submittals did not consider the rolling averaging method, because the 

existing Data Acquisition and Handling System (DAHS) is not configured for this averaging 

period. Based on EPA comments of the proposed Env-A 2300 Rule, PSNH has consulted the 

software vendor which supplies the DAHS and is reviewing the best available option to manage 

this averaging period . Current method of achieving this is through a new "Smart Reporting" 

software trial program. PSNH is confident in working with the vendor that the rolling average 

period will be achievable. Preliminary information suggests that implementing the new software 

has an estimated cost of $10,000 and an annual recurring cost of $2,017(1 . 

2 - Mwatensinm Impacts 

Calendar Month Analysis Previously Submitted),' 

pSNH's highest priority is ensuring compliance with all emission limits . PSNH has reviewed 

historical data and concluded that start-ups, shut downs partial load operating conditions and 

upsets can significantly impact average emission rates. PSNI-1's current method of operation to 

account for these events is to operate NOx control equipment to maintain an emission rate of 
Mr. Robert Scott, Director 

December 15,2010 

Page 4 of 7 

approximately t) .25 lb1MMBtu calendar month average to ensure compliance with the 15.4 

ton/day limit or the equivalent 0.371b/MMBtu emission rate. This method of operation results in 

approximately a 0. t S lWMBtu difference between the average NOx emission rate and the limit, 

this allows for operational flexibility as described above (i .e. start-up, shutdown, partial load 

operation etc). Further limitations based on a calendar month would impact operation and 

increase incremental maintenance and capital cost. For complete breakdown of the costs 

represented in Table 2a. and a calendar month analysis reference PSNH's August 16, 2010, 

submittal. 

Table 2a. Incremental Maintenance and Capital Cost 

Errmissitan Calendar Annual Increase Predicted 

Limit Month Loss of Maintenance Incremental 

(IblNXmBtu) control Investment (Cost of Air Cost 

Target of SCR heater and 

{lbJMMBtu) Catalyst SCR . Maintenance) 

0.37 U.22 so $O S{? ' 

0.34 0.19 $143,000 $195,004 ~33$ OOQ 

3t}-Da~r Rolling Averas~e analysis: 

In addition to the above analysis and based on EPA comments to the draft rule and DES's request 

for additional information, PShtH further analyzed the impact of changing its current method 

which is based on a calendar month average and reviewed a 30-day rolling emission limit, as well 

as the incremental cost associated with this limit. PSNH agrees with EPA that the 30-day rolling 

average method addresses flexibility for start-up, shutdown, emergency and malfunction. 

However, additional flexibility is necessary to maintain short term partial load capability. 

PSNH has determined that a 0.30 lblMMBtu emission rate on a 30-day rolling average will 

accommodate reasonably anticipated operating scenarios while achieving approximately 24°fo 

reduction in potential emissions . The maintenance costs that will be incurred by complying with 

this limit is estimated to be $3{1,004 per year, and can be attributed to additional cleaning and 

inspection of the SCR and air heater. PSNH also analyzed more stringent limits and determined 

costs similar to those represented in Table 2a above would be incurred, The increase cost 

associated with a more stringent limit can be attributed to the cascading effect of increased 

loading of the SCR. 

Increased loading of the SCR results in the following conditions each more irnpactful as loading 

increases. More detail associated with these conditions can be found in the August 16, 2010, 

PSriH submittal. 

1) Blinding of Catalyst; 

2) More Frequent Maintenance Outages; 

3) Fouled reagent distribution nozzles ; 

4) Accelerated catalyst derogation ; and 

S) Loss of investment of catalyst. 
Mr. Robert Scott, Director 

December 15, 2010 

Page 5 of 7 

Table 2b Incremental Maintenance and CaDital C 

based on 

Rolling Average 

Emission Annual Increase 

Limit Loss of Maintenance 

(1blt+lIMBtu) I Investment (Cost of Air 

0.37 

4.3{I 

o.2s-o.3o 

As noted in condition 2 above there will likely be additional maintenance outages to ensure 

optimum SCR performance. Replacement power costs that customers would incur from an 

additional maintenance outage are described in Item 3. 

3 - Replacement Power Costs associated with more stringent limit than Q.301hrI4iNIBtu 

NOx Emission Rate 

Merrima,ck Station will need to consider a number of additional compliance efforts if not 

provided the necessary flexibility to deal with events as described above. 

Increased maintenance costs to maintain peak NQx reduction capability could be signifc,ant. For 

example, air heater and SCR cleanings wilJ be required more frequently because of increased 

loading of the SCR. This results in additional maintenance costs and replacement power costs 

associated with the required outages. In addition to the maintenance outages additional cleaning 

will 

Outage 

be completed 

duration is 

as 

from 

a proactive 

time offline 

measure during forced outages resulting in delayed start-ups . 

until the unit is phased. 

Of SCR heater and 

Catalyst SCR 

Maintenance) 

Predicted 

Incremental 

Cost 

$U s(} so 

$o $30,000 1 x30,000 

1 990 _$195,000 $338,000 

If air heater washing were completed to comply with a step change in the NUx rate as shown 

below, the cost per ton of NQx reduction would be extremely costly . Again this number can 

increase greatly if an air heater cleaning was completed during a high priced market . 

Table mpact of more stringent Limit 

F Replacem~nt Power Cost 

~e Per putaae 

Short (3 days) _ _ IMA ,pvkp 

Mid _ (4.5 days) ~.y. $1 ,100, 000 

Long (6 days) __$1,4A(#,040 

Replacement Power Costs : The table uses an assumption of $3tllmwhr difference 

between the cost of MK2 and the market cost. This number can vary greatly depending 

on energy market prices . 

It should be reiterated to meet more stringent emission rate than t} .30 1b NQxIMM'.Btu, under the 

conditions referenced above, PSNH may be forced to shutdown for air heater/SCR cleaning and 

also may be forced to shutdown rather than operate at partial load. Each of these aforementioned 

scenarios has significant cost as described above in Table S. 
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Mr. Robert Scott, Director 

December 15, 2010 

Page 7of7 

PSNH understand the cost per ton of complying with the {1 .34 thfMMBtu calculated on a 34-day 

rolling average is under the BART threshold and is willing to accept this limit, which results in 

approximately 20% reduction of MI+C2's potential Nt?ar emissions. This analysis demonstrates 

that the implementation of a more stringent limit than t? .301611vINIBtu will result in significant 

cost to our customers -with little cnvironmwrntal benefit . With running the SCR hander, more 

frequent air heater cleaning, extended outages, and forced outages, and limit partial load 

operation. 

If you have questions or require additional information, please contact me at 634-2440 or Sheila 

Bttrkc at 6342512. 

Sincerely, 

Elizabeth H. Tiltotson 

Technical Business Manager--Generation 

cc: 

Sheila Burke, Generation Staff 

David Cribbie, Generation Staff