BART Analysis for 

PSNH Merrimack Station Unit MK2 

January 14, 2011 

Amended August 26, 2011 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 1 

BART Analysis for 

PSNH Merrimack Station Unit MK2 

1 . INTRODUCTION 

PSNH Merrimack Station has two coal-fired steam-generating boilers that operate nearly 

full time to meet baseload electric demand. Unit MK2 is a wet-bottom, cyclone-type boiler 

with a heat input rating of 3,473 MMBtu/hr and an electrical output of 320 MW. Installed in 

1968, this generating unit is equipped with selective catalytic reduction to remove oxides of 

nitrogen (NOx) formed during the combustion process. Two electrostatic precipitators 

operate in series to capture particulate matter (PM) in the flue gases. Also, construction is 

nearing completion on a limestone forced oxidation scrubber system that will reduce sulfur 

dioxide (SOZ) emissions. Retrofit options for this unit are limited because the facility 

already has controls in place for these major pollutants of concern. Only a few emission 

control technologies are compatible with the type of boiler design employed, and space for 

new retrofits is very limited. 

2. CURRENTLY AVAILABLE RETROFIT TECHNOLOGIES, POTENTIAL 

COSTS, AND OTHER ENVIRONMENTAL AND ENERGY IMPACTS 

2.1 Retrofit Technologies for NOX Control 

Because of the current boiler design, the only NOx emission control technology options 

available and potentially applicable to Unit MK2 are selective non-catalytic reduction and 

selective catalytic reduction. 

Selective Non-Catalytic Reduction (SNCR) 

SNCR is a post-combustion technology that involves injecting ammonia or urea into specific 

temperature zones in the upper furnace or convective pass. The ammonia or urea reacts with 

NOx in the flue gas to produce nitrogen and water. The effectiveness of SNCR depends on 

the temperature where reagents are injected, the mixing of the reagent in the flue gas, the 

residence time of the reagent within the required temperature window, the ratio of reagent to 

NOx, and the sulfur concentration in the flue gas . (Sulfur in the flue gas, originating from 

the sulfur content of the fuel, can combine with ammonia to form solid sulfur compounds 

such as ammonium bisulfate that may become deposited in downstream equipment.) NOx 

reductions of 35 to 60 percent have been achieved through the use of SNCR on coal-fired 

boilers operating in the United States . 

Selective Catalytic Reduction (SCR) 

SCR is another post-combustion technology that involves injecting ammonia into the flue 

gas in the presence of a catalyst to reduce NOx to nitrogen and water. The SCR reactor can 

be located at various positions in the process, including upstream of an air heater and 

particulate control device, or downstream of an air heater, particulate control device, and 

flue gas desulfurization system. The performance of SCR is influenced by flue gas 

temperature, fuel sulfur content, ammonia-to-NOx ratio, inlet NOx concentration, space 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 2 

velocity, catalyst design, and catalyst condition. NOX emission reductions of about 75 to 90 

percent have been obtained with SCR on coal-fired boilers operating in the U.S . 

2.1 .1 Potential Costs of NOx Controls 

The estimated costs of NOx emission controls for SNCR and SCR at Merrimack Station Unit 

MK2 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 electric 

generating unit (EGU) the size of Unit MK2. For SNCR, the total annual cost is estimated 

to be about $5,110,000, or $593/ton of NOX removed. For an SCR system, the total annual 

cost is estimated to be $5,070,000, or $312/ton. Stated costs are for year-round operation. 

Table 2-1. Estimated NOx Control Costs 

! Control Capital Cost O&M Cost Total Annual Cost Average Cost 

Technology ($/kW) $ ($/yr) ($/yr) ($/ton) 

SNCR 12.1 3,880,000 4,780,000 5,110,000 593 

SCR 117.8 37,710,000 1,910,000 5,070,000 312 

Estimates are derived from USEPA, Documentation for EPA Base Case 2006 (V.3 .0) Using the Integrated 

Planning Model, November 2006. Costs are scaled for boiler size . All costs are adjusted to 2008 dollars. 

Total annual cost is for retrofit of a 320-MW unit with 80% capacity factor and 2,243 million kWh annual 

generation . 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 8,613 tons of NOX removed for SNCR and an estimated 

16,269 tons of NOX removed for SCR. 

Because Unit MK2 already has SCR controls in 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/ton for operation limited to the ozone season (May 1 

through September 30) . These costs are approximately equal to $530/ton and $790/ton, 

respectively, in 2008 dollars. PSNH currently operates Unit MK2 full time in order to meet 

NOx RACT requirements. 

Year-round operation 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 proportional to operating time, the difference in cost between yearround and seasonal SCR operation for Unit MK2 is about $3,300,000, based on PSNH's 

1998 cost estimates. The cost differential could be about half that amount, if based on the 

more recent generic estimates presented in Table 2-l . 

2.1 .2 Other Environmental and Energy Impacts of NOx Controls 

SNCR and SCR both use urea or anhydrous ammonia. Ammonia is a regulated toxic air 

pollutant in New Hampshire. Facilities using these technologies must limit their ammonia 

emissions, which may be released either in their flue gases or as fugitive emissions from the 

handling and storage of urea or anhydrous ammonia. A facility must also maintain a risk 

management plan if the quantities of stored ammonia exceed the applicable regulatory 

threshold. 

Ammonia from SNCR that becomes entrained in the fly ash may affect the resale value or 

disposal cost of the ash. Ammonia in the flue gas may produce a more visible plume, 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 3 

depending on the ammonia concentration in the gas stream . High ammonia concentrations 

in the boiler from SNCR can react with sulfate to form ammonium bisulfate, which deposits 

on the economizer, air heater, and other surfaces. Ammonium bisulfate can also plug filter 

bags in a baghouse. SNCR may generate nitrous oxide emissions, a greenhouse gas. 

With SCR, the formation of ammonium bisulfate may be exacerbated by the ability of this 

catalyst-based technology to oxidize S02 to S03, resulting in higher sulfate concentrations 

than would otherwise exist. Ammonium bisulfate formation can be reduced by controlling 

excess ammonia and using catalysts that minimize S02 oxidation. The air heater and other 

surfaces where the ammonia bisulfate may deposit must be acid washed periodically . Acid 

washing helps to maintain the efficiency of the air heater and prevents plugging to allow the 

free flow of flue gases through it . An SCR may also require a fan upgrade to overcome 

additional pressure drop across the catalyst. The increase in fan capacity consumes a small 

amount of energy . (In the case of Unit MK2, the existing fan was sufficient to accommodate 

the additional pressure drop.) 

NOx emission reductions provide environmental and public health benefits beyond visibility 

improvement - most notably, reductions in acid rain and ground-level ozone. NOX is a 

chemical precursor to ozone formation and is one of the primary compounds contributing 

directly to acid rain formation. A decrease in acid rain production improves water quality 

and the health of ecosystems sensitive to low pH. 

2.2 Retrofit Technologies for PM Control 

PM control technologies available and potentially applicable to Unit MK2 are electrostatic 

precipitators, fabric filters, mechanical collectors, and particle scrubbers. 

Electrostatic Precipitators (ESPs) 

Electrostatic precipitators capture particles through the use of electrodes, which are electrical 

conductors used to make contact with non-metallic parts of a circuit. An ESP consists of a 

small-diameter negatively charged electrode (usually a set of individual wires or a grid) and 

a grounded positively charged plate. In operation, a strong electric charge from the 

negatively charged electrode sets up a one-directional electric field. When particle-laden 

gases pass through this electric field, the particles become charged and are then drawn to the 

positive collecting surface (the plate), where they are neutralized. The particles are then 

collected by washing or knocking the plate, causing the particles to fall into a collection 

hopper. Existing electrostatic precipitators are typically 40 to 60 percent efficient. New or 

rebuilt ESPs can achieve collection efficiencies of more than 99 percent. 

For older units, options for upgrading an ESP system include: replacement of existing control 

systems with modern electronic controllers; replacement of old-style wire and plate systems 

inside the ESP with new, rigid electrode systems; addition of new ESP fields ; or addition of 

entire new units (in series). The feasibility of any particular upgrade will be influenced by 

spatial limitations or design constraints on a case-by-case basis. 

Fabric Filters 

Fabric filtration devices, or baghouses, incorporate multiple fabric filters/bags inside a 

containment structure . These devices work on the same principal as a vacuum cleaner bag. 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 4 

The particle removal efficiency of the fabric filter system depends on a variety of particle 

and operational parameters. The physical characteristics of particle size distribution, particle 

cohesion, and particle electrical resistivity are important variables. Operational parameters 

affecting collection efficiency include air-to-cloth ratio, operating pressure loss, cleaning 

sequence, interval between cleanings, and cleaning intensity. The structure of the fabric 

filter, filter composition, and bag properties also affect collection efficiency. Collection 

efficiencies of baghouses may exceed 99 percent. 

Mechanical Collectors and Particle Scrubbers 

Mechanical collectors, such as cyclones, are most effective at collecting coarse particulate 

matter (i .e ., particles with a diameter of 10 micrometers or larger). Finer particles escape 

cyclones along with the flue gases. For this reason, mechanical collectors are generally 

most useful when used in conjunction with other pollution control equipment. The typical 

collection efficiency of mechanical collectors is about 85 percent for larger particle sizes. 

Scrubbing systems involve the injection of water and/or chemicals into the flue gas to wash 

unwanted pollutants from the gas stream through physical or chemical absorption/adsorption . 

Scrubbing systems have been shown' to reduce PMIO emissions by 50 to 60 percent but are 

generally less effective for removal of fine particles. 

Because mechanical collectors and particle scrubbers are more costly and less efficient than 

other control options (i .e ., ESPs, baghouses), these lower-performing technologies are rarely 

used today for removing particulate matter from power plant emissions. Consequently, 

mechanical collectors and scrubbers are not considered further in this analysis for the control 

of PM emissions. 

2.2 .1 Potential Costs of PM Controls 

Table 2-2 presents cost data for PM controls as developed from NESCAUM's Assessment of 

Control Technology Options for BART-Eligible Sources, March 2005 . Approximate cost 

ranges are provided for two types of ESPs and two types of fabric filters applicable to a 

retrofit installation the size of Unit MK2. Capital and operating costs are based on flue gas 

flow rates in actual cubic feet per minute (acfm) . 

Table 2-2. Estimated PM Control Costs 

Capital Cost O&M Cost Total Average 

Control Technology Annual Cost Cost 

($/kW) ($) ($/yr) ($/yr) ($/ton) 

Dry ESP 73-194 23 .3-62.1 million 1 .1-1 .9 million 3 .0-7 .1 million 100-240 

Wet ESP 73-194 23 .3-62.1 million 0.6-1 .6 million 2 .6-6 .8 million 90-230 , 

Fabric filter - reverse air 82-194 26 .4-62.1 million 1 .6-2 .4 million 3 .8-7 .6 million 130-260 

Fabric filter-pulse jet 58-194 18 .6-62.1 million 2 .2-3 .1 million 3 .7-8 .3 million 130-280 ' 

Reference: NESCAUM, Assessment of Control Technology Options for BART-Eligible Sources, March 2005. All costs 

are adjusted to 2008 dollars. Total annual cost is for retrofit of a 320-MW unit with 80% capacity factor and flue gas 

flow rate of 1.36 million acfm. Total annual cost includes amortization of capital cost over 15 years at 3 .0% interest rate . 

Average cost per ton is based on 29,850 tons of PM removed for ESPs and 29,759 tons of PM removed for fabric filters . 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 5 

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. Because 

Unit MK2 already has two dry ESPs installed and operating, the tabulated costs are useful for 

comparative purposes only. For facilities with existing ESPs, typical equipment replacement 

costs to upgrade performance may be in the range of $10,000 to $30,000 per MW. (M. Sankey 

and R. Mastropietro, "Electrostatic Upgrade Strategy : Get the Most From What You Have," 

Hamon Research-Cottrell, Inc., April, 1997.) 

2.2 .2 Other Environmental and Energy Impacts of PM Controls 

PM controls collect particulate matter, or fly ash, suspended in the flue gases. In some 

cases, the fly ash is injected back into the boiler, an arrangement that improves boiler 

efficiency by recapturing the residual heating value of the fly ash. If the fly ash is not 

reinjected, it must be either landfilled or reclaimed, e.g ., as a supplement in concrete 

production or as a component in other manufactured products. 

2.3 Retrofit Technologies for SOZ Control 

S02 control technologies available and potentially applicable to Unit MK2 are scrubber 

systems for flue gas desulfurization, and use of low-sulfur coal. 

Flue Gas Desulfurization 

Scrubber systems use chemical reagents to "scrub" or "wash" unwanted pollutants from a gas 

stream. Flue gas desulfurization (FGD) processes based on this technology concept are 

classified as either wet or dry. Wet scrubbers are more commonly used at power plants to 

control acid gas emissions. Scrubbers of all types may be effective for the removal of 

particulate matter, mercury, sulfur dioxide, and other air pollutants . 

In the wet FGD process, an alkaline reagent is applied in liquid or slurry form to absorb 

S02 in the flue gas. A PM control device is always located upstream of a wet scrubber . 

Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the 

commercially proven wet FGD systems. Wet regenerative (meaning the reagent material 

can be treated and reused) FGD processes are an attractive option because they allow higher 

sulfur removal rates and produce minimal wastewater discharges . 

For coal-fired power plants, the reagent is usually lime or limestone; and the reaction 

product is calcium sulfite or calcium sulfate. The solid compounds are collected and 

removed in downstream process equipment. Calcium sulfate (gypsum) sludge produced in 

FGDs can be recycled into saleable byproducts such as wallboard, concrete, and fertilizer. 

Sulfate products that are not recycled must be landfilled . 

S02 removal efficiencies for existing wet limestone scrubbers range from 31 to 97 percent 

with an average of 78 percent (NESCAUM, "Assessment of Control Technology Options 

for BART-Eligible Sources," March 2005). For new FGD systems installed at large (>750 

MW) coal-fired power plants, the presumptive norm is 95 percent reduction of SOZ emissions 

(USEPA, Appendix Y to Part 51 - Guidelines for BART Determinations under the Regional 

Haze Rule). 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 6 

Dry (or semi-dry) FGD processes are similar in concept to wet FGD processes but do not 

saturate the flue gas stream with moisture. Dry scrubbers are of two general types: dry sorbent 

injection and spray dryers . With the former, an alkaline reagent such as hydrated lime or 

soda ash is injected directly into the flue gas stream to neutralize the acid gases . In spray 

dryers, the flue gas stream is passed through an absorber tower in which the acid gases are 

absorbed by an atomized alkaline slurry . The S02 removal efficiencies range from 40 to 60 

percent for existing dry injection systems and from 60 to 95 percent for existing lime spray 

dryer systems (NESCAUM, 2005). A PM control device (ESP or fabric filter) is always 

installed downstream of a dry or semi-dry scrubber to remove the sorbent from the flue gas. 

Low-Sulfur Coal 

Because S02 emissions are directly related to the sulfur content of the fuel burned, reducing 

the amount of sulfur in the fuel reduces S02 emissions. Usually, for operational reasons, a 

facility cannot make a complete switch from one fuel type to another. Instead, the facility 

may be able to blend different fuels to obtain a lower-sulfur mix that emits less SOZ upon 

combustion - for example, blending low-sulfur bituminous or subbituminous coal with a highsulfur bituminous coal. The feasibility of fuel switching or blending depends on the 

physical characteristics of the plant (including boiler type), and significant modifications to 

systems and equipment may be necessary to accommodate the change in fuels. Switching to 

a lower-sulfur coal can affect coal handling and preparation systems, ash handling systems, 

boiler performance, and the effectiveness of PM emission controls. To meet federal acid rain 

requirements, many facilities have switched to lower-sulfur coals, resulting in S02 emission 

reductions of 50 to 80 percent. 

2.3 .1 Potential Costs of SOZ Controls 

PSNH Merrimack Station is required by New Hampshire law to install an FGD system to 

reduce mercury emissions (with SOZ removal as a co-benefit) at both Unit MK1 (not a 

BART-eligible unit) and Unit MK2 (a BART-eligible unit). A company estimate for the 

project placed the capital cost at $457 million, or $1,055/kW (both amounts in 2008$) to 

install a wet limestone FGD system. Using 2002 baseline emissions of 30,657 tons of SOZ 

from Units MKl and MK2 combined, and a minimum capture efficiency of 90 percent for this 

pollutant, the annualized capital cost translates to about $1,400 per ton of SOZ removed. 

The project cost is said to be in line with the costs of multiple-unit scrubber installations 

occurring elsewhere in the country. However, PSNH's estimated cost per kilowatt is at least 

triple the cost range for FGD systems as reported in MACTEC Federal Programs, Inc., 

"Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I Areas," Final, 

July 9, 2007 (see Reasonable Progress Report, Attachment Y) . The PSNH estimated cost is 

also more than double the estimate of $300/kW to $500/kW as reported in a 2008 survey of 

FGD systems (George W. Sharp, "What's That Scrubber Going to Cost?," Power, March 1, 

2009). The higher cost-per-kW for Unit MK2 may reflect industry-wide increases in raw 

material, manufacturing, and construction costs but may also reflect site-specific factors 

such as unit size, type, and difficulty of retrofit. 

The costs of switching to lower-sulfur coal at PSNH Merrimack Station would rest on the 

incremental cost of purchasing the lower-sulfur material at prevailing market prices . Even if 

a lower-sulfur coal is available at reasonable additional cost, operational considerations 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 7 

related to the physical characteristics of Unit MK2 may dictate the choice of coal for this 

unit. (Only certain types of coal can be used in wet-bottom, cyclone boilers; and lower-sulfur 

coals have already been tested and adopted for regular use at this facility.) Commodity spot 

prices for coal vary considerably. For example, from late March to early May 2009, the price 

spread between Northern Appalachia coal (<3 .0 S02) and Central Appalachia coal (1 .2 S02) 

ranged from $10 to $25 per ton (source: Energy Information Administration, 

http ://www.eia .doe.gov/fuelcoal.html) . 

2.3 .2 Other Environmental and Energy Impacts of S02 Controls 

An FGD system typically operates with high pressure drops across the control equipment, 

requiring increased energy usage for blowers and circulation pumps. Some configurations 

of FGD systems also require flue gas reheating to prevent operational problems (including 

physical damage to equipment), resulting in higher fuel usage per, unit of net electrical 

generation. Documentation for EPA's Integrated Planning Model (IPM(g) indicates that a 

wet FGD system reduces the generating capacity of the unit by about 2 percent. 

Flue gas desulfurization has impacts on the operation of solid waste and wastewater 

management systems. In addition to removing SOz, the FGD process removes mercury and 

other metals and solids. Often, gypsum produced in a limestone FGD process is recycled or 

sold to cement manufacturers; otherwise, the sludge must be stabilized and placed in an 

approved landfill . Gypsum must be dewatered before it can be handled, resulting in a 

wastewater stream that requires treatment. This wastewater stream increases the sulfates, 

metals, and solids loadings on the receiving wastewater treatment plant. Sometimes an 

additional clarifier is required to remove wastewater solids coming from the FGD system. 

Wet FGDs increase the amount of water vapor entrained in the flue gas. The result is a 

lower stack exit temperature and a more visible plume at the stack outlet . 

3. DISCUSSION OF CURRENT POLLUTION CONTROL EQUIPMENT AND EMISSIONS 

3.1 Discussion of Current NOX Emissions and Controls 

In 1994, PSNH installed an SCR system on Unit MK2, the first such system to be used on a 

coal-fired, wet-bottom, cyclone boiler in the United States . The SCR was designed to meet 

NOX Reasonably Available Control Technology (RACT) limits . Specifically, Unit MK2 is 

subject to a NOx RACT Order limit of 15.4 tons per calendar day and a second NOx RACT 

Order limit of 29.1 tons per calendar day for combined emissions from Units MKl and 

MK2. The facility must also meet a less stringent federal acid rain program limit of 0.86 lb 

NOx/MMBtu. PSNH has a monetary incentive to surpass the NOx RACT requirements 

because further emission reductions allow the utility to accumulate DERs. Actual NOx 

emissions for Unit MK2 were reported as 2,871 tons in baseline year 2002. 

Since January 2001, the SCR on Unit MK2 has reduced NOx emissions to between 0 .15 and 

0.37 lb/MMBtu (calendar 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 0.371b/MMBtu.) Data available from the period of 1993 to early 1995, prior to operation 

of the SCR, provide a baseline for uncontrolled NOx emissions in the range of 2.0 to 2.5 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 8 

lb/MMBtu. Taken together, this information indicates that Unit MK2 achieves a control 

level that exceeds 85 percent most of the time and frequently surpasses 90 percent. 

3.2 Discussion of Current PM Emissions and Controls 

PSNH Merrimack Station Unit MK2 has two electrostatic precipitators (ESPs), dry type, 

operating in combination with a fly ash reinjection system . The ESPs have been upgraded 

with state-of-the-art electronic controls. Installation of the ESPs has reduced PM emissions 

from this unit by about 99 percent, based on a review of 2002 emissions data. The current air 

permit for the facility requires that Unit MK2 meet a total suspended particulate (filterable 

TSP) limit of 0 .227 lb/MMBtu and a TSP emissions cap of 3,458.6 tons/year. However, the 

0.227 lb/MMBtu rate does not reflect the true capabilities of the ESPs to control particulate 

emissions. Stack testing on three separate dates in 1999 and 2000 found actual TSP 

emissions to be 0 .043, 0.041, and 0 .021 lb/MMBtu after controls . The most recent test, in 

May 2009, produced an emission rate of 0.032 lb/MMBtu. Total TSP emissions from this 

unit were 210 tons in 2002. 

3 .3 Discussion of Current S02 Emissions and Controls 

New Hampshire law requires PSNH Merrimack Station to install and operate a scrubber 

system for both Unit MKl and Unit MK2 by July 1, 2013 . While the primary intent of this 

law is to reduce mercury emissions from the company's coal-fired power plants, a major cobenefit is S02 removal. Pursuant to this statutory obligation, New Hampshire issued a 

permit to PSNH on March 9, 2009, for the construction of a wet, limestone-based FGD 

system to control mercury and S02 emissions at Merrimack Station. The permit requires an 

S02 control level of at least 90 percent for Unit MK2. The specific language of the permit 

states as follows : 

Beginning on July 1, 2013, . . .S02 emissions shall be controlled to 10 percent of the uncontrolled 

SOZ emission rate (90 percent SOZ removal) . . .The Owner shall submit a report no later than 

December 31, 2014 that includes the calendar month average SOZ emission rates at the inlet and 

outlet of the FGD and the corresponding calendar month average emissions reductions during the 

preceding 12 months of operation, . . . DES will use this data to establish the maximum sustainable 

rate of SOz emissions reductions for MK2. The maximum sustainable rate is the highest rate of 

reductions that can be achieved 100 percent of the time . . .This established rate shall be 

incorporated as a permit condition for MK2. Under no circumstances shall the SOz removal 

efficiency for MK2 be less than 90 percent. 

These permit conditions effectively require that actual S02 removal efficiencies exceed 90 

percent on average for Unit MK2. This plant must also meet general regulations for coalburning devices that limit the sulfur content of the coal to 2 .0 pounds per million BTU gross 

heat content averaged over any consecutive 3-month period, and 2 .8 pounds per million 

BTU gross heat content at any time. Since 2002, the facility has operated well within these 

fuel limits . More specifically, PSNH has worked to control coal sulfur content to reduce 

S02 emissions and minimize the purchase of S02 allowances . Because the particular boiler 

design does not permit the burning of straight low-sulfur coal, the company blends coals to 

bring average sulfur content to a level that is consistent with sustainable boiler operations . 

PSNH must also meet a fleet-wide SOZ emissions cap of 55,150 tons/year effective for all 

electrical generating units at its Merrimack, Newington, and Schiller Stations. In 2002, 

actual S02 emissions from Unit MK2 were 20,902 tons. 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 9 

4. REMAINING USEFUL LIFE OF UNIT 

Where a reasonable control option is available for a BART-eligible unit, the unit should be 

controlled in a manner consistent with BART and the expected useful life of the unit . 

Originally, electric generating units were estimated to have a life expectancy of 30 to 40 

years, but many units are lasting 50 years or more. In many cases, it is less expensive to 

keep existing units operating than to build replacement facilities and/or new transmission 

lines. Merrimack Station Unit MK2 was built in 1968. PSNH's commitment to install new 

emission controls on this unit demonstrates the company's belief that this unit is capable of 

supplying electricity to the region for many years beyond the present. 

5. DEGREE OF VISIBILITY IMPROVEMENT ANTICIPATED FROM BART 

5.1 CALPUFF Modeling Analysis 

The New Hampshire Department of Environmental Services (NHDES) conducted a CALPUFF 

modeling analysis to assess the anticipated visibility effects of BART controls at PSNH 

Merrimack Station Unit MK2. Visibility can be quantified using deciviews (dv), a 

logarithmic unit of measure to describe increments of visibility change that are just 

perceptible to the human eye. NHDES conducted a set of CALPUFF runs for Unit MK2 

under controlled and uncontrolled conditions . Before considering the findings of this 

modeling work, it is useful to review the results of the BART eligibility modeling performed 

by the Mid-Atlantic/Northeast Visibility Union (MANE-VU). 

In previous modeling, MANE-VU used CALPUFF to assist in the identification of BARTeligible sources. This modeling assumed natural visibility conditions (about 7 dv) to produce 

the most conservative results possible, thereby minimizing the number of sources that would 

"model out" of BART requirements . Under these conditions, uncontrolled emissions from 

Unit MK2 produce theoretical CALPUFF worst-case impacts of 2.24 dv at Acadia National 

Park. EPA considers it acceptable to exempt sources when this form of conservative 

modeling indicates that a source produces less than 0.5 dv of impact. MANE-VU considers 

an exemption level of 0.2 to 0.3 dv to be more appropriate but prefers, and has applied, an 

even more conservative exemption level of 0 .1 dv. CALPUFF modeling results for baseline 

emissions from Unit MK2 exceed all of these exemption levels . 

The BART assessment modeling provides a comparison of visibility impacts from current 

allowable emissions with those from the post-control emission level (or levels) being 

assessed . Results are tabulated for the average of the 20% worst natural visibility (about 

11 .7 to 12.4 dv) and 20% worst baseline visibility (about 22.8 dv) modeled days at each 

nearby Class I area. For any pair of control levels evaluated, the difference in the level of 

impairment predicted is the degree of improvement in visibility expected. 

Rather than use CALPOST to manipulate background deciview calculations, NHDES 

normalized CALPUFF modeling results and then applied predicted concentrations to a 

logarithmic best-fit equation to the actual observed PM2.5-to-deciview relationship measured 

at Acadia NP, Great Gulf NWR, and Lye Brook NWR. Thus, 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-extinction-to-deciview 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 10 

equation. In accordance with BART guidance, the natural visibility condition (about 7 dv) 

was used for exemption purposes, and 20% worst natural and 20% worst baseline visibility 

were used for assessment of BART control effectiveness . The CALPUFF-predicted 

visibility benefits from BART controls on 20% worst natural and 20% worst baseline 

visibility days are as follows: 

Table 5-1. CALPUFF Modeling Results for Merrimack Station Unit MK2: 

Visibility Improvements from BART Controls 

On the 20% Worst Natural Visibilty Days (deciviews) 

Pollutant Control Level Acadia Great Gulf Lye Brook 

S02 90% with FGD 1 .07 0.83 0.17 

NOx Additional 25% with SCR upgrade 0.21 0 .18 0.10 

PM 90% with upgraded controls 0.16 0 .12 0.03 

On the 20°1o Worst Baseline Visibility Days (deciviews) 

Pollutant Control Level Acadia Great Gulf Lye Brook 

S02 90% with FGD 0.26 0.20 0.03 

N 

Ox 

Ox Additional 25% with SCR upgrade 0.07 0.06 0.03 

PM 90% with upgraded controls 0.07 0.05 <0.01 * ' 

* below sensitivity limit of model 

Note: Values in boldface are considered as having greater validity in the modeling estimation of maximum 

visibility benefits from BART controls . 

While the full impact of Unit MK2 was predicted to be as large as 2 .24 dv at Acadia 

National Park under natural conditions, the predicted visibility benefit from a 90% reduction 

in sulfur emissions at Unit MK2 on the most visibility-impaired days is only 0.26 dv. At 

first this result may appear to be too low; however, on further examination, it is found that 

CALPUFF predicts the same amount of sulfate from Unit MK2 reaching Acadia under both 

best and worst visibility conditions. The 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 concentrations to much higher levels . Because the deciview scale is 

logarithmic, the same mass reduction of 0.259 pg/m3 of sulfate from this one source results 

in wide differences in deciview impacts for different background visibility conditions at 

opposite ends of the range. 

5.1 CALGRID Modeling Analysis 

NHDES also conducted a screening-level analysis 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 performed to assess the effects of 

installing an FGD system on Unit MK2. The simulation covered the full summer modeling 

episode (from May 15 to September 15, 2002) and used MANE-VU's 2018 beyond-on-theway (BOTW) emissions inventory scenario as a baseline . The BOTW emissions scenario 

reflects controls from potential new regulations that may be necessary to attain National 

Ambient Air Quality Standards and other regional air quality goals, beyond those 

regulations that are already "on the hooks" or "on the way." 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 11 

The CALGRID model outputs took the form of ambient concentration reductions for SOZ, 

PM2,5, and other haze-related pollutants within the region . NHDES post-processed the 

modeled concentration reductions to estimate the corresponding visibility improvements at 

nearby Class I areas (i .e ., concentration impacts were converted to visibility impacts) . 

Based on the CALGRID modeling results, the installation of scrubber technology with 90% 

removal efficiency on Unit MK2 is expected to reduce near-stack maximum predicted 24-

hour average S02 concentration impacts by up to 21 pg/m3 (8 ppb by volume ; see Figure 5-

1) and maximum predicted 24-hour average PM2.5 concentration impacts by up to 1 ~Ig/m3 . 

The largest modeled pollutant concentration reductions occur within a 50-kilometer radius of 

the facility . For the affected Class I areas (located 100 to 500 kilometers away), reductions 

in the maximum predicted concentrations of S02, PM2.5, and other haze-related pollutants, 

combined, are expected to yield a nominal improvement in visibility (about 0.1 deciview) on 

direct-impact hazy days. 

Figure 5-1 

Episode Maximum 24-Hmir SC)2 Differelice Concentrations 

2018 B(7Tw minus R010 Take Out PSNH Mertmstck MK-2 Serubber 

May 15- Sept 1E, 2002 

S02 

concenn~Atfons 

(PPB) 

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3 .00 

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0.50 

0 .25 

fi .10 

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1-2 .00 

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-8 .00 

NHDES 4~3V9 

CALr;R D 245 

Modeling Dornain 

NHDES's use of CALGRID differs somewhat from EPA's preferred methodology. 

CALPUFF is EPA's preferred model for performing long-range visibility assessments of 

individual sources to distant Class I areas, in part because it is considered to be a 

conservative model or one that is capable of estimating 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 emissions are controlled. 

CALGRID is a sister program to CALPUFF and shares much 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 visibility days and cumulative impacts by modeling 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 12 

all source sectors. NHDES chose to use CALGRID for screening 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 maximum impact conditions that may or may not be associated 

with 20% worst days. While the CALPUFF model's CALPOST post-processor has an 

option for application on 20% worst natural visibility days, it does not in fact isolate those 

20% worst natural visibility 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 directions that may be preferentially included or excluded on such days. 

The above analyses indicate that CALPUFF and CALGRID have aligned better in their 

predictions than might be expected. This result may be attributed to the similar chemistry 

used in both models and to the specific circumstances of this case in which the prevailing 

wind direction on the 20% worst visibility days carries Unit MK2 emissions directly toward 

Class I areas such as 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 directions for worst visibility days to the best day calculations . 

6. DETERMINATION OF BART 

Based on the completed review and evaluation of existing and potential control measures for 

PSNH Merrimack Station Unit MK2, it is determined that the NOx, PM, and S02 controls 

described below represent Best Available Retrofit Technology for this unit . 

6.1 Selecting a Pollution Control Plan for NOx 

PSNH currently operates an SCR system on Unit MK2. This system was installed in 1994 

to meet the requirements of NOx RACT and the ozone season NOx budget program. SNCR 

is the only other control technology available for controlling NOx emissions from this unit. 

SCR yields higher NOx removal rates and is more cost-effective than SNCR. For units that 

already have seasonally operated SCRs, year-round operation is EPA's presumptive norm for 

BART. PSNH estimated, in 1998, that the existing SCR system could be operated yearround at a cost of $494 per ton of NOx removed. 

For an early-generation SCR that has received previous retrofits to improve its performance, 

further upgrades to this NOx control system appear to be impractical and would yield 

negligible (generally less than 0 .1 dv) improvement in visibility . Additional upgrades would 

require major redesign and construction at a location where physical space is already 

constrained. Capital costs would be comparable to installing a new SCR and would achieve 

only marginal additional reductions in NOx emissions. Because Unit MK2 has an existing 

SCR system designed to meet other air program requirements that could be operated yearround at reasonable cost, full-time operation of the existing SCR is considered to be BART 

for NOx control on this unit. 

EPA has provided presumptive BART emission rates that are broadly applicable to power 

plants larger than 750 MW but are not necessarily representative of smaller EGUs like Unit 

MK2. In the case of Unit MK2, 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 control efficiency, would be above the presumptive norm of 0.10 lb/MMBtu 

applicable to larger EGUs of its type. The past decade of emissions records for Unit MK2 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 13 

shows monthly average NOx emission rates normally ranging 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/MMBtu*, corresponds to a NOx control rate of approximately 85 percent. 

PSNH has described operational and infrastructural changes that would be needed in order 

to allow the company to guarantee a NOx performance level lower than the current effective 

limit of 0.37 lb/MMBtu (see Supporting Documentation, attached) . This could be 

accomplished by increasing the frequency of maintenance cleanings and accelerating the 

rate of catalyst replacement to ensure a high level of NOx reduction capability at all times. 

The four major cost components would be: 

1 . The direct costs of extra inspections and maintenance cleanings for the air heater and 

SCR system, 

2. The cost of purchased replacement power covering the periods of additional 

scheduled maintenance outages, 

3 . The cost of extra catalyst (early catalyst replacement), and 

4 . The increased cost of purchased replacement power associated with reduced 

flexibility to operate at partial load. 

Calculations performed by PSNH assume a NOx emission rate of 0.8 lb/MMBtu during 

partial load operation. This relatively high emission rate means that, the lower the emission 

limit is set, the smaller must be the total time of partial load operation as a percentage of 

total operating time . As the emission limit is set lower, outage time would necessarily have 

to increase to prevent excessive emissions (that would otherwise occur under partial load 

operation). Replacement power at such times would represent an unavoidable cost. 

Taking into account all of the described cost factors, PSNH has estimated that a reduction in 

the NOX emission limit to 0.301b/MMBtu (an effective reduction of 0.071b/MMBtu) would 

have an incremental cost of approximately $800 per ton of NOx removed and would result in 

a potential incremental emission reduction of about 1,000 tons per year. The indicated cost 

per ton falls within the generally regarded cost-effective range. At the same time, PSNH has 

estimated that further reduction of the NOx emission limit to 0.25-0 .30 lb/MMBtu would 

yield diminishing returns, with the incremental cost per ton approximately one order of 

magnitude higher. NHDES concurs that such additional costs are not justifiable given the 

fact of negligible visibility benefit. When the historical performance of Unit MK2 is 

considered alongside the operational factors and estimated costs to achieve a higher 

performance level, NHDES finds that a NOx emission rate of 0.30 lb/MMBtu reasonably 

represents the sustainable performance capabilities of this unit and is also appropriate as a 

BART control level for NOx on a 30-day rolling average basis. 

6.2 Selecting a Pollution Control Plan for PM 

PSNH currently operates two ESPs in series on Unit MK2. Mechanical collectors (cyclones) 

are effective only for coarse particle removal and would be impractical as a retrofit for Unit 

MK2, where the more efficient ESPs already exist. Fabric filters have performance levels 

* The 0.37 lb/MMBtu NOX emission rate for MK2 is calculated from its maximum heat input rate of 3,473 

MMBtu/hr and the applicable NOX RACT limit of 15.4 tons per day, as follows: 

[(15 .4 tons/day x 1 day/24 hr) x 2,000 Ib/ton] = 3,473 MMBtu/hr = 0.37 lb/MMBtu 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 14 

comparable to ESPs and are a suitable PM control technology for power plant emissions. 

However, fabric filters are also impractical as a retrofit for Unit MK2 under present 

circumstances: ESPs already exist, physical space at the facility is limited, and the addition 

of an FGD system is now in progress . 

The existing ESPs were previously upgraded to include state-of-the-art electronic controls. 

Further upgrading would require either major equipment substitutions or the addition of a 

third ESP in series with the two existing units . Adding a third ESP might be physically 

impossible because of the aforementioned 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 $10,000 to $30,000 

per MW. For Unit MK2, additional costs of this magnitude are not easily justified when 

weighed against the visibility improvement (less than 0 .1 dv on the 20 percent worst visibility 

days) that would be realized. 

The current PM emission limit for Unit MK2 is not reflective of the performance capabilities 

of the existing ESPs. However, the volume of available stack test data is insufficient to 

establish a conclusive, long-term BART performance level of 0.04 lb/MMBtu or lower for 

this unit. New Hampshire has adopted a new administrative rule that will hold TSP emissions 

to a maximum of 0.08 lb/MMBtu but will apply this limitation more broadly than BART 

requires. The new PM emission limit will affect both of Merrimack Station's coal-fired utility 

boilers - Unit MK1 (not a BART-eligible facility) and Unit MK2 - as explained below. 

In the new rule, Units MK1 and MK2 are placed within a regulatory "bubble" for the 

purposes of TSP compliance . This arrangement serves both necessity and convenience 

because the two units will share a common stack. The following procedure was used to 

calculate the maximum allowable emission rate for the combined source : 

1 . For BART-eligible Unit MK2, the maximum heat input rating of 3,473 MMBtu/hr 

was multiplied by MANE-VU's lowest presumptive control level for TSP emissions, 

0 .021b/MMBtu, to obtain an emission rate of 69 .461b/hr . 

2. For non-BART Unit MK1, the maximum heat input rating of 1,238 MMBtu/hr was 

multiplied by the unit's permitted TSP limit, 0 .27 lb/MMBtu, to determine an 

emission rate of 334.26 lb/hr. 

3 . The individual emission rates were summed to yield a total maximum emission rate 

of 403 .72 lb/hr. This value was divided by the total maximum heat input rate, 4,711 

MMBtu/hr, to obtain the new TSP emission limitation of 0.08 lb/MMBtu (rounded 

down from 0.086 lb/MMBtu). 

By including Unit MK1 in the rule, the allowable TSP emissions from the two coal-fired 

units combined will be less than the allowable emissions would be if the limit for Unit MK1 

remained separate and unchanged, and the limit for Unit MK2 were reduced to 0 .04 

lb/MMBtu, its approximate performance capability from actual stack test data.t 

' For the bubble concept, the combined emission rate = 0 .08 lb/MMBtu x 4,711MMBtu/hr = 377 lb/hr. For the 

stand-alone alternative, the sum of the individual emission rates = (0 .04 lb/MMBtu x 3,473 MMBtu/hr) + (0.27 

lb/MMBtu x 1,238 MMBtu/hr) = 473 lb/hr. 
BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 15 

It is concluded that the existing ESPs, operating in conjunction with the FGD process, will 

provide the most cost-effective controls for particulate emissions. Continued operation of 

the existing ESPs, controlled to emission rates not exceeding the new emission limit described 

above, represents BART for PM control on Unit MK2. 

6.3 Selecting a Pollution Control Plan for S02 

PSNH Merrimack Station is installing a flue gas desulfurization system to remove mercury 

emissions in compliance with New Hampshire law. As a co-benefit, the FGD system is 

expected to remove more than 90 percent of SOZ emissions . Because this installation is 

already mandated and because it will attain SOZ removal rates approaching the BART 

presumptive norm of 95 percent (generally applicable to facilities larger than Merrimack 

Station), the FGD system is considered to be BART for S02 control on Unit MK2. (Note 

that, at an installed cost exceeding $1,000/kW, the FGD system being added to this facility 

is more expensive than the industry average and might not be viewed as cost-effective if its 

only purpose were to satisfy BART requirements .) 

7. SUMMARY AND CONCLUSIONS 

Table 7-1 summarizes Best Available Retrofit Technology for PSNH Merrimack Station 

Unit MK2 for the pollutants NOx, PM, and SOZ. The summary includes existing controls 

that have been determined to meet or exceed BART requirements as well as changes in 

progress that are consistent with BART requirements . NHDES has already issued a 

temporary permit (construction permit) for the installation of the flue gas desulfurization 

system and is not requiring additional control technology for Merrimack Station at this time in 

order to comply with BART. 

Table 7-1. Summary of BART Determinations for Unit MK2 

Pollutant Current Emission Additional Emission BART Controls BART ', 

Controls Controls in Progress Emission Limit 

NOx SCR None SCR 0.301b/MMBtu, 

30-day rolling average 

PM Two ESPs in series None Two ESPs in series 0.081b/1VIIVIBtu 

total suspended 

particulate (TSP) 

SOZ Fuel sulfur limits set at Flue gas desulfurization Flue gas desulfurization 10% of uncontrolled 

2.0 lb sulfur/MMBtu (FGD), with required (FGD), with required SOZ emissions, 

(averaged over 3 mos.) S02 percent reduction SOz percent reduction calendar monthly 

and 2.8 lb sulfur/MMBtu set at maximum set at maximum average 

at any time sustainable rate, but not sustainable rate, but not 

less than 90% on a less than 90% on a 

calendar monthly calendar monthly 

average basis average basis ; existing 

fuel sulfur limits to 

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