## BARTAnalysis for PSNH Merrimack Station Unit MK2

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

## BARTAnalysis for PSNHMerrimack 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 awet-bottom, cyclone-type boiler with a heat input rating of3,473 MMBtu/hr andan 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 systemthat 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 . CURRENTLYAVAILABLE RETROFIT TECHNOLOGIES, POTENTIAL COSTS, ANDOTHERENVIRONMENTAL ANDENERGY IMPACTS 2 .1 Retrofit Technologies for NOXControl 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) SNCRis a post-combustion technology that involves injecting ammonia or urea into specific temperaturezones 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 ofthe reagentwithin the required temperature window, the ratioofreagent 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 formsolid sulfur compounds such as ammoniumbisulfate that may become deposited in downstreamequipment.) 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 ofa catalyst to reduce NOx to nitrogen andwater. The SCRreactor can be located at various positions in the process, including upstream of an air heater and particulate control device, or downstreamof 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, spaceBART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 2

velocity, catalyst design, and catalyst condition. NOXemission reductions of about 75 to 90 percent have been obtained with SCRon coal-fired boilers operating in the U .S. 2 .1 .1 Potential Costs of NOx Controls The estimated costs of NOx emission controls for SNCRand SCRat MerrimackStation 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 SCRsystem, the total annual cost is estimated to be $5,070,000, or $312/ton. Stated costs are for year-round operation. Table 2-1. Estimated NOxControl Costs ! Control Capital Cost O&M Cost Total Annual Cost Average Cost Technology ($/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 fromUSEPA, Documentationfor 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 ofNOXremoved for SCR . Because Unit MK2already has SCRcontrols in place, the listed costs servefor 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. PSNHcurrently operates Unit MK2full time in order to meet NOx RACT requirements. Year-round operation is EPA's presumptive normfor 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 halfthat amount, if based on the more recent genericestimates presented in Table 2-l . 2.1.2 Other Environmental and Energy Impacts of NOxControls 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 fromthe 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 fromSNCR 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,BARTAnalysis - PSNHUnit 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 fromSNCRcan react with sulfate to formammoniumbisulfate, which deposits on the economizer, air heater, and other surfaces. Ammoniumbisulfate can also plug filter bags in a baghouse. SNCRmaygenerate nitrous oxide emissions, a greenhouse gas. With SCR, the formation of ammoniumbisulfate may be exacerbated by the ability ofthis catalyst-based technology to oxidize S02 to S03, resulting in higher sulfate concentrations than would otherwise exist. Ammoniumbisulfate formation can be reduced by controlling excess ammonia and using catalysts that minimize S02oxidation. 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 flowof flue gases through it. An SCR may also require a fan upgrade to overcome additional pressure drop across the catalyst. The increase in fancapacity consumes a small amount ofenergy. (In the case ofUnit MK2, the existing fanwas sufficient to accommodate theadditional 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. Adecrease in acid rain production improves water quality and the health ofecosystems 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 throughthe use ofelectrodes, whichare 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 ofindividual 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 drawnto 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 canachieve collection efficiencies of more than 99 percent. For older units, options for upgrading an ESPsysteminclude: replacement of existing control systems with modern electronic controllers; replacement of old-style wire and plate systems inside the ESPwith new, rigid electrode systems; addition of new ESPfields; 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 vacuumcleaner bag.BART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 4

The particle removal efficiency of the fabric filter systemdepends on a variety of particle andoperational parameters. The physical characteristics ofparticle 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 ofbaghouses may exceed 99percent. Mechanical Collectors andParticle 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 fromthe gas streamthrough physical or chemical absorption/adsorption. Scrubbing systems have been shown' to reduce PMIOemissions 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 frompower plant emissions. Consequently, mechanical collectors and scrubbers are not considered further in this analysis for thecontrol of PM emissions. 2.2.1 Potential Costs of PM Controls Table 2-2presents cost data for PM controls as developedfromNESCAUM'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 cubicfeet 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 ,

- reverse air Fabric filter 82-194 26.4-62.1 million 1 .6-2.4 million 3.8-7.6 million 130-260 Fabric filter-pulsejet 58-194 18.6-62.1 million 2.2-3.1 million 3.7-8.3 million 130-280 ' Reference: NESCAUM, Assessment ofControl Technology OptionsforBART-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 1.36millionacfm . Total annual cost includes amortization ofcapital cost over 15 years at 3.0%interest rate. A verage cost perton is based on 29,850tons of PM removedfor ESPs and 29,759 tons ofPM removed forfabric filters.BART Analysis -PSNH Unit MK2 January 14, 2011 ; amendedAugust 26, 2011 Page 5

Thecosts for ESPs and fabric filters are ofsimilar magnitude, with total annual costs ranging fromabout $2.6 million to $8.3 million, or $90to $280 per ton of PM removed. Because Unit MK2already 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$10,000to $30,000per MW . (M . Sankey and R . Mastropietro, "Electrostatic Upgrade Strategy: Get the Most FromWhat 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 froma 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 formto absorb S02 in the flue gas. A PM control device is always located upstreamof 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) FGDprocesses are an attractive option because they allowhigher sulfur removal rates and produce minimalwastewater 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 downstreamprocess equipment. Calciumsulfate (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 from31 to 97 percent with an average of 78 percent (NESCAUM, "Assessment of Control Technology Options for BART-Eligible Sources," March 2005) . For new FGDsystems 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 - PSNHUnit 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 streamwith moisture. Dry scrubbers are oftwogeneral 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 streamto neutralize the acid gases. In spray dryers, the flue gas streamis passed through an absorber tower in whichthe acid gases are absorbed by an atomized alkaline slurry. The S02 removal efficiencies range from40 to 60 percent for existing dry injection systems and from60 to 95 percent for existing lime spray dryer systems (NESCAUM, 2005) . A PM control device (ESP or fabric filter) is always installed downstreamofa dryor semi-dry scrubber to remove the sorbent fromtheflue gas. Low-Sulfur Coal Because S02emissions are directly related to the sulfur content ofthe fuel burned, reducing the amount of sulfur in the fuel reduces S02 emissions. Usually, for operational reasons, a facility cannot make a complete switch fromone 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 ofthe plant (including boiler type), and significant modifications to systems and equipment may be necessary to accommodatethe 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 80percent. 2.3.1 Potential Costs ofSOZ Controls PSNH Merrimack Station is required by New Hampshire law

to install an FGD systemto 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 FGDsystem . Using 2002 baseline emissions of 30,657 tons of SOZ fromUnits MKl and MK2combined, anda minimum captureefficiency of90percent forthis pollutant, the annualized capital cost translates to about $1,400per ton ofSOZ 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-VUClass I Areas," Final, July 9, 2007 (see Reasonable Progress Report, Attachment Y) . The PSNHestimated cost is also more than double the estimate of $300/kW to $500/kW

as reported in a 2008 survey of FGDsystems (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, anddifficulty ofretrofit. The costs of switching to lower-sulfur coal at PSNH Merrimack Station would rest on the incremental cost ofpurchasing the lower-sulfur material at prevailing market prices. Even if a lower-sulfur coal is available at reasonable additional cost, operational considerationsBART 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 ofcoal 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, fromlate Marchto 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 ofS02Controls An FGDsystemtypically operates with high pressure drops across the control equipment, requiring increased energy usage for blowers and circulation pumps. Some configurations of FGDsystems 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 FGDsystemreduces the generating capacity ofthe 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 FGDprocess removes mercury and other metals and solids. Often, gypsum produced in a limestone FGDprocess is recycled or sold to cement manufacturers; otherwise, the sludge must be stabilized and placed in an approved landfill . Gypsummust be dewatered before it can be handled, resulting in a wastewater streamthat 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 fromthe FGDsystem . 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 thestack outlet. 3 . DISCUSSIONOF CURRENT POLLUTIONCONTROL EQUIPMENTANDEMISSIONS 3.1 Discussion of Current NOXEmissions and Controls In 1994, PSNH installed an SCRsystemon Unit MK2, the first such systemto be used on a coal-fired, wet-bottom, cyclone boiler in the United States. The SCRwas designed to meet NOX Reasonably Available Control Technology (RACT) limits. Specifically, Unit MK2is 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 fromUnits MKl and MK2 . The facility must also meet a less stringent federal acid rain programlimit of0 .86 lb NOx/MMBtu. PSNH has a monetary incentive to surpass the NOx RACT requirements because further emission reductions allowthe utility to accumulate DERs. Actual NOx emissions for Unit MK2were reported as 2,871 tons in baseline year 2002. SinceJanuary 2001, the SCRon Unit MK2has reduced NOx emissions to between0.15 and 0 .37 lb/MMBtu (calendar monthlyaverage), 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 .5BART Analysis - PSNHUnit 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 ofthe time and frequently surpasses 90percent. 3.2 Discussion ofCurrent 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 fromthis unit by about 99percent, 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 of0.227 lb/MMBtu and aTSPemissions cap of 3,458.6 tons/year. However, the 0 .227 lb/MMBtu rate does not reflect the true capabilities ofthe 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 fromthis unit were 210tons in 2002. 3.3 Discussion of Current S02 Emissions and Controls New Hampshire lawrequires PSNH Merrimack Station to install and operate a scrubber systemfor both Unit MKl and Unit MK2byJuly 1, 2013. While the primary intent ofthis law is to reduce mercury emissions fromthe company's coal-fired power plants, a major cobenefit is S02 removal . Pursuant to this statutory obligation, NewHampshire issued a permit to PSNH on March 9, 2009, for the construction of a wet, limestone-based FGD systemto control mercury and S02emissions at Merrimack Station. The permit requires an S02control 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 FGDand the corresponding calendar month average emissions reductions during the preceding 12 months of operation, . . .DES will use this data to establish the maximumsustainable rate of SOz emissions reductions for MK2 . The maximumsustainable 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 MK2be less than 90percent. 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 coalburningdevices that limit the sulfur content ofthe coal to 2.0 pounds per million BTUgross 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 S02allowances. Because the particular boiler design does not permit the burning of straight low-sulfur coal, the company blends coals to bring averagesulfur 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 fromUnit MK2were 20,902 tons.BART Analysis - PSNHUnit MK2 January 14, 2011 ; amended August 26, 2011 Page 9

4 . REMAININGUSEFUL 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 MK2was built in 1968 . PSNH's commitment to install new emission controls on this unit demonstrates the company's beliefthat 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 ofthe BART eligibility modeling performed by the Mid-Atlantic/Northeast Visibility Union (MANE-VU) . In previous modeling, MANE-VUused 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 MK2produce 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-VUconsiders 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 of0.1 dv. CALPUFF modeling results for baseline emissions fromUnit MK2exceed all ofthese exemption levels. The BART assessment modeling provides a comparison of visibility impacts fromcurrent 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-deciviewrelationship 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-deciviewBART Analysis - PSNHUnit 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 forMerrimack Station Unit MK2 : Visibility Improvements fromBART Controls On the 20%

Worst NaturalVisibilty Days (deciviews) Pollutant Control Level Acadia Great Gulf Lye Brook S02 90%

with FGD 1 .07 0.83 0.17 NOx Additional 25% with SCRupgrade 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 NOx Ox Additional 25% with SCRupgrade 0 .07 0.06 0.03 PM 90%

with upgraded controls 0.07 0.05 <0 .01 * ' * below sensitivity limit ofmodel Note: Values in boldface are considered as having greater validity in the modeling estimation of maximum visibility benefits fromBART 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 froma 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 fromUnit 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 fromother sources on the 20% worstvisibility 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 fromthis one source results in wide differences in deciviewimpacts for different background visibility conditions at opposite ends ofthe range. 5.1 CALGRIDModeling 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 CALGRIDphotochemical air quality model was performed to assess the effects of installing an FGDsystemon Unit MK2 . The simulation covered the full summer modeling episode (fromMay 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 frompotential newregulations that may be necessary to attain National Ambient Air Quality Standards and other regional air quality goals, beyond those regulations that are already "onthe hooks" or "ontheway."BART Analysis -PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 11

The CALGRID model outputs took the formof 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 convertedtovisibility impacts) . Based on the CALGRIDmodeling results, the installation of scrubber technology with 90% removal efficiency on Unit MK2 is expected to reduce near-stack maximumpredicted 24- hour average S02concentration impacts by up to 21 pg/m3 (8 ppb by volume; see Figure 5- 1) and maximumpredicted 24-hour average PM2 .5 concentration impacts by up to 1 ~Ig/m3. The largest modeled pollutant concentration reductions occurwithin a 50-kilometer radius of the facility. For the affected Class I areas (located 100to 500kilometers away), reductions in the maximumpredicted 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 Maximum24-Hmir SC)2 Differelice Concentrations 2018 B(7Tw

minus R010Take Out PSNH Mertmstck MK-2Serubber

May 15- Sept 1E, 2002 S02 concenn~Atfons (PPB) 4.00 3.00 2 .00 1 .00 0 .50 0.25 fi .10 -1 .00 1-2.00 i 3.00 -4.00 .8.00 6 .00 -7.00 -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 modelingBART Analysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 12

all source sectors. NHDES chose to use CALGRIDfor screening since it is much easier to track the dynamics of impacts fromsingle sources to multiple Class I areas on targeted days, rather thanjust 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 whichthe prevailing wind direction on the 20% worstvisibility days carries Unit MK2emissions 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 forworstvisibility days to the best day calculations. 6 . DETERMINATIONOF BART Based on the completed review and evaluation ofexisting 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 PSNHcurrently operates an SCRsystemon Unit MK2 . This systemwas 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 fromthis unit. SCRyields 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 SCRsystemcould be operated yearround at a cost of $494per ton of NOx removed. For an early-generation SCRthat 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 SCRand wouldachieve only marginal additional reductions in NOx emissions. Because Unit MK2 has an existing SCR systemdesigned to meet other air programrequirements that could be operated yearround at reasonable cost, full-time operation ofthe existing SCRis considered to be BART for NOxcontrol 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 MK2BART Analysis -PSNH Unit MK2 January 14, 2011 ;amended August 26, 2011 Page 13

shows monthly average NOx emission rates normally ranging between 50 and 100percent ofthe 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 companyto guarantee aNOxperformance 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. Thefour major cost components would be: 1 . Thedirect costs ofextra inspections and maintenance cleanings for the air heater and SCRsystem, 2 . Thecost ofpurchased replacement power covering the periods ofadditional scheduled maintenance outages, 3. The cost ofextra catalyst (early catalyst replacement), and 4. The increased cost ofpurchased 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 ofthe described cost factors, PSNH has estimated that a reduction in the NOXemission limit to 0.301b/MMBtu (aneffective reduction of 0 .071b/MMBtu) would have an incremental cost ofapproximately $800pertonof NOxremoved and would result in apotential incremental emission reduction of about 1,000 tons per year. The indicated cost per ton fallswithin the generally regarded cost-effective range. At the same time, PSNHhas 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 notjustifiable 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 PSNHcurrently 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 fromits maximumheat input rate of 3,473 MMBtu/hr and the applicable NOX RACT limit of 15.4tons perday, as follows: [(15.4 tons/day x 1 day/24 hr) x 2,000Ib/ton] = 3,473 MMBtu/hr = 0 .37 lb/MMBtuBART 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 FGDsystemis 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 ofa 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 thevisibility improvement (less than 0.1 dv on the 20 percentworstvisibility days) that would be realized. The current PM

emission limit for Unit MK2is not reflective ofthe 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 TSPemissions to a maximumof 0

.08 lb/MMBtu but will apply this limitation more broadly than BART requires. The new

PM emission limit will affect both of MerrimackStation'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 maximumheat input rating of 3,473 MMBtu/hr was multiplied by MANE-VU's lowest presumptive control level for TSPemissions, 0.021b/MMBtu, to obtain an emission rate of69.461b/hr. 2 . For non-BART Unit MK1, the maximumheat 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 from0

.086 lb/MMBtu) . By including Unit MK1 in the rule, the allowable TSP emissions fromthe two coal-fired units combined will be less than the allowable emissions would be ifthe 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 fromactual 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 ofthe individual emission rates = (0.04 lb/MMBtu x 3,473 MMBtu/hr) + (0 .27 lb/MMBtu x 1,238 MMBtu/hr) =473lb/hr.BARTAnalysis - PSNH Unit MK2 January 14, 2011 ; amended August 26, 2011 Page 15

It is concluded that the existing ESPs, operating in conjunction with the FGDprocess, 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 systemto remove mercury emissions in compliance with New Hampshire law

. As a co-benefit, the FGDsystemis 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 normof 95 percent (generally applicable to facilities larger than Merrimack Station), the FGDsystemis considered to be BART for S02control on Unit MK2 . (Note that, at an installed cost exceeding $1,000/kW, the FGDsystembeing 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. SUMMARYANDCONCLUSIONS 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 systemand is not requiring additional control technology for Merrimack Stationat 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 rollingaverage 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%ofuncontrolled

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