## BARTAnalysis for PSNHNewington Station Unit NTl

January 14, 2011 AmendedAugust 26, 2011BARTAnalysis - PSNHUnit NT1 January 14, 2011 ; amendedAugust 26, 2011 Page 1 

## BARTAnalysis for PSNH Newington Station Unit NT1 1. INTRODUCTION Unit NT1 is the sole electrical generating unit at PSNH Newington Station. It operates at irregular times, principally during periods ofpeak electric demand. Power is derivedfroman oil- and/or natural-gas-fired steam-generating boiler with a heat input rating of 4,350 MMBtu/hr and an electrical output of 400 MW . Installed in 1968, the boiler is equipped with low-NOx burners, an overfire air system, andwater injection to minimize the formation of oxides of nitrogen (NOx) during the combustion process. The facility also has an electrostatic precipitator (ESP) to capture particulate-matter (PM) in the flue gases. Partial control ofS02emissions is provided by sulfur content limits on the fuel oil . 2 . CURRENTLYAVAILABLE RETROFIT TECHNOLOGIES, POTENTIAL COSTS, ANDOTHERENVIRONMENTALANDENERGY IMPACTS 2.1 Retrofit Technologies for NOx Control NOX emission control technology options available and potentially applicable to Unit NT1 are combustion controls, selective non-catalytic reduction, and selective catalytic reduction. Combustion Controls Controls on the combustion process can reduce NOx formation by as much 75 percent. Combustion controls or firing practices include such measures as staged combustion, limiting excess air, providing overfire air, recirculating the flue gases, using low-NOx burners, and injectingwater or steam . Operating with lowexcess air involves restricting the amount of combustion air to the lowest possible level while maintaining efficient and environmentally compatible boiler operation. Because less oxygen is introduced into the combustion zone, NOX formation is inhibited. Adjustments to the air supply may affect normal boiler operation and may reduce operational flexibility. The effectiveness of limiting excess air varies fromboiler to boiler, but typical NOXreductions are 10to 25percent fromuncontrolled levels. Overfire air (OFA) is a method where some of the total combustion air is diverted fromthe burners and injected through ports above the top burner level . This staged combustion reduces fuel-based NOX formation in the oxygen-deficient primary combustion zone and limits thermal NOXformation becauseofthe lower peak flametemperature (i .e., combustion occurs over a larger portion of the furnace) . For oil-fired boilers, OFA typically reduces NOXemissions by 15 to 45 percent. . Flue gas recirculation (FGR) involves reinjecting a portion of the cooled flue gas into the combustion chamber. FGR dilutes the oxygen concentration in the combustion zone and depresses peak flame temperature by adding a large amount of cooled gas to the fuel-airBART Analysis - PSNH Unit NT1 January 14, 2011 ; amended August 26, 2011 Page 2

mixture, resulting in less thermal NOxformation. FGRreduces NOxemissions by about 40 to 60percent in oil-fired boilers. Low-NOx burners (LNB) are designed to control fuel/air mixing and increase heat dissipation. These alternative burners can be installed on new boilers or retrofitted on older units. LNBtechnology integrates staged combustion in the burner. Atypical LNBcreates a fuel-rich primary combustion zone, thus lowering the formation of fuel-based NOx. At the same time, limited combustion air reduces the flame temperature, minimizing the formation of thermal NOx. Combustion is completed in a lower-temperature, fuel-lean zone. LNB retrofits have been shownto reduce NOxformation by 30to 55 percent. Water or steamcan be injected into the boiler combustion zone to reduce the peak flame temperature, with a corresponding reduction in thermal NOx formation. Water/steam injection can reduce NOx emissions by as much as 75 percent in gas-fired boilers and slightly less in oil-fired boilers. Selective Non-Catalytic Reduction (SNCR) SNCRis a post-combustion technology that involves injecting ammonia or urea into specific temperature zones in the upperfurnace or convective pass. The ammonia or urea reacts with NOXin the flue gas to produce nitrogen andwater. The effectiveness of SNCRdepends 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 ratio ofreagent 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.) There is limited commercial experience with SNCR fromwhich tojudge its effectiveness for oilfired boilers. NOx reductions of 35 to 60 percent have been achieved through the use of SNCR on some oil-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 NOxto nitrogen andwater. The SCRreactor 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 velocity, catalyst design, and catalyst condition. NOx emission reductions of about 75 to 90 percent have been obtained with SCRon coal-fired boilers operating in the U .S. Although there is little experience with SCRsystems on oil-fired boilers, SCRretrofits for oil-fired EGUs using the latest technology would be expected to achieve NOx control efficiencies toward the upper endofthis range. 2.1 .1 Potential Costs of NOx Controls The estimated costs of NOx emission controls at Newington Station Unit NT1 are presented in Table 2-1 . These estimates are based on assumptions used in EPA's Integrated Planning Model for the EPA Base Case 2006 (V.3.0), for retrofitting an electric generating unitBART Analysis - PSNH Unit NT1 January 14, 2011 ; amended August 26, 2011 Page 3

(EGU) the size ofUnit NT1 . For low-NOx burners,the total annual cost is estimated to be about $830,000, or $1,470 per ton of NOx removed. With the addition of overfire air, this cost rises to $1,130,000, or $1,600 per ton. For SNCR, the total annual cost is estimated to be $730,000, or $1,030 per ton. For SCR, the total annual cost doubles to $1,410,000; but the unit cost is only moderately higher at $1,180 per ton of NOx removed. Because Unit NTl is primarily a peak-load generator, these estimates are based on a 20-percent capacity factor. Table 2-1. Estimated NOxControl Costs Control Capital Cost O&M Cost Total Annual Cost Average Cost Technology ($/kW) $ ($/yr) ($/yr) ($/ton) LNB 21 .9 7,900,000 170,000 830,000 1,470 LNB+OFA 29.8 10,700,000 230,000 1,130,000 1,600 SNCR 12.3 3,300,000 450,000 730,000 1,030 SCR 36.7 11,500,000 440,000 1,410,000 1,180 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 400-MW unit with 20%capacity factor and 701million 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 the following estimates of NOX removed: 563 tons for LNB; 704 tons for LNB+OFA; 704tons for SNCR ; and 1,196tons for SCR

. Low-NOx burners have previously been reported to operate in a cost range of $200 to $500 per ton of NOx removed (NESCAUM, Assessment of Control Technology Options for BART-EligibleSources, March 2005) ; however, this cost range is likely to be more relevant to larger plants operating at higher capacity factors thanNewington Station. 2.1.2 Other Environmental and Energy Impacts of NOx Controls SNCR and SCRboth 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 . Afacility 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, depending on the ammonia concentration in the gas stream . High ammonia concentrations in the boiler fromSNCR can react with sulfate to formammoniumbisulfate, which deposits on the economizer, air heater, and other surfaces. Ammoniumbisulfate can also plug filter bags in a baghouse. SNCRmay generate nitrous oxide emissions, a greenhouse gas. With SCR, the formation of ammoniumbisulfate 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. Ammoniumbisulfate formation can be reduced by controllingBART Analysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 4

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 ofthe air heater and prevents plugging to allow the free flowof flue gases through it. An SCRmay also require a fan upgrade to overcome extra pressure drop across the catalyst. The increase in fan capacity consumes a small amount ofenergy. NOXemission reductions provideenvironmental 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 NT1 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 fromthe negatively chargedelectrode sets up a one-directional electric field. When particleladengases pass throughthis electric field, the particles become charged andare then drawn to the positive collecting surface (the plate), where they are neutralized. The particles are then collected by washingor knocking the plate, causing the particles to fall into acollection hopper. Existing electrostatic precipitators are typically 40to 60 percent efficient. New or rebuilt ESPs canachieve collection efficiencies ofmore than 99percent. For older units, options for upgrading an ESPsysteminclude: replacement of existing control systems with modern electronic controllers; replacement ofold-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 acase-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. 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 mayexceed 99 percent.BART Analysis -PSNHUnit NTI January 14, 2011 ; amended August 26, 2011 Page 5

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 ofmechanical collectors is about 85percent for larger particle sizes. Scrubbing systems involve the injection ofwater 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 offine 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 andscrubbers 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 developedfromNESCAUM'sAssessment 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 NT1 . Capital and operating costs are based on flue gas flow rates in actual cubic feet per minute (acfm) . Table 2-2

. PM Control Costs Capital Cost O&M Cost Total Average Control Technology Annual Cost Cost ($/kW) $ ($/yr) ($/yr) ($/ton) Dry ESP 73-194 29.3-78.1 million 1 .4-2.4 million 3.8-9.0 million 27,000-63,000 Wet ESP 73-194 29.3-78.1 million 0.8-2.0 million 3.2-8.5 million 23,000-60,000 Fabric filter-reverse air 82-194 33.2-78.1 million 2.0-3.0 million 4.8-9.6 million 14,000-29,000 Fabric filter-pulsejet 58-194 23.4-78.1 million 2.7-3.9 million 4.7-10.4 million 14,000-31,000 Reference: NESCAUM, Assessment ofControl TechnologyOptionsforBART-EligibleSources, March2005. (Note that these costs were developedfor coal-fired boilers.) All costs are adjusted to 2008 dollars. Total annual cost is forretrofit ofa400-MW

unit with 20%

capacity factor and flue gas flowrate of 1 .71 million acfm . Total annual cost includes amortization ofcapital cost over 15 years at 3.0%interest rate. Average cost perton is basedon 142tons of PM removed for ESPs and 335tons of PM removed for fabric filters. The costs for ESPs and fabric filters are of similar magnitude, with total annual costs ranging fromabout $3.2 million to $10 .4 million, or $14,060 to $63,000 per ton of PM removed. Because Unit NT1 already has an ESPinstalled 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 $30,000 per MW . (M . Sankey and R

. Mastropietro, "Electrostatic Upgrade Strategy: Get the Most From What You Have," Hamon Research-Cottrell, Inc., April, 1997.)BARTAnalysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 6

2.2.2 Other Environmental and Energy Impacts of PM Controls PMcontrols 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 NTl are scrubber systems for flue gas desulfurization, and use oflow-sulfur coal . Flue Gas Desulfurization Scrubber systems usechemical 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 SOZ in the flue gas. APM control device is always located upstreamof a wet scrubber. Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the commercially proven wet FGDsystems. Wet regenerative (meaning the reagent material can be treated and reused) FGDprocesses 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 calciumsulfite 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 notrecycled 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 normis 95 percent reduction of SOZ emissions (USEPA, Appendix Yto Part 51 -Guidelines for BART Determinations under the Regional Haze Rule) . While experience with FGDsystems on smaller, oil-fired EGUs is generally lacking, it is anticipated that such iiistallations would performat a similar level, achieving S02 removal efficiencies of90percent or greater. Dry (or semi-dry) FGDprocesses are similar in concept to wet FGD processes but do not saturate theflue gas streamwith moisture. Dry scrubbers are oftwo general types: drysorbent 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 which the acid gases are absorbed by an atomized alkaline slurry. The SOZ removal efficiencies range from40 to 60 percent for existing dry injection systems and from60 to 95 percent for existing lime sprayBART Analysis -PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 7

dryer systems (NESCAUM, 2005) . A PMcontrol device (ESP or fabric filter) is always installed downstreamofa dryor semi-dry scrubber to remove thesorbent fromtheflue gas. Low-Sulfur Fuels Because S02emissions are directly related to the sulfur content of the fuel burned, reducing the amount of sulfur in the fuel reduces S02 emissions. For facilities that burn fuel oil, switching to a lower-sulfur fuel may be a cost-effective control option. Switching from high-sulfur residual fuel oil to low-sulfur residual fuel oil or low-sulfur distillate fuel oil is one possible control strategy. For facilities that have the option to replace fuel oil with natural gas or can co-fire with natural gas, increasing the use of natural gas is another effective control strategy. Sulfur dioxide emissions fromburning natural gas are negligible in comparison to those fromburning fuel oil . When substituting natural gas for fuel oil, the resulting S02 emission reductions are roughly proportional to the fraction of natural gas burned on a Btu-equivalent basis. 2.3.1 Potential Costs ofS02Controls There is little or no experience with, or cost data on, flue gas desulfurization at oil-fired power plants. However, the technology is similar to FGDfor coal-fired plants. Therefore, the costs of an FGDsystemfor PSNHNewington Station may be crudely approximated by extrapolating from

the costs of FGDfor PSNH MerrimackStation. The flue gas desulfurization system at Merrimack Station is being installed to reduce mercury emissions (with S02 removal as a co-benefit) at its two coal-fired boilers. These units have a combined generating capacity of 433 MW, or slightly greater than the capacity of Newington Station Unit NTl . The company's capital cost estimate for the wet limestone FGDsystemis $457 million, or $1,055/kW (both amounts in 2008$), which is said to be in line with project costs for multiple-unit scrubber installations occurring elsewhere in the United States. However, PSNH's estimated cost per kilowatt is at least triple the cost range for FGDsystems as reported in MACTEC Federal Programs, Inc., "Assessmentof 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 FGDsystems (George W

. Sharp, "What's That Scrubber Going to Cost?," Power, March 1, 2009) . The higher cost-per-kWfor Unit MK2 may reflect industry-wide increases in rawmaterial, manufacturing, and construction costs but may also reflect site-specific factors such as unit size, type, anddifficulty ofretrofit. Using the latest Merrimack Station estimate of $1,055/kW for scaling purposes, the total capital cost of a wet limestone FGD systemfor Newington Station Unit NT1 would be roughly $422,000,000. Much caution is necessary in relating this number to the Newington facility: Note that the cost of FGDon oil-fired boilers previously has been estimated to be about twice the cost of FGDon coal-fired boilers of comparable size (NESCAUM, 2005) . The costs of switching to a low-sulfur fuel oil at Unit NT1 would depend on the incremental costs of purchasing the lower-sulfur product at prevailing market prices. The long-term price differential between 1 .0%-sulfur (low-S) residual fuel oil and 2.0%-sulfur residual fuel oil is estimated to be about 7.5 cents/gallon. The differential between 0 .5%-sulfur (ultralow-S) residual fuel oil and 2.0%-sulfur residual fuel oil is estimated to be about twicethisBART Analysis -PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 8

amount, or 15 cents/gallon (both estimates in 2008$ based on Energy Information Agency compiled price data for the period 1983-2008 .) Using these unit prices, the total cost of switching to low-S residual fuel oil is approximately $3.3 millionperyear, or $1,900per ton of S02 emissions removed; and the cost of switching to ultra-low-S residual fuel oil is approximately $6.6 million per year, or also $1,900 per ton of SOZ emissions removed (both estimates basedon 2002 actual fuel oil usage; note that fuel oil usage in 2006-2009has been below 2002 levels). These results imply that thecosts ofswitching fuel oils may be relatively constant on a $/ton basis as long as supplies are adequate. Table 2-3 summarizes the approximate costs of flue gas desulfurization and fuel switching as SOZ control options for PSNH Newington Station Unit NT1 . The costs for switching from2.0%-S residual fuel oil to 1 .0%-S or 0 .5%-S residual fuel oil are listed. At any given time, the actual cost of fuel switching would vary in proportion to the applicable fuel price differential . Table 2-3 . SOZ Control Costs Control Capital Cost O&M Cost Total Average Technology Annual Cost Cost ($/kW) $ ($/yr) ($/yr) ($/ton) FGD 1,055 422,000,000 unknown unknown unknown Switchto 1 .0%-S oil - - 3,300,000 3,300,000 $1,900 Switch to 0.5%-S oil - - 6,600,000 6,600,000 $1,900 Capital cost estimate for FGDis based on reported cost per kilowatt-hour for FGD system at PSNH Merrimack Station

. Actual costs for Newington Station could be much higher. O&M costs for fuel switching are based on 2002 annual fuel usage of44,140,000gallons and estimated fuel price differential of 7.5 or 15 0/gallon for substitution of 1 .0%-S or 0.5%-S residual fuel oil, respectively. In a similar analysis performed independently by PSNH (see attached letter), the company has estimated the costs offuel switching based on historical fuel prices for the period 2002- 2009 as compiled by Platts+. Table 2-4 reproduces the fuel oil prices used by PSNH : Table 2-4

. Historical Fuel Oil Prices, 2002-2009($/barrel) Year 2%S Oil 1%S Oil 0.7%S Oil 0 .5%S Oil 0.3%S Oil 2002 21 .20 22.45 23.26 23.80 25.25 2003 24.95 27.48 29.26 30.45 32.63 2004 25.25 27.92 30.04 31 .46 34.53 2005 37.00 41 .00 44.00 46.00 50.10 2006 45.50 46.30 48.46 49.90 54.12 2007 53.70 53.45 56.54 58.60 62.86 2008 75.25 77.80 81 .10 83.30 92.16 2009 49.90 50.75 51 .98 52.80 55.83 Source: Platts. 2009 data include costs through 9/09. + + Platts, a division ofThe McGraw-Hill Companies, is aprovider of energy informationservices.BART Analysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 9

Using this historical fuel price record and PSNH's calculated SOz emission reductions from fuel switching, the New Hampshire Department of Environmental Services (NHDES) has prepared alternate estimates of the increased costs of fuel switching from2.0%-S residual fuel oil to 1 .0%-S or 0 .5%-S residual fuel oil, and other variations, in Table 2-5. Costs are listed in terms of $/barrel, $/hour, and $/ton. This analysis produces somewhat less conservative (lower) estimates of the cost of fuel switching than the $1,900/ton estimate given above. In either analysis, the cost-effectiveness of switching to 0 .5%-sulfur residual fuel oil appears reasonable as long as supplies remain stable. Switching to 0 .3%-sulfur fuel oil could also prove reasonable in the future if prices were to stay within their recent historical rangeand future supplies could be assured. Table 2-5

. Costs of Fuel Switching Based on Historical Fuel Oil Prices Fuel SOZ Emission

Reduction* Increased Cost

($/barrel Increased Cost

($/hour)** $/ton of

SOZ Removed*** Switch (Ib/hr) low high low high low high 4 2%to 1% 5,228 .7 0 4 0 2,692 0 1,030 1% to 0.7% 1,470.3 1 3.3 673 2,222 414 3,022 0.7%to 0.5% 957.0 1 2.2 673 1,482 586 3,095 0.5%to 0.3% 935.3 3 9 2,020 6,059 2,967 12,957 2% to 0.7% 6,699.0 2 7 1,34 4,712 402 1,407 42% to 0 .5% 7,656

.0 3 9 2,019 6,058 528 1,583 2% to 0 .3% 8,591 .3 4 17 2,692 11,444 627 2,664 * Calculated reduction, fromPSNHletter dated December 4, 2009 . ** $/barrel = 42 gal/barrel = 0.153846 MMBtu/gal x MMBtu/hr = $/hr *** $/hr = lb/hr x 20001b/ton = $/ton Besides switching residual fuel oils to reduce S02 emissions, other proposed options include replacing 2.0%-S residual fuel oil with low-sulfur distillate fuel oil or natural gas. Although distillate fuel oil is sometimes used during startup of Unit NT1, the boiler is not designed to operate routinely on this fuel ; and retrofitting the boiler for this purpose would involve major capital expenditure. Burner replacements to combust distillate fuel oil could exceed $20to $30 million (approximately $1 to 2 million per burner) in direct capital costs, not includingtheadditional costs ofengineering andany required auxiliary equipment. The cost determinations associated with using natural gas are more complicated. Unit NT1 can be fired with either natural gas or liquid fuel (i .e., residual fuel oil or biofuel), or it can be co-fired with both types of fuel at the same time. However, because of physical limitations to the boiler's design, the unit cannot operate at full capacity when fueled solely by natural gas. In order to reach maximumheat input, the boiler must either use liquid fuel or be co-fired with both fuel types. (Unit NT1 can operate at up to about 50 percent of maximumheat input from natural gas, with no corresponding limitation on liquid fuel .) Firing Unit NT1 entirely with natural gas might be technically feasible butwould require more than just burner replacements: it would require modifications to other major boiler components or replacement of the entire boiler. Such measures cannot be economically justified. However, using natural gas -to the extent that Unit NT1 can burn this fuel with existing equipment - remains a viable option as long as the cost ofthis fuel is competitive with the cost ofresidual fuel oil and biofuel .BART Analysis -PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 10

Volatile energy commodity prices in recent years and the uncertainty of future fuel prices make it difficult to provide a useful estimate ofthe cost of substituting natural gas for residual fuel oil . As seen in Figure 2-1, past prices of natural gas and petroleumfuels, on a BTUequivalent basis, exhibit similar trends; but the price differentials show wide variation from year toyear. Consequently, no cost estimate for this fuel switching option is presented.

Figure 2-l . Comparison ofFossil Fuel Prices for Electric Generation

in New England (1990-2008) 3 m a`r a N d N a` d
Q 1,600 1,600 1 .400 1,300 1,200 1,100 1,000 900 800 

### 700

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 Data source: Energy InformationAdministration, FormEIA-923, "Power Plant Operations Report ."

http://www

.eia.doe.gov/cneaf/electricity/st_profiles/e_profiles sum .html 0 600 500 400 300 200 100

2.3.2 Other Environmental and Energy Impacts of S02 Controls 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(p) indicates that a wet FGDsystemreduces thegenerating capacity ofthe unit by about 2percent. Flue gas desulfurization has impacts on the operation of solid waste and wastewater management systems. In addition to removing S02, 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 . -I- ----~ ---- i ~ -

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Wet FGDs increase the amount of water vapor entrained in the flue gas. The result is a lowerstack exit temperature anda more visible plumeat the stack outlet. Switching to lower-sulfur fuel oil generally reduces boiler maintenance requirements because less particulate matter is emitted. With fewer material deposits occurring on internal boiler surfaces, the intervals between cleanings/outages can be longer. Also, because lower-sulfur oil reduces the formation of sulfuric acid emissions, corrosion is reducedand equipment life is extended. 3 . DISCUSSIONOF CURRENT POLLUTIONCONTROL EQUIPMENTANDEMISSIONS 3 .1 Discussion of Current NOx Emissions and Controls PSNH Newington Station Unit NTI currently operates with low-NOx burners, an overfire air system, and water injection to minimize NOX formation. For compliance with NOx RACT requirements, the facility's existing air permit limits NOx emissions fromthis unit to a daily average of 0

.35 lb/MMBtu when burning oil and 0 .25 lb/MMBtu when burning a combination of oil and gas. NHDES reviewed emissions data for Unit NTI for the period from2003 to 2005, when more than 99 percent ofthe gross heat input came fromresidual fuel oil . Monthly average NOx emissions ranged between 0.21 and 0 .30 lb/MMBtu. These values compare favorably with the facility's NOx RACT limits. Actual NOx emissions from this unit were 943 tons in 2002. 3.2 Discussion ofCurrent PM Emissions and Controls Unit NTI has an electrostatic precipitator to capture PM emissions. In an EPAinspection report on this unit fromDecember 15, 1989, a table of design values for the ESP listed a particulate removal efficiency of 93 percent. It is unknown whether the stated efficiency is representative of actual long-term performance. The facility's air permit (TV-OP-054, March 9, 2007; administrative amendment, December 17, 2007) sets an emission limit of 0.22 lb/MMBtu total suspended particulate matter (filterable TSP) . The single available stack test on Unit NT1 measured a controlled TSPemission rate of0 .058 lb/MMBtu,whichis well below

the permit limit. The tested emission rate lies within the expected range for a properly operating ESP at a plant like Newington and may serve as a better measure of performance than any stated efficiency for this control device. Actual TSPemissions from Unit NTI were 198tons in 2002. 3.3 Discussion of Current S02 Emissions and Controls Sulfur dioxide emissions are partially controlled at PSNH Newington Station by existing limits on fuel oil sulfur content. Permitted fuel sulfur limits are 2.0%sulfur by weight for No. 6 fuel oil and 0

.4%sulfur by weight for No. 2 fuel oil . Unit NTI does not have an individual limitation on sulfur dioxide emissions but is subject to an annual cap of 55,150 tons of S02 for all electrical generating units at PSNH's Merrimack, Newington, and Schiller Stations combined. Actual SOZ emissions fromUnit NT1 were 5,226 tons in 2002. The average sulfur content of No. 6 fuel oil burned that year was 1 .2%by weight, which is typical ofvalues fromthe most recent decade. In 2009, the average was 1 .0% .BART Analysis -PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 12

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. Newington Station Unit NT1 was built in 1969 . However, because this facility runs primarily on fuel oil, its remaining useful life may depend more on future commodity supplies/prices and other external factors than on the longevity ofplant equipment. 5 . DEGREE OF VISIBILITY IMPROVEMENT ANTICIPATED FROM BART 5.1 CALPUFF Modeling Analysis NHDES performed a set of CALPUFF model runs for the New Hampshire BART-eligible sources under controlled and uncontrolled conditions. The same methodologies used for the CALPUFF modeling work for Merrimack Station Unit MK2were applied to the modeling for Newington Station Unit NT1 . 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 NTl produce theoretical CALPUFF worst-case impacts of 1 .22 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 ofimpact. 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 of 0 .1 dv. CALPUFF modeling results for baseline emissions fromUnit NT1 exceed all of these exemption levels. The CALPUFF-predicted visibility benefits fromBART controls on 20% worstnatural and 20%

worst baseline visibility days are presented in Table 5-1 . As seen in the table, more benefit would result generally from S02 emission reductions than NOx emission reductions. This finding reinforces MANE-VU's early determination that SOZ was the primary target pollutant for maximizing visibility improvements. NOx, while also an important visibility impairing pollutant, reacts with ammonia less preferentially than does SOZ and is also less hydrophilic than SO2 . As a result, NOx has a lower rate of formation ofhaze-causing particles and impairs visibility less effectively than a similar mass ofS02

.BART Analysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 13
Table 5-1 . CALPUFF Modeling Results for Newington Station Unit NT1 :

Visibility Improvements fromBART Controls 01u the2(l% Pollutant SOZ

NOx PM Control Level

FGD (90%sulfur reduction*) 1 .0%-S residual fuel oil (50%sulfur reduction*) 0.5%-S residual fuel oil (75%sulfur reduction*) 0.3%-S residual fuel oil (85%sulfur reduction*) 0 .50 lb SOZ/MMbtu (77%sulfur reduction*) aturalVisibility Days (deciviews)

Switchfrom0

.501bSOZ/MMbtu emission limitto 0.3%Sresidualfuel oil SNCR (25%NOxreduction**) SCR (78%NOxreduction") Baghouse (85%PM

reduction On the20% tBase Acadia 0 .57 0 .30 0 .46 GreatGulf

0 .45 Lye Brook

0 .09 0 .24 - 0

.05 0 .36 0

.07 0 .52 0

.40 0 .47 

# C -_- -- <0 .05 L 0 .11 0 .34 0 .05 0 .08 0 .37 0

.08 0 .03 0 .10 0 .30 0 .04 tieV'isjbility Days (deciviews

- Pollutant ~ Control Level Acadia Great Gulf SOZ

NOx FGD

(90% sulfur reduction*) 1.0%-S residual fuel oil (50%sulfur reduction*) 0 .5%-S residual fuel oil (75%sulfur reduction*) 0 .3%-S residual fuel oil (85%sulfur reduction*) 0 .50lb SO2/MMbtu (77%sulfur reduction*) Switchfrom0

.50lb SOz/MMbtu emission limit to 0

.3%Sresidualfuel oil SNCR (25%NOxreduction**) SCR (78%NOxreduction**) PM Baghouse

1 (85%PM

reduction**) * frommaximum

permitted level ** frombaseline level with existing controls *** belowsensitivity limit of model 0 .13 0.07 0 .11 0 .13 0 .11 0 .01 0 .04 0 .11 0 .02 0

.10 <0

.01*** 0 .04 0 .12 0 .01 Lye Brook <0.01*** 0 .06 <0.01*** 0 .09 0 .10 0 .09 0 .01 0 .03 0 .10 0 .02 0

.01 0 .01 0 .01 <0 .01*** 0 .01 0 .03 <0.01***

Note: Values in boldface are considered as having greater validity in the modeling estimation of maximum visibility benefits fromBART controls.BART Analysis -PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 14

5 .1 CALGRIDModeling Analysis NHDES also conducted a screening-level analysis of the anticipated visibility effects of BART controls at PSNH Newington Station Unit NT1 . Specifically, one modeling run using the CALGRIDphotochemicalair quality model was performedto assess the effects of switching to lower-sulfur fuel for this unit. The simulation covered the full summer modeling episode (fromMay 15 to September 15, 2002) with MANE-VU's 2018 beyondon-the-way (BOTW) emissions inventory scenario as abaseline. 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 converted to visibility impacts) . Based on the CALGRIDmodeling results, switching to lower-sulfur fuel oil for Unit NTl is expected to reduce near-stack maximumpredicted 24-hour average SOZ concentration impacts by about 1 .4 ~tg/m3. Reductions in the maximum predicted concentrations of S02, PM2 .5, and other haze-related pollutants, combined, would yield negligible visibility improvement at the affected Class I areas. 6 . DETERMINATIONOF BART Based onthe completed review andevaluation of existing and potential control measures for PSNH Newington Station Unit NT1, it is determined that the NOx, PM, and SOZ controls described below

represent Best Available RetrofitTechnology for this unit. 6 .1 Selecting a Pollution Control Plan for NOx Use of low

excess air reduces NOXemissions but can often result in greater PM and/or CO emissions. Many ofthe NOXreduction benefits acquired through the implementation oflow excess air are already being achieved at Unit NT1 through the use of low-NOx burners, overfire air, andwater injection; so the application of low excess air would be redundant in this case. Flue gas recirculation reduces the peak flame temperature in much the same way as overfire air and has the additional benefit of reducing the oxygen content in the combustion zone, leading to further reductions in NOX formation. Because Unit NTI operates with an existing overfire air system, and because this boiler has already been modified by the installation of natural gas lances, FGR is economically impractical and might also be physically infeasible. The NOx emission reductions being achieved at Unit NT1 through the use of combustion control technologies are a substantial improvement over no controls. Retrofitting the facility with SCRor SNCRwould reduce NOx emissions by an additional 300to 700tons per year. Despite the sizeable emission reductions that SCRor SNCRwould provide, with annualized costs of $0.7 to $1 .3 million, neither technology option could be implemented costeffectively. Note that these dollar amounts do not include the significant additional costs of redesigning Newington Station's layout to address spatial constraints. Also, the estimated costs are based on 2002 emission levels, when the plant's capacity factor was around 20 percent. With thecapacity factor having fallen to less than 10percent over the period 2006-BART Analysis -PSNH Unit NT1 January 14, 2011 ; amended August 26, 2011 Page 15

2009, it is difficult tojustify additional technology retrofits to reduce NOx emissions at this facility today. This conclusion is reinforced by the small improvement in visibility that might be obtained with such retrofits on the few occasions when meteorological conditions would indicate maximum impacts. Another consideration with SCR or SNCR is flue gas and fugitive ammonia emissions. Based on past operation ofUnit NT1 and on typical ammonia "slip" rates, it is estimated that fugitive ammonia emissions with either technology would be in the vicinity of 32 tons annually. Ammonia is a regulated toxic air toxic pollutant in New Hampshire and is also a significant contributor to visibility impairment. However, the issue is not so much the magnitude of ammonia slip, toxicity, or visibility impairment as the fact that ammonia slip would occur at all . On balance, this is a relatively minor negative to be weighed in the context ofother factors. Based on all ofthese considerations, NHDES finds that SCRand SNCRare not cost-effective as Best Available Retrofit Technology for NOx control at this facility andwill not be evaluated further. The existing NOx controls, which include low-NOx burners, overfire air, and water injection, aredetermined to fulfill BART requirements for NewingtonStation Unit NT1. Because additional retrofits are not proposed, completion of the BART assessment for Unit NT1 becomes a matter of ascertaining this facility's long-termperformance capability with existing equipment. NHDES reviewed emissions data for Unit NT1 for the period from 2003 to 2005, when more than 99 percent ofthe gross heat input came fromresidual fuel oil . Monthly average NOx emissions ranged between 0 .21 and 0.30 lb/MMBtu. These values compare favorably with the facility's NOx RACT limit of 0.25 lb/MMBtu, daily average, when burning natural gas and 0 .35 lb/MMBtu, daily average, when burning fuel oil . However, the extent of the data record is insufficient to demonstrate that the facility could sustainably meet more restrictive emission limits than these. The current NOx RACT limitations for Unit NT1 are therefore considered to represent BART control levels. 6 .2 Selecting a Pollution Control Plan for PM PSNH currently operates an electrostatic precipitator on Unit NTI . ESPs performwith removal efficiency rates similar to those offabric filters but operateat about halfthe cost for plants ofthis size. Although it may be technically feasible to improve performance ofthe existing ESPthroughsome formof upgrade, it is difficult tojustify any major capital expense at this facility in light of its recent operating history. Since 2006, the plant's capacity factor has been below10 percent. In consideration of the facts that Unit NT1 already operates a fully functional ESP, that additional capital outlay for PM control cannot be economically justified at this time, and that any resulting benefit to visibility would be negligible, it is determined that the existing ESPfulfills BART requirements. The single available stack test on this unit indicates that the ESP yields controlled TSP emission rates in the vicinity of 0 .06 lb/MMBtu versus a currently permitted rate of 0 .22 lb/MMBtu. The extent ofthe data record is insufficient to support consideration ofa BART performance level more restrictive than the existing permit limit. The facility's Title V operating permit requires that a compliance stack test for PMemissions be performed on Unit NT1 before the permit expires on March 31, 2012. NHDES will review the stack test results to ascertain the unit's performance and incorporate any newlimit into a permitBARTAnalysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 16

amendment by the permit expiration date, as appropriate. The permit expiration date precedes theeffective date ofproposed BART control measures by fifteen months. 6 .3 Selecting a Pollution Control Plan for S02 Flue gas desulfurization is a potential SOZ control option for PSNH Newington Station Unit NTI . However, the cost per ton for FGDon oil-fired boilers is estimated to be about twice the cost of this technology on coal-fired boilers and could well exceed $1,000/kWfor Newington Station

. Given the high costs of this option, it is apparent that FGDwould be uneconomical as a retrofit for apeak-demand plant the size ofUnit NTI . Use of a lower-sulfur fuel is a practical option for controlling S02emissions at Newington Station. When natural gas is available at reasonable cost relative to residual fuel oil, natural gas is the preferred fuel because of its very low sulfur content. Otherwise, use of low-sulfur residual fuel oil is a reasonable option. For relatively minor increases in the cost of fuel, switching to 1 .0%-sulfur or 0 .5%-sulfur residual fuel oil would provide significant reductions in fuel sulfur content with proportional reductions in S02emissions. When not firing exclusively on natural gas, Newington Station Unit NTI has traditionally burned No. 6 fuel residual fuel oil at 2 .0 percent (nominal) sulfur content. From2002 to 2009, the actual average annual sulfur content ofthe fuel oil ranged between 1 .03 and 1 .54 percent by weight, with no significant trend (average fuel sulfur contentwas 1 .21 percent in 2002) . For New

Hampshire's BART analysis of this plant, the following fuel sulfur values were assumed: Nominal %S Assumed Actual %S (permit limitation) (chemical assay) 2.0 1 .2 1 .0 0 .8 0.5 0 .4 Under these assumptions, switching from2.0 %S (nominal) to 1 .0 %S (nominal) residual fuel oil would produce a one-third reduction in sulfur dioxide emissions, and switching to 0 .5 %S (nominal) residual fuel oil would produce a two-thirds reduction in sulfur dioxide emissions at this facility. The proposed fuel switching could be accomplished without capital expense and would have predictable costs tied directly to fuel consumption and fuel price differentials. The cost per ton would be no more than about $1,900 (historical fuel prices suggest a range of $0 to $2,000 per ton) . At the 2002 production level of 700 million kilowatt-hours, estimated annual costs (long-term average, 2008$) for switching to 1 .0%or 0 .5%residual fuel oil would be about $3.3 or $6.6 million (equivalent to $0.0047 or $0.0094 per kWh), respectively. The cost per kilowatt-hour would vary more or less in proportion to the fuel price differential and would not change significantly with increases or decreases in production level . While fuel availability is always a consideration, supplies should not be a significant factor in obtaining fuels whose sulfur content is as low as 0.5 percent. Residual fuel oil at 1 .0% sulfur is alreadywidely distributedwithin the region; and there is greater assurance todayof the availability 0.5%-sulfur residual fuel oil than in 2008, when NewHampshire beganBARTAnalysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 17

drafting its BART determinations. Maine, Massachusetts, New Jersey, and other states within MANE-VUare moving toward or already require the use of0.5%-sulfur residual fuel oil, thus ensuring the presence ofa regional market for this commodity. NHDES considered the possible useof0 .3%-sulfur residual fuel oil for Unit NT1 ; butthis fuel has hadonly very limitedusewithin the northern New England region, and its future availability and price remain uncertain. More specifically, the fact that some plants in Connecticut are using 0 .3%-sulfur residual fuel oil today does not guarantee the availability of this fuel in northern New

England, whichobtains its bulk oil shipments throughdifferent ports. For Unit NT1, the possible use of low-sulfur residual fuel oil is complicated by the plant's lowcapacity factor and existing fuel stocks and storage facilities. The plant now has a sizeable quantity of higher-sulfur residual fuel oil in storage tanks on site. Because there is no practical way to offload and replace the existing inventory with a lower-sulfur residual fuel oil, the existing stock ofhigher-sulfur fuel oilwould have to be used up before requiring that Unit NT1 be fired exclusively with low-sulfur fuel oil . Also, it is anticipated that the plant will continue to have a low utilization rate andcapacity factor in the coming years (its capacity factor was less than 7 percent in 2009) . Given this scenario, depletion of the existing stock ofresidual fuel oil could take more than a year, or substantially longer ifthe facility co-fires with natural gas to reduce sulfur dioxide emissions. EPAhas suggested greater use ofnatural gas and/or low-sulfur distillate fuel oil for Unit NTI in place of residual fuel oil . The substitution of No. 2 distillate fuel oil for No. 6residual fuel oilwould not be practical for this facility for twomajor reasons: the high cost of burner replacements needed to implement this option, and the plant's lowutilization rate and capacity factor. Unit NT1 would produce relatively few kilowatt-hours of generation through whichto recover capital costs. Greater use of natural gas is a reasonable option when its price is competitive with that of residual fuel oil . Recent years have witnessed sudden and dramatic swings in the price of natural gas relative to fuel oil as supply/demand has shifted. While the future price and availability of natural gas remain difficult to discern, the market for natural gas is expected to expand amid global concerns about carbon emissions and a visible renaissance in gas explorationand development. Unit NT1 has considerable operational flexibility with respect to fuel selection. The boiler can be fired with either natural gas or liquid fuel as the only fuel, or it can be co-fired with both fuel types simultaneously. However, because of physical limitations to the boiler's design, the unit can operate at no more than about 50 percent of maximum heat input when fueled solely by natural gas. There is already a natural incentive for PSNHto operate Unit NT1 with natural gas as much as possible whenever the price ofthis fuel is competitive with or less than the price of liquid fuels. In recognition of the dual-fuel capability of Unit NT1, NHDES has developed for this facility a requirement by rule establishing a new sulfur dioxide emission limitation of 0 .50 lb/MMBtu§ applicable to any fuel type or mix. The recently adopted rule (Attachment GG) § This limit is calculated using USEPA's published AP-42 emission factor for SO2 of 150(S) lb SOz/1000 gallons. Assuming 0

.5% fuel sulfur content byweight and aheating value of 150,000Btu/gallon for No. 6fuel oil, the SOZ emission rate would be 150 x 0.5 = 0 .075 lb/gallon, andthe SOZ emission factor would be 0.075BARTAnalysis - PSNHUnit NT1 January 14, 2011 ; amended August 26, 2011 Page 18

will allow

the facility the flexibility to burn natural gas and/or fuel oil in any feasible ratio, depending on market conditions. New Hampshire's new

rule will cause a substantial reduction in S02 emissions fromUnit NT1 regardless of fuel type while rendering unnecessary any need to speculate on the direction of relative fuel supplies and prices. For the first regional haze progress report, due no later than December 17, 2012, NHDESwill reviewfuel usage, fuel supplies, fuel prices, and plant utilization/capacity factors to determine whether the fuel sulfur limitation described above is still appropriate as BART control for Unit NT1 . Should the review indicate a different BART control level, the facility's Title V operating permit will be amended as necessary before its expiration date of March 31, 2012, fifteen months prior to the effective date of proposed BART control measures. The use of low- or ultra-low-sulfur residual fuel oil will be reconsidered as part of this review . Looking beyond 2012, a possible further reduction in the sulfur content of fuel oil burned at this facility would be consistent with MANE-VU's plan to reduce sulfur levels to 0 .25-0.5%for all residual fuel oils throughout the region by 2018 (refer to "Statement of the Mid-Atlantic/ Northeast Visibility Union (MANE-VU) Concerning a Course of Action within MANE-VU toward Assuring Reasonable Progress," June 20, 2007, included in Attachment E) . 7 . SUMMARYANDCONCLUSIONS Table 7-1 summarizes Best Available Retrofit Technology for PSNH Newington Station Unit NT1 for the pollutants NOx, PM, and S02. The summary includes existing controls that have been determined to fulfill BART requirements as well as new operating conditions consistent with BART requirements. Amore stringent sulfur dioxide emission limitation, established by a rule change, will require the facility to reduce average fuel sulfur content through appropriateadjustments to its fuel mix.

Table 7-1 . Summaryof BART Determinations for Unit NT1 Pollutant Current Emission BART Controls BART

Controls Emission Limit NOx Low-NOx burners, Low-NOxburners, 0 .35 lb/MMBtu (oil) and overfire air, and water overfire air, and water 0.25 lb/MMBtu (oil/gas), injection injection daily avg. (= RACT limit) PM ESP ESP 0.221b/MMBtu total suspended particulate (TSP) SOZ 2.0%

sulfur content limit SOZ emission limitation of 0 .50lb/MMBtu, on residual fuel oil ; 0 .50lb/MMBtu, 30-day rolling average 0.4%sulfur content limit applicable to any fuel type on distillate fuel oil or mix

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